19931994
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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 DECEMBERDecember 31, 19931994
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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
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Commission File Number 1-368-2
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CHEVRON CORPORATION
(Exact name of registrant as specified in its charter)
225 Bush Street,
Delaware 94-0890210 San Francisco, California 94104
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(State or other (I.R.S. Employer (Address of principal (Zip Code)
jurisdiction of Identification Number) executive offices)
incorporation or
organization)
Registrant's telephone number, including area code (415) 894-7700
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
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Common stock par value $3.00$1.50 per share New York Stock Exchange, Inc.
Preferred stock purchase rights MidwestChicago 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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X][ ]
Aggregate market value of the voting stock held by nonaffiliates
of the Registrant
As of February 28, 19941995 - $28,168$30,975 million
Number of Shares of Common Stock outstanding as of
February 28, 19941995 - 325,825,185651,937,188
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of Annual Meeting and Proxy Statement Dated March 25, 199424, 1995 (in Part
III)
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TABLE OF CONTENTS
PAGEPAGE(S)
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ITEM YEAR 19931994 MARCH 25, 1994
-24, 1995
---- 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 . . . . . . . . . . . . . 45 -
(c) Description of Business and Properties . . 45 -
Capital and Exploratory Expenditures . . . 56 -
Petroleum - Exploration . . . . . . . . . 67 -
Petroleum - Oil and Natural Gas Production 911 -
Production Levels . . . . . . . . . . . 911 -
Development Activities . . . . . . . . . 1013 -
Petroleum - Natural Gas Liquids . . . . . 1518 -
Petroleum - Reserves and
Contract Obligations . . . . . . . . . . . 1619 -
Petroleum - Refining . . . . . . . . . . . 1620 -
Petroleum - Refined Products Marketing . . 1821 -
Petroleum - Transportation . . . . . . . . 1923 -
Chemicals . . . . . . . . . . . . . . . . 2124 -
Coal and Other Minerals . . . . . . . . . 2225 -
Real Estate . . . . . . . . . . . . . . . 2226 -
Research and Environmental Protection . . 2326 -
2. Properties . . . . . . . . . . . . . . . . . . . 2529 -
3. Legal Proceedings . . . . . . . . . . . . . . . 2529 -
4. Submission of Matters to a Vote of
Security Holders . . . . . . . . . . . . . . . . 2832 -
Executive Officers of the Registrant . . . . . . 2832 -
PART II
5. Market for the Registrant's Common Equity
and Related Stockholder Matters . . . . . . . . 3034 -
6. Selected Financial Data . . . . . . . . . . . . 3034 -
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . 3034 -
8. Financial Statements . . . . . . . . . . . . . . 3034 -
8. Supplementary Data - Quarterly Results . . . . . 3034 -
Supplementary Data - Oil and
Gas Producing Activities . 3034 -
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure . . . . . 3034 -
PART III
10. Directors and Executive Officers
of the Registrant . . . . . . . . . . . . . . . 30 4-634 2-4
11. Executive Compensation . . . . . . . . . . . . . 30 15-1734 11-13
12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . 30 2-334 5
13. Certain Relationships and Related Transactions . 3034 -
PART IV
14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K . . . . . . . . . . . . 3135 -
PART I
ITEM 1. BUSINESS
(a) GENERAL DEVELOPMENT OF BUSINESS
SUMMARY DESCRIPTION OF CHEVRON
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Chevron Corporation (1), a Delaware corporation, is a major international oil
company. It provides administrative, financial and management support for, and
manages its investments in, domestic and foreign subsidiaries and affiliates,
which engage in fully integrated petroleum operations, chemical operations,
real estate development and other mineral and energy related activities in the
United States and approximately 100 other countries. Petroleum operations
consist of exploring for, developing and producing crude oil and natural gas;
transporting crude oil, natural gas and petroleum products by pipelines,
marine vessels and motor equipment; refining crude oil into finished petroleum
products; and marketing crude oil, natural gas and the many products derived
from petroleum. Chemical operations include the manufacture and marketing of a
wide range of chemicals for industrial uses.
Incorporated in Delaware in 1926 as Standard Oil Company of California, the
company adopted the name Chevron Corporation in 1984. Domestic integrated
petroleum operations are conducted primarily through three divisions of the
company's wholly owned Chevron U.S.A. Inc. subsidiary. Exploration and
production ("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 U.S.A. Products Company.
Warren Petroleum Company engages in all phases of the domestic natural gas
liquids business. A list of the company's major subsidiaries is presented on
page 40EX-2 of this Annual Report on Form 10-K. As of December 31, 1993,1994, Chevron
had 47,57645,758 employees, 7877 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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After starting the year at a five-year low, crude oil prices rebounded in the
second quarter of 1994 on news of OPEC's decision at their March 1994 meeting
to hold production at their current level of 24.5 million barrels per day for
the balance of the year (subsequently extended through 1995) and concern of
supply disruptions due to local disturbances in Nigeria. Crude oil prices
rose slightlybegan to fall in the first quarter of 1993August and remained
steadycontinued to trend downward through the second quarter before trending downward for the remainderend of the
year. The decline was particularly prominent duringyear due to ample crude supplies, settlement of the last two
months of 1993, with prices reaching their lowest level in five years by year
end. The weak global economy has dampened the demand for petroleum and
petroleum related products. Increased production from non-OPEC countries,
particularly from the North Sea, and OPEC's failure to adjust their
production levels accordingly has further exacerbated the decline in crudeNigerian oil prices. Partially mitigating the effects of
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(1) As used in this report, the term "Chevron" and such terms as "the
company," "the corporation," "our," "we," and "us" may refer to Chevron
Corporation, one or more of its consolidated subsidiaries, or to all of
them taken as a whole, but unless the context clearly indicates
otherwise, should not be read to include "affiliates" of Chevron (those
companies owned approximately 50 percent or less).
As used in this report, the term "Caltex" may refer to the Caltex Group
of companies, any one company of the group, any of their consolidated
subsidiaries, or to all of them taken as a whole and also includes the
"affiliates" of Caltex.
All of these terms are used for convenience only, and are not intended as
a precise description of any of the separate companies, each of which
manages its own affairs.
- 1 -
lower crude oil prices were higherworker's strike in early September and an abnormally mild winter in most parts
of the United States. The company's U.S. realizations declined 72 cents per
barrel from the previous year, representing the fourth consecutive year
average realizations have fallen.
U.S. natural gas prices. Unseasonableprices also trended downward throughout 1994 after having
posted increases in the prior three years. Factors contributing to the
decrease in natural gas prices included poor utility demand driven by the
relatively mild summer and winter weather patterns, lowin many parts of the U.S., increased
Canadian gas exports to the U.S., high gas storage levels the lossand improved
performance of three nuclear power plants that experienced downtime in the Southeast for a portion of the year, and the environmentally preferred
attributes of natural gas all contributed to the stronger natural gas prices.previous
year. In the United States, the Henry Hub, Louisiana spot price for natural
gas, a common benchmark for natural gas prices, averaged $2.21$1.86 per thousand
cubic feet (MCF) in 1993, an increase1994, a decrease of $.41$.25 per MCF over 1992. Strong refined
product prices, which did not decline as rapidly as crude oil prices, also
helped to dampen the effects of lower crude oil prices. However, product
prices in the United States fell late in the year and have remained low into
1994. If both crude oil and refined product prices continue at their low
levels, thefrom 1993.
The company's earnings and cash flow from ongoing operations may be
negatively affected. Widely fluctuating prices have become characteristic of
the petroleum industry for the past several years.
Chevron's average realization from U.S. crude oil production declined from
$16.50 per barrel in 1992 to $14.58 per barrel in 1993 to $13.86 per barrel in 1994 while average liquids
realizations from international liftings, including equity affiliates,
declined by $1.84$1.23 per barrel to $16.09$14.86 per barrel. Average U.S. natural gas
realizations from production increaseddecreased to $1.77 per MCF in 1994 from $1.99 per
MCF in 1993 from $1.70
per MCF in 1992.1993.
The following table compares the high, low and average companyChevron posted prices
for West Texas Intermediate (WTI), an industry benchmark light crude oil, for
each of the quarters during 19931994 and for the full years of 1994, 1993, 1992, and
1991:
-1992:
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WEST TEXAS INTERMEDIATE CRUDE OIL
CHEVRON POSTED PRICES
(Dollars per Barrel)
1994
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1ST Q 2ND Q 3RD Q 4TH Q YEAR 1993 -------------------------------------
1st Q 2nd Q 3rd Q 4th Q Year 1992 1991
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High 20.2515.00 19.75 19.50 18.00 18.0019.75 20.25 21.75
29.50
Low 17.50 18.00 16.0013.00 13.75 15.75 15.75 13.00 13.00 16.50
16.75
Average 19.09 19.10 17.01 15.5813.80 16.71 17.48 16.68 16.18 17.68 19.71 20.20
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For the first two months of 1994,1995, average natural gas realizations for the
company's U.S. operations were $2.14$1.43 per MCF. During this period, the
company's posted price for WTI ranged from $13.00$16.50 per barrel to $15.00$18.00, with
an average of $13.86.$17.28. On March 21, 1994,20, 1995 the company's posted price for WTI was
$14.25$17.50 per barrel.
Chevron's refining and marketing operations in the United States were
adversely affected by scheduled and unscheduled refinery downtime and other
refinery operating problems in the first half of 1994. These refinery problems
increased the company's operating costs and caused the company to purchase
more costly third-party products to supply the company's marketing system.
This put additional pressure on the company's sales margins on refined
products which were already depressed most of the year due to ample supplies
in the marketplace. The company's average sales price per barrel of refined
product declined for the fourth year in a row, falling to $24.37 per barrel in
1994 from $25.35 per barrel in 1993.
The company's chemical operations improved significantly in 1994 as improving
worldwide economies, including the U.S., reduced industry overcapacity,
resulting in higher sales volumes and stronger prices for the company's
commodity chemicals. Sales and other operating revenues from the company's
chemical operations, including sales to other Chevron companies, increased
$431 million from the $3,296 million recorded in 1993.
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CHEVRON STRATEGIC DIRECTION
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To improve financial performance and to compete more effectively, Chevron
developed and began implementingimplemented seven "strategic intents" in 1992. These are
to:
- - SHIFT EXPLORATION AND PRODUCTION EMPHASIS TO INTERNATIONAL OPPORTUNITIES.1992 and added an
eighth "strategic intent" in 1993. The company periodically reviews and
modifies these "strategic intents" to reflect Chevron's current operating
environment. The eight "strategic intents" for 1995 are:
- BUILD A COMMITTED TEAM TO ACCOMPLISH THE CORPORATE MISSION. The company
continues to believe the success of the other seven strategic intents is
dependent on the commitment and dedication that Chevron employees bring
to their jobs. For the past three years, Chevron has measured employees'
attitudes about the company and diagnosed areas of employee concerns by
the use of the Worldwide Employee Survey. Due in large part to employee
responses to the surveys, the company has recently developed or revamped
programs in the areas of skills development, job selection, and upward
feedback, a process in which employees are given the opportunity to
evaluate their immediate supervisor. In 1994, the company sought to
articulate this "strategic intent" by issuing a vision statement that
outlined the attributes of a committed team. Underlying the vision
statement was the need to promote trust, respect, support and teamwork
among and between its employees and supervisors. The company is
encouraging informed risk taking and encouraging employees to take an
active role in planning and decision making while also increasing their
accountability. Due in part to this "strategic intent," a greater number
of cross-functional teams are being formed in the company to make
decisions and manage projects, demonstrating a greater amount of teamwork
and cooperation among its employees. In January 1995, the company
announced a new program that will provide employees with a cash bonus if
the company achieves certain financial goals. In 1995 the program, called
"Chevron Success Sharing," will be based on Chevron's adjusted Return on
Capital Employed (ROCE). If the company achieves an ROCE of 10 percent or
greater and its ROCE is among the top four of its major U.S. competitors,
a cash bonus, varying from two to eight percent of an employee's annual
salary depending on the company's relative ROCE ranking, will be paid to
employees eligible to participate in the program.
- FOCUS ON REDUCING COSTS ACROSS ALL ACTIVITIES. Operating expenses,
adjusted for special items, declined $150 million in 1994 when compared
to 1993, sustaining the prior year's cost reductions as well as
offsetting inflation and mitigating expenses associated with refinery
problems in the first half of 1994. When 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 1994 have declined by over $1 billion. Although a portion of
the cost reduction is related to discontinued operations, the company
believes the majority is the result of a permanent reduction in the
company's ongoing cost structure.
The company remains committed to further reductions in operating expense
in 1995. Four "breakthrough" initiatives are currently in various stages
of study or implementation that could result in large, permanent cost
savings. These four "breakthrough" initiatives involve ways to reduce
corporate energy costs; ways to reduce the cost of goods and services by
working more efficiently with fewer suppliers; improvements to the
project management process which is used to evaluate and administer large
capital projects; and improvements in inventory management in order to
avoid tying up working capital in excessive inventories.
- CONTINUE UPSTREAM GROWTH IN INTERNATIONAL AREAS. The company continues
to believe opportunities to discover and develop major new reserves in
the United States are limited due to regulatory barriers and drilling
prohibitions on many of the most promising areas of development. In 1993, 68 percent of the1994,
international exploration and production (E&P) capital spending rose 3
percent to approximately 71 percent of total E&P capital spending,
including affiliates, was allocated toaffiliates. This same ratio of international operations. In 1994,
that numberversus total E&P
spending is expected to increase to 75 percent.continue in 1995. As recently as 1990, U.S.
exploration and production capital spending was approximately 50 percent
of the total. As an important example of this new emphasis, in
April 1993, the company entered into a joint venture agreement with the
Republic of Kazakhstan to develop the massive TengizSince 1991, international oil field in that
country.and gas production has
increased nearly 25 percent and oil and gas reserves have increased 80
percent.
- 23 -
- - GENERATE $1 BILLIONGREATER THAN $800 MILLION IN CASH ANNUALLYPER YEAR FROM U.S. EXPLORATION AND PRODUCTION
OPERATIONS.UPSTREAM.
Chevron is emphasizing a steady cash flow from a core group of
approximately 400 oil and gas fields concentrated in California, Texas,
the Rocky Mountains and the Gulf of Mexico. In 1993, netNet cash flow after capital
and exploratory expenditures for U.S. exploration and production
operations was more thanfell to $750 million in 1994 from $1.2 billion. Lower operating expensesbillion in 1993 due to
weak crude oil and an
improved natural gas market helpedprices throughout most of the year.
The company modified this "strategic intent" in 1995 by lowering the
annual cash generation amount from $1 billion to mitigate$800 million. This
modification reflects the effects of lower crude
oil prices. If crude oil prices do not rebound, this goal may be difficult
to achieve in 1994.
- - RESHAPE THE U.S. REFINING AND MARKETING COMPANY INTO A TOP COMPETITOR.
Chevron is currently the leading U.S. marketer of refined products and has
the largest refining capacitysignificant change in the nation.outlook for both
crude and U.S. natural gas prices since the original "strategic intent"
was set in 1991 combined with the progress achieved in cost reduction.
The company continues to evaluate its current properties as well as
evaluate and acquire new properties that the company believes will help
it meet and sustain its cash generation goal. In 1994, the company
acquired certain gas properties in West Texas by purchasing 100 percent
of the stock of Pakenham, Inc., a subsidiary of Wes-Tex Drilling Company.
The company believes these properties hold considerable development
potential. Over the next five years, Chevron plans to drill about 150
wells on these properties at a cost of approximately $100 million and
expects production to triple to 90 million cubic feet per day by 1999.
- ACHIEVE TOP FINANCIAL PERFORMANCE IN U.S. DOWNSTREAM. Chevron is seeking
to strengthen its competitive position by investing in core refineries,
reducing the size of its refining system and concentrating on specific
marketing regions. Major projects are continuing atThe company sold its Philadelphia, Pennsylvania,
refinery to Sun Company, Inc. in August 1994 and its Port Arthur, Texas,
refinery to Clark Refining and Marketing, Inc. in February 1995. These
refineries no longer fit Chevron's plan to have a more focused U.S.
refining operation and their sales eliminated large capital expenditures
that would otherwise have been required to make the company's Richmondrefineries more
competitive and El Segundo, California refineries in order to produce reformulated
fuels to meet the January 1995 emission requirements of the Clean Air Act Amendments of 1990 and the 1996 requirements of the California Air
Resources Board. The company expects to complete the sale of its
Philadelphia, Pennsylvania and Port Arthur, Texas refineries in 1994,
thereby reducing its refining capacity about 25 percent.
-1990.
- GROW CALTEX IN ATTRACTIVE MARKETS.MARKETS WHILE ACHIEVING SUPERIOR COMPETITIVE
FINANCIAL PERFORMANCE. Management believes that the demand for petroleum
products will continue to grow in the Asia Pacific region andregion. Chevron's 50
percent owned Caltex affiliate, a leading competitor in these areas, has
madeand is continuing to make significant capital investments to expand and
upgrade its refining capacity.capacity and its retail marketing systems. Refinery
upgrade projects are currently underwaycontinuing in Singapore and Korea, as well as the
construction of a new refinery in Thailand. In 1994, Caltex opened
representative offices in Ho Chi Minh City and Hanoi to develop and
evaluate business opportunities in Vietnam. In China, Caltex is exploring
technical and commercial aspects of developing a business relationship
with Sinopec's Nanjing Refinery operated by Jinling Petrochemical
Corporation. Caltex is also studying the feasibility of a joint venture
with Shantou Ocean Enterprises to build a liquefied petroleum gas (LPG)
terminal in Shantou, China.
- - EXPLOITIMPROVE COMPETITIVE STRENGTHSFINANCIAL PERFORMANCE IN CHEMICALS. The petrochemicalCHEMICALS WHILE DEVELOPING
ATTRACTIVE OPPORTUNITIES FOR GROWTH. Financial results for the company's
chemical operations improved significantly in 1994 as the chemical
industry is
highly cyclical.in general rebounded from a period of depressed earnings due to
sluggish world economies and production overcapacity. Improving world
economies resulted in increased demand for the company's commodity
chemicals, which are used to package or manufacture numerous consumer
goods. In order to improve its competitive position,addition, the company is concentrating on areasbelieves the restructuring and cost
reduction plans that have been implemented in recent years positioned the
company to take advantage of the petrochemical businessimproved industry conditions. In 1995,
the company plans to continue its restructuring with the closing of its
nitric acid and fertilizer plants in which it holds
a competitive advantage, such asRichmond, California, while also
investing in areas demonstrating growth potential. Chevron plans to
invest about $200 million in its proprietary Aromax (R) process usedchemical operations in 1995, including
plans to produce high value benzene fromexpand production capacity by 65 percent at its linear low
value by-products of the oil
refining process. The first Aromax (R)density polyethylene (LLDPE) plant in the U.S., located at the
company's Pascagoula, Mississippi, refinery, wasCedar Bayou, Texas. This expansion
is expected to be completed in 1993. The
company also announced, in January 1994, a cost reduction plan intended to
reduce annual operating expense by approximately $100 million by 1996.
An
integral part of the plan is to divest or close non-core assets and
sharpen the company's focus on the remaining core businesses.
- 4 -
- 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 U.K., respectively, The Pittsburg & Midway Coal Mining Co. (P&M),
operator of the company's mineral 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. Chevron
manages these four units for cash flow and profitability, and for growth
when attractive opportunities exist. In 1993, Chevron continued1994, GOGB expanded its service
station network by approximately 7 percent to disposetotal about 500 service
stations at year-end. P&M completed its planned sale of marginally performing or non-strategic assets, including various oil
and gas properties locatedChevron's non-
coal interests in 1994 with the sale of its 50 percent interest in the
United StatesStillwater platinum and Indonesia. The company
also divested its ORTHO lawn and garden products business, retail
marketing operationspalladium mine in Guatemala, Nicaragua and El Salvador, certain
undeveloped coal properties in the U.S.,Montana and its Vinwood Cellars Winery in
California. Properties currently for sale include the company's 52.5 percent
interest in some zinc-lead prospects in Ireland, refineries
locatedIreland. CL&D generated over $140
million in Philadelphia, Pennsylvaniasales of developed and Port Arthur, Texas,undeveloped real estate properties in
1994.
In 1994, Chevron continued to dispose of other marginally performing or
non-strategic assets, including the aforementioned refinery sales and the
company's headquarters building located in San Francisco, California. - - FOCUS ON REDUCING COSTS ACROSS ALL ACTIVITIES. Chevron undertook an
extensive cost-cuttingDue
to recent downsizing and work force reduction programrestructuring of its operations, it was
determined that employees currently located in early 1992.
These efforts,the headquarters building
could be accommodated in combination with the company's continuing programother two San Francisco office
buildings. Relocation of employees is expected to dispose of non-core or underperforming assets, reduced 1993 operating
costs, adjusted for special items, by approximatelyoccur over the next 5
percent or 40 cents
a barrel from 1992 levels. When compared to the base year of 1991, ongoing
operating, selling and administrative expenses have dropped by 11 percent,
or 94 cents a barrel. To remain competitive, the company's management has
set a number of new goals, including a new cost-reduction target of an
additional 25 cents a barrel by the end of 1994.
In 1993, the company established a new "strategic intent:"
- - BUILD A COMMITTED TEAM TO ACCOMPLISH THE CORPORATE MISSION.years.
The company believes the success of the other seven strategic intents is dependent on
the commitmentcurrently seeking prospective purchasers for its real
estate development assets in California and dedication that Chevron employees bring to their jobs.
In a 1992 employee surveyis currently reviewing its
oil and a 1993 update, Chevron measured employee
- 3 -
commitment using a model that assesses employee's willingness to expend
discretionary effort on the job, combined with how strongly they feel the
company deserves that effort. The surveys highlighted employee concerns
on issues that the company is addressing. Due,gas operations in part, to the results
of the survey, the company has initiated a number of work and family
programs to help employees improve their productivity and commitment,
such as flexible schedules, part-time work, job sharing and various leave
programs. The company also presented commemorative wristwatches to its
employees and a one time cash bonus equal to 5 percent of their annual
salaries in appreciation for their efforts in meeting the company's five
year goal, established in 1989, to be number one in stockholders' return
among five peer U.S. oil companies. In February 1994, the company took
delivery of a new vessel, the Chevron Employee Pride, named in honor of
its worldwide workforce.western Canada.
(b) INDUSTRY SEGMENT AND GEOGRAPHIC AREA INFORMATION
The company's primary business is its integrated petroleum operations.
Secondary operations include chemicals and minerals. The petroleum activities
of the company are widely distributed geographically, with major operations in
the United States, Australia, United Kingdom, Canada, Nigeria, Angola, Congo,
Papua New Guinea, China, Indonesia and Zaire. The company's Caltex affiliate,
through its subsidiaries and affiliates, conducts exploration and production
operations in Indonesia and refining and marketing activities in the Eastern
Hemisphere, with major operations in Japan, Korea, Australia, the Philippines,
Thailand and South Africa. Tengizchevroil (TCO), a 50/50 joint venture with a
subsidiary of the national oil company of the Republic of Kazakhstan conducts
production activities in Kazakhstan, a former Soviet republic.
The company's and its affiliates' chemicals operations are concentrated in the
United States, but include operating facilities in France, Japan and Brazil.
The company's and its affiliates' principal minerals activities include bothconsist of
coal and platinum and palladium operations in the United States.
Tabulations setting forth three years' identifiable assets, operating income,
sales and other operating revenues for the company's three industry segments,
by United States and International geographic areas, may be found in Note 9 to
the Consolidated Financial Statements beginning on page FS-22 of this Annual
Report on Form 10-K.
(c) DESCRIPTION OF BUSINESS AND PROPERTIES
The petroleum industry is highly competitive in the United States and
throughout most of the world. This industry also competes with other
industries in supplying the energy needs of various types of consumers.
The company's operations can be affected significantly by changing economic,
regulatory and political environments in the various countries, including the
United States, in which it operates. The company evaluates the economic and
political risk of initiating, maintaining or expanding operations in any
geographical area.
- 5 -
In the United States, environmental regulations and federal, state and local
actions and policies concerning economic development, energy and taxation may
have a significant effect on the company's operations.
Internationally, the company is monitoringcontinues to closely monitor the civil unrest in
Angola and the political uncertainty in Nigeria and Zaire and the possible
threat these may pose to the company's oil and gas exploration and production
operations and the safety of the company's employees located in those
countries.
The company attempts to avoid unnecessary involvement in partisan politics in
the communities in which it operates but participates in the political process
to safeguard its assets and to ensure that the community benefits from its
operations and remains receptive to its continued presence.
- 4 -
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 are substantially of a short-term duration.
The company enters into forward exchange contracts as a hedge against some of
its foreign currency exposures. Interest rate swaps are entered into as part
of the company's overall strategy to manage the interest rate risk on its
debt. The impact of the forward exchange contracts and interest rate swaps on
the company's results of operations is not material.
CAPITAL AND EXPLORATORY EXPENDITURES
Chevron's capital and exploratory expenditures during 19931994 and 19921993 are
summarized in the following table:
-------------------------------------------------------
CAPITAL AND EXPLORATORY EXPENDITURES
(Millions of Dollars)
1994 1993 1992
------ ------
Exploration and Production $2,586 $2,217 $2,097
Refining, Marketing and Transportation 1,105 1,166
1,263
Chemicals 135 224 251
Coal and Other Minerals 44 42 79
All Others 103 90 112
------ ------
Total Consolidated Companies 3,973 3,739 3,802
Equity in Affiliates 846 701 621
------ ------
Total Including Affiliates $4,819 $4,440 $4,423
====== ======
-------------------------------------------------------
Total consolidated expenditures in 1993 were essentially flat1994 increased 6 percent when compared to
1992, declining less than 2 percent between periods. An1993, largely due to a $369 million increase in exploration and production
(E&P) expenditures of $120 millionthat was more thanpartially offset by lowerdecreases in chemical
expenditures of $89 million and decreases in the company's other operations.
Explorationrefining, marketing and
productiontransportation expenditures amounting to $61 million.
Consolidated E&P expenditures amounted to 5965 percent of the company's total
consolidated expenditures a 4in 1994, compared with 59 percent increase over 1992 levels.in 1993. The
percentage increase was due solely to increased expenditures in international
E&P as U.S. E&P expenditures, continued to decline, down 4as a percentage points to 34
percent of total consolidated
expenditures, remained relatively unchanged from 1993. U.S. E&P expenditures
in 1993. This decrease reflects
the continued shift in1994 included the company's emphasis from U.S. exploration and
production activities to international opportunities.acquisition of certain natural gas operations
in West Texas. Major international E&P expenditures in 19931994 included the
acquisition of exploration and development interests in the Republic of Congo
and exploration and development activities associated with the Alba Field in
the U.K. North Sea, the North West Shelf Project in Australia, the Hibernia
Project offshore Newfoundland, the Duri steamflood projectSteamflood Project
- 6 -
in Indonesia, Areas B and C in Angola, the Niger Delta region in Nigeria and
the Tengiz projectProject in Kazakhstan. Refining, marketing and transportation
outlays in 19931994 included expenditures for upgrading U.S. refineries to produce
fuels, such as low aromatics and ultra low sulfur
diesel fuel and reformulated gasoline in order to comply with current and future federal, state and local air
quality regulations.regulations as well as other projects intended to upgrade and increase
efficiencies at the refineries.
The company's share of capital and exploratory expenditures by its affiliates
was $846 million in 1994, an increase of 21 percent from $701 million in 1993.
This increase was primarily due to expenditures by the company's Caltex
affiliate in the high growth Pacific Rim areas on refinery expansion/upgrade
projects in Korea and Singapore and the construction of a new refinery in
Thailand.
In 1994,1995, the company expects to spend approximately $4.9$5.1 billion, including
its share of equity affiliates' expenditures, an increase of approximately 115
percent over 19931994 levels. Equity affiliate spending, primarily CaltexConsolidated expenditures in the high growth Pacific Rim areas, account for this increase
as consolidated expenditures in 19941995 are expected to
remain relatively flat at $3.7$3.9 billion while affiliate expenditures are
expected to increase 37 percent to $1.2 billion. Worldwide E&P expenditures
are expected to total $2.4$2.7 billion, of which approximately 7570 percent will be
for international projects such as the continued development of the Hibernia
Field, expansion of the North West Shelf Project, enhanced recovery projects
in Indonesia, development of the Tengiz projectField in Kazakhstan, development of
the Alba and Britannia fields in the North Sea, development of the N'Kossa and
Kitina fields in Congo, and other development projects in West Africa.
Refining,Worldwide refining, marketing and transportation expenditures are estimated at
$2.1$1.9 billion, with U.S. expenditures of about $1 billion, including continued upgrades$900 million. These U.S.
expenditures are largely due to U.S.major capital programs to manufacture clean
fuels at the Richmond and El Segundo, California, refineries to produce reformulated gasoline in order to comply withas mandated by
the
Clean Air Act Amendments of 1990 and California Air Resources Board regulations. Major international refining
and marketing expenditures in 1995 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. Chemical expenditures
are also expected to rise in 1995 due to planned expansion of the linear low-
density polyethylene manufacturing plant at the Cedar Bayou, Texas, chemical
facility.
The actual expenditures for 19941995 will depend on various conditions affecting
the company's operations, including crude oil prices, and may differ
significantly from the company's forecast. If low oil prices persist, expenditures, particularly for
exploration and production, may be lower than forecast. Significant
expenditures are expected over the next few years at the company's
manufacturing facilities to comply with federal, state and local
environmental regulations and to enable these facilities to produce cleaner
fuels for industrial and consumer use.
- 5 -
PETROLEUM - EXPLORATION
The following table summarizes the company's net interests in productive and
dry exploratory wells completed in each of the last three years and the number
of exploratory wells drilling at December 31, 1993.1994. "Exploratory wells"
include delineation wells, which are wells drilled to find a new reservoir in
a field previously found to be productive of oil or gas in another reservoir
or to extend a known reservoir beyond the proved area. "Wells drilling"
include wells temporarily suspended.
- -----------------------------------------------------------------------------
EXPLORATORY WELL ACTIVITY
NET WELLS COMPLETED (1)
WELLS DRILLING ---------------------------------------
AT 12/31/9394 1994 1993 1992 1991
------------------- ----------- ---------- -----------
GROSS (2) NET (2) PROD. DRY PROD. DRY PROD. DRY
--------- ------- ---- ---- ---- ---- ---- ----
United States 37 3343 32 53 17 32 14 42 16 39 25
--------- ------- ---- ---- ---- ---- ---- ----
Canada 13Africa 11 27 26 10 - 24 21
Africa 134 5 2 3 4 3 3
2 5
Other
International 42 18 55 42 27 35 10 - 9 515 4 1 5
--------- ------- ---- ---- ---- ---- ---- ----
Total
International 61 2653 22 60 44 30 39 18 7 27 31
--------- ------- ---- ---- ---- ---- ---- ----
Total
Consolidated
Companies 98 5996 54 113 61 62 53 60 23
66 56
Equity in
Affiliate -Affiliates 8 4 - 1 1 1 - 1 1-
--------- ------- ---- ---- ---- ---- ---- ----
Total Including
Affiliates 98 59104 58 113 62 63 54 61 23 67 57
========= ======= ==== ==== ==== ==== ==== ====
(1) Indicates the number of wells completed during the year regardless of
when drilling was initiated. Completion refers to the installation of
permanent equipment for the production of oil or gas or, in the case of a
dry well, the reporting of abandonment to the appropriate agency.
(2) Gross wells include the total number of wells in which the company has an
interest. Net wells are the sum of the company's fractional interests in
gross wells.
-----------------------------------------------------------------------------
- -----------------------------------------------------------------------------7 -
At December 31, 1993,1994, the company owned or had under lease or similar
agree-
mentsagreements undeveloped and developed oil and gas properties located throughout
the world. Undeveloped acreage includes undeveloped proved acreage. The
geo-
graphicalgeographical distribution of the company's acreage is shown in the next table.
- -----------------------------------------------------------------------------
ACREAGE* AT DECEMBER 31, 19931994
(Thousands of Acres)
DEVELOPED
UNDEVELOPED DEVELOPED AND UNDEVELOPED
---------------- -------------- ----------------
GROSS NET GROSS NET GROSS NET
------- ------ ----- ----- ------- ------
United States 3,994 3,123 4,626 2,841 8,620 5,9644,301 2,854 6,059 2,558 10,360 5,412
------- ------ ----- ----- ------- ------
Canada 18,213 10,374 528 383 18,741 10,75718,325 10,514 615 395 18,940 10,909
Africa 17,147 12,726 135 53 17,282 12,77926,589 18,143 139 55 26,728 18,198
Asia 54,297 23,944 61 21 54,358 23,96542,809 19,296 45 16 42,854 19,312
Europe 3,231 1,195 58 11 3,289 1,2063,060 1,362 62 14 3,122 1,376
Other International 9,656 3,257 57 16 9,713 3,27310,191 3,671 54 15 10,245 3,686
------- ------ ----- ----- ------- ------
Total International 102,544 51,496 839 484 103,383 51,980100,974 52,986 915 495 101,889 53,481
------- ------ ----- ----- ------- ------
Total Consolidated
Companies 106,538 54,619 5,465 3,325 112,003 57,944105,275 55,840 6,974 3,053 112,249 58,893
Equity in Affiliates 3,202 1,601 233 116 3,435 1,717
------- ------ ----- ----- ------- ------
Total Including
Affiliates 109,740 56,220 5,698 3,441 115,438 59,661108,477 57,441 7,207 3,169 115,684 60,610
======= ====== ===== ===== ======= ======
* Gross acreage includes the total number of acres in all tracts in which
the company has an interest. Net acreage is the sum of the company's
fractional interests in gross acreage.
- -----------------------------------------------------------------------------
- 6 -
The company had $222$257 million of suspended exploratory wells included in
properties, plant and equipment at year-end 1993.1994. The wells are suspended
pending drilling of additional wells to determine if commercially producible
quantities of oil or gas reserves are present. The ultimate disposition of
these well costs is dependent on the results of this future activity.
During 1993,1994, the company explored for oil and gas in the United States and
about 21 other countries. The company's 19931994 exploratory expenditures,
including affiliated companies' expenditures but excluding unproved property
acquisitions, were $533$526 million compared with $547$533 million in 1992, a 3 percent decrease.1993. Domestic
expenditures represented approximately 3440 percent of the consolidated
companies' worldwide exploration expenditures, essentially unchangeda 5 percent increase from the
prior year. Significant activities in Chevron's exploration program during
19931994 include the following (number of wells are on a "gross" basis):
UNITED STATES: Domestic exploratory expenditures, excluding unproved property
acquisitions, were $183$209 million in 1993,1994, compared to $189$183 million spent in
1992.1993. In addition, the company incurred costs of $11$28 million for unproved
property acquisitions in 1993.1994. The company continued to focus its 1993 exploratory
efforts in 1994 in the Gulf of Mexico, Texas, California, the Rocky Mountains
and in other areas where it has existing production. FifteenTwelve wildcat
exploratory wells were initiated in 1993.
Seven1994 of these exploratorywhich eleven were in new areas and
one was in an existing core area. Including three wells commenced in late
1993, thirteen wells were completed in 1993,1994, resulting in two discoveries located in the Houston Salt Basin and in
the Gulf of Mexico. Plans to spud aThe company's exploratory well in the Norphlet Trend prospect in Destin Dome Block
97, located 30 miles south of Pensacola, Florida in the Gulf of Mexico,
were deferred until March 1994 due to delaysresulted in the permit process.a dry hole. Exploration efforts in high-potential areas, including
Alaska's Arctic National Wildlife Refuge (ANWR) and parts of offshore Florida,
California and North Carolina have been blocked by legal restrictions and
drilling moratoria. Chevron and other oil companies have sued the Department
of Interior to recover bonus payments, lease rentals and certain geophysical
costs for federal offshore leases that remain undrilled due to state, federal,
and private objections to drilling. The company is seeking to recover
approximately $126 million, plus interest, spent on leases off Florida, North
Carolina and Alaska. Currently all parties have filed Motions for Summary
Judgment in this matter. Oral arguments were held on January 31, 1995 and a
ruling is expected in 1995.
- 8 -
AFRICA: In Africa, the company spent $104$81 million during 19931994 on exploratory
efforts, excluding the acquisition of unproved properties, compared with $108$104
million in 1992.1993. The company also acquired $9$19 million of unproved properties
in 1993.1994.
In Nigeria, the companycompany's operations are managed by three subsidiaries.
Chevron Nigeria Limited (CNL) operates and holds a 40 percent interest in
concessions totaling 2.3 million acres 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 600,000 acres with six 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, through a production sharing
contract signed in October 1994 with the Nigerian National Petroleum Company
(NNPC), in six other Benue Basin blocks. CNL drilled sixseven exploratory and
appraisal wells in 1993, with all six either having proved
reserves assigned or assignment deferred pending further exploration or
evaluation work. The company1994 which resulted in three new field discoveries, two
successful appraisal wells and two dry holes. CNL also acquired 3-D seismic
data covering Nigerian acreage of 1,410200 square kilometersmiles. COCNL, through its
operating partner, drilled one exploratory well in 19931994 which discovered gas
and separately entered
intogas condensate. CPNL will begin seismic studies in 1995 as part of a farm-in arrangementwork
program expected to span the next six years to explore for oil in six Benue
Basin blocks, totaling approximately 5,600 square miles. The company will
finance the exploration phase and offset its cost from any future crude oil
production. This production sharing agreement is a departure from the joint
venture agreements of three offshore
concessions.the past in which cost and revenue were shared according
to each party's interest in the venture.
In Angola, the company is the operator of a 7,0002,700 square kilometermile concession off
the coast of Angola's Cabinda exclave. The concession is divided into Areas A,
B, and C, with Area A generating all
currentthe majority of 1994 production. One successful exploration well wasArea B
production commenced in November 1994 with the commissioning of installations
in the Kokongo Field. Chevron has a 39 percent interest in the concession. Six
exploratory wells were drilled in 1994, with three wells in Area A during 1993 resulting
in oil discoveries. Two of these wells will be developed by drilling from
existing facilities while the discovery ofthird well will be appraised in 1995 for the
Numbi South East field which
was brought on stream in 1993 by linking it to the existing Numbi Field
facilities. Twoappropriate installation facilities required for development. The other three
exploratory wells were drilled in Areas B and C and a third
was drilled at the end of the year. These resulted in the
discoverydiscoveries of the M'Bili Field in Area CN'Sangui and a non-commercial accumulation in Area B. The
third well was tested in Area B as a discovery well, N'Sangui, in January
1994. Options for the development of M'Bili are currently being evaluated.Minzu fields. The current Exploration Periodexploration license
for Areas B and C was to expire at the end
of February 1994 with a provision to fulfill all obligations by the end of
August 1994. The company has requested an extension of the Exploration
Period. Under the existing agreement, two exploratory wells will be drilled
in Areas B and Cexpired in 1994. AnNegotiations are currently underway to
renew this agreement for five additional well may be drilled if the
extension is granted.years. In 1994, Chevron (operator)(operator
with 31 percent interest) and its partners are currently
negotiatingcompleted negotiations of a
Production Sharing Agreement for the recently awarded Deepwater Block 14, located due west of Areas
B and C. The Angolan government approved the agreement in December 1994 and
signing occurred in February 1995. A seismic program is expectedscheduled to be completedbegin in
April 1995 followed by the first of four exploration obligation wells in early
1996.
Offshore Congo, Chevron currently participates in two production licenses and
signedtwo exploration licenses. The company has a 29 percent interest in 1994. In the Congo, a regional 3-D
survey was acquired in 1993 covering the southern part ofKitina
production license and the Marine VII Block which includes bothexploration license operated by AGIP.
Between October 1994 and March 1995 Chevron acquired a 30 percent interest in
the KitinaN'Kossa production license and Kitina South discoveries, as well
as several additionalthe Haute Mer exploration prospects.license operated
by ELF Congo. The company and its partners plan to drill two wildcat wells in
1995, one in each of the two exploration areas. The company opened an office
in Congo in January 1995 to facilitate its participation in the two joint
ventures.
In Namibia,Zaire, the company has been conducting a detailed seismic evaluation of the offshore Namibia Block
2815, where Chevron50 percent interest in, and is the operator. In 1993, Chevron farmed-outoperator of, a
portion390 square mile concession off the coast of its interestZaire. Exploration activity in
1994 resulted in an oil discovery in the concession, reducing its share from 60 percent to 40
percent.
- 7 -
Tshiala East exploration well. An
existing production well was also deepened in 1994 and a new reservoir
underlying Mibale Field was discovered. An exploration well in the Mibale
Field and the Tshiala West #1 well commenced in December 1994.
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Exploration expenditures,
excluding unproved property acquisitions, were $246$236 million in 1993,1994, a
decrease of $4$10 million from the 19921993 amount of $250$246 million. In addition,
unproved properties of $430$21 million primarily related to the
company's investment in Tengizchevroil (TCO), were acquired in 1993.1994.
In the North Sea, Chevron participated in four wildcat wellsEurope, Chevron's exploration efforts were concentrated in the U.K. sector
in 1993. A discovery was made inof the Paleocene Parliament prospect,
toNorth Sea and off the northeastcoast of Alba and Britannia, thereby establishing area
potential. During the U.K.'s 14th licensing round,Wales where the company was awarded
operatorshiphas conducted
research and a joint environmental appraisal of fourthe coast in order to allay
local concern about the environmental impacts of exploration off the
Pembrokeshire coast.
- 9 -
In Ireland, the company converted three blocks in the coastal watersCeltic Sea from seismic
options to full exploration licenses in February 1995. In addition, the
company filed an application for blocks in the deep water area west of Britain.Ireland
during the Porcupine Basin Licensing Round.
In Canada, exploration efforts in 19931994 continued to be concentrated in the
western part of the country.country near existing infrastructures that would allow any
reserves to be brought on production quickly. A total of 23 wildcat26 exploratory wells
were drilled in 1993 which reflected an increase1994, resulting in drilling activity as a share of total
exploratory expenditures.
In Indonesia, Chevron2 oil and its partners drilled nine exploratory wells in
1993, three of which resulted in oil6 gas discoveries.
In Australia, Chevron and its partners in West Australia Petroleum Pty., Ltd.
(WAPET) participated in two successful exploration wells resulting in an oil
discovery in the drillingCrest 1 well and a gas discovery in the Chrysaor 1 well. Both
discoveries are located off the western coast of Australia. The company
completed its 3D seismic surveys over the northern part of the North West Shelf
exploration well West Dixon-1, which proved unsuccessful. A preliminary
interpretation ofBarrow Island
oil field and over the Gorgon 3-D seismic survey was completed in 1993 and
WAPET has approved the exploratory drilling for gas of North Gorgon-2onshore Dongara gas/oil field in 1994. WAPET also acquiredPermit WA-253-P,
covering a 519,000 acre block north of Gorgon, in 1993. The
new permit, WA-253-P, will bewas issued to WAPET on behalf
of Chevron (50 percent) and a partner during 1994. In December 1994, Chevron
signed an agreement to farm-in to WA-215-P in earlythe area between Barrow and
Thevenard Island. A farm-in well will be drilled late in the first half of
1995. In addition, the company and its partners in the North West Shelf
Project continued their interpretative work on the East Dampier 3D seismic
survey. As a result of this work, two exploration wells will be drilled in
1995. In March 1995, the company announced that one of these wells, Perseus-1,
had discovered a natural gas and condensate deposit in the waters off
northwest Australia, between the North Rankin and Goodwyn fields. The company
withdrew from a permit it held with Shell in the Timor Sea in 1994.
In Papua New Guinea, the government has agreed to grant Chevron and its partners an extension of its exploratory license. The extension
significantly extendspartners' 1994 efforts were focused on
the time remaining for exploration of a large areadelineation of the Papuan FoldGobe Main oil field. In addition, two new exploratory
wells commenced in 1994: the SE Mananda 2X well extended a previous oil
discovery that may eventually be tied in with the Kutubu field's production
and Thrust Belt. Explorationthe TA-1X well was drilling at year-end on another prospect between the
Gobe and Kutubu fields. In 1995, the company and its partners anticipate an
active exploration program to follow up the prospect development work that was
carried out in 1994. Exploratory efforts continuein 1995 are expected to focus on
untested trends in the PPL-161 and PDL-2 licenses, where prospects with
Kutubu-sized potential still remained to be tested. In the past, exploration
efforts have largely concentrated nearon a single trend which included the Kutubu
project facilitiesfields, the Gobe fields, and export system. The Gobe
4X well was drilled before year-end at a location approximately 15
kilometers northwest of the SE Gobe field, resulting in an additional oil
and gas discovery on this 40 kilometer-long anticline.Mananda discovery.
In China, Chevron was awarded sole interest incompleted seismic studies on Block 33/08 in the East China
Sea in December. Seismic studies1994. The company was awarded sole interest in this block in late 1993.
Two exploratory wells are planned for 1995, the first of which commenced in
February. This wildcat well, designated Wenzhou 15-1-1, reached its targeted
depth and was plugged and abandoned. The second quarter
1994well is scheduled to determine the optimum location for exploratory drilling. All
exploration and drilling activities will be coordinated from Chevron's
newly-opened Shanghai office. The HZ/32-4-1 exploratory wellcommence
in the Pearl
River Mouth Basin oflate March 1995. A production sharing agreement, granting sole interest in
Block 62/23 in the South China Sea, was abandoned as a dry holesigned by the company and the Chinese
National Offshore Oil Company in 1993.
Other areas where exploration activities occurred in 1993 include Bolivia
where the firstlate February 1995. A natural gas exploratory
well (Cuevo West)is planned for this block in 1996. Exploration obligations for the
current phase of Contract area 16/08 were fulfilled in 1994. Studies are
planned in 1995 to determine the optimum program for the three marginal
discoveries in this Contract area.
In Bolivia, Chevron at year-end was completednegotiating the final terms of a farm out
of the Caipipendi Exploration Block which, if successful, will lead to a
partner funded seismic program over prospects in March 1994
as a dry hole,the southern half of the
block.
In Trinidad and Tobago, where the first of four exploratory wells, (RockyRocky Palace #1)#1,
was spuddeddrilled and tested in late 1993,1994. Iguana River #1, the second exploratory well,
was drilled in 1994 but encountered mechanical problems and was unable to
reach the reservoir objectives. Ste. Croix #1, the third well in the program,
has been approved for drilling in mid-1995.
In Colombia, where evaluation
oftwo prospects were identified in the Rio Blanco Block using
seismic data acquired in the Llanos foothills continued in 1993 with the
acquisition of a seismic program, Yemen where the1994. The company plans to drill an exploratory well
Al Harsh
#1 was unsuccessful,on one of these prospects in mid-1995. Drill site permitting and Azerbaijan where Chevron and the State Oil Company
of the Azerbaijan Republic (SOCAR) signed an agreement to jointly study oil
and gas reserve potential in the southern third of the Caspian Sea.road
construction is currently underway.
- 810 -
PETROLEUM - OIL AND NATURAL GAS PRODUCTION
The following table summarizes the company's and its affiliate's 1993affiliates' 1994 net
production of crude oil, natural gas liquids and natural gas.
- -----------------------------------------------------------------------------
19931994 NET PRODUCTION* OF CRUDE OIL AND NATURAL GAS LIQUIDS AND NATURAL GAS
CRUDE OIL & NATURAL GAS
NATURAL GAS LIQUIDS (THOUSANDS OF
(BARRELS PER DAY) CUBIC FEET PER DAY)
----------------- -------------------
United States
-California 130,330 139,110127,770 137,110
-Gulf of Mexico 127,500 1,134,910118,370 1,109,390
-Texas 73,420 403,62069,270 431,530
-Louisiana 5,790 30,0604,470 38,010
-Wyoming 10,610 155,1209,690 151,480
-Colorado 16,56014,290 -
-New Mexico 8,630 94,7208,560 104,540
-Other States 21,380 98,46016,220 112,610
------- ---------
Total United States 394,220 2,056,000368,640 2,084,670
------- ---------
Africa 217,600237,600 -
Canada 49,510 217,65051,510 246,820
United Kingdom (North Sea) 49,430 27,67070,720 30,400
Indonesia 31,730 1,05020,310 560
Australia 17,780 163,58020,570 199,140
Papua New Guinea 31,04029,770 -
China 8,2008,250 -
Other International 7,750 6,1109,570 4,840
------- ---------
Total International 413,040 416,060448,300 481,760
------- ---------
Total Consolidated
Companies 807,260 2,472,060816,940 2,566,430
------- ---------
Equity in Affiliates 142,890 53,370175,570 64,140
------- ---------
Total Including
Affiliates 950,150 2,525,430992,510 2,630,570
======= =========
* Net production excludes royalties owned by others.
- -----------------------------------------------------------------------------
PRODUCTION LEVELS:
In 1993,1994, net crude oil and natural gas liquids production, including
affiliates, increased by about onefor the second year in a row, rising four percent to
992,510 barrels per day from 950,150 barrels per day from
943,940 barrels per day in 1992.1993. Production
increases were noted in Papua
New Guineaa number of countries. In the U.K., production from
Alba Field, which went on stream in January 1994, and additional production
from Ninian Field, as a result of the company's acquisition of an additional 6
percent equity interest in December 1993, caused U.K. production to increase
43 percent to 70,720 barrels of oil per day. Oil production in Africa
increased 9 percent to 237,600 barrels per day primarily due to increased
Nigerian production as a result of full year production and additional wells being broughtfrom three fields
placed on stream in late 1993, from the Kutubu project,four new fields placed on stream in Kazakhstan1994 and
higher production quotas in 1994, and Angolan production, which increased in
1994 due to new wells in the startupTakula, Numbi and N'Sano fields. Indonesian
production, including the company's share of a new joint venture partnershipits affiliate's production, rose
6 percent to
- 11 -
173,250 barrels per day in April 1993, and in Indonesia due to
production increases1994 as thea result of the application of enhanced
recovery methods in certain fields. In Kazakhstan, Chevron's net oil
production doubled to 22,630 barrels per day in 1994 due to full year
production and increased export quotas in the latter half of the year. These
production increases were partially offset by production declines in the
United States due to divestments of producing properties in 1992late 1993,
primarily Milne Point, and normal field declines.
Net production of natural gas, including affiliates, declined 250,920increased 4 percent to
2,630,570 thousand cubic feet per day, or 9 percent,day. Increases were noted in 1993 from 1992. The decrease
was primarilyAustralia due
to normal field declines and 1992 divestitures of
producing properties in the United States and the Netherlands. The decline
was partially offset byinitial production from the startupRoller, Skate and Crest fields, in Canada as a
result of reduced re-injection requirements and the company'sshallow gas program, which
is designed to rapidly develop and produce gas from low-depth reserves, in the
U.S. due primarily to new joint venturewells in Kazakhstan.the Laredo area of Texas and one month's
production from the Pakenham, Inc. acquisition, and in Kazakhstan due to full
year production.
The natural gas industry is undergoing rapid and significant changes that have
squeezed margins and caused markets to become more competitive. In the United
States, natural gas producers have traditionally sold their production to
pipeline companies, who in turn distribute the product to their customers. As
a result of FERC Order 636, producers now can sell directly to customers and
provide many of the services previously provided by the pipeline companies.
Chevron has concentrated its natural gas marketing efforts on the longer term
contract market. These customers, which include local distribution companies
and industrials, require premium bearing services and marketing arrangements
that Chevron can fulfill. The company's sales to these customers have risen
significantly, while sales to pipeline companies have correspondingly
declined. - 9 -
Chevron has recently completed a detailed evaluation of its existing
natural gas marketing efforts and, as a result, will be dedicating additional
resources to the effort of marketing gas to targeted end-users. The company
has developed and implemented a process that it believes will significantly
reduce the cycle time associated with identifying, piloting, and capitalizing
on new natural gas marketing opportunities. This new process should allow the
company to more readily move natural gas out of mature, lower margin markets
into emerging, high-growth premium markets.
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 1994, 1993, 1992
and 19911992 are
reported in Table III on pages FS-32 toand FS-33 of this Annual Report on Form
10-K. The following table summarizes the company's and its affiliates' gross
and net productive wells at year-end 1993.
-1994.
-----------------------------------------------------------------------------
PRODUCTIVE OIL AND GAS WELLS AT DECEMBER 31, 19931994
PRODUCTIVE (1) PRODUCTIVE (1)
OIL WELLS GAS WELLS
------------------ -------------------
GROSS (2) NET(2) GROSS (2) NET (2)
--------- ------ --------- -------
United States 27,155 12,460 3,164 1,56927,898 14,180 3,992 1,715
--------- ------ --------- -------
Canada 2,042 1,017 330 1461,818 963 301 168
Africa 830 320 4861 335 5 2
United Kingdom (North Sea) 180 24207 35 - -
Other International 968 350 54937 349 37 15
--------- ------ --------- -------
Total International 4,020 1,711 388 1633,823 1,682 343 185
--------- ------ --------- -------
Total Consolidated Companies 31,175 14,171 3,552 1,73231,721 15,862 4,335 1,900
Equity in Affiliates 4,311 2,156 28 144,524 2,262 33 16
--------- ------ --------- -------
Total Including Affiliates 35,486 16,327 3,580 1,74636,245 18,124 4,368 1,916
========= ====== ========= =======
Multiple completion wells
included above: 388 183 20 14432 218 21 11
(1) Includes wells producing or capable of producing.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.
-----------------------------------------------------------------------------
- -----------------------------------------------------------------------------12 -
DEVELOPMENT ACTIVITIES:
The company's development expenditures, including affiliated companies but
excluding proved property acquisitions, were $1,508 million in 1994 and $1,451
million in 1993 and
$1,525 million in 1992.1993.
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 developmentaldevelopment wells drilling at December 31, 1993.1994. (A "development
well" is a well drilled within the proved area of an oil or gas reservoir to
the depth of a stratigraphic horizon known to be productive. "Wells drilling"
include wells temporarily suspended.)
- -----------------------------------------------------------------------------
DEVELOPMENT WELL ACTIVITY
NET WELLS COMPLETED (1)
WELLS DRILLING --------------------------------------
AT 12/31/9394 1994 1993 1992 1991
------------------- ----------- ---------- -----------
GROSS (2) NET (2) PROD. DRY PROD. DRY PROD. DRY
--------- ------- ---- ---- ---- ---- ---- ----
United States 97 8062 59 194 5 293 11 217 5 445 6
--------- ------- ---- ---- ---- ---- ---- ----
Canada 14Africa 12 41 12 45 4 66 5
Africa 6 29 - 10 - 10 1
13 1
Other
International 51 16 16 - 10 - 17 132 9 48 4 57 12 55 4
--------- ------- ---- ---- ---- ---- ---- ----
Total
International 71 3044 13 57 4 67 12 65 5 96 7
--------- ------- ---- ---- ---- ---- ---- ----
Total
Consolidated
Companies 168 110106 72 251 9 360 23 282 10
541 13
Equity in
Affiliates 45 2241 20 98 - 93 - 159 5 171 10
--------- ------- ---- ---- ---- ---- ---- ----
Total Including
Affiliates 213 132147 92 349 9 453 23 441 15 712 23
========= ======= ==== ==== ==== ==== ==== ====
(1) Indicates the number of wells completed during the year regardless of
when drilling was initiated. Completion refers to the installation of
permanent equipment for the production of oil or gas or, in the case of
a dry well, the reporting of abandonment to the appropriate agency.
(2) Gross wells include the total number of wells in which the company has
an interest. Net wells are the sum of the company's fractional interests
in gross wells.
- -----------------------------------------------------------------------------
- 10 -
Significant 19931994 development activities include the following:
UNITED STATES: Chevron's U.S. development expenditures were $475$416 million in
1993,1994, a decrease of $8$59 million from the 19921993 figure of $483$475 million.
Expenditures for proved reserve acquisitions amounted to $95 million in 1994,
primarily due to the company's acquisition of certain gas properties in West
Texas from Wes-Tex Drilling Company, compared to $12 million in 1993.
Additions to proved reserves during 19931994 from extensions, discoveries and
improved recovery, before revisions, were 9857 million barrels of crude oil and
natural gas liquids and 356538 billion cubic feet of natural gas. TheAdditions to
proved reserves from acquisitions were approximately 1 million barrels of
crude oil and natural gas liquids and 55 billion cubic feet of natural gas.
Chevron's development of theits wholly owned San Joaquin Valley diatomite
reserves in the Lost Hills Field in California continued in 1993. Forty onewith the drilling and
completion of 37 new wells were drilled and 45the reworking of 42 older wells were
reworked using reservoir
fracturing techniques. A four year water injection project, initiated in 1992,
to sustain reservoir pressure and further boost production continued into its
secondthird year with the drilling of 4239 injection wells and the conversion of 187
producing wells to injection. When completed, the 520-acre project will have
over 200 injectors with a total injection rate of 40,000 barrels of water per
day. The combination of reservoir fracturing and water injection is expected
to significantly increase both the production rate and the amount of oil
ultimately recoverable from this resource.
Production in the Point Arguello project, offshore California, averaged
74,000 barrels of oil per day in 1993. Chevron owns approximately 25 percent of the Point Arguello project, offshore
California, and operates two offshore platforms (Hermosa and Hidalgo), the
onshore Gaviota oil and gas plant and the interconnecting pipelines. Chevron
and its partners ceased double-hull tankering of oil from the project to the
Los Angeles area on February 1, 1994 in compliance with the terms of the
tankering permit granted by the California Coastal Commission. These terms
required suspension of tankering if Chevron and its partners were unable to
sign, by February 1, an agreement with a pipeline developer, who possessed the
necessary discretionary permits needed for a new pipeline, that the developer
could use for pipeline financing.
- 13 -
Production from the project averaged 78,000 barrels of oil per day in 1994,
somewhat below its full production capacity but at about the same level as
under tankering. About a third of current production is delivered via pipeline
to Los Angeles area refineries. However, due to a shortage of adequate
transportation facilities to Los Angeles, the balance of production is shipped
via pipeline to markets in the Midwest, resulting in increased transportation
costs. In March 1994, the company announced that an agreement had been reached
with a pipeline developer to build a 130-mile pipeline in Southern California
that would carry Point Arguello oil production to Los Angeles. Chevron and
certain other project partners will have a minority interest in the pipeline.
The pipeline project is currently in the environmental review stage and is
scheduled to be certified in October 1995. However, a property owner in the
pipeline right of way is pushing for an alternate route, which may cause
further delays. If the environmental review is certified in October 1995, the
issuance of permits and the start of construction are expected in the first
quarter of 1996. A workover and drilling program, designed to add proved
reserves and abate the decline in production rate commencedcontinued in August 1993 on1994 with the
two offshore platforms. Five workoversdrilling and completion of two new wells improving
Chevron's leaseand one redrill during the year.
In 1994, Chevron completed an economic evaluation of the viability of
developing the Green Canyon 205 Field located 2,600 feet below the ocean's
surface in the Gulf of Mexico. Preliminary field development plans have been
finalized; however, alternative development concepts will be considered
through the first half of 1995, at which time a final selection will be made.
Preliminary engineering work is expected to begin in early 1995. Initial
production by 4,300 barrels of oil per day, were completed
in 1993. Three additional wells areis planned for 1999 and is expected to be drilled in 1994. Chevron
and its partners began double-hulled tankering to Los Angeles of some
250,000 barrels of oil three to four times per month from the field's
processing plant at Gaviota in August 1993 under an agreement with the
California Coastal Commission. Previously, production was limited to
approximately 60,000 barrels per day or 70 percent of full capacity of
85,000 barrels per day due to limited onshore pipeline capacity. Fourth
quarter production averaged 80,700exceed 50,000 barrels per
day. Chevron has a 67 percent interest in this field.
The terms ofdrilling phase at the permit
granted by the California Coastal Commission allowed tankering to continue
until January 1, 1996 but required suspension of tankering from February 1,
1994 until such time that Chevron and its partners sign an agreement with a
pipeline developer that the developer could use to finance construction of
a new line. In late January 1994, Chevron approached the California Coastal
Commission to permit short-term tankering beyond February 1 due to damage
to a key crude oil pipeline system to Los Angeles caused by the Northridge
earthquake. The request was not acted upon by January 31 and short-term
tankering was subsequently suspended on February 1. Although production was
initially maintained by routing to alternate markets, the shortage of
adequate transportation facilities has subsequently resulted in reduced
production. In March 1994, the company announced that an agreement had been
reached on building a new 130 mile pipeline in Southern California that
would carry Point Arguello oil production to Los Angeles. The company
anticipates construction on the Pacific Pipeline will commence in early 1995
and be operational in early 1996. Pending the construction of this new
pipeline, the company is seeking to resume limited tanker shipments through
1995.
Natural gas production fromcompany's Garden Banks Block 191 "A" platform in the Gulf
of Mexico was completed in late 1994. Natural gas production from this block
started in late 1993. Daily1993 and is currently producing at a daily rate of 200 million
cubic feet of gas, exceeding original production should reachestimates of 150 million
cubic feet per day during the first quarter of 1994. During 1994, six additional wells
will be drilled under simultaneous drilling and production operations.day. Chevron is the operator and holds a 50 percent interest in
this block.
In the Gulf of Mexico's Norphlet Trend,gas trend, which stretches some 80 miles from
the Destin Dome area (offshore Florida) to the Mobile Block 861 area (offshore
Mississippi), two wells,production from the Mobile Block 861 #8 (Chevron 50 percent
interest) andwell commenced in
February 1994. Production from three additional wells drilled in 1994 is
expected to start in 1996 with the completion of a processing facility
currently being fabricated for the Mobile 861 Area. Production from three
wells in the Mobile Block 917 #2 (Chevron 91.3 percent interest), were
completed and tested916 Area offshore Alabama is expected to come on
stream in 1993. Production from 861 #8, which tested at 57April 1995 with a combined daily net rate of 50 million cubic feet
of gas. Chevron's interest in various blocks in the Norphlet gas trend vary
from 33 percent to 100 percent.
Nine of thirty-six prospects identified using the 3-D seismic survey of the
Eugene Island 238 Field in the Gulf of Mexico have been drilled by the end of
1994. Seven wells were successful, resulting in four gas and three oil
discoveries. A new production platform, added in 1994 to accommodate the oil
discoveries, will increase production by 9,000 barrels per day (total), commencedday. Three
additional wells will be drilled and an additional satellite platform will be
installed in February 1994 while1995. By the end of 1995, daily total production from 917 #2, which tested at 46for the field is
forecasted to exceed 200 million cubic feet per day
(total), will commenceof gas and 15,000 barrels of oil.
Chevron has a 100 percent interest in 1995. The company and its partners are currently
drilling or planning to drill additional exploratory wells in Mobile Blocks
863, 864, and 916 and Destin Dome 97 in 1994.
A new platform was installed inthis field except for Block 229, where
Chevron's wholly owned Main Pass 299 Field
in July 1993. Ten development wells are planned with three wells having
been completed and placed in production in December 1993. Productioninterest is expected to peak at 3,000 barrels per day late in 1994.
- 11 -
70 percent.
Chevron continued to aggressively develop "tight gas" (gas which is produced
from a tight, low-permeability formation) in the Laredo, Texas area. In 1993,1994,
twenty-five wells were drilled, with twenty-three successes,
adding net proved reserves of 70176 billion cubic
feet of gas. ProductionCurrent net production averaged 135 million cubic feet of gas per day in 1993. The S. Uribe No. 11
well was completed in 1993 with a sustained flow rate of 23165 million cubic feet of gas per
day. The company acquired more than 12,000 new acres in 1994 for future
development. Chevron's interest in the leases is 100 percent except for one
lease in which the company's interest is 59 percent.
In 1994, the company purchased the stock of Pakenham, Inc., a subsidiary of
Wes-Tex Drilling Company. Assets acquired in the purchase included 47 natural
gas producing wells in West Texas, 52 billion cubic feet of net proved natural
gas reserves and a gathering system that is currently used to transport
natural gas to a pipeline owned by Valero Transmission Company. Warren
Petroleum Company, Chevron's gas processing unit, is expanding its operations
to include the Pakenham gas gathering and processing business. The company
believes the field holds the potential to further increase the company's gas
reserves and expects to add wells that will more than triple the current
production of 25 million cubic feet per day to 90 million cubic feet per day
by 1999.
- 14 -
AFRICA: Developmental expenditures in Africa were $276 million in 1994,
compared to $239 million in 1993,
compared1993. Expenditures for proved reserve acquisitions
amounted to $189$145 million in 1992.1994. Additions to proved reserves from
extensions, discoveries and improved recovery, before revisions, were 105103
million barrels of crude oil and natural gas liquids. Additions to proved
reserves from acquisitions were approximately 76 million barrels of crude oil
and natural gas liquids. Acquisition expenditures and proved reserves from
acquisitions in 1994 were both primarily related to the company's activities
in the Congo.
In Angola, where Chevron's equity interest is 39 percent, ten15 development wells
were added in Area A fields in 1993. In order1994. Production from the greater Takula Area
fields increased in 1994 due to sustainongoing development of the N'Sano and Numbi
Southeast fields and from infill programs in existing reservoirs. A new
production six existing
wellsplatform and associated pipelines were installed in N'Sano Field
during 1994 and development drilling commenced at mid-year. A decline in
production from the greater Malongo Area A were reworkedfields was reversed in 1994 through a
combination of production from new exploration discoveries and threecontinued
infill activity. One offshore processing platformsplatform in the Malongo and Takula Fields wereSouth Field
was revamped and modernized in 1993.
Production1994. The company expects to maintain
production from Area A in future years through the N'Sano Field, discovered in 1992, was tied back to
existing Takula facilities. A new production platform to fully develop
N'Sano reserves is under construction for installation later this year.combination of infill
drilling, workovers, facility modernization, waterflood and gas injection.
Areas B and C continued to be the major focus of 1994 development programs in
1993. The first phase of development in these areas involvesAngola with the installation of two integrated drilling and production
platforms in the Kokongo Field.Field in Area B. The East Kokongo platform will also beis
designed as the hub for future phases of development for Areas B and C. AC and
includes a thirty-eight mile pipeline linking the platforms to onshore
terminal facilities was completedin Malongo. Drilling rigs were installed in the fourth
quarter of 1993. Platform1994 which resulted in initial production being established in late
November. By year-end, two wells had been completed and additional drilling is
expected to continue into 1996. The Nemba Field in Area B is expected to
operate as a satellite of East Kokongo. Contracts were awarded in 1994 for an
early production system consisting of three subsea wells, a tanker for
floating production service and related flowlines and pipelines. Production
start-up is scheduled for the second half of 1995. Tenders were issued in 1994
for the construction of additional Area B facilities, consisting of two
integrated platforms and associated pipelines, related to the development of
Lomba Field and the southern portion of Nemba Field. Start-up is forecasted
for 1997 at which time the early production system at Nemba will be completed in Brazilde-
commissioned and deliveredthe three subsea wells tied-back to Angola with oil production scheduled to begin in late
1994.Nemba South for continued
production. The second phaseLomba installation will operate as a satellite of Nemba South.
Contracts for the development is scheduled forof the Sanha and N'Dola fields andin Area C were
released in the fourth quarter of 1994 following resolution of partner
financing issues. The development will consist of two productionintegrated platforms and
related pipelines and facilities which are currently being fabricated in South
Africa. These fields will act as satellites of East Kokongo with start-up
forecasted for which contracts were awarded in 1993. Commencement of
work has been delayed by partner financing issues. Preliminary development
plans for the third phase involving development of the Nemba and Lomba
fields have been submitted for governmental approval.early 1997.
In Nigeria, Chevron is operator and has a 40 percent interest in
concessions totalling 2.3 million acres in onshore and offshore regions in
the Niger Delta. Producing facilities for three new fields, Opuekeba, Idama
and Inda, were completed and the fields came on stream during the second
half of 1993. Combined production from these new fields, along withtotal production from the Belma and Belma North unitized26 CNL-operated fields averaged 369,200
barrels of oil per day, an increase of over 41,000 barrels of oil per day from
1993. This increase was the result of new field development which
beganprograms,
development drilling in October 1993, is expected to add 60,000 barrels per day to the
totalexisting fields, workover programs and increased
commercial allowables. Four new fields, Abigborodo, Jokka, Kito and Benin
River, were placed on production capacity in 1994. Upgrade construction work on twoBenin River production platforms, Tapa and Delta South, were completedcommenced in
1993.December 1994 from one well. Detailed engineering for the full development of
Benin River will continue in 1995 with full production start-up planned for
1996. The platform upgrade program marked its second year in 1994. This
is
the beginning of a multi-year program, which will includeintended to upgrade all existing platforms in order to extend the
useful life and enhance the safety and environmental performance of these
facilities, continued at Delta, Meren 1 and also
enhance safetyOkan fields. Engineering was
completed for Utonana and environmental performance.is underway for Abiteye, Makaraba, Isan/West Isan,
Malu and two satellite platforms at Okan. Work on the Escravos Gas Project,
Phase I, continued in 1993.1994 with the completion of sand-filling at the onshore
site for the Liquefied Petroleum Gas (LPG) extraction/fractionation plant. In
addition, 93 percent of the detailed design engineering work for Phase I of
the project was completed in 1994. This first phase will utilize gas that is
currently being flared in the Okan and Mefa fields. The project will include
offshore gas compression facilities, an onshore Liquified Petroleum
Gas (LPG)LPG extraction plant, and a
floating LPG storage unit anchored offshore. The project will sell gas under a
long term contract to the Nigerian Gas Company in addition to producing
approximately fifteen
thousand15,000 barrels per day of hydrocarbon liquids for export. TheStart-
up of the project is scheduled for start-upnow expected in 1997. At year-end, discussions were underway onmid-1997.
- 15 -
In the assignment ofCongo, Chevron asand its partners have begun developing the developerKitina Field.
Development consists of a West African Gas Pipeline
which would deliver gasdrilling jacket with some topside facilities, tied
via a pipeline to Ghana via Beninother onshore processing and Togo.export facilities at Djeno
Terminal. Production is forecasted to begin in mid-1997 with peak production
of 50,000 barrels per day by 1999. In late 1994 the company and its partners
successfully drilled an appraisal well in the 1992 Kitina South discovery. The
company has an
additional subsidiarydevelopment of the N'Kossa Field started in Nigeria that holds1993. Two producing platforms
connected to a 20 percent interestfloating barge containing processing facilities will allow
crude oil and LPG to be loaded onto tankers for direct export. Production is
forecasted to commence in five
offshore oil fields operated by another partner.mid-1996 at a rate of 80,000 barrels per day,
reaching peak production of about 120,000 barrels per day in 1998.
In Zaire, where the company has a 50 percent interest in a 390 square mile
concession off the coast,one development well, one re-drill, and exploration activities resumed in
1993 as political unrest subsided. Two developmental wells and four wellfive workovers in the Mibale, Motoba and Libwa fields were
completed in 1993.
In1994. Early production from the Congo, where Chevron hasTshiala East exploration
discovery was developed by installation of a 29.3 percent interest, the 1991 Kitina
discovery in the offshore Marine VII Block was successfully delineated with
a second appraisal well. Engineeringsatellite production platform and
tie-back to existing processing facilities. Additional development planning
studies are currently underway to determine the optimalevaluate further development and reservoir management plan forof this field.
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Development expenditures
in 19931994 were $737$816 million compared to $853$737 million in 1992.1993. Additions to
proved reserves from extensions, discoveries and improved - 12 -
recoveries were 6691
million barrels of crude oil and natural gas liquids and 46708 billion cubic feet of natural gas. Additions to proved reserves from
acquisitions were approximately 1.1 billion barrels of crude oil and
natural gas liquids and 1.5 trillion cubic
feet of natural gas.
In the United Kingdom the company has interests in over 50 blocks on the U.K.
Continental Shelf which totalstotal approximately 1.7 million gross acres.
Chevron held interests, varying from 4.9 to 33.3 percent, in fiveacres, including
six producing fields in the North Sea during 1993. A sixth field, Alba, started
production in January 1994.where interests vary from 4.9 to 33.3
percent. At the Ninian Field in the U.K. North Sea, Chevron increased its interest by 6.5(24 percent to 23.6 percent in December
1993. Chevroninterest)
and its partners beganare paid a tariff for processing third partythird-party oil and gas
in
1992production using available processing capacity at the Ninian facilities. TheIn
1994 third-party oil flowing through the Ninian partners receive tariffs for processing and exporting theField's facilities increased
with production from three subsea produced satellite fields -Columba and Dunbar Fields coming on stream. This follows
production from Staffa Lyell and Strathspey.
Staffa productionField which was brought on stream in 1992, followed by production
from Lyell Field
(Chevron owns a 33.3 percent interest) in Marchearly 1993 and Strathspey in DecemberField at
year-end 1993. Lyell production peaked at 31,000 barrels per
day and has stabilized at a daily average of 19,000 barrels per day.
Strathspey production is currently averaging 17,000 barrels per day, with
an expected peak of 41,000 barrels per day. In 1993, Chevron and its
partners announced a commercial framework for bringing on future satellite
fields through Ninian. Direct drillingProduction from Ninian Northern platform into
the first of four potential satellite prospects began in December. At the
Alba Field in the North Sea, development of the first phase of that project
was successfully completed witha two-phase development plan
for the installation and hook-up of theNorth Sea's Alba Northern platform and the Alba floating storage unit (FSU)Field, in November.
Initial production, expected to peak at 70,000 barrels per day later this
year, beganwhich Chevron has a 33 percent interest,
commenced in January 1994 after the FSU1994. Average daily gross oil production was fully commissioned. Work also
began in 1993 on plans42,400
barrels, with a fourth quarter average of 62,900 barrels of oil per day. Plans
for the second phase of Alba, which will develop the southern area of the
reservoir.reservoir, continued in 1994 with conceptual engineering studies to select a
preferred development option. A decision is expected by late 1995 which should
result in first production from the southern part of the field in 1996. The
Alba Field, in which Chevron has a 33
percent interest, is estimated to contain up to 400 million barrels of
recoverable reserves. At the Britannia Fieldgas field development in the North Sea was approved by the United
Kingdom Department of Trade and Industry at the end of 1994. Development will
initially consist of a 3-D
seismic survey was completedsteel drilling, production and accommodation platform
and a subsea well center, along with a gas offtake pipeline and onshore gas
processing facilities. Condensate from the field will be transported ashore
via the Forties pipeline system. Gas and gas liquids will be transported to
and processed at the St. Fergus terminal in 1992 and analyzed in 1993 as a guide for
field mapping and development drilling. Delineation drilling results and
technical studies indicate thatnortheast Scotland. Peak
production is expected to be approximately two and one-half trillion740 million cubic feet of gas 175 millionand
70,000 barrels of condensate and upper day. Initial production is expected to
30 million
barrels of crude oil will be recoverable, withcommence in late 1998. Agreements have been reached to sell gas to four
purchasers. Chevron's share equating to
approximatelyof production is just over 30 percent. Preliminary facility engineering studies are
nearing completion and a firm decision on development options and
commercial arrangements is expected in 1994.
In Canada, the company continues to concentrate its development efforts in six
core producing areas in Alberta and one in Manitoba where operating
efficiencies and lower operating costs can be realized using existing
infrastructure. In 1994, the company drilled 49 wells that were targeted at
new reserves around existing fields along with 58 development wells. The
company also continued its development of the late-1993 Simonette oil
discovery with further delineation drilling and site construction activities
in 1994.
Chevron increased its ownershiphas a 27 percent interest in the Hibernia Field, located approximately
200 miles offshore Newfoundland, by 5 percentNewfoundland. In 1994, the Gravity Based Structure (GBS)
was floated to about 27
percent in January 1993 after onea deep water construction site where final construction,
including installation of the four original projecttopside structures will be completed before mid-
1997, the date for its scheduled towing to the drilling site. Engineering cost
and construction delays caused by the
- 16 -
complexity of the GBS have resulted in higher than projected pre-production
costs for the project. The company is working very closely with the Hibernia
Management Development Company and with partners withdrew. In 1993, construction onto keep the project continued with the awarding
of the supermodule fabrication contracts, the pouring of the base slabon
schedule and to control construction costs. Initial production has been
delayed and is now forecasted for the Gravity Base Structure, and the completion of supermodule and hook-up
engineering.1998. Hibernia investment is projected to be
about $200slightly over $210 million in 1994,1995, an increase of $54$17 million over 19931994
levels. Initial production is
scheduled for 1997. The company's capitalized investment in this project was $375$570 million
at year-end 1993.1994.
In Indonesia, Chevron's interests in 1413 contract areas are managed by its 50
percent owned P.T. Caltex Pacific Indonesia and Amoseas Indonesia affiliates.
The Duri Steamflood project,Project, begun in 1985 to assist the difficult production
process for the relatively heavy, waxy Duri crude, is being completed in 12
stages (Areas 1-12). Development of Area 7 is currently underway.underway and steaming
began early in 1995. Area 8 is due to be on stream early in 1997. More than
three billion additional barrels of oil are expected to be recovered from the
Duri Field as a result of steamflooding. Total production at Duri averaged
247,000300,000 barrels per day in 1993 and is
expected to peak at just over 300,000 barrels per day by the late 1990s.1994. A waterflood project involving 21 fields in
Central Sumatra, including the Minas field, continued in 1993. Water injection1994. Over the next
20 years, waterflood operations will be introduced or expanded at Minasthese
fields.
First steam from the Darajat geothermal field, located 115 miles southeast of
Jakarta, was initiateddelivered to Prusahaan Listrik Negara (PLN), Indonesia's state
electricity agency, in December 1993 as part oflate 1994. The Darajat I plant was commissioned in late
1994 with initial production targeted for PLN's nearby 55-megawatt power
plant. Negotiations with the conversion of the peripheral waterfloodIndonesian government on developing Darajat II is
expected to a
pattern waterflood which is designedcommence in 1995. This future expansion will allow production to
improve oil recovery. Chevron sold
its 17.5 percent share in the South Natuna Sea Block B effective January 1,
1994. Chevron's net share of production from this block averaged
approximately 11,300 barrels of oil and natural gas liquids per day in
1993.
- 13 -
increase to 130 megawatts by 1999.
In Kazakhstan, the company formed a 50/50 joint venture with Tengizmunaigaz, a
subsidiary of Kazakhstanmunaigaz - the national oil company of the Republic of
Kazakhstan - to develop the Tengiz and Korolev oil fields on the northeast
coast of the Caspian Sea. This joint venture affiliate, Tengizchevroil (TCO),
began operations in April 1993, adding net
proved reserves to Chevron of 1.1 billion barrels of crude oil and natural
gas liquids and 1.5 trillion cubic feet of natural gas. Current1993. TCO's total production has averaged about 30,000capacity was 65,000
barrels per day which is approximately 46
percentfor most of 1994. However, production in the rated crude oil production capacityearly part of
1994 was limited to 35,000 barrels per day due to the amount of mercaptans,
foul-smelling sulfur compounds, in the oil. The mercaptan problem was resolved
at mid-year through the use of chemical scavengers and exports reached 65,000
barrels per day.day in the fourth quarter. Production capacity was increased to
95,000 barrels per day at year-end with the completion of a second processing
plant. By the end of 1995, production capacity is scheduled to increase to
130,000 barrels per day and could reach 260,000 barrels per day by the late
1990's. However, the pace of further development beyond the 130,000 barrels
per day is dependent on the availability of additional export capacity.
Current production is restricted by the limited treatment and transportation facilities currently
available to TCO to bring the oil to world markets. Tengiz crude oil
production is currently exchanged for Russian crude which is then exported
from Russia to world markets. Natural gas, natural gas
liquidsProduction levels have been and sulfur are being sold into local markets. Overcontinuing
to be restricted by the next three
to five years, plans call for TCO to spend about $1.5 billion on expanding
production capacity and infrastructure. Current capacity is expected to
double to 130,000monthly export quotas (currently 65,000 barrels per
dayday) set by 1995Russia under this agreement. The company has been in prolonged
negotiations with the Caspian Pipeline Consortium, composed of the Republics
of Russia and could reach 260,000 barrels
per day byKazakhstan and the late 1990s. The paceSultanate of field development from 130,000 to
260,000 barrels per day is predicated on the construction of an export
pipeline system capable of handling the full production from the fields.
NegotiationsOman, to agree on terms for aan
export pipeline system that would enable the project which would be
separate from the TCO joint venture's Tengiz development project, have
proved to be very difficult,increase its
production and itsell its output directly to world markets. It is currently
impossible to predict the eventual outcome of these negotiations or its impact
on the joint venture.
In Australia, drilling commenced in October 1994 in the Goodwyn Field which is
being developed as part of the North West Shelf Project in which Chevron holds
a one-sixth interest, is scheduledinterest. Production started in February 1995 with total initial
production expected at around 10,000 barrels of condensate per day, rising to
start80,000 barrels of condensate and 900 million cubic feet of natural gas per day
at its peak in 1996. First production in 1994. Completion of the offshore platform, originally
scheduled for 1993, was delayed due to repair work on the piles. Upon
completion of the repair work, in first quarter 1994, the topside modules
will be installed and commissioned. Production will flow by a 30 inch
diameter pipeline to the nearby North Rankin platform and then by trunkline
to shore. The participants in the North West Shelf Project approved, in
1993, the development offrom the Wanaea Field, theand Cossack Field, and an LPG
extraction and export project.oil field
development is expected late in 1995. Combined initialpeak production from the two
oilfields is forecastforecasted at 115,000 barrels of oil per day startingand should occur in
late 1995.mid-1996. The liquids-rich gas from Wanaea will be combined with gas from the
North Rankin and Goodwyn fields and processed at the onshore gas plant at
Karratha, which is being modified to allow the export sale of LPG. Two new
LPG storage tanksIn 1994,
Chevron and a second product loading jetty are currently under
constructionits partners in West Australian Petroleum Pty., Ltd. (WAPET)
continued to handleevaluate options for the extra production. Following start-up in early
1996, LPG exports are expected to average 25,000 barrelscommercialization of the Gorgon gas
field. The North Gorgon 2 appraisal well was
- 17 -
successful with combined tests from four sands of 175 million cubic feet of
gas per day. Drilling
and construction forInitial production from the Roller/Skate oilfield development
progressed
according to schedulecommenced in 1993. Production is scheduled to commence inMay 1994, at a peak rate of 32,000averaging 40,000 barrels per day. Associated gas from
the Roller/Skate and Saladin fields will beis being piped to shore and either sold in
the Perth market or stored in the Dongara field for future sales. The Roller/SkateCrest
discovery well was put on extended production tests in 1994 and was producing
over 6,000 barrels of oil per day in December. Full field development will
consist of drilling two more wells onshore Thevenard Island and tying them
into existing facilities in which Chevron holds about amid-1995. Chevron's interest in WAPET projects
varies from 26 percent
interest, is a project of the West Australian Petroleum Pty., Ltd.to 50 percent.
In Papua New Guinea, Chevron (19 percent interest) and its partners are
reviewingcurrently undertaking front-end engineering work on the feasibilityGobe fields in the
southeastern portion of developing the PPL-161 license. This work is expected to lead to
the submission of a Petroleum Development License application to the Papua New
Guinea government in 1995. The Gobe fields consist of SE Gobe Field with possible(discovered in
1991) and Gobe Main (discovered in 1993). A delineation program on Gobe Main
was conducted in 1994 that defined the scope of the oil discovery and allowed
planning for a joint development of the two fields to progress. If the
government approves the development application in early 1996, initial oil
production commencingfrom the Gobe fields will commence in 1994.1997. Chevron and its
partners, as well as other competitor groups, have made significant gas
discoveries in the Papuan Basin. 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 is
scheduled for the Kutubu fields in early 1995. This program, which will
contain both vertical and horizontal wells, is expected to allow production
from the Kutubu fields to remain at a rate in excess of 100,000 barrels of oil
per day throughout 1995.
In China, work continued in 1994 on projects to develop the HZ/32-2 and
HZ/32-3 Fieldsfields in the South China Sea were initiated in 1993 with the awarding of the major contract.Sea. The plan includes two platforms, 12
additional wells and a tie-in to the existing production facility at the
HZ/21-1 Field. Initial production, expected to peak at 45,000 barrels per day,
is scheduled for 1995.mid-1995. Chevron holds a 16 percent interest in the venture.
Other development projects includedIn Kuwait, the completion ofcompany signed a three-and-a-half year agreement with the
expanded
development ofKuwait Oil Company in August 1994 to provide technical services to help
develop the ChichimeneBurgan Field, in the Llanos Basin area of Colombia.
The project included development drilling, production facilities and a 35
kilometer pipeline. Expected peak production of 10,000 barrels ofworld's second largest oil per
day is expected in 1994. Chevron holds a 50 percent interest in the field.
- 14 -
PETROLEUM - NATURAL GAS LIQUIDS
Chevron's wholly owned Warren Petroleum Company is engaged in all phases of
the domestic natural gas liquids (NGL's) business and is the largest U.S.
wholesale marketer of natural gas liquids, selling to customers in 46 states.
Warren also conducts Chevron's international liquefied petroleum gas (LPG)
trading and sales activities. Sales in 19931994 totaled 287 thousand281,000 barrels per day
(includes sales of 79,00072,000 barrels per day to Chevron subsidiaries). Warren's
business encompasses:
EXTRACTION - Warren operates 18 gas processing plants in Oklahoma, Texas,
Louisiana and New Mexico with a total processing capacity of 3.5 billion
cubic feet of gas per day and holds equity interests in anotheran additional 25
plants. Natural gas from Chevron's and other producers' wells is piped to
these plants, where the various liquids are extracted. GasWarren's share of
gas liquids production from these plants was 64,00066,000 barrels per day in
1993.1994.
FRACTIONATION - Raw natural gas liquids are collected from Warren's
processing plants, third-party purchases and Warren's gas liquids import
facility on the Houston Ship Channel and transported via pipelines to
Warren's fractionation plant at Mont Belvieu, Texas. The 220,000 barrel
per day capacity facility fractionates raw NGL's into ethane, propane,
normal butane, iso-butane and natural gasoline products. The Mont Belvieu
complex includes a 45 million barrel capacity underground gas liquids
storage facility.
- 18 -
DISTRIBUTION - Gas liquids are distributed to refineries, chemical
producerspetrochemical
manufacturers and independent distributors via terminals supplied by
pipelines, barges, tank cars and trucks. NGL imports and exports are
handled at Warren's marine terminal, the Warrengas Terminal, located on
the Houston Ship Channel and linked to the Mont Belvieu complex by
dedicated pipelines. In 1993, Warren continued itsPetrochemical manufacturers are the main purchasers
of ethane while propane is sold to petrochemical manufacturers as well as
residential and commercial users. Refineries are the major customers for
the remaining types of NGL's.
Warren's activities in international LPG business development included
marketing LPG for other Chevron companies in Canada, West Africa, the U.K.,
and Australia. International sales more than doubled from
13,000 barrels per dayIn 1994, the company also lent support to a Caltex study of LPG
opportunities in 1992 to 28,000 barrels per day in 1993.China.
In 1994, Warren completed thebegan construction of an underground natural gas salt dome
storage facility at Hattiesburg, Mississippi, on behalf offield gathering and compression
facilities to support Chevron U.S.A. Production Company.Company's Pakenham Field
acquisition in West Texas. The five billion cubic feet storage terminal began
receiving gas deliveriescompany also converted an underutilized
ethylene pipeline owned by Chevron Chemical Company to an isobutane pipeline
in December 1993. A major expansion of1994, allowing Warren to utilize the Mont
Belvieu fractionator was also completed in 1993. A new butane hydrotreating
and isomerization unit was added, increasing itsexcess fractionation capacity by
20,000 barrels per day.it had
at its Mt. Belvieu, Texas plant to produce isobutane for transportation and
sale in the Texas City, Texas market.
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)
1994 1993 1992 1991
---- ---- ----
United States - Warren 209 208 191 172
United States - Other 36 3 3
---- ---- ----
Total United States 215 211 194
175
Canada 27 30 26 21
Other International 7 7 87
---- ---- ----
Total Consolidated Companies 249 248 227 204
==== ==== ====
---------------------------------------------------
- 15 -
PETROLEUM - RESERVES AND CONTRACT OBLIGATIONS
Table IV on pages FS-33 toand FS-34 of this Annual Report on Form 10-K sets
forth the company's net proved oil and gas reserves, by geographic area, as of
December 31, 1994, 1993, 1992, and 1991.1992. During 1993,1994, the company filed estimates of
oil and gas reserves with the Department of Energy, Energy Information Agency.
TheseThose estimates were consistent with the reserve data reported on page FS-34
of this Annual Report on Form 10-K.
The quantities of crude oil that the company is obligated to deliver in
the future under existing contracts in the United States and
internationally, which specify delivery of fixed and determinable
quantities, are not significant in relation to the quantities available
from production of the company's proved developed reserves in those areas.
The company sells gas from its producing operations under a variety of
contractual arrangements. Most contracts generally commit the company to sell
quantities based on production from specified properties but certain gas sales
contracts specify delivery of fixed and determinable quantities. In the United
States, the quantities of natural gas the company is obligated to deliver in
the future under existing contracts is not significant in relation to the
quantities available from the production of the company's proved developed
U.S. reserves in these areas. Outside the United States, the company has contracts, principallyreplaced
its single Western Australian domestic gas contract with six agreements,
involving sales to five direct-end users. Those agreements commit the State Energy
Commission of Western Australia, which have remaining obligationscompany
to deliver 269approximately 258 billion cubic feet of natural gas through 2005.
The company believes it can satisfy these contracts from quantities available
from production of the company's proved developed Australian natural gas
reserves.
- 19 -
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, 19931994
------------------ REFINERY INPUTS
OPERABLE --------------------
LOCATIONS NUMBER CAPACITY 1994 1993 1992 1991
-
---------------------------- ------ -------- ---- ---- ----
Pascagoula, Mississippi 1 295 324 283 294 306
Port Arthur, Texas (1) 1 185 158 177 189 195
Richmond, California 1 235230 220 228 228 221
El Segundo, California 1 226230 227 233 235
180
Philadelphia, Pennsylvania 1 172(1) - - 94 184 164
162
Other*Other (2) 6 282261 190 202 201 214
-- ----- ----- ----- -----
Total United States 11 1,39510 1,201 1,213 1,307 1,311 1,278
-- ----- ----- ----- -----
Burnaby, B.C., Canada 1 4550 47 43 41 41
Milford Haven,
Wales United Kingdom 1 115 116 120 103 107
-- ----- ----- ----- -----
Total International 2 160165 163 163 144 148
-- ----- ----- ----- -----
Total Consolidated Companies 13 1,55512 1,366 1,376 1,470 1,455 1,426
Equity in Various
Affiliate Locations 14 492 460 435 399 369
-- ----- ----- ----- -----
Total Including Affiliate 27 2,04726 1,858 1,836 1,905 1,854 1,795
== ===== ===== ===== =====
*(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; Barber's Point, Hawaii; Salt Lake City,
Utah; Perth Amboy, New Jersey; Willbridge, Oregon; and Richmond Beach,
Washington. InputsCapacity and input amounts for El Paso represent Chevron's
share.
-----------------------------------------------------------------------------
At the company's Nikiski, Alaska, refinery, closed in
1991, are included in the above data for 1991.
- -----------------------------------------------------------------------------
- 16 -
Based on refinery statistics published in the December 20, 1993 issueend of The Oil and Gas Journal,1994, Chevron had the largest U.S. refining capacity and hadranked
among the fifth largesttop ten in worldwide refining capacity including its share of
affiliate's refining capacity. The company wholly ownsowned and operates 11operated 10
refineries in the United States and one each in Canada and the United Kingdom.
The company's Caltex Petroleum Corporation affiliate owns or has interests in
14 operating refineries in Japan (4), Korea, the Philippines, Australia, New
Zealand, Bahrain, Singapore, Pakistan, Thailand, Kenya and South Africa.
The company also owns closed refineries in Nikiski, Alaska; Cincinnati,
Ohio; and Baltimore, Maryland. Excluded from the affiliate's refineries are
3 closed refineries in Japan.
Production records were set at all locations in 1993 as refineries focused
on maximizing unit utilization. In 1993, distillationDistillation operating capacity utilization in 1994 averaged 93 percent in the
United States and 94 percent worldwide (including affiliate), compared with 94
percent in the United States and 95 percent worldwide (including affiliate), compared with 90 percent in the United
States and 92 percent worldwide in 1992.1993. Chevron's
capacity utilization of its domestic cracking and coking facilities, which are
the primary facilities used to convert heavier products to gasoline and other
light products, averaged 8890 percent in 1993, unchanged1994, up 2 percent from 1992.
During 1993,1993.
In 1994, the company continued work on various expansion/upgrade projects,
which are expected to cost over $1 billion when completed, the first facility to use Chevron's
patented Aromax (R) technology at the Pascagoula, Mississippi refinery. This
process produces high value benzene from lower valued refining feed stockits Richmond and
will facilitate the company's ability to comply with the requirement to
reduce the benzene content inEl Segundo, California, refineries. These projects are aimed at meeting
regional clean air requirements and producing cleaner burning motor gasoline
mandatedand diesel fuel as required by the California Air Resources Board and the
Federal Clean Air Act Amendments of 1990. At the El Paso, Texas refinery, the company entered
into an operating agreement with a neighboring refinery which allowed
Chevron, as operator,Projects to combine the most efficient units from each
refinery in order to lower costs and increase yields. The company alsoproduce federal
reformulated gasoline were completed a $40 million facility at the Salt Lake City, Utah refinery which
will allow the company to economically manufacture ultra low sulfur diesel
fuel, one of the few such facilities in that area.
In August 1993, the company installed its proprietary Isodewaxing (R)
technology at the Richmond lube oil refining plant. This process, which
uses a new catalyst developed by the company, boosted lube oil production
by 1,500 barrels per day.
The U.S. downstream industry is going through massive recapitalization in
order to meet stringent new environmental regulations. This led to the 1993
announcement of a major restructuring of the company's downstream
operations. An integral part of this plan is to divestboth refineries in Philadelphia, Pennsylvania and Port Arthur, Texas since these refineries no
longer fit in Chevron's long term plans to have a more strategically
focused U.S. refining operation and will reduce the capital expenditures
that would have been required under the 1990 amendments to the Clean Air
Act. In 1993, the company established an $837 million pre-tax provision for
the divestment of these two refineries. This charge was composed primarily
of a write-down of the refineries' facilities and related inventories to
their estimated realizable values. Also included in the charges were
provisions for environmental site assessments and employee severance. The
company has taken into account probable environmental cleanup obligations
in estimating the realizable value of the refineries. Responsibility for
these obligations will be negotiated with potential buyers. While
negotiations for the refinery sales are ongoing, it is expected that the
reserve will be sufficient to complete the restructuring. In late February
1994, the company signed a letter of intent with Sun Company, Inc. for the
sale of the Philadelphia refinery. In late March 1994, the company
announced it has entered into exclusive negotiations with Clark Refining &
Marketing, Inc. regarding the sale of its Port Arthur, Texas, refinery.
The company will invest nearly $1 billion in its Richmond and El Segundo,
California refineries over the next three years to produce reformulated
gasoline.1994. In addition,
a $300 million investment to upgrade key processing units to improve yields of
high value light products is underwaycontinuing at the Richmond refinery.
At the company's Milford Haven, Wales refinery, a new isomerization unit
was brought on stream in 1993. This $54 million unit will enable the
refinery to produce a higher octane blend stock in response to increased
demand for lead-free gasoline and anticipated benzene reduction in European
gasoline.
- 1720 -
In March 1994,For the last few years, the U.S. downstream industry has been going through
massive recapitalization in order to meet the stringent new environmental
requirements under the 1990 amendments to the Clean Air Act. As a result, in
1993, the company announced that it will license technology and
provide engineering design for a major upgraderestructuring of the company's downstream
operations which included the divestment of refineries in Philadelphia,
Pennsylvania and Port Arthur, Texas. These refineries no longer fit in
Chevron's long term plans to have a more strategically focused U.S. refining
operation and the Kirishi Refinery,
operated by Kirishinefteexport, in Russia. The key refining process unit
covered bydivestitures would reduce the agreement is a new hydrocracker, scheduled for startup in
mid-1999, which will use Chevron's Isocracking technologycapital expenditures that
would have been required to maximize
production of middistillates such as diesel fuel and jet fuel.meet the Clean Air Act amendments. The company
will also provide technologysold its Philadelphia, Pennsylvania, refinery to remove ammoniaSun Company, Inc. in August
1994 and hydrogen sulfide from
water usedits Port Arthur, Texas, refinery to Clark Refining and Marketing,
Inc. in February 1995.
Federal regulations required that reformulated gasoline (RFG) be sold in nine
mandated areas in the refining process, yielding clean waterUnited States beginning January 1, 1995. In addition,
certain states and other areas voluntarily opted for reuse.the RFG requirement. Some
of these areas have subsequently withdrawn, or are considering withdrawing,
from the voluntary requirement. Also, in some areas complaints have surfaced
that an RFG ingredient, MTBE, is causing illness among users. The company is
unable to predict the outcome of these developments on its operations and the
industry. Chevron is selling RFG in a total of nine mandated and voluntary
areas.
In 1994, Caltex and its partners completed front-end engineering designcontinued construction of a grassroots,
130,000 barrels per day refinery in Thailand. Mechanical completion of the
refinery is expected by the first quarter of 1996, with full production
commencing by mid-1996. The engineering,
procurement and construction contract was awarded in October andanticipated fall 1995 completion of the project is on target for completion in 1996. Work continued on the
expansion/upgrade projectResiduum
Fluid Catalytic Cracking (RFCC) unit at the Singapore export refinery. Completionrefinery will
mark the completion of the project, scheduled for mid-1995,that refinery's expansion/upgrade project. The upgrade
will increase refining capacity by 60,000 barrels per day, increase yield of
light products by 33,000 barrels per day, and enable the refinery to produce
oxygenated unleaded gasoline and low sulfur diesel fuel. A JapaneseAt the Yocheon
refinery in South Korea, construction of an RFCC unit is currently underway to
position Caltex's Honam affiliate of Caltex placedfor Korea's shift to a new
residuum desulfurizer into service at the Negishi, Japan refinery. This
unit, along with the cracker unit installed last year, will allow the
refinery to increase yields of higher-value products and reduce dependence
on low sulfur crudes.higher-margin,
lighter product mix.
PETROLEUM - REFINED PRODUCTS MARKETING
PRODUCT SALES: The company and its affiliates, primarily Caltex Petroleum Corporation sellaffiliate
markets petroleum products throughout much of the world. The principal
trademarks for identifying these products are "Chevron","Chevron," "Gulf" (principally
in the United Kingdom) and "Caltex". Domestic"Caltex." U.S. sales volumes of refined products
by the company during 19931994 amounted to 1,4231,314 thousand barrels per day,
equivalent to approximately nineeight percent of total U.S. consumption. Worldwide
sales volumes, including the company's share of affiliates'affiliate's sales, averaged
2,3462,248 thousand barrels per day in 1993, an
increase1994, a decrease of about onefour percent over
1992.1993. This decrease was largely due to the sale of the company's Philadelphia,
Pennsylvania, refinery in August 1994, and refinery downtime in the first half
of 1994.
- 21 -
The following table shows the company's and its affiliates'affiliate's refined product
sales volumes, excluding intercompany sales, over the past three years.
--------------------------------------------------------
REFINED PRODUCTS SALES VOLUMES
(Thousands of Barrels Per Day)
1994 1993 1992 1991
----- ----- -----
UNITED STATES
Gasolines 615 652 646 632
Gas Oils and Kerosene 277 325 347
312
Jet Fuel 260 247 252 249
Residual Fuel Oil 65 94 110 145
Other Petroleum Products* 97 105 115 106
----- ----- -----
Total United States 1,314 1,423 1,470 1,444
----- ----- -----
INTERNATIONAL
United Kingdom 118 111 108
110
Canada 56 50 39
38
Other International 140 168 147 142
----- ----- -----
Total International 314 329 294 290
----- ----- -----
Total Consolidated
Companies 1,628 1,752 1,764 1,734
Equity in Affiliate 620 594 565 533
----- ----- -----
Total Including
Affiliate 2,248 2,346 2,329 2,267
===== ===== =====
* Principally naphtha, lubes, asphalt and coke.
--------------------------------------------------------
- 18 -
The company's Canadian sales volumes consist of refined product sales in
British Columbia and Alberta by the company's Chevron Canada Ltd. subsidiary.
In the United Kingdom, the sales volumes reported comprise a full range of
product sales by the company's Gulf Oil (Great Britain) Ltd. subsidiary. The
19931994 volumes reported for "Other International" relate primarily to
international sales of aviation, marine fuels, and refined products in Latin
America, the Far East and elsewhere. The equity in affiliates'affiliate's sales in 1993 consist primarily1994
consists of the company's interest in Caltex Petroleum Corporation, which
operates in 6361 countries including Australia, the Philippines, New Zealand,
South Africa and, through Caltex affiliates, in Japan and Korea.
The company introduced several new products in 1993. In September, the
company began delivering JP-8, a kerosene-based jet fuel, to the U.S.
military. Over the next two years, JP-8, a safer and more versatile fuel,
capable of powering tanks, trucks and other military vehicles, will phase
out naphtha-based JP-4. In October, low aromatics diesel fuel in California
and ultra low sulfur diesel fuel in the rest of the country were introduced
to comply with various federal and state air quality regulations.
Reformulated heavy duty motor oils that meet the needs of low sulfur diesel
fuel users were also introduced nationwide in October.
RETAIL OUTLETS: In the United States, the company supplies, directly or
through jobbers, over 9,000approximately 8,600 motor vehicle, aircraft and marine retail
outlets, including more than 2,4002,000 company-owned or -leased motor vehicle
service stations. The company's gasoline market area is concentrated in the
Southeastern, South CentralSouthern, Southwestern and Western states. Chevron estimates it is the fourth
largest seller of gasoline in the United States and is among the top three
marketers in 1615 states.
During 1993,Chevron is continuing its efforts to increase non-fuel related revenues
through its existing customer and asset base. In 1994, the company completedrevised its
credit terms for Chevron credit card holders and introduced a "Gold" tier to
its Travel Club. The company is also gauging consumer interest in having
McDonald's restaurants on the acquisition and brand conversionpremises of 55company-owned service stations, with
a number of test sites in south Florida
that were acquiredTexas and Louisiana now in operation. Revenues from
ExxonDirect Mail Marketing, introduced in exchange for comparable properties1993, continued to grow in the
Baltimore-Washington D.C.-Eastern Virginia areas. Chevron branded retail
fuel sales in Arkansas, Western Kentucky and Western Tennessee were
discontinued in 1993.
In 1993, Chevron introduced a "Direct Mail Marketing" and a "Premium Card"
program to credit card customers.1994.
The company also expandedcontinued to expand its "Fast Pay""FastPay" system by approximately 400700
stations in 1993,1994, increasing the total service stations with the system to
a total of over 1,300
stations2,000 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.
During 1993, the company outsourced
purchasing, warehousing and distribution responsibilities for its Tire,
Batteries and Accessories business (TBA).- 22 -
Internationally, the company's branded products are sold in 214200 owned or
leased stations in British Columbia, Canada and in 467 (230498 (233 owned or leased)
stations in the United Kingdom. In 1993, the company completed the
sale of its retail marketing operations in Guatemala, El Salvador and
Nicaragua.
PETROLEUM - TRANSPORTATION
TANKERS: Chevron's controlled seagoing fleet at December 31, 19931994 is
summarized in the following table. All controlled tankers were utilized in
1993.
-1994.
-----------------------------------------------------------------------------
CONTROLLED TANKERS AT DECEMBER 31, 19931994
U.S. FLAG FOREIGN FLAG
----------------------------- ------------------------------
CARGO CAPACITY CARGO CAPACITY
NUMBER (millions of barrels) NUMBER (millions of barrels)
------ --------------------- ------ ---------------------
Owned 1 - 23 22
Bareboat
Charter 6 2 7 12
Time-Charter - - 26 27
Bareboat
Charter 7 2 6 11
Time Charter - - 9 58 4
---- ---- ---- ----
Total 7 2 41 4338 38
==== ==== ==== ====
- -----------------------------------------------------------------------------
- 19 -
Federal law requires that cargo transported between domestic ports be carried
in ships built and registered in the United States, owned and operated by U.S.
entities and manned by U.S. crews. At year-end 1993,1994, the company's U.S. flag
fleet was engaged primarily in transporting crude oil from Alaska and
California terminals to refineries on the West Coast and Hawaii, refined
products between the Gulf Coast and East Coast, and refined products from
California refineries to terminals on the West Coast, Alaska and Hawaii.
At year-end 1993,1994, two of the company's controlled international flag vessels
were being used for floating storage. The remaining international flag vessels
were engaged primarily in transporting crude oil from the Middle East,
Indonesia, Mexico, West Africa and the North Sea to ports in the United
States, Europe, the United Kingdom, and Asia. Refined products also were
transported worldwide.
In addition to the tanker fleet summarized in the table on page 19,above, the company
owns a one-sixth undivided interest in each of fivesix liquefied natural gas (LNG)
ships that are bareboat chartered to the Australian North West Shelf Project.
One of the ships, the Northwest Stormpetrel, was delivered in late December
1994. These ships, along with two time charteredtime-chartered LNG vessels, transport LNG
from Australia primarily to eightvarious Japanese gas and electric utilities.
One additional LNG ship has been ordered with delivery expectedChevron continued to upgrade and "right-size" its fleet of vessels in late 1994.
In 1993, the company took1994 by
taking delivery of onetwo 1.1 million and two 1.0 million barrel capacity, double hull tankers and
soldselling two 2.0 million, one 1.2 million and two 3.2one .9 million barrel capacity
tankers. The company also took delivery of a 1.0
million barrel capacity tanker, the Chevron Employee Pride, in February
1994 and expects to take delivery of an additional 1.0 million barrel
capacity tanker in October 1994. During 1993, the company reduced its time
charteredtime-chartered fleet by a net one tanker
and 1.0 million barrels of capacity.capacity during 1994.
Page 2428 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.
- 23 -
PIPELINES: Chevron owns and operates an extensive system of domestic crude
oil, refined products and natural gas pipelines. The company also has direct
or indirect interests in other domestic and international pipelines. The
company's ownership interests in pipelines are summarized in the following
table:
-----------------------------------------------------------
PIPELINE MILEAGE AT DECEMBER 31, 19931994
WHOLLY PARTIALLY
OWNED OWNED (1) TOTAL
----- ----- ------
UNITED STATES:
Crude oil (2) 5,696 624 6,3205,150 620 5,770
Natural gas 569 44 613413 32 445
Petroleum products 3,709 1,610 5,3194,041 1,472 5,513
----- ----- ------
Total United States 9,974 2,278 12,2529,604 2,124 11,728
----- ----- ------
INTERNATIONAL:
Crude oil (2) - 747 747785 785
Natural gas - 197 197205 205
Petroleum products 12 130 142109 121
----- ----- ------
Total International 12 1,074 1,0861,099 1,111
----- ----- ------
Worldwide 9,986 3,352 13,3389,616 3,223 12,839
===== ===== ======
(1) Reflects equity interest in lines.
(2) Includes gathering lines related to the transportation
function. Excludes gathering lines related to the
domestic production function.
-----------------------------------------------------------
- 20 -
The company has signed an agreement with Pemex, the national oil company of
Mexico, to build a $8.5 million, 19-mile pipeline from Chevron's El Paso,
Texas, refinery to a Pemex storage terminal just south of Ciudad Juarez,
Mexico. The pipeline will transport gasoline, diesel, and possibly kerosene
and is expected to be in service in 1996, pending approval by various
regulatory agencies.
CHEMICALS
The company's Chevron Chemical Company subsidiarychemical operation manufactures and markets commodity chemical
products for industrial use. Theuse and chemical industry, historically,
has been cyclicaladditives for fuels and is highly competitive. Since its last peak in the
late 1980s, industry conditions have deteriorated aslubricants.
After a period of ample supplies caused by industry production overcapacity,
have exerted downward pressure on prices. In
the pastpetrochemical industry rebounded dramatically in 1994. The excess industry
capacity of the last four years weakwas rapidly eliminated as improved
industrialized economies, particularly in the United States, raised demand duefor
consumer goods, many of which are made from or packaged with plastics derived
from commodity chemicals marketed by the company. The elimination of the
industry's excess capacity tightened supplies, which led to U.S.higher margins for
the company's products. The profitability of chemical operations in 1994 was
further enhanced by the restructuring and worldwide recessions has
further weakened prices.cost reduction programs the company
had undertaken in recent years which positioned the company to benefit from
improved industry conditions.
At year-end 1993,1994, Chevron Chemical Company owned and operated 2420 U.S.
manufacturing facilities in 1210 states, owned manufacturing facilities in
Brazil and France, and owned a majority interest in a manufacturing facility
in Japan. The principal domestic plants are located at Cedar Bayou, Orange and
Port Arthur, Texas; St. James and Belle Chasse, Louisiana; Philadelphia, Pennsylvania; Marietta, Ohio;
Pascagoula, Mississippi; St. Helens, Oregon; and Richmond, California. The
company's three major operating divisions are "Aromatics and Derivatives,"
which are marketed in 32 countries, "Olefins and Derivatives," which are
marketed in 45 countries and "Oronite Additives," which are marketed in over
80 countries. The following table shows, by chemical division, 19931994 revenues
and the number of owned or majority owned chemical manufacturing facilities
and combined operating capacities as of December 31, 1993.1994.
- 24 -
-----------------------------------------------------------------------------
CHEMICAL OPERATIONS
MANUFACTURING
FACILITIES 19931994
------------------- ANNUAL REVENUE (1)
DIVISION U.S. INTERNATIONAL CAPACITY ($ MILLIONS)
-Millions)
--------------------- ---- ------------- ------------------- ------------
Olefins and
Derivatives 1211 - 6,9907,050 million lbs. $1,003$1,186
Aromatics and
Derivatives 75 - 6,5705,210 million lbs. 718944
Oronite Additives 2 3 160 million gal. 746
Fertilizers832
Other (including
excise tax) 2 - (2) 86
Consumer Products 1 - (2) 133
Other
(including excise
taxes) - - (2) 37119
-- - ------
Totals 2420 3 $2,723$3,081
== = ======
(1) Excludes intercompany sales.
(2) No meaningful common measurement.
- -----------------------------------------------------------------------------
The company divestedplans to expand its last major assetlinear low density polyethylene (LLDPE)
manufacturing facility at Cedar Bayou, Texas in 1995 with project completion
expected in the agricultural-related
chemical business withfirst quarter of 1996. The expansion will increase the sale of its ORTHO consumer products division, a
leading supplier of lawn and garden products in the United States, to
Monsanto Company in 1993. The sale was the result of studies that concluded
that the company's agricultural-related businesses were non-competitive or
were non-core. The company decided to divest those businesses and focus its
attention on areas of strength - petrochemicals, plastics and additives.
Construction was completed during 1993 on the first U.S. benzene
manufacturing plant using the company's proprietary Aromax (R) technology at
the Pascagoula, Mississippi refinery. This technology will enable Chevron
to produce high-value benzene from certain low-value by-products of the oil
refining process. Benzene is a prime building block for a wide range of
consumer products such as sporting goods, nylon, laundry detergent,
children's toys and automobile tires.
In March 1993, the company announced that a letter of intent had been
signed with the Saudi Venture Capital Group, a consortium of Saudi Arabian
business leaders, to develop an aromatics facility in Jubail, Saudi Arabia,
if necessary Saudi government approval can be obtained. The planned
facility would be owned and operated by a newly formed joint venture
company. This joint company, owned on an equal basis by Chevron and the
Saudi group, would market within Saudi Arabia, while Chevron would market
all products outside Saudi Arabia. The facility will utilize Chevron's
patented Aromax (R) reforming technology and have aplant's
production capacity of 420,000 tons
of benzene per year and 270,000 tons of cyclohexanesLLDPE by 340 million pounds per year. The projectplant is currently delayed whilealso
capable of manufacturing high density polyethylene. These materials are used
to produce a variety of products for the Saudi government revises its petrochemical
investment policy.packaging industry.
The company is alsocontinuing with its previously announced plans to withdraw from
its agricultural and consumer product businesses. Plans to shut down the
company's nitric acid and fertilizer plants in Richmond, California by the early stagesend
of examining
opportunities to employ the Aromax (R) technology in Asia, where chemical
demand is growing rapidly.
- 21 -
In January 1994,July 1995 were announced by the company announced a cost-reduction plan intendedin late January 1995. Chevron sold
the majority of its nitrogen fertilizer business to reduce annual operating expense by approximately $100 million by 1996.
Major elements ofUnocal in 1991 and has
operated the plan include completing the divestiture of thefacilities since that time under contract with Unocal. The
company's agricultural businesses, including the closing of the consumer
products plant in Maryland Heights, Missouri and the sale of theremaining fertilizer plant in St. Helens, Oregon; the sale of Chevron's asphalt business in
Brazil; closing of the company's oil-field chemical business; reorganizing
the Oronite Additives Division into global regions; and streamlining and
reducing costs at the company's three largest plants in Cedar Bayou and
Orange, Texas, and Belle Chasse, Louisiana.
An agreement was reached in March 1994 with Institut Francais du
Petrole to jointly develop a new high-purity paraxylene technology called
Eluxyl. If the demonstration unit using this new technology, to be
constructed and operated at Chevron's Pascagoula, Mississippi, refinery,
proves successful, the company plans to integrate the technology at
Pascagoula and expand its paraxylene activities worldwide.Oregon is currently for
sale.
COAL AND OTHER MINERALS
COAL: The company's wholly-owned coal mining and marketing subsidiary, The
Pittsburg and Midway Coal Mining Co. (P&M), owned and operated four surface
and three underground mines at year-end 1993.1994. Three of the mines are located
in New Mexico and one each in Alabama, Wyoming, Kentucky and Colorado. All of
the mines produce steam coal used primarily for electric power generation.
P&M's strategy is to focus on regional markets in the United States,
capitalizing on major utility growth markets in the Westsouthwest and Southeast. Approximately 88southeast.
In 1994, the company restructured its interest in the Black Beauty Coal
Company by adding a new partner who contributed both cash and additional coal
properties to the partnership. This restructuring reduced the company's
interest in the partnership from 50 percent of P&M'sto 33 percent. The Black Beauty
Coal Company's principal operations are in the Indiana/Illinois coal sales are made to
electric utilities.market.
Sales of coal from P&M's wholly-owned mines and from its 50 percent interest in the Black
Beauty Coal Company were 20.820.4 million tons in 1994, a decrease of
approximately 2 percent from 1993 an increasesales of 26 percent over 1992. About 5720.8 million tons. However, 1994
production was at 94 percent of theseestimated capacity, a 2 percent increase over
1993. About 59 percent of 1994 sales came from two mines, the McKinley Mine in
New Mexico and the Kemmerer Mine in Wyoming. The average selling price for
coal from mines owned and operated by P&M was $24.39 per ton in 1994 compared
to $24.62 per ton in 1993, contributing $414 million and $426 million to
Chevron's consolidated sales and other operating revenues.revenues in 1994 and 1993,
respectively. At year-end 1993,1994, P&M controlled approximately 560538 million tons
of developed and undeveloped coal reserves.
Demand growth for coal in the U.S.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. Although coal-fired
generationIn 1994, the
electric utility industry consumed over 80 percent of electricity grew during 1993, competition amongall coal producers kept downward pressure on regional coal prices during much of the
year. However,produced in the
East, a prolonged strike by United Mine Workers of
America restricted coal production, tightening coal supplies and driving up
spot market prices in the latter half of the year. P&M sells about 88States.
- 25 -
Approximately 87 percent of itsP&M's coal productionsales are made to electric utilities.
Of those sales, about 50 percent are under multi-year supply agreements, so itcontracts longer than 10 years and
20 percent are under three to ten year contracts. As a result, P&M is not
particularly exposed to short-term fluctuations in market prices. Generally,
these contracts contain negotiated cost pass through and inflation adjustment
provisions.
P&M controls a significant inventory of low-sulfur coal reserves, and the
company expects demand for this type of coal to grow as utilities start to
implement
programstheir strategies to comply with the air quality emission standards of Phase I
of the Clean Air Act Amendments of 1990.1990, which began on January 1, 1995. In
addition, P&M anticipates that the Energy Policy Act of 1992 will increase
competition in the electric power market and will provide new market
opportunities for low-cost coal producers.
OTHER MINERALS: P&M managesIn 1994, the company's investments in non-coal minerals.
The company expressedcompleted its long-term intentionpreviously announced plan
to exit the non-coal minerals business and most such assets have been sold in recent years. The principal
assetsby selling its two remaining are anon-coal
assets: the company's 50 percent interest in the Stillwater Mining Company, a
Montana platinum-palladium mining operation, and athe company's 52.5 percent
interestholding in some zinc-lead prospects in Ireland. The company's share of sales and other
revenues from non-coal operations was approximately $21 million in 1993. The
sale of the company's 52.5 percent holding in the Irish zinc-lead prospects
has been delayed due to legal challenges. The company expects these challenges
to be resolved and the sale completed during 1994.
REAL ESTATE
The company's real estate activities are carried out primarily through its
wholly owned subsidiaries, Chevron Land and Development Company and Huntington
Beach Company (collectively, Chevron Land). - 22 -
TheirChevron Land's activities are
predominantly handled by the company's offices in Newport Beach and San
Francisco, California.
Real estate operations have concentrated on converting Chevron's surplus fee
production properties in California into residential and commercial real
estate. After making major infrastructure improvements, the properties are
sold to third parties or jointly developed. At the end of 1993,1994, Chevron Land
managed over 26,000approximately 35,000 acres of real estate in California.
Chevron Land participates in residential developments through partnerships
with home builders. During 1993, the company sold approximately 160 homes
in California. Although this represents a 78 percent increase from the 90
homes sold in 1992, the California housing market continues to be weak as
California lags the rest of the nation in realizing significant renewed
economic growth. The company anticipates that the California real estate
market will not begin to recover until late 1994 at the earliest and is
currently positioning itself to take advantage of the recovery when it
occurs by developing properties at a pace that meets market demand while
preserving current real estate development entitlements. Ten residential
housing projects were actively being developed at year-end, eight through
joint venture partnerships.
Although Chevron's current development emphasis is on the residential
sector, the Company also participates in commercial real estate investment
and development activities. The Montebello Town Square in Southern
California, a 250,000 square foot community shopping center situated on 20
acres of a former oil field, was sold by the company in 1993. The company
also leases approximately 70,000 acres of irrigated farmland and 160,000 acres
of rangeland to local growers and ranchers in California's San Joaquin Valley.
In 1993, Chevron Land restructuredparticipates in residential developments through partnerships
with home builders. During 1994, the company sold over 340 homes in
California, more than doubling the 160 homes sold in 1993. The California
economy is now beginning to show signs of renewed economic growth and the
company is positioning itself to take advantage of the recovery by developing
properties at a pace that meets market demand while preserving current real
estate development entitlements.
In addition to its organization by
reducing its workforce 20sales of residential real estate, the company also
generated over $140 million in revenues from about 25 sales involving
commercial, recreational or undeveloped real estate. The largest of these
sales involved the sale of two undeveloped properties to Kaufman and Broad and
the sale of two golf courses and related facilities to Club Corporation of
America. These sales were made through the company's 80 percent and closing or consolidating 5interest in
the Coto de Caza Partnership.
The company announced in March 1995 that it has established a marketing team
for the possible sale of its offices. Currently, Chevron Land's activities are predominately handled byreal estate development assets. If a satisfactory
price and other terms can be obtained, the company's officescompany hopes to conclude the sale
in Newport Beach and San Francisco, California.1995.
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 19931994 numbered approximately 2,400.
In January 1994, the company signed an agreement with China National
Petroleum Corporation to provide enhanced oil recovery technology for
testing in Daqing, China's largest oil field. The technology, called
"microbial profile modification," consists of pumping bacterial spores and
nutrients into a reservoir to plug off highly permeable zones in order to
improve the sweep efficiency of a waterflood. The agreement calls for 15
months of testing in Chevron Petroleum Technology Company's labs in La
Habra, California, followed by a two year pilot program in Daqing.2,000.
- 26 -
Chevron's research and development expenses were $179 million, $206 $229,million
and $250$229 million for the years 1994, 1993 and 1992, respectively.
In 1994, the company developed a synthetic-based drilling mud for offshore
use. Drilling mud is a liquid mixture that transports drill cuttings or small
rock fragments out of the well. Conventional oil-based muds produce toxic oil-
coated cuttings that are illegal to dispose of offshore. The new synthetic
drilling mud meets all environmental requirements for discharge directly into
the ocean, thereby eliminating the additional expense needed to transport and
1991, respectively.dispose of the cutting onshore.
The company owns, controls, orsigned an agreement in 1994 with Excel Paralubes, a joint venture
of Conoco Inc. and Pennzoil Products Co., which licensed the company's
Isodewaxing technology for a new lube oil manufacturing facility to be built
at Conoco's Lake Charles refinery in Westlake, Louisiana. The Isodewaxing
technology was also selected by Petro-Canada for a major expansion of their
lube oil facilities in Mississauga, Ontario. 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. The Petro-Canada
facility is expected to come on stream in the fourth quarter 1996, followed by
the Excel Paralube facility in 1997. The company also licensed, under numerous patents, butin 1994, its
business is not dependent upon patents.residuum desulfurization technology to Tohoku Oil Co. of Japan for its 100,000
barrel per day Sendai refinery and to Formosa Petrochemical Corporation for
its 450,000 barrel per day refinery in Taiwan.
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 ongoing corporate strategies is to give
high priority to environmental, public and governmental concerns. Chevron's
revised corporate policy on Health, Environment and Safety was approved by the
Stockholdersstockholders in 1991. In 1992, a comprehensive series of 101102 management
practices was approved by senior management to strengthen the implementation
of the policy. The program is called "Protecting People and the Environment"
and is modeled after the Chemical Manufacturers Associations' program called
"Responsible Care." It is also similar to the American Petroleum Institute's
program called "Strategies for Today's Environmental Partnership." The program also encompasses previousIn 1994,
the company programspublished 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 control pollution such as the SMART (Save Money and Reduce
Toxics) program which focuses on routine, process related, hazardous waste.
- 23 -
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, particularly Alaska, offshore Florida and offshore California.
Difficulties and delays in obtaining necessary permits, because of
environmental concerns, such as those
experienced by Chevron and its partners in the Point Arguello Field offshore
California, can delay or restrict oil and gas development projects. While
events such as these can impact current and future earnings, either directly
or through lost opportunities, the company does not believe they will have a
material effect on the company's consolidated financial position, its
liquidity, or its competitive position relative to other domestic or
international petroleum concerns. The situation has, however, been a factor,
among others, in the shift of the company's exploration efforts to areas
outside of the United States.
TheSince 1991, the company will spend an estimated $1.1has spent about $1.2 billion in capital expenditures
over the next 5 years 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. The Clean Air Act
Amendments of 1990 (CAAA) requires the production ofrequire that only reformulated gasoline (RFG).
Beginning in January 1995, only RFG may be sold
in the nine worst ozone areas in the United States. In addition,States beginning on January 1,
1995 while other areas may voluntarily opt into the RFG requirement. Chevron
began selling RFG in nine areas in 1995. The California Air Resources Board
(CARB)
requires a more stringent reformulated gasoline to be sold statewide beginning in
March 1996. CAAA required a significant decrease in1996 and work is continuing at the sulfur
content of diesel fuel sold in U.S. markets beginning October 1993. CARB,
in additioncompany's Richmond and El Segundo,
California, refineries to the federal requirements, also mandated a reduction in the
aromatics content of diesel fuel sold in California. Chevron introduced low
aromatics diesel fuel in California and ultra low sulfur diesel fuel in the
rest of the nation in October 1993.meet these requirements.
- 27 -
The Federal Oil Pollution Act of 1990 (OPA) expanded federal authority to
direct responses to oil spills to improve preparedness and response
capabilities and to impose penalties on spillers for restoration costs and
loss of use of the resources during restoration. Under OPA, the U.S. Coast
Guard imposed new regulations on owners of vessels operating in U.S. waters
after December 28, 1994 which required owners to meet strict guidelines for
financial responsibility in the case of an oil spill. The company complied
with the requirements by self-insurance and was issued a Certificate of
Financial Responsibility for each of its vessels operating in U.S. waters
prior to the December 28 deadline. OPA also requires the phase outscheduled phase-out
of single hull tankers and the phase in of double hull tankers for trading to U.S. ports.ports, which has resulted in the
utilization of more costly double hull tankers. Many of the coastal states
have enacted or are preparing legislation in these same areas. In 1990,1994, the
company began a
fleet modernization program, which included seventook delivery of two double hull tankers, for
delivery during the 1992-1994 period. Sixlast of these tankers have been
delivered through the first week of March 1994.seven such
vessels ordered in 1990. The company has been actively involved in the Marine
Preservation Association, a non-profit organization that funds the Marine
Spill RecoveryResponse Corporation (MSRC). MSRC owns the largest stockpile of oil
spill response equipment in the nation and operates five strategically located
U.S. coastal regional centers.
The company expects the enactment of additional federal and state regulations
addressing the issue of waste management and disposal and effluent emission
limitations for offshore oil and gas operations. While the costs of operating
in an environmentally responsible manner and complying with existing and
anticipated environmental legislation and regulations, including loss
contingencies for prior operations, are expected to be significant, the
company anticipates that these costs will not have a material impact on its
consolidated financial position, its liquidity, or its competitive position in
the industry.
During 1993,In 1994, the company's U.S. capitalized environmental expenditures were $620$645
million, representing approximately 3133 percent of the company's total
consolidated U.S. capital and exploratory expenditures. The company's U.S.
capitalized environmental expenditures were $620 million and $430 million in
1993 and $284 million in
1992, and 1991, respectively. These environmental expenditures include capital
outlays to retrofit existing facilities, as well as those associated with new
facilities. The expenditures are predominantly in the petroleum segment and
relate mostly to air and water quality projects and activities at the
company's refineries, oil and gas producing facilities and service stations.marketing
facilities. For 1994,1995, the company estimates that capital expenditures for
environmental control facilities will be approximately $637$558 million. The
actual expenditures for 19941995 will depend on various conditions affecting the
company's operations and may differ significantly from the company's forecast.
The company is committed to protecting the environment wherever it operates,
including strict compliance with all governmental regulations. The future
annual capital costs of fulfilling this commitment are uncertain, but for the
next several years are
expected to continue at current levels.
- 24 -
decrease after expenditures required to produce fuels that reduce
air pollution and air toxicity reached their peak in 1994.
Under provisions of the Superfund law, Chevron has been designated as a
potentially responsible party (PRP) for remediation of a portion of 223238
hazardous waste sites. Since remediation costs will vary from site to site as
well as the company's share of responsibility for each site, the number of
sites in which the company has been identified as a PRP should not be used as
a relevant measure of total liability. At year-end 1993,1994, the company's
environmental remediation reserve related to Superfund sites amounted to $56$61
million. TheForecasted expenditures for the largest of these sites, located in
California, accounts foramounts to approximately 20 percent of the reserve.
The company's 19931994 environmental expenditures, remediation provisions and
year-end environmental reserves are discussed on pages FS-3FS-2 through FS-4 of
this Annual Report on Form 10-K. These pages also contain additional
discussion of the company's liabilities and exposure under the Superfund law
and additional discussion of the effects of the Clean Air Act Amendments of
1990.
- 28 -
ITEM 2. PROPERTIES
The location and character of the company's oil and gas and minerals and real
estate properties and its refining, marketing, transportation and chemical
facilities are described above under Item 1. Business and Properties.
Information in response to the Securities Exchange Act Industry Guide No. 2
("Disclosure of Oil and Gas Operations") is also contained in Item 1 and in
Tables I through VI on pages FS-30 to FS-35 of this Annual Report on Form
10-K. Note 12, "Properties, Plant and Equipment"Equipment," to the company's financial
statements contained on page FS-24FS-25 of this Annual Report on Form 10-K presents
information on the company's gross and net properties, plant and equipment,
and related additions and depreciation expenses, by geographic area and
industry segment for 1994, 1993 1992 and 1991.1992.
ITEM 3. LEGAL PROCEEDINGS
A. Cities Service Tender Offer Cases.CITIES SERVICE TENDER OFFER CASES.
The complaint by Cities Service Co. ("Cities Services"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 now been resolved and will ultimately be
dismissed.
Plaintiff Cities Service has now made new claims by way of a motion to
amend the petition, which motion was submitted for rulingfiled its Second Amended Petition on February 28,April 25, 1994,
but has not yet been ruled on by the court. The amended pleading addsadding Oxy U.S.A. as the successor to plaintiff Cities Service, addsadding Chevron
U.S.A. Inc. (asas successor to Gulf Oil Corporation)Corporation and addsadding Chevron
Corporation as a new defendant. In addition to the existing claims for breach
of contract and fraud, the amendments addadded the following causes of action: for
willful and malicious breach of contract, negligent misrepresentation,
interference with prospective economic advantage in connection with the 1989
proposed Oxy-Cities DOEDepartment of Energy ("DOE") settlement, and adds the claimed
DOE liability as additional contract damages and as additional fraud damages.
The proposed amendment also addsadded a claim for punitive damages based upon the alleged
fraud, negligent misrepresentation, willful breach and interference claims. The new claim requestsclaims and
requested not less than $100 million on each of the several claims, together
with pre-judgment interest and punitive damages. It also requestsrequested $12 million
plus prejudgment interest for Cities' costs in defending against DOE
proceedings since 1989, and an order entitling Cities ServicesService 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.
Plaintiff's motion to bifurcate this case for two trials was granted by the
trial court on January 23, 1995. The first trial will concern plaintiff's
claims for alleged breach of contract, willful and malicious breach of
contract, and negligent misrepresentation. The second trial will cover
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.
Various discovery motions are pending. There is no discovery cut-off and no
trial date has yet been set.
- 2529 -
B. In re Gulf Pension Litigation.IN RE GULF PENSION LITIGATION.
In two lawsuits, which were commenced on December 2, 1986 and April 24, 1987
and consolidated on July 17, 1987 in the U.S. District Court for the Southern
District of Texas as In re Gulf Pension Litigation,IN RE GULF PENSION LITIGATION, former employees of Gulf
Oil Corporation who were participants in the Gulf Pension Plan contendcontended that
a partial termination of the Gulf Pension Plan hashad occurred and they arewere
entitled to immediate vesting and distribution of plan benefits and to
distribution of alleged excess plan assets, which it
is alleged haveallegedly had been
unlawfully seized by Gulf or Chevron. The action is
brought under the Employee Retirement Income Security ActAll aspects of 1974 and
common law, and is primarily an actionthis case have now been
resolved except for damages. Defendants have filed
an answer denying plaintiffs' allegations. On August 21, 1987, the Court
certified a class on these issues consisting of "all former members of the
Gulf Pension Plan and the spouses or the beneficiaries of such members." On
January 4, 1990, the Court certified a subclass of plaintiffs who also
contend that Chevron unlawfully denied them benefits due upon their alleged
involuntary termination. A partial settlement agreement was reached during
trial on November 19, 1990 and approved by the court at a January 25, 1991
hearing.
On April 10, 1991, the Court issued its opinion on the remaining issues in
the case. The Court ruled that partial terminations of the Gulf Pension
Plan occurred, and ordered all participants in the plan as of July 1, 1986claim to be vested in their benefits under the plan. The Court also ruled that
participants in the Gulf Contributory Retirement Plan ("CRP") and the
Supplemental Annuity Plan of Mene Grande Oil Company ("SAP") were entitledentitlement to the surplus assets of those plans. However, the Court ruled that
Chevron, otherwise, has the right to retain surplus funds remaining in the
Gulf Pension Plan after all obligations to the Plan Participants have been
satisfied. Accordingly, the Court found no impropriety in the merger of the
Gulf Pension Plan into the Chevron Retirement Plan or the use of plan
assets to fund a special early retirement program and pension supplement.
However, the Court did rule that Gulf and Chevron had incorrectly paid
certain investment management fees out of plan assets and had incorrectly
received a benefit from the use of pension plan assets in the negotiation
of a divestiture sale agreement.
On October 15, 1991, the court approved the terms of a second partial
settlement agreement. As a part of the second partial settlement, the
parties agreed not to appeal the partial termination issues except as
relevant to plaintiff's claim that they are entitled to surplus Gulf
Pension Plan assets that are not attributable to CRP/SAP. The second
partial settlement does not affect the court's ruling that the plaintiffs
are not entitled to approximately $620 million in
surplus funds in the Gulf Pension Plan. Plaintiffs have appealed this part ofThis issue was decided adversely to
plaintiffs by the case toDistrict Court on April 10, 1991.
On October 21, 1994, the Fifth Circuit Court of Appeals. Chevron has appealedAppeals affirmed the rulingDistrict
Court's determination that it
incorrectly paid management fees outthe plaintiffs were not entitled to surplus assets
of the plan's assetsGulf Pension Plan. On November 18, 1994, plaintiffs filed a petition
for rehearing and that it
received a benefit from the use of pension funds. On April 29, 1993 Chevron
reached a settlementsuggestion for rehearing en banc with the Internal Revenue Service regardingFifth Circuit.
Both of these issues, which includedwere denied on December 1, 1994.
On March 1, 1995, the plaintiffs filed a payment toPetition for a Writ of Certiorari
with the Chevron Retirement Plan and a
payment of excise taxes. Subsequently, Chevron's appeal was dismissed by
the court, although the underlying judgement was not vacated.United States Supreme Court.
C. Clean Water Act Violations.
On September 23, 1993, thePERTH AMBOY NEW SOURCE PERFORMANCE STANDARD PENALTY.
The United States Environmental Protection Agency (EPA) instituted an administrative proceeding seeking civil penalties in excess
of $100,000 from the company for its self-reported violationsclaims that Chevron's
Perth Amboy refinery violated various provisions of the Clean WaterAir Act since July 1986 at production facilities located onNew
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 Outer
Continental ShelfNSPS applied to the
refinery. This NSPS applicability determination has been appealed to the
United States Circuit Court of Appeals for the GulfThird Circuit. The EPA's
penalty demand is $15.2 million. Chevron has made a counteroffer of Mexico. The company has agreed with the
EPA to settle this matter for $121,000.$150,000.
D. Premanufacture Notifications for Detergent Additives.PREMANUFACTURE NOTIFICATION FOR DETERGENT ADDITIVES.
On September 30, 1993,30,1993, the EPA instituted an administrative proceeding,
seekingassessing civil penalties of about $17 million from the company for alleged violations of the
Toxic Substances Control Act (TSCA). The EPA contends that the company was
required to file Premanufacture Notifications (PMNs) with regard to six
chemical substances manufactured or imported since 1990. The company believes
that no PMNs were required because the chemicals were within the scope of
existing TSCA inventory listings. Nevertheless, the company reported the
situation to the EPA when it was advised by a third party that the EPA may,
without public notice, have revised its interpretation of TSCA regulations to
require PMNs to be filed in such circumstances. Thereafter, under protest, the
company suspended the production and importation of the - 26 -
chemicals and filed
PMNs for them, continuing the suspension for the 90-day period contemplated by
TSCA. The detergents in question are very similar to common detergents and
intermediates used in their production, and the EPA does not appear to claim
that failure to file a PMN resulted in any health or safety risk. The EPA
permitted the company to dispose of its current stocks of the chemicals during
the period that the company suspended their production and importation. The
company has challenged the penalty assessment through an administrative
appeal.
E. El Segundo Refinery Reformulated Gasoline Project.EL SEGUNDO REFINERY REFORMULATED GASOLINE PROJECT.
On September 22, 1993, the EPA instituted an administrative proceeding
contending that the company had not received a permit required under the Clean
Air Act Amendments of 1990 (CAAA) for field activities at the El Segundo
refinery relating to the production of reformulated gasolines, which will bewas
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. However, theThe EPA may continue to seekalso sought civil penalties from the
company for activities conducted prior to the issuance of the permit. The
company has declined to accept the EPA's penalty demand of $1.635 million and
is in the process of formulating a counteroffer. The matter has been referred
to the Department of Justice for enforcement.
- 30 -
F. PORT ARTHUR REFINERY ASSESSMENT.
On August 3, 1994, the Environmental Protection Agency (EPA) issued a Notice
of Violation and Civil Penalty Assessment against the Port Arthur Refinery,
alleging exceedances of the refinery's water discharge permit on 24 occasions
between 1989 and 1994. The EPA further alleged various violations of record-
keeping and reporting requirements regarding monitoring of the wastewater
effluent discharge pursuant to the permit. The EPA sought civil penalties in
excess of $100,000. The refinery denied all allegations, many of which were
subject to the "upset" defense available to dischargers during extraordinary
weather events and temporary maintenance of wastewater treatment equipment.
Without admitting liability, Chevron agreed to pay a fine of $124,000 and to
implement various changes in recordkeeping procedures.
G. CHEVRON PIPELINE COMPANY PENALTY ASSESSMENT.
By letter dated December 13, 1994, the EPA alleged that Chevron has violated
the New Source Performance Standards applicable to petroleum liquid storage
vessels ("Subpart Ka") and thereby has violated section 111(e) of the Clean
Air Act. More particularly, the EPA contends that one petroleum liquid storage
vessel at Chevron's pipeline facility in La Mirada, California, has
continuously operated in violation of one provision of Subpart Ka since 1979.
The EPA has proposed a civil penalty of $306,000 for Chevron's alleged
violation of the Act. Chevron has contacted EPA and will commence settlement
negotiations with the EPA in the near future.
Other previously reported legal proceedings have been settled or the issues
resolved so as not to merit further reporting.
- 2731 -
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of 19931994 to a vote of
security holders through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT AT MARCH 1, 19941995
MAJOR AREA OF
NAME AND AGE EXECUTIVE OFFICE HELD RESPONSIBILITY
- ------------------- -------------------------------- ----------------------
K.T. Derr 5758 Chairman of the Board since 1989 Chief Executive
Director since 1981 Officer
Executive Committee Member
since 1986
J.D. Bonney 6364 Vice-Chairman of the Board Worldwide Exploration
since 1987 and Production
Director and Executive Activities, Pipe-Coal,
Committee Member since 1986 lines, Coal and
Other Minerals, Administrative
Services, Aircraft
Services
J.N. Sullivan 5657 Vice-Chairman of the Board Worldwide Refining,
since 1989 Marketing and Trans-
Director since 1988 portation Activities,
Executive Committee Member Chemicals,
since 1986 Real Estate,
Environmental,
Human Resources,
Research
W.E. Crain 64 Vice-President since 1986 Worldwide Exploration
Director and Executive and Production
Committee Member since 1988
R.E. Galvin 6263 Vice-President since 1988 U.S. Exploration
President of Chevron U.S.A. and Production
Production Company since 1992
Executive Committee Member
since 1993
D.R. Hoyer 62D.J. O'Reilly 48 Vice-President since 19871991 U.S. Refining,
President of Chevron U.S.A. Marketing and
Products Company since 19921994 Supply
Executive Committee Member
since 19931994
M.R. Klitten 4950 Vice-President and Chief Finance
Financial Officer since 1989 Finance
Executive Committee Member
since 1989
R.H. Matzke 5758 Vice-President since 1990 Overseas Exploration
President of Chevron Overseas and Production
Petroleum Inc. since 1989
Executive Committee Member
since 1993
J.E. Peppercorn 5657 Vice-President since 1990 Chemicals
President of Chevron Chemical
Company since 1989
Executive Committee Member
since 1993
H.D. Hinman 5354 Vice-President and General Law
Counsel since 1993
Executive Committee Member
since 1993
- 2832 -
The Executive Officers of the Corporation consist of the Chairman of the
Board, the Vice-Chairmen of the Board, and such other officers of the
Corporation who are either Directors or members of the Executive Committee, or
are chief executive officers of principal business units. Except as noted
below, all of the Corporation's Executive Officers have held one or more of
such positions for more than five years. Messrs. Galvin, Hoyer,O'Reilly, Matzke and
Peppercorn are rotating members of the Executive Committee, with two serving
at any one time.
R.E. Galvin - Regional Vice-President, Exploration, Land and
Production, Chevron U.S.A. Inc. - 1985
- Vice-President, Chevron Corporation and
Senior Vice-President, Exploration, Land and
Production, Chevron U.S.A. Inc. - 1988
- President, Chevron U.S.A. Production Company
(a Division of Chevron U.S.A. Inc.) - 1992
H.D. Hinman - Partner, Law Firm of Pillsbury Madison &
Sutro - 1973
- Vice-President and General Counsel,
Chevron Corporation - 1993
M.R. Klitten - Comptroller, Chevron U.S.A. Inc. - 1985
- President, Chevron Information Technology
Company - 1987
- Vice-President for Finance,and Chief Financial Officer,
Chevron Corporation - 1989
R.H. Matzke - President, Chevron Canada Resources Limited - 1986
- President, Chevron Overseas Petroleum Inc. - 1989
- Vice-President, Chevron Corporation and President,
Chevron Overseas Petroleum Inc. - 1990
D.J. O'Reilly - General Manager of El Segundo Refinery,
Chevron U.S.A. Inc. - 1986
- 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
J.E. Peppercorn - Senior Vice-President, Chevron Chemical Company - 1986
- President, Chevron Chemical Company - 1989
- Vice-President, Chevron Corporation and President,
Chevron Chemical Company - 1990
- 2933 -
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The information on Chevron's common stock market prices, dividends, principal
exchanges on which the stock is traded and number of stockholders of record is
contained in the Quarterly Results and Stock Market Data tabulations, on page
FS-12 of this Annual Report on Form 10-K.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data for years 19891990 through 19931994 are presented on page
FS-36 of this Annual Report on Form 10-K.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONSResults 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 4139 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 4139 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 pagepages 2 through 4 through 6 of the Notice of Annual
Meeting of Stockholders and Proxy Statement dated March 25, 1994,24, 1995, is
incorporated herein by reference in this Annual Report on Form 10-K. See
Executive Officers of the Registrant on pages 2832 and 2933 of this Annual Report
on Form 10-K for information about executive officers of the company.
There was noItem 405 of Regulation S-K calls for disclosure of any known late filing or
failure by an insider to file a report required by sectionSection 16 of the Exchange
Act. ITEM 11. EXECUTIVE COMPENSATION
The informationThis disclosure is contained on pages 15 through 17page 21 of the Notice of Annual Meeting
of Stockholders and Proxy Statement dated March 25, 1994,24, 1995 and is incorporated
herein by reference in this Annual report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The information on pages 11 through 13 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 24, 1995, is incorporated herein
by reference in this Annual Report on Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information on pages 2 and 3page 5 of the Notice of Annual Meeting of Stockholders and
Proxy Statement dated March 25, 1994,24, 1995, is incorporated herein by reference in
this Annual Report on Form 10-K.
ITEM 13.CERTAIN13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There were no relationships or related transactions requiring disclosure under
Item 404 of Regulation S-K.
- 3034 -
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTS: PAGE (S)
--------
Report of Independent Accountants FS-13
Consolidated Statement of Income
for the three years ended December 31, 19931994 FS-14
Consolidated Balance Sheet at December 31,
19931994 and 19921993 FS-15
Consolidated Statement of Cash Flows
for the three years ended December 31, 19931994 FS-16
Consolidated Statement of Stockholders' Equity
for the three years ended December 31, 19931994 FS-17
Notes to Consolidated Financial Statements FS-18 to FS-29
(2) FINANCIAL STATEMENT SCHEDULES:
Report of Independent Accountants on
Financial Statement Schedules 35
Schedule V - Property, Plant and Equipment 36
Schedule VI - Accumulated Depreciation, 37
Depletion and Amortization of Property,
Plant and Equipment
Caltex Group of Companies Combined
Financial Statements and Schedules C-1 to C-21C-20
The Combined Financial Statements and Schedules of the Caltex Group
of Companies are filed as part of this report and follow the
Five-Year Financial Summary (page FS-36).report. All other schedules
are omitted because they are not applicable or the required
information is included in the consolidated financial statements or
notes thereto.
(3) EXHIBITS:
The Exhibit Index on pages 3337 and 3438 of this Annual Report on Form
10-K lists the exhibits that are filed as part of this report.
(b) REPORTS ON FORM 8-K:
The company filed no reportsA Current Report on Form 8-K, duringdated January 24, 1995, was filed by
the fourthcompany on January 24, 1995. This report announced unaudited
preliminary earnings for the quarter and the twelve months ended
December 31, 1994.
A Current Report on Form 8-K, dated February 27, 1995, was filed by
the company on February 28, 1995. This report announced the sale
of 1993the Port Arthur, Texas, fuels refinery to Clark Refining and
throughMarketing, Inc. and a $98 million increase to 1994 preliminary
earnings as a result of the reversal of a previously established
provision for the closure of the refinery.
A Current Report on Form 8-K, dated March 30, 1994.10, 1995, was filed by
the company on March 10, 1995. This report contained the Company's
1994 Financial Statements (audited) and Management's Discussion
and Analysis of Financial Condition and Results of Operations.
A Current Report on Form 8-K, dated March 10, 1995, was filed by
the company on March 10, 1995. This report contained Summarized
Financial Data for the three years ended December 31, 1994 for the
company's Chevron Transport Corporation subsidiary.
- 3135 -
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 30th29th day of March
1994.1995.
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 30th29th day of March 1994.1995.
PRINCIPAL EXECUTIVE OFFICERS DIRECTORS
(AND DIRECTORS)
KENNETH T. DERR* SAMUEL H. ARMACOST*
-
------------------------------------- --------------------------------------
Kenneth T. Derr, Samuel H. Armacost
Chairman of the Board
J. DENNIS BONNEY* WILLIAM E. CRAIN*
-SAM GINN*
------------------------------------- --------------------------------------
J. Dennis Bonney, William E. CrainSam Ginn
Vice-Chairman of the Board
JAMES N. SULLIVAN* SAM GINN*
-CARLA A. HILLS*
------------------------------------- --------------------------------------
James N. Sullivan, Sam GinnCarla A. Hills
Vice-Chairman of the Board
CONDOLEEZZA RICE*CHARLES M. PIGOTT*
--------------------------------------
PRINCIPAL FINANCIAL OFFICER Condoleezza RiceCharles M. Pigott
MARTIN R. KLITTEN* S. BRUCE SMART, JR.*
-CONDOLEEZZA RICE*
------------------------------------- --------------------------------------
Martin R. Klitten, Condoleezza Rice
Vice-President and
Chief Financial Officer
S. BRUCE SMART, JR.*
--------------------------------------
S. Bruce Smart, Jr.
Vice-President, Finance
JOHN A. YOUNG*
--------------------------------------
John A. Young
PRINCIPAL ACCOUNTING OFFICER
DONALD G. HENDERSON* GEORGE H. WEYERHAEUSER*
-JOHN A. YOUNG*
------------------------------------- --------------------------------------
Donald G. Henderson, George H. WeyerhaeuserJohn A. Young
Vice-President and Comptroller
*By: /s/ MALCOLM J. McAULEY GEORGE H. WEYERHAEUSER*
-------------------------------- --------------------------------------
Malcolm J. McAuley, George H. Weyerhaeuser
Attorney-in-Fact
- 3236 -
EXHIBIT INDEX
EXHIBIT
NO. DESCRIPTION
-
------- --------------------------------------------------------------------
3.1 Restated Certificate of Incorporation of Chevron Corporation, dated
November 23, 1988,August 2, 1994, filed as Exhibit 3.1 to Chevron Corporation's
AnnualQuarterly Report on Form 10-K10-Q for 1989,the quarter and six month period
ended June 30, 1994, and incorporated herein by reference.
3.2 By-Laws of Chevron Corporation, as amended December 7, 1989,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 AnnualQuarterly Report on Form 10-K10-Q for 1989,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 Definitions of Selected Financial Terms (page 38).
12.2 Computation of Ratio of Earnings to Fixed Charges (page 39)EX-1).
22.121.1 Subsidiaries of Chevron Corporation (page 40)EX-2).
24.123.1 Consent of Price Waterhouse LLP (page 35)EX-3).
24.223.2 Consent of KPMG Peat Marwick LLP (page C-5 of financial statements for
the Caltex Group of Companies)EX-4).
- 3337 -
EXHIBIT INDEX
(continued)
EXHIBIT
NO. DESCRIPTION
- ------- --------------------------------------------------------------------
25.124.1 Powers of Attorney for directors and certain officers of Chevron
to Corporation, authorizing among other things, the signing of reports
on their behalf, filed as Exhibit 25.1 to Chevron Corporation'sthe Annual Report on
24.13 Form 10-K for 1988 and incorporated herein by
reference.
25.2 Poweron their behalf.
99.1 Definitions of Attorney for a certain director of Chevron Corporation,
authorizing, among other things, the signing of reports on his
behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1989, and
incorporated herein by reference.
25.3 Power of Attorney for a certain officer of Chevron Corporation,
authorizing, among other things, the signing of reports on his
behalf, filed as Exhibit 25.3 to Chevron Corporation's Annual Report
on Form 10-K for 1989 and incorporated herein by reference.
25.4 Power of Attorney for a certain director of Chevron Corporation,
authorizing, among other things, the signing of reports on her
behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1991, and
incorporated herein by reference.
25.5 Power of Attorney for a certain director of Chevron Corporation,
authorizing, among other things, the signing of reports on her
behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1993, and
incorporated herein by reference.Selected Financial Terms (page EX-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, 225 Bush Street, San Francisco, California
94104.
- 34 -
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULES
To the Board of Directors of Chevron Corporation
Our audits of the consolidated financial statements referred to in our report
dated February 25, 1994 appearing on page FS-13 of this Annual Report on Form
10-K also included an audit of the Financial Statement Schedules listed in
Item 14(a) of this Form 10-K. In our opinion, these Financial Statement
Schedules present fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements.
PRICE WATERHOUSE
San Francisco, California
February 25, 1994
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Form S-3 (No. 2-98466)
and Form S-8 (Nos. 33-3899, 33-34039 and 33-35283) of Chevron Corporation,
and to the incorporation by reference in the Prospectus constituting part of
the Registration Statement on Form S-3 (No. 33-14307) of Chevron Capital
U.S.A. Inc. and Chevron Corporation, and to the incorporation by reference in
the Registration Statement on Form S-3 (No. 33-58838) of Chevron Canada
Finance Limited and Chevron Corporation, and to the incorporation by
reference in the Prospectus constituting part of the Registration Statement
on Form S-8 (No. 2-90907) of Caltex Petroleum Corporation of our report dated
February 25, 1994 appearing on page FS-13 of this Annual Report on Form 10-K.
We also consent to the incorporation by reference of our report on the
Financial Statement Schedules which appears above.
PRICE WATERHOUSE
San Francisco, California
March 30, 1994
- 35 -
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING CAPITAL LEASES)
(Millions of Dollars)
OTHER
BALANCE AT CHANGES BALANCE AT
BEGINNING ADDITIONS (1) ADD END OF
CLASSIFICATION OF PROPERTY OF PERIOD AT COST (RETIREMENTS) (DEDUCT) (2) PERIOD
- ----------------------------- ---------- ------------- ------------- ------------ ----------
--------------------------------1993------------------------------
Petroleum
Exploration and Production (3) $25,599 $1,677 $ (948) $ 9 $26,337
Refining, Marketing & Transportation 13,129 1,179 (1,272) 42 13,078
Chemicals 2,083 198 (57) (12) 2,212
Coal and Other Minerals 847 35 (22) - 860
Corporate and Other 2,352 96 (83) (45) 2,320
------- ------ ------- ----- -------
Total $44,010 $3,185 $(2,382) $ (6) $44,807
======= ====== ======= ===== =======
-------------------------------1992----------------------------
Petroleum
Exploration and Production (3) $27,800 $1,609 $(3,824) $ 14 $25,599
Refining, Marketing & Transportation 12,241 1,284 (361) (35) 13,129
Chemicals 2,132 208 (277) 20 2,083
Coal and Other Minerals 839 59 (51) - 847
Corporate and Other 2,256 209 (114) 1 2,352
------- ------ ------- ----- -------
Total $45,268 $3,369 $(4,627) $ - $44,010
======= ====== ======= ===== =======
-------------------------------1991----------------------------
Petroleum
Exploration and Production (3) $27,918 $1,761 $(1,878) $ (1) $27,800
Refining, Marketing & Transportation 11,234 1,439 (432) - 12,241
Chemicals 1,973 205 (36) (10) 2,132
Coal and Other Minerals 1,050 82 (294) 1 839
Corporate and Other 2,133 178 (64) 9 2,256
------- ------ ------- ----- -------
Total $44,308 $3,665 $(2,704) $ (1) $45,268
======= ====== ======= ===== =======
NOTES:
(1) Additions are reported net of the write-off of prior years' exploratory wells, which were $29, $57
and $35 in 1993, 1992 and 1991, respectively.
(2) Includes inter-functional transfers in all years.
(3) Includes investment in unproved oil and gas properties.
- 36 -
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT (INCLUDING CAPITAL LEASES) (1)
(Millions of Dollars)
ACCUMULATED DEPRECIATION, DEPRECIATION, OTHER
DEPLETION AND AMORTIZATION BALANCE AT DEPLETION AND CHANGES BALANCE AT
FOR CLASSIFICATIONS OF BEGINNING AMORTIZATION ADD END OF
PROPERTY LISTED IN SCHEDULE V OF PERIOD EXPENSE (RETIREMENTS) (DEDUCT) (2) PERIOD
- ----------------------------- ---------- ------------- ------------- ------------ ----------
----------------------------- 1993 -------------------------------
Petroleum
Exploration and Production $14,916 $1,583 $ (709) $ 5 $15,795
Refining, Marketing & Transportation 5,126 566 (501) 14 5,205
Chemicals 722 149 (32) - 839
Coal and Other Minerals 329 54 (21) - 362
Corporate and Other 729 100 (68) (20) 741
------- ------ ------- ----- -------
Total $21,822 $2,452 $(1,331) $ (1) $22,942
======= ====== ======= ===== =======
----------------------------- 1992 ------------------------------
Petroleum
Exploration and Production $15,854 $1,760 $(2,705) $7 $14,916
Refining, Marketing & Transportation 4,826 527 (211) (16) 5,126
Chemicals 763 145 (196) 10 722
Coal and Other Minerals 315 50 (36) - 329
Corporate and Other 660 112 (42) (1) 729
------- ------ ------- ----- -------
Total $22,418 $2,594 $(3,190) $ - $21,822
======= ====== ======= ===== =======
----------------------------- 1991 ------------------------------
Petroleum
Exploration and Production $15,358 $1,840 $(1,342) $ (2) $15,854
Refining, Marketing & Transportation 4,603 466 (249) 6 4,826
Chemicals 656 141 (24) (10) 763
Coal and Other Minerals 398 55 (138) - 315
Corporate and Other 567 114 (27) 6 660
------- ------ ------- ----- -------
Total $21,582 $2,616 $(1,780) $ - $22,418
======= ====== ======= ===== =======
NOTES:
(1) Depreciation, depletion and amortization methods are disclosed in Note 1 to the Consolidated
Financial Statements appearing on pages FS-18 to FS-19 of this Annual Report on Form 10-K.
(2) Includes inter-functional transfers in all years.
- 37 -
EXHIBIT 12.1
DEFINITIONS OF SELECTED FINANCIAL TERMS
RETURN ON AVERAGE STOCKHOLDERS' EQUITY
Net income divided by average stockholders' equity. Average stockholders'
equity is computed by averaging the sum of the beginning of year and end of
year balances.
RETURN ON AVERAGE CAPITAL EMPLOYED
Net income plus after-tax interest expense divided by average capital
employed. Capital employed is stockholders' equity plus short-term debt plus
long-term debt plus capital lease obligations plus minority interests.
Average capital employed is computed by averaging the sum of capital employed
at the beginning of the year and at the end of the year.
TOTAL DEBT-TO-TOTAL DEBT PLUS EQUITY RATIO
Total debt, including capital lease obligations, divided by total debt plus
stockholders' equity.
CURRENT RATIO
Current assets divided by current liabilities.
INTEREST COVERAGE RATIO
Income before income tax expense and cumulative effect of change in
accounting principle, plus interest and debt expense and amortization of
capitalized interest, divided by before-tax interest costs.
- 38 -
EXHIBIT 12.2
CHEVRON CORPORATION - TOTAL ENTERPRISE BASIS
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Dollars in Millions)
Year Ended December 31,
------------------------------------------
1993 1992(1) 1991 1990 1989
------ ------ ------ ------ ------
Net Income before Cumulative
Effect of Changes in
Accounting Principles $1,265 $2,210 $1,293 $2,157 $ 251
Income Tax Expense 1,389 1,508 1,302 2,387 1,322
Distributions Greater Than
(Less Than) Equity in
Earnings of Less Than 50%
Owned Affiliates 6 (9) (20) (6) (9)
Minority Interest (2) 2 2 6 3
Previously Capitalized
Interest Charged to
Earnings During Period 20 18 17 15 15
Interest and Debt Expense 390 490 585 707 718
Interest Portion of Rentals (2) 169 152 153 163 118
------ ------ ------ ------ ------
EARNINGS BEFORE PROVISION
FOR TAXES AND FIXED CHARGES $3,237 $4,371 $3,332 $5,429 $2,418
====== ====== ====== ====== ======
Interest and Debt Expense $ 390 $ 490 $ 585 $ 707 $ 718
Interest Portion of Rentals (2) 169 152 153 163 118
Capitalized Interest 60 46 30 24 42
------ ------ ------ ------ ------
TOTAL FIXED CHARGES $ 619 $ 688 $ 768 $ 894 $ 878
====== ====== ====== ====== ======
- ----------------------------------------------------------------------------
RATIO OF EARNINGS TO FIXED CHARGES 5.23 6.35 4.34 6.07 2.75
- ----------------------------------------------------------------------------
(1) The information for 1992 reflects the company's adoption of the Financial
Accounting Standards Board Statements No. 106, "Employers' Accounting for
Postretirement Benefits Other than pensions" and No. 109, "Accounting for
Income Taxes," effective January 1, 1992.
(2) Calculated as one-third of rentals.
- 39 -
EXHIBIT 22.1
SUBSIDIARIES OF CHEVRON CORPORATION*
Name of Subsidiary State or Country
(Reported by Principal Area of Operation) in Which Organized
- ----------------------------------------- ------------------
UNITED STATES
Chevron U.S.A. Inc. Pennsylvania
Principal Divisions:
Chevron U.S.A. Production Company
Chevron U.S.A. Products Company
Warren Petroleum Company
Chevron Capital U.S.A. Inc. Delaware
Chevron Chemical Company Delaware
Chevron Investment Management Company Delaware
Chevron Land and Development Company Delaware
Chevron Oil Finance Company Delaware
Chevron Pipe Line Company Delaware
Huntington Beach Company California
The Pittsburg & Midway Coal Mining Co. Missouri
INTERNATIONAL
Bermaco Insurance Company Limited Bermuda
Cabinda Gulf Oil Company Limited Bermuda
Chevron Asiatic Limited Delaware
Chevron Canada Limited Canada
Chevron Canada Enterprises Limited Canada
Chevron Canada Resources Canada
Chevron International Limited Liberia
Chevron International Oil Company, Inc. Delaware
Chevron Niugini Pty. Limited Papua New Guinea
Chevron Overseas Petroleum Inc. Delaware
Chevron Standard Limited Delaware
Chevron U.K. Limited United Kingdom
Chevron Transport Corporation Liberia
Chevron Nigeria Limited Nigeria
Gulf Oil (Great Britain) Limited United Kingdom
Insco Limited Bermuda
Transocean Chevron Company Delaware
*All of the subsidiaries in the above list are wholly owned, either directly
or indirectly, by Chevron Corporation. Certain subsidiaries are not listed
since, considered in the aggregate as a single subsidiary, they would not
constitute a significant subsidiary at December 31, 1993.
- 40 -
INDEX TO MANAGEMENT'S DISCUSSION AND ANALYSIS,
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PAGE(S)
--------------
Management's Discussion and Analysis . . . . . . . . . . . . . FS-1 to FS-12
Quarterly Results and Stock Market Data . . . . . . . . . . . . FS-12
Report of Management . . . . . . . . . . . . . . . . . . . . . FS-13
Report of Independent Accountants . . . . . . . . . . . . . . . FS-13
Consolidated Statement of Income . . . . . . . . . . . . . . . FS-14
Consolidated Balance Sheet . . . . . . . . . . . . . . . . . . FS-15
Consolidated Statement of Cash Flows . . . . . . . . . . . . . FS-16
Consolidated Statement of Stockholder's Equity . . . . . . . . FS-17
Notes to Consolidated Financial Statements . . . . . . . . . . FS-18 to FS-29
Supplemental Information on Oil and Gas Producing Activities . FS-30 to FS-35
Five-Year Financial Summary . . . . . . . . . . . . . . . . . . FS-36
- 4139 -
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
KEY FINANCIAL RESULTS
Millions of dollars, except per-share amountsMILLIONS OF DOLLARS, EXCEPT PER-SHARE AMOUNTS 1994 1993 1992
1991
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Sales and Other Operating Revenues $35,130 $36,191 $38,212 $38,118
Income Before Cumulative Effect of
Changes in Accounting Principles $ 1,693 $ 1,265 $ 2,210 $ 1,293
Cumulative Effect of Changes
in Accounting Principles - - $ (641)
-
Net Income $ 1,693 $ 1,265 $ 1,569
$ 1,293
Special Credits (Charges) Credits Included in Income* $ 22 $ (883) $ 651 $ (66)
Per Share:
Income Before Cumulative Effect of
Changes in Accounting Principles $ 3.892.60 $ 6.521.94 $ 3.693.26
Net Income $ 3.892.60 $ 4.631.94 $ 3.692.31
Dividends $ 3.501.85 $ 3.301.75 $ 3.25
=============================================================================
*Before cumulative effect of changes in accounting principles1.65
Return On:
Average Capital Employed 8.7% 6.8% 8.5%
Average Stockholders' Equity 11.8% 9.1% 11.0%
===============================================================================
* BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES.
Chevron's worldwide net income for 19931994 was $1.265$1.693 billion, down 19up 34 percent and 28 percent
from 19921993 and 1991,1992, respectively. However, special items in all years, and the
cumulative effect of adopting two new accounting standards in 1992, affected
the comparability of the company's reported results. Special items, after
related tax effects, increased earnings in 1994 by $22 million, decreased
earnings in 1993 earningsby $883 million and increased earnings in 1992 earningsby $651 million and decreased 1991 earnings
$66
million. Also, the cumulative effect of adopting the two new accounting standards
reduced 1992 earnings $641 million. Excluding the effects of special items in
all years and the 1992 accounting changes, 19931994 earnings of $1.671 billion
declined 22 percent from very strong operating earnings of $2.148 billion were up 38in
1993 and increased 7 percent from $1.559 billion in 1992 and increased 58 percent
from $1.359 billion in 1991.1992.
OPERATING ENVIRONMENT AND OUTLOOK. Worldwide petroleum industry conditions
were weak throughout 1994. Crude oil prices began trending downwardwere at midyear. The decline accelerateda five-year low at the
beginning of the year. Although prices recovered somewhat during the lastyear,
supplies remained plentiful. The company's U.S. realizations were, on average,
72 cents per barrel less than in the prior year, and its international
realizations declined $1.23 per barrel. Average crude oil prices have declined
for four consecutive years.
U.S. natural gas prices, after increasing the past two monthsyears, began falling in
1994 and averaged 22 cents per thousand cubic feet less than in 1993, as ample
supplies and mild weather held down prices. The company's international
natural gas prices fell by about the same amount.
Sales margins on refined products were depressed much of 1993,
withthe year. For
example, in the United States, product prices reaching their lowest levelaveraged about $1 per barrel
less than in over five years by year-end.
During the previous year as highly competitive markets, particularly in
the East, held down prices. These market conditions tended to lengthen the
time lag for product prices to reflect the gradually increasing crude oil
costs during the year.
On the other hand, the chemicals industry experienced a dramatic turnaround
from the excess capacity and weak demand of the past four years. Strengthening
industrialized economies, particularly in the United States, resulted in
strong demand and higher prices - and Chevron's chemicals earnings rebounded
substantially.
All these industry conditions have continued into 1995. The company's posted
price for West Texas Intermediate (WTI), a benchmark crude declined $5.50oil, was $16.75 per
barrel to $13.25 at year-end 1993.
Worldwide demand for crude oil has been dampened by1994 and $17.50 at February 28, 1995. The Henry Hub natural
gas spot price, an industry marker, was $1.61 per thousand cubic feet at
year-end 1994 and $1.55 at February 28, 1995. U.S. refined products prices in
January 1995 were about flat with December. Planned major maintenance
shutdowns at two of the weak global economy;
productioncompany's core refineries resulted in lower refinery
utilization rates, lower sales volumes and increased product purchases in the
non-OPEC countries has increased, particularlyearly part of 1995. Chemicals operations remained strong.
Chevron began selling federally mandated reformulated gasoline January 1, 1995
in the
North Sea; and the OPEC producers have not adjusted their production levels
accordingly. On the other hand, natural gas pricesnine areas in the United States, remained strongaccounting for about 20 percent of its
January gasoline sales volumes. The increased cost of manufacturing
reformulated gasoline has not yet been fully reflected in 1993, with the company's average realization of $1.99
per thousand cubic feet nearly 30 cents higher than in 1992. For most of
1993, refined product prices did not decline as quickly as crude oil prices,
resulting in strong worldwide sales margins. However, late in the year, the
decline accelerated in the United States and product prices have remained
at lower levels into early 1994.
Economic indicators show evidence that the U.S. economy is improving;
however, recessionary conditions continue in other major countries. Bitter
cold weather in the U.S. Midwest and East strengthened crude oil prices
somewhat in early 1994 but by February 25 Chevron's posted price for WTI
had fallen back to the year-end 1993 level. Natural gas prices remained
firm, with average U.S. natural gas realizations in January 1994 of $2.03
per thousand cubic feet.
If both crude oil and refined product prices continue at their low levels,
the company's earnings from ongoing operations may be negatively affected.
Widely fluctuating prices have become characteristic of the petroleum
industry for the past several years.prices.
The company has made significant
progress in streamlining its businesses and reducing costs in recent years
and believes it has improved its ability to operate more competitively and
profitably.
YEAR-END 1993 MARKED THE END OF A FIVE-YEAR PERIOD, FOR WHICH AGGRESSIVE
MANAGEMENT PERFORMANCE OBJECTIVES HAD BEEN SET IN EARLY 1989. The company
declared its mission was to provide superior financial results for the
company's stockholders. The objective was set to have a higher total
stockholder return - stock appreciation plus reinvested dividends - than
five other major U.S. oil companies against which the company measures
its performance. To achieve this, the company embarked uponon an aggressive program several years ago to restructureincrease
its businesses, improve management decision makingcompetitiveness and accountability, shedachieve superior returns for its stockholders.
Businesses were restructured, marginal and non-core assets reduce operating
costs, improve work processes,were divested and
through selective investments, position
the company for long-term growth. Over the 1989-1993 period, Chevron's
total annual stockholder return averaged 18.9 percent, the best among its
peer group. The company disposed of marginal and non-core assets, generating
almost $4 billion in cash proceeds during this period, and reduced its
annualcompany's cost structure by about $1 billion in 1993 fromwas significantly reduced. At
FS-1
1991 levels. Using the company's method of measuring cost performance,
costs were reduced from $7.45 per barrel in 1991 to $6.51 in 1993, a
reduction of $.94 per barrel, or nearly 13 percent.
IN EARLY 1994, THE COMPANY ANNOUNCED A NEW FIVE-YEAR GOAL OF MAINTAINING
ITS POSITION AS THE NO. 1 MAJOR U.S. OIL COMPANY IN TOTAL STOCKHOLDER
RETURN. Key elements include targeting a further $.25 per barrel reduction
in operating and administrative costs bysame time, the end of 1994; attaining a 12
percent return on capital employed, after adjusting for special items; and
pursuingcompany has selectively pursued growth opportunities - particularly in international explorationits
areas of strength.
The company continues to review and productionanalyze its operations and throughmay incur
future charges related to the restructuring of its Caltex affiliate,businesses and disposition
of marginal or non-strategic assets. In particular, the company is currently
reviewing its oil and gas operations in refiningwestern Canada and marketing
activitiesoptions to maximize
the value of certain real estate operations located in the fast growing Asia-Pacific region.California.
UNITED STATES REFINING AND MARKETING DEVELOPMENTS. The companyIn connection with the
previously announced a
major restructuring of its U.S. refiningdownstream operations, Chevron
sold its Philadelphia refinery in August 1994 and marketing business in May 1993.
The company's refineries atits Port Arthur, Texas,
and Philadelphia,
Pennsylvania, will be sold and investmentsrefinery in retail marketing activities in
the East will be concentrated in the Gulf Coast states. AsFebruary 1995. The two refineries had a result, the
company's U.S. refiningcombined capacity will decreaseof about
350,000 barrels per day or about 25 percent andof the company's total U.S.
refined product sales volumes may decline about
250,000refining capacity prior to the sales. The Philadelphia refinery had been
operated as a merchant refinery, with its 175,000 barrels per day or about 17 percentoutput sold
to independent petroleum marketers. Products for the company's marketing
system that were previously supplied by the Port Arthur refinery will be
obtained from 1993 volumes. However,other sources.
The restructuring reflected the new refiningcompany's strategy to focus its resources in
the West, Southwest and those parts of the South where the company's marketing
business is strongest. The smaller refinery organization while smaller, is expected to be
more efficient, with improved cash flow and return on capital employed. It willThe
disposition of the two refineries has also eliminate theeliminated large capital
investments that would have otherwise been required
for these facilities underrequired.
In connection with the Clean Air Act and other environmental
regulations. A provision of $543 million was recorded for the financial
effects of the restructuring. In late February 1994,Port Arthur refinery sale, the company signed a
letterretained certain
environmental cleanup obligations. The company has accrued for presently
anticipated costs of intent to sell the Philadelphia refinery to Sun Company, Inc.
While negotiations for the refinery sales are ongoing, it is expected that
the reserve$282 million, most of which will be sufficient to completeexpended over
approximately the restructuring.
UNITED STATES EXPLORATION AND PRODUCTION DEVELOPMENTS.next ten years. It is possible additional provisions may be
necessary in the future. The interim
tankering permit issuedexpenditures will be funded by future cash flows
from operations, with no material effect anticipated on the California Coastal Commission required the
Point Arguello partners to have signed an agreement by February 1, 1994
that would allow a pipeline developer to secure financing for construction
of a pipeline to the Los Angeles area. Because of ongoing negotiations, the
deadline was not met and tankering was suspended. With tankering, the
project had been producing over 80,000 barrels per day. The partners have
thus far maintained production volumes by routing the oil to alternate
markets, pending resolution of the negotiations and resumption of
tankering. Chevron is operator and owns approximately 25 percent of the
project.company's
liquidity.
INTERNATIONAL EXPLORATION AND PRODUCTION DEVELOPMENTS. Liquids production from
50 percent owned Tengizchevroil (TCO), the company'sa joint venture with the Republic of
Kazakhstan, to
develop the Tengiz and Korolev oil fields on the northeastern coast of
the Caspian Sea, began operations in April 1993. The oil is being exported
into world markets under a transportation/exchange agreement with Russia,
whereby TCO receives and exports crude oil from Russia in exchange for
providing Russia with comparable amounts of Tengiz crude. Natural gas,
natural gas liquids and sulfur are being sold into local markets. Upon
formation of the joint venture, Chevron's net proved reserves of crude
oil and natural gas liquids increased 1.1 billion barrels and net proved
reserves of natural gas increased 1.5 trillion cubic feet, representing the
company's share of TCO's current net proved reserves.
Crude oil production capacity is 65,000averaged about 46,000 barrels per day; however, because
of pipeline transportation constraints, production has averaged
approximatelyday in 1994, up from 30,000
barrels per day since April.in 1993. At year-end 1993, the
company's cash investment in1994 TCO was producing about $220 million. In addition,65,000
barrels per day. With the company has accrued future field development obligations and amounts
payable after completion and demonstrated operability of an export
pipeline system. Over the next three to five years, plans call for TCO
to spend about $1.5 billion to reach a second processing plant in December
1994, production capacity of 260,000increased to 95,000 barrels per day by the late 1990s. Current capacityand is expectedscheduled
to doubleincrease to 130,000 barrels per day by the end of 1995. TheBeyond this, the
pace of further field development from
130,000 to 260,000 barrels per day is dependent on the ability toavailability of
additional export capability. Production levels are dependent on monthly
export quotas set by Russia, under a transportation/exchange agreement, and
are currently set at 65,000 barrels per day. Chevron has been in prolonged
negotiations with the full production capacity. This will ultimately requireCaspian Pipeline Consortium, composed of the constructionRepublics
of an export pipeline system, which is separate fromRussia and Kazakhstan and the TCO joint
venture's Tengiz development project. NegotiationsSultanate of Oman, to agree on terms for aan
export pipeline system that would enable the project have proved to be very difficult, and it is currently
impossiblesell its output
directly to predictworld markets.
Although the eventual outcome or its impact on the joint
venture.
In January 1994, production began from the Alba oil field in the United
Kingdom North Sea. Chevron is operator and owns one-third of this project.
Production should peak at about 70,000 barrels per day later in 1994.
FS-2
Chevron has significant oil and gas exploration and productioncompany's operations in Nigeria and in the Angolan exclave of
Cabinda where itshave been generally unaffected by the political uncertainty and civil
unrest that continues to exist in those countries, the company continues to
closely monitor developments. Chevron has significant oil producing properties
in both countries and has major development projects underway. In 1994, the
company's net share of net
production isin Nigeria averaged about 130,000 barrels
per day, and in Angola about 100,000 barrels of crudeper day.
Chevron's partner in Nigeria, the government-owned Nigerian National Petroleum
Corporation (NNPC) has fallen behind in paying its cash calls to Chevron, as
well as to other oil per daycompanies operating in Nigeria. However, NNPC continues
to make payments and the company believes all amounts owed it will ultimately
be paid.
The Nigerian government effectively devalued its currency, the naira, in
January 1995 by changing from each of these
countries. Angola has experienced civil unrest following its 1992 elections;
separately, elements seeking independence of Cabinda from Angolaa fixed exchange rate to a floating, free market
rate. This devaluation did not have periodically created civil unrest ina significant effect on the areafinancial
position of the company's operations.
Also, the nullification of the Nigerian elections in 1993 has been followed
by a period of political uncertainty. To date, none of these events has hadsubsidiary and is not expected to have a
significant impacteffect on the company's operations, but the company is closely
monitoring developments.its ongoing operations.
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.
FS-2
Using definitions and guidelines established by the American Petroleum
Institute, Chevron estimates its worldwide environmental spending in 19931994 was
nearlyabout $1.5 billion for its consolidated companies. Included in these
expenditures were $683 million of which
$675environmental capital expenditures, and $638
million were capital expenditures. These amounts doof 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 for future
environmental cleanup programs (but not include non-cash provisions recorded for environmental remediation programs, but
include spending charged against such reserves.during
the year).
In addition to the various federal, state and localcosts for environmental laws and
regulations governingprotection associated with its
ongoing operations and products, the company (as well as other companies
engaged in the petroleum or chemicals industries) is required to incurincurs expenses for
corrective actions at various facilities and waste disposal sites. An
obligation to take remedial action may be incurred as a result of the
enactment of laws, such as the federal Superfund law, or the issuance of new
regulations or as the result of accidentalthe 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 a facility isoperations are closed
or sold. Most of the expenditures to fulfill these obligations relate to
facilities and sites where past operations followed practices and procedures
that were considered acceptable under regulationsstandards existing at the time, performed, but now will
require investigatory and/or remedial work to ensure adequate protection to
the environment.meet current standards.
During 1993,1994, the company recorded $215$505 million of before-tax provisions to
provide for environmental remediation efforts, including Superfund sites.
Actual expenditures charged against these provisions and other previously
established reserves amounted to $183$182 million in 1993.1994. At year-end 1993,1994, the
company's environmental remediation reserve was $746 million,$1.219 billion, including $56$61
million related to Superfund sites. Receivables of $18 million have been
recorded for expected reimbursements of expenditures for environmental
cleanup.
Under provisions of the Superfund law, the Environmental Protection Agency
(EPA), as well as certain state agencies, have has designated Chevron a potentially responsible party (PRP) for, or has
otherwise involved it, in the remediation of a portion of 223238 hazardous waste sites. At
year-end 1993,1994, the company's cumulative share of costs and settlements for
approximately 145168 of these sites, for which payments or provisions have been
made in 19931994 and prior years, was about $89$96 million, including a provision of
$6$16 million made during 1993.1994. 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 and other regulatory agencies to require Chevron to assume other
responsible parties' costs at designated hazardous waste sites are not
expected to have a material effect on the company's consolidated financial
position or liquidity.
ProvisionsGenerally, provisions are recorded for work at identified sites where an
assessment or remediationcleanup plan has been developed and for which costs can
reasonably be estimated. In 1994, the company recorded environmental
remediation provisions aggregating $223 million for its U.S. marketing sites
where no specific contamination had yet been identified, using estimates based
on its history of required remediation at other similar sites.
It is likely the company will continue to incur additional charges for
environmental programsremediation relating to past operations. These future costs are
indeterminable due to such factors as the unknown magnitude of possible
contamination, the unknown timing and extent of the corrective actions that
may be required, the determination of the company's liability in proportion to
other responsible parties and the extent to which such costs are recoverable
from insurance or other sources.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 Chevron'sits
consolidated financial position or liquidity. Also, the company does not
believe its obligations to make such expenditures have had or will have any
significant impact on the company's competitive position relative to other
domestic or
FS-3
international petroleum or chemicals concerns. Although
environmental compliance costs are substantial, the company has no reason to
believe they vary significantly from similar costs incurred by other companies
engaged in similar businesses in similar areas. The company believes that such
costs ultimately are reflected in the petroleum and chemicals industries'
prices for products and services.
The petroleum industry is incurring major capital expenditures to meet
clean-air regulations, such as the 1990 amendments to the Clean Air Act will requirein the
United States. For companies operating in California, where Chevron has a
significant capital
expenditures forpresence, the industry to meet clean-air regulations.California Air Resources Board has imposed even
stricter requirements. The company's worldwide capital expenditures related to
air quality were $434are believed to have peaked at $495 million in 1993.
Estimated 19941994. For 1995,
total worldwide environ-
FS-3
mental capital environmental expenditures are $686estimated at $622 million, of which $478$438
million willare expected to be spent to meet federal and state clean-air
regulations for its products and facilities.on air quality related measures. This is in
addition to the ongoing costs of complying with other environmental regulations.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 and gas and mineralcoal properties at the end of their productive
lives. Most such costs are environmentally related. Provisions are recognized
through depreciation expenseon a unit-of-production basis as the properties are produced. The amount of
these reserves at year-end 19931994 was about $1.5
billion.$1.520 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.lives unless a decision to sell or
otherwise abandon the facility has been made.
OTHER CONTINGENCIES. At year-end 19931994 the company had $222$257 million of suspended
exploratory wells included in properties, plant and equipment. The wells are
suspended pending the drilling of additional wells to determine if commercially
producible quantities of oil orand gas reserves are present. The ultimate disposition of theseThese well costs is dependentwill be
capitalized or expensed depending on the results of this future drilling
activity.
The company is the subject of various lawsuits and claims and other contingent
liabilities. These are discussed in the notes to the accompanying consolidated
financial statements. The company believes that the resolution of these matters
will not materially affect its financial position or liquidity.
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 are substantially 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.
NEW ACCOUNTING STANDARDS. In November 1992, the Financial Accounting
Standards Board (FASB) issued1994 first quarter, the company adopted two
new accounting standards, Statement of Financial Accounting Standards (SFAS)
No. 112, "Employers'"Employers Accounting for Postemployment Benefits,"
which established accounting standards for employers who provide benefits
to former or inactive employees after termination but before retirement. In
May 1993, the FASB issuedBenefits" and SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities." The
company's current accounting practices
are substantially in compliance with the new standards. Accordingly, the
adoption of these two standards in the first quarter of 1994 willdid not have a material effect on the company's
consolidated financial statements and will
not affecthad no effect on its liquidity. The 1994
consolidated financial statements also include the disclosures required by SFAS
119, "Disclosure about Derivative Financial Instruments and Fair Value of
Financial Instruments," dealing with instruments that can only be settled in
cash.
SPECIAL ITEMS. Net income is affected by transactions that are unrelated to, or
are not representative of, the company's ongoing operations for the periods
presented. These transactions, defined by management and designated "special
items," can obscure the underlying results of operations for a year as well as
affect comparability between years. The adjacent table below summarizes the gains
(losses) gains,, on an after-tax basis, from special items included in the company's
reported net income.
Millions of dollarsMILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------
Asset Dispositions $ 122 $757 $149
Restructurings and Reorganizations (554) (40) (185)------------------------------------------------------------------------------
Prior-Year Tax Adjustments (130)$ 344 $(130) $ 72
173
Environmental Remediation Provisions (90) (44) (160)Asset Dispositions 48 122 757
Asset Write-Offs and Revaluations - (71) (133)
(24)Environmental Remediation Provisions (304) (90) (44)
Restructurings and Reorganizations (45) (554) (40)
LIFO Inventory (Losses) GainsLosses (10) (46) (26)
16
Other (11) (114) 65
(35)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Special Items $ 22 $(883) $651
$(66)
===========================================================================================================================================================
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
1994, prior-year tax adjustments increased earnings $344 million, including the
FS-4
net reversal of $301 million of tax and related interest reserves resulting
from the company's global settlement with the Internal Revenue Service 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, but increased earnings by $72
million in 1992.
ASSET DISPOSITIONS in 1993 resulted from1994 consisted of the sale of the company's continuing program
to disposelead and zinc
prospect in Ireland, generating an after-tax profit of marginal and non-strategic assets.$48 million. This sale
completed the company's withdrawal from non-coal minerals activities. The Ortho
lawn and garden products business was the major asset sold in 1993, generating
a $130 million gain. In addition, oil and gas properties in the United States
and Indonesia, undeveloped coal properties in the United States and marketing
assets in Central America were sold during the yearin 1993 resulting in a net loss of $8
million. In 1992, assets sold included oil and gas properties in the United
States, United Kingdom, Canada and Sudan; a U.S. fertilizer business;business in the United
States; and a copper interest in Chile. In addition, the stock of a U.S. oil
and gas subsidiary was exchanged with Pennzoil Company for 15,750,00031,500,000 shares of Chevron stock, a
transaction valued at $1.1 billion. The
FS-4
combination of these and other smaller
sales resulted in after-tax gains of $757 million. In 1991, sales of producing properties in the United States,
Oman and Spain; non-producing properties in the United Kingdom; certain U.S.
geothermal properties; an agricultural chemicals interest, together with the
company's share of the gain on an asset sale by its Caltex affiliate,
resulted in net gains of $149 million.
RESTRUCTURINGS AND REORGANIZATIONS charges in 1993 amounted to $554 million,
primarily the second quarter provision to restructure Chevron's U.S.
refining and marketing business. This charge, totaling $543 million, was
composed primarily of a write-down of the refineries' facilities and related
inventories to their estimated realizable values. Also included in the
charges were provisions for environmental site assessments and employee
severance. The company has taken into account probable environmental cleanup
obligations in estimating the realizable value of the refineries.
Responsibility for these obligations will be negotiated with potential
buyers. In 1992, Chevron recorded a net charge of $40 million associated
with restructuring and work-force reductions - provisions of $105 million
for work-force reductions were offset by $65 million of pension settlement
gains in connection with the company's enhanced early retirement program.
During 1991, charges of $185 million were recorded for the reconfiguration
of the Port Arthur refinery and companywide work-force reductions.
PRIOR-YEAR TAX ADJUSTMENTS are generally the result of issues in open tax
years being settled with taxing authorities or being re-evaluated by the
company as a result of new developments. Also, adjustments are required
for the effect on deferred income taxes of changes in statutory tax rates.
ENVIRONMENTAL REMEDIATION PROVISIONS pertain to estimated future costs for
environmental remediation programs at certain of the company's U.S. service
stations, marketing terminals, refineries, chemical plants and other
locations; divested operations in which Chevron has liability for future
remediation costs; and sites, commonly referred to as Superfund sites, for
which the company is a PRP. In addition to an amount included in the 1993
restructuring charge discussed above, such provisions amounted to $90
million in 1993, $44 million in 1992 and $160 million in 1991.1992.
ASSET WRITE-OFFS AND REVALUATIONS in 1993 were comprised of certain U.S.
refinery assets, U.S. and Canadian production assets, and miscellaneous
corporate assets. Asset write-offs in 1992 consisted of a $110 million
write-down of the company's Canadian Beaufort Sea oil properties and a net $23 million
charge related to certain U.S. refining, marketing and chemical fertilizer
assets.
CertainENVIRONMENTAL 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. In addition to environmental
remediation and cleanup costs included in the 1994 and 1993 restructuring
charges discussed below, provisions for environmental remediation amounted to
$304 million in 1994, $90 million in 1993, and $44 million in 1992.
RESTRUCTURINGS AND REORGANIZATIONS charges in 1994 were a net $45 million
addition to the $543 million charge provided in 1993 to restructure the
company's U.S. refining and marketing business. The 1994 adjustment included $6
million applicable to the effect of the restructuring on the company's
chemicals operations. The adjustment also included 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.
The 1993 charge was composed primarily of a write-down of the company's
Philadelphia and Port Arthur refinery assetsfacilities 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.
The Philadelphia refinery was sold in August 1994 and the Port Arthur refinery
was sold in February 1995. At year-end 1994, the reserve balance of $24$715
million, were written offbefore tax, was comprised of $491 million applicable to the loss on
the Port Arthur facilities and inventories and $224 million for retained future
Port Arthur environmental cleanup obligations. Additional Port Arthur
environmental reserves had been established prior to the decision to sell the
refinery.
In 1992, Chevron recorded a net charge of $40 million associated with
restructuring and work-force reductions in 1991.connection with the company's
enhanced early retirement program.
LIFO INVENTORY GAINS ANDLIQUIDATION LOSSES result from the reduction of inventories in
certain inventory pools valued under the Last-In, First-Out (LIFO) accounting
method. LIFO losses decreased 1993 net income in 1994, 1993 and 1992 by $10 million,
$46 million and 1992 net income $26 million. However, drawdowns of LIFO-valuedmillion, respectively, as inventories increased net income in 1991 by $16 million as low-cost inventories, relative
towere liquidated at
higher than then-current costs, were liquidated.costs. These amounts include the company's equity
share of Caltex LIFO inventory effects. Chevron's consolidated petroleum
inventories were 99 million barrels at year-end 1994 and 1993 and 105 million
barrels at year-end 1992 and 121 million barrels at year-end 1991.1992.
OTHER SPECIAL ITEMS in 1994 included charges for litigation and regulatory
settlements of $31 million, which were partially offset by a casualty insurance
recovery of $20 million. In 1993, included net additions of $70 million to reserves for
various litigation and regulatory issues and a one-time cash bonus award to
employees totaling $60 million, were partially offset by a favorable inventory
adjustment of $16 million. In 1992, insurance recoveries and chemical products
licensing agreements of $76 million were partially offset by $11 million of net
additions to reserves for various litigation and regulatory issues.
In 1991, additions of $35 million were made to
litigation and regulatory reserves.FS-5
RESULTS OF OPERATIONS. StrongResults for 1994 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 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 in its U.S. operations, particularly in the first
half of the year, that further reduced earnings. Chemicals operations, however,
were very strong, benefiting from improved industry fundamentals and the
restructuring and cost reduction programs undertaken in recent years.
In 1993, compared with 1992, strong worldwide refined product sales margins and
higherhigh U.S. natural gas prices mitigated the effects of lower crude oil prices in 1993, but the most important contributorprices.
Another contributing factor to the company's improved operating performance in
1993 was the large reduction in its operating and administrative costs. Also,
lower interest and exploration expenses helped earnings. Chemicals operations
continuedwere at depressed levels.
Similar to 1993, the increaselevels in 1992 operating earnings from 1991 levels
reflected reduced operatingboth years, reflecting continued industry
overcapacity and administrative costs, higher U.S. natural
gas prices and improved U.S. refined product sales margins. These benefits
were partly offset by lower earnings in international refining and marketing
andweak worldwide chemicals operations as weak global economic conditions held
down product prices, shrinking sales margins.
FS-5
economies.
SALES AND OTHER OPERATING REVENUES were $36.2$35.1 billion, down from $36.2 billion
in 1993 and $38.2 billion in 1992 and $38.1 billion in 1991.1992. Revenues declined from 19921993 and 19911992 levels
primarily due to lower prices for crude oil, natural gas and refined products
prices
partly offsettogether with lower refined product sales volumes. These factors also accounted
for corresponding declines in PURCHASED CRUDE OIL AND PRODUCTS. The decline in
total revenues was partially mitigated by higher natural gas prices.
The $.6 billion decline inchemicals revenues and
gasoline excise tax collections.
OTHER INCOME in 1993 was dueall years included net gains resulting from the disposition of
non-core assets, which caused other income to lower asset sales
gains.fluctuate from year to year.
OPERATING, SELLING AND ADMINISTRATIVE EXPENSES, adjusted for special items,
declined significantly as a
result of$150 million in 1994. Annual operating costs in 1994 were over $1
billion less than in 1991, the company's extensive cost-reduction programs initiatedbase measurement year set when the company
launched its cost reduction program in early 1992. Operating expenses in 1994
included unanticipated costs associated with unscheduled refinery shutdowns and
administrative costs in 1993, adjusted for
special items, declined $358 million from 1992. Coupled withmaintenance, as well as other refinery operating problems. Although a portion
of the $512
millioncost reduction in 1992 from 1991 levels,is a result of operations disposed of over the two-year reduction in costs
totaled $870 million, an 11 percentyears, the
bulk of the decrease from 1991. The company believes
it has achievedis due to a significant reduction to the company's ongoing
cost structure. Reported selling, general and administrative expenses in its cost structure and that most1994
included the reversal of $319 million of accrued interest reserves on federal
income taxes payable resulting from the cost savings will be sustainable.
Millionscompany's settlement with the IRS of
dollarsnine open tax years, 1979 through 1987.
MILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Reported Operating Expenses* $6,314 $6,267 $6,145 $6,933
Reported Selling, General
and Administrative Expenses 963 1,530 1,761
1,704
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operational Costs 7,277 7,797 7,906 8,637
Eliminate Special Charges Before Tax (161) (531) (282)
(501)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Adjusted Ongoing Operational Costs $7,116 $7,266 $7,624
$8,136
=============================================================================
*Operations are charged at market rates for consumption of the company's own
fuel. These "costs" are eliminated in the consolidated financial statements.
For cost performance measurement, such costs are included and amounted to==============================================================================
* OPERATIONS ARE CHARGED AT MARKET RATES FOR CONSUMPTION OF THE COMPANY'S OWN
FUEL. THESE "COSTS" ARE ELIMINATED IN THE CONSOLIDATED FINANCIAL STATEMENTS.
FOR COST PERFORMANCE MEASUREMENT, SUCH COSTS ARE INCLUDED AND AMOUNTED TO
$1,027, $1,017 AND $1,251 and $1,272 inIN 1994, 1993 AND 1992, and 1991, respectively.RESPECTIVELY.
TAXES on income were $1.1 billion in 1994, $1.2 billion in 1993, and $1.3
billion in 1992, and $959
million in 1991, equating to effective income tax rates of 39.6 percent, 47.9
percent, 36.2 percent and 42.636.2 percent for each of the three years, respectively. The lower
effective tax rate for 1994 is attributable to the effect of favorable
prior-year tax adjustments resulting from a global settlement with the Internal
Revenue Service for the years 1979 through 1987, which included the reversal of
excess interest reserves with little associated tax effect. The increase in the
1993 tax rate from 1992 levels is due primarily to unfavorable prior-year tax
adjustments, including an increase in deferred income taxes resulting from the
1one percent increase in the U.S. corporate income tax rate. The lower effective tax1992 rate
for 1992 is primarily attributable
toincluded the effect of a low overall tax cost on property dispositions, primarily the tax-free exchange, which resulted in a large book gain
with Pennzoil. Partially offsetting these effects were
lower favorable prior-yearno associated tax adjustments in 1992 and proportionately
lower equity affiliate income that is recorded on an after-tax basis. The
1991 effective tax rate benefited from favorable prior-year tax adjustments.cost.
CURRENCY TRANSACTIONS increaseddecreased net income $64 million in 1994 compared with
increases of $46 million in 1993 and $90 million in 1992 compared with a decrease of $4 million in 1991.1992. These amounts include
the company's share of affiliates' currency transactions. The gainloss on currency
transactions in 19931994 resulted primarily from fluctuations in the value of Nigerian currencythe
Australian and Philippine currencies relative to the U.S. dollar. In 1993,
gains resulted from fluctuations in the currency of Nigeria. In 1992, gains
resulted from fluctuations in the currencies inof the United Kingdom, Canada,
Australia and Nigeria.
FS-6
RESULTS BY MAJOR OPERATING AREAS
Millions of dollarsMILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Exploration and Production
United States $ 518 $ 566 $1,043
$ 285
International 539 580 594
717
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Exploration and Production 1,057 1,146 1,637
1,002
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Refining, Marketing and Transportation
United States 40 (170) 297
(153)
International 239 252 111
486
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Refining, Marketing and Transportation 279 82 408
333
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Petroleum 1,336 1,228 2,045
1,335
Chemicals 206 143 89 151
Coal and Other Minerals 111 44 198 7
Corporate and Other 40 (150) (122)
(200)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect
of Changes in Accounting Principles $1,693 $1,265 $2,210 $1,293
Cumulative Effect of Changes
in Accounting Principles - - (641)
-
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Net Income $1,693 $1,265 $1,569
$1,293
=============================================================================
FS-6
==============================================================================
SPECIAL ITEMS BY MAJOR OPERATING AREAS
Millions of dollarsMILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Exploration and Production
United States $ (66) $(136) $413
$(46)
International 20 (61) 14
138
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Exploration and Production (46) (197) 427
92
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Refining, Marketing and Transportation
United States (285) (725) (53)
(335)
International (10) 1 (3)
133
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Refining, Marketing and Transportation (295) (724) (56)
(202)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Petroleum (341) (921) 371
(110)
Chemicals (9) 112 53 34
Coal and Other Minerals 48 - 159 (4)
Corporate and Other 324 (74) 68
14
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Special Items Included in Net Income $ 22 $(883) $651 $(66)
=============================================================================$ 651
==============================================================================
U.S. EXPLORATION AND PRODUCTION earnings in 1993,1994, excluding special items, improved 11were
down 17 percent from 1993 levels and down 7 percent from 1992 levelsresults.
MILLIONS OF DOLLARS 1994 1993 1992
------------------------------------------------------------------------------
Earnings Excluding Special Items $584 $702 $ 630
------------------------------------------------------------------------------
Prior-Year Tax Adjustments - (40) 5
Asset Dispositions - (54) 419
Asset Write-Offs and more than doubled from 1991 results.
In 1993, the effects ofRevaluations - (13) -
Environmental Remediation Provisions (51) (13) (2)
Restructurings and Reorganizations - (2) (35)
LIFO Inventory (Losses) Gains (4) 1 5
Other (11) (15) 21
------------------------------------------------------------------------------
Total Special Items (66) (136) 413
------------------------------------------------------------------------------
Reported Earnings $518 $566 $1,043
==============================================================================
Operationally, lower average crude oil and natural gas prices and lower crude
oil and natural gas production volumes were more than offset by lower operating
expenses and higher natural gas prices. Also, natural gas contract
settlementslevels in 1994 contributed to the earnings improvement. Whiledecline from 1993.
Crude prices were sharply lower in the last half of 1993, but recovered to the
point that in December 1994, the company's average realizations were $3.12 per
barrel higher than in December 1993. Overall, however, the company's average
crude oil realization declined $1.92for 1994 decreased $.72 per barrel to $14.58 in 1993,
average natural$13.86. Natural gas
prices increased to $1.99fell throughout 1994, averaging $1.77 per thousand cubic feet compared with $1.70 for 1992. Becausethe
year, down $.22 from the 1993 average price. Natural gas accounts for almost
half of the company's extensive cost cutting
efforts and disposition of higher-costU.S. oil and gas properties, 1993
earnings per equivalent barrel, excluding special items, increased $.18 to
$.95.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Earnings Excluding Special Items $702 $ 630 $331
- -----------------------------------------------------------------------------
Asset Dispositions (54) 419 (49)
Prior-Year Tax Adjustments (40) 5 (50)
Environmental Remediation Provisions (13) (2) (3)
Asset Write-Offs and Revaluations (13) - -
Restructurings and Reorganizations (2) (35) -
LIFO Inventory Gains 1 5 1
Other (15) 21 55
- -----------------------------------------------------------------------------
Total Special Items (136) 413 (46)
- -----------------------------------------------------------------------------
Reported Earnings $566 $1,043 $285
=============================================================================production volumes.
Cost cutting efforts and higher natural gas prices were also the major factors in
1992's1993's earnings improvement over 1991,from 1992, offsetting lower crude oil prices and
lower production levels.
Exploration expense declined over
the three-year period, and depreciation expense dropped in line with lower
production volumes.
Net liquids production for 19931994 averaged 394,000369,000 barrels per day, down 6
percent from 394,000 in 1993 and down 15 percent from 432,000 barrels per day
in 1992 and 454,000 in 1991.1992. Net natural gas production for 1993 waspro-
FS-7
duction in 1994 averaged about 2.1 billion cubic feet per day, about the same
level as 1993 but down from approximately 2.3 billion cubic feet per day in 1992 and 1991.1992. The
production declines resulted from producing property sales, in liquids and
natural gas were due primarilyconnection with
the company's decision to the dispositionconcentrate its efforts on a core portfolio of about
400 producing properties, in
late 1992.and from normal field declines.
INTERNATIONAL EXPLORATION AND PRODUCTION earnings in 1994, excluding special
items, improvedwere down 19 percent from 1993 levels and down 11 percent over the levels offrom 1992
results, due primarily to foreign currency effects. In 1994, foreign exchange
losses were $28 million, whereas in 1993 and 1991 when crude oil prices
were much higher. Because of the terms of the operating agreements in some
of the countries in which the company produces, fluctuations in crude oil
prices have less impact on earnings than in the United States. Contributing
factors1992, foreign exchange gains
amounted to the higher 1993 earnings included lower operating expenses,
lower exploration expenses$57 million and higher production volumes.
Millions of dollars$80 million, respectively.
MILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Earnings Excluding Special Items $519 $641 $580
$579
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Prior-Year Tax Adjustments 20 (63) (27)
45
Asset Dispositions - 29 166 93
Asset Write-Offs and Revaluations - (19) (110) -
Restructurings and Reorganizations - (2) (9) -
LIFO Inventory Losses - (1) (1)
Other -
Other (5) (5)
-
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Special Items 20 (61) 14
138
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Reported Earnings $539 $580 $594
$717
=============================================================================
FS-7
Both net liquids==============================================================================
Operationally, higher production volumes did not fully offset the effect of
lower average crude oil and natural gas production have increased steadily over the
three-year period. Ongoing development projectsprices in Indonesia1994. The company's average
international liquids prices, including equity in affiliates, declined to
$14.86 per barrel from $16.09 in 1993 and West
Africa, the mid-1992 start up of production$17.93 in Papua New Guinea1992. Average natural gas
prices were $1.84 per thousand cubic feet in 1994 compared with $2.08 and the
second quarter$2.07
in 1993 start up of the Tengiz joint venture all contributed to
the increase inand 1992, respectively. In 1994, net liquids production. Increases in netproduction, including
production from equity affiliates, increased 12 percent over 1993 to 624,000
barrels per day, and was up 22 percent from 1992 production levels. Net natural
gas production have occurred primarilyvolumes also increased in Australia's North West Shelf Project1994, up 16 percent from 1993 to 546
million cubic feet per day and in Canada. Net liquids production in 1993 was 10up 18 percent higher than in
1991,from 1992 levels. Production of
crude oil and net natural gas production increased 5 percent over this same
three-year period. Foreign currency transaction gains were $57 million in
1993, compared with $80 million in 1992 and $19 million in 1991.has been increasing steadily since the late 1980s,
reflecting the company's strategy of growing its international operations.
SELECTED OPERATING DATA
1994 1993 1992
1991
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
U.S. EXPLORATION AND PRODUCTION
Net Crude Oil and Natural Gas
Liquids Production (MBPD) 369 394 432 454
Net Natural Gas Production (MMCFPD) 2,085 2,056 2,313 2,359
Natural Gas Liquids Sales (MBPD) 215 211 194 175
Revenues from Net Production
Crude Oil ($/bbl.) $13.86 $14.58 $16.50 $17.10
Natural Gas ($/MCF) $ 1.77 $ 1.99 $ 1.70 $ 1.53
INTERNATIONAL EXPLORATION AND PRODUCTION (1)
Net Crude Oil and Natural Gas
Liquids Production (MBPD) 624 556 512 504
Net Natural Gas Production (MMCFPD) 546 469 463 447
Natural Gas Liquids Sales (MBPD) 34 37 33 29
Revenues from Liftings
Liquids ($/bbl.) $14.86 $16.09 $17.93 $18.36
Natural Gas ($/MCF) $ 1.84 $ 2.08 $ 2.07 $ 2.28
U.S. REFINING AND MARKETING
Gasoline Sales (MBPD) 615 652 646 632
Other Refined Product Sales (MBPD) 699 771 824 812
Refinery Input (MBPD) 1,213 1,307 1,311 1,278
Average Refined Product Sales Price ($/bbl.) $24.37 $25.35 $25.96 $26.40
INTERNATIONAL REFINING AND MARKETING (1)
Refined Product Sales (MBPD) 934 923 859 823
Refinery Input (MBPD) 623 598 543 517
CHEMICALS SALES AND OTHER OPERATING REVENUES (2)
United States $3,079 $2,694 $2,929
$3,217
International 648 602 566
550
--------------------------------------------------------------
Worldwide $3,727 $3,296 $3,495
$3,767
============================================================================================================================================================
(1) Includes equity in affiliates for all years. Per unit revenues from net
production forINCLUDES EQUITY IN AFFILIATES. REFINERY INPUT IN 1992 and 1991 have been restated to include equity
affiliates. Refinery input in 1993 includes South Africa, where local
government restrictions prohibited this disclosure inDOES NOT INCLUDE
SOUTH AFRICA WHERE LOCAL GOVERNMENT RESTRICTIONS PROHIBITED DISCLOSURE OF
REFINERY INPUT IN 1992 and prior
years.AND PRIOR YEARS.
(2) Millions of dollars. Includes sales to other Chevron companies.MILLIONS OF DOLLARS. INCLUDES SALES TO OTHER CHEVRON COMPANIES.
MBPD=thousands ofthousand barrels per day; MMCFPD=millions ofmillion cubic feet per day;
bbl.=barrel; MCF=thousands ofthousand cubic feet
FS-8
U.S. REFINING AND MARKETING earnings, excluding special items, improved 59declined 41
percent from 1993's strong results and were down 7 percent from 1992 levels.
Sales volumes in 1994 declined 8 percent from 1993 levels, largely due to the
sale of the company's Philadelphia refinery in August.
MILLIONS OF DOLLARS 1994 1993 1992
------------------------------------------------------------------------------
Earnings Excluding Special Items $ 325 $ 555 $350
------------------------------------------------------------------------------
Prior-Year Tax Adjustments - (38) 7
Asset Dispositions - (1) -
Asset Write-Offs and more than tripled from 1991 results whenRevaluations - (25) (31)
Environmental Remediation Provisions (249) (77) (42)
Restructurings and Reorganizations (39) (543) (1)
LIFO Inventory Gains (Losses) 3 (44) (22)
Other - 3 36
------------------------------------------------------------------------------
Total Special Items (285) (725) (53)
------------------------------------------------------------------------------
Reported Earnings $ 40 $(170) $297
==============================================================================
Sales margins were lower in 1994 compared with 1993. Refined products prices
were weak demand andas ample supplies depressed refined products margins.
Although averagecreated a highly competitive market. The company
also experienced unscheduled refinery downtime and other refinery operating
problems early in 1994 that increased operating expenses and required more
expensive third-party product pricespurchases to supply the company's marketing
system.
Compared with the previous year, the strong earnings in 1993 declined from the prior year,reflected lower
crude oil prices and lower operating costs, and stronger markets resultedresulting in higher average sales
margins compared withthan in 1992. Late in 1993, margins
declined somewhat as product prices fell faster than crude oil prices. Total product sales volumes declined 3 percent from 1992's level,1992
levels, although sales of higher-valued motor fuels increased about 1 percent.
FS-8
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Earnings Excluding Special Items $ 555 $350 $ 182
- -----------------------------------------------------------------------------
Restructurings and Reorganizations (543) (1) (83)
Environmental Remediation Provisions (77) (42) (157)
LIFO Inventory (Losses) Gains (44) (22) 10
Prior-Year Tax Adjustments (38) 7 (33)
Asset Write-Offs and Revaluations (25) (31) (24)
Asset Dispositions (1) - -
Other 3 36 (48)
- -----------------------------------------------------------------------------
Total Special Items (725) (53) (335)
- -----------------------------------------------------------------------------
Reported Earnings $(170) $297 $(153)
=============================================================================
Industry conditions and operating problems that plagued the company's U.S.
refining and marketing business in 1991 largely turned around in 1992.
Cost-cutting programs, operating efficiencies generated by downsizing the
Port Arthur refinery and improved operations at other refineries all
contributed to the improved earnings in 1992. Sales of refined products
increased 2 percent over 1991 levels. Refinery operating problems in 1991
reduced product yields while increasing maintenance costs and the requirement
for outside product purchases.
INTERNATIONAL REFINING AND MARKETING earnings include international marine
resultsoperations and equity earnings of the company's Caltex Petroleum Corporation
affiliate. Excluding special items, 1994 earnings were about level with 1993,
earningsbut more than doubled from the
weak level of 1992, but were still below 1991's strong results.
Millions of dollars1992.
MILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Earnings Excluding Special Items $249 $251 $114
$353
- -----------------------------------------------------------------------------
Asset Dispositions 13 - 59------------------------------------------------------------------------------
Prior-Year Tax Adjustments - (4) 7
76
LIFO Inventory Losses (3) (9) (2)Asset Dispositions - 13 -
Asset Write-Offs and Revaluations - (1) - -
Restructurings and Reorganizations - (1) (1)
LIFO Inventory Losses (10) (3) (9)
Other -
Other (3) -
-
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Special Items (10) 1 (3)
133
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Reported Earnings $239 $252 $111
$486
- -----------------------------------------------------------------------------
International downstream operations improved significantly as product sales
margins recovered==============================================================================
Earnings in 1994 reflected lower results from the prior year's weak levels in all the company's
marketing areas - Canada, the United Kingdom
operations and inseveral of the Caltex major areas of operations, especially South Africa and Singapore. Lower crude oil and
operating costs coupled with stronger markets boostedparticularly
refining operations in Bahrain. United Kingdom operations were impacted by weak
sales margins in 1993.
Also,and the company's internationaleffects of an explosion and fire at the cracking facility
that manufactures its gasoline. Shipping and trading earnings also declined. On
the other hand, Canadian results improved significantly.
Equity earnings of Caltex were $227 million, $180 million and $259 million
for 1993, 1992, and 1991, respectively. In 1993, earnings were reduced $52
million for Chevron's share of Caltex ongoing adjustments to the carrying
value of its petroleum inventories to reflect market values; earnings in
1991 included a special gain of $59 million from an asset sale. Total refined
producton higher sales volumes increased 7 percent from 1992 and 12 percent from 1991.
Caltex volumes increased 6 percent in each year, continuing its average
annual 6 percent growth of the past several years.
Earningsstronger
markets. Results in 1992 fell from 1991 levels asreflected weak global economic conditions that held
down product prices, shrinking sales margins in all the company's areas of
operations.
Sales volumes for 1994 increased slightly over 1993 levels as a 5 percent
increase in marketing sales was mostly offset by a decline in the company's
trading sales volumes; however, 1994 volumes were up nearly 9 percent from 1992
due to continued demand growth in the Caltex areas of operations. Caltex
volumes, excluding transactions with Chevron, increased 4 percent from 1993 and
6 percent from 1992 to 1993, continuing its growth of the past several years.
Equity earnings of Caltex were $210 million, $227 million and $180 million for
1994, 1993, and 1992, respectively. Between 1994 and 1993, there was a
favorable swing of $69 million resulting from inventory adjustments and an
unfavorable impact of $43 million caused by foreign currency transactions. In
1991, operating1994, Chevron's share of annual Caltex earnings benefited $17 million from
strong sales margins,
particularlyupward adjustments to the carrying value of its petroleum inventories to
reflect market values after a 1993 write-down of $52 million. Caltex foreign
currency transactions were losses of $27 million in the first quarter1994 but were gains of that year when product prices did not
fall as quickly as crude oil prices$16
million and $21 million in the aftermath1993 and 1992, respectively.
Total international refining and marketing foreign currency transaction losses
were $19 million in 1994, compared with gains of the Persian Gulf War.$2 million in 1993 and $13
million in 1992.
FS-9
CHEMICALS earnings, excluding special items, fell 14 percentwere up dramatically from 1993 and
1992 levelslevels. The improving U.S. economy reduced industry overcapacity,
resulting in higher sales volumes at stronger prices, and 74 percentreversing 5 years of
successively lower operating earnings caused by industry over-expansion just
prior to a downturn in the U.S. economy. Restructurings and cost reduction
programs undertaken in recent years positioned the company's chemicals
businesses to benefit from 1991 results.
Millionsthe improved industry conditions. Operating results
were strong in all the company's divisions - additives, aromatics and,
especially, olefins. Olefins results would have been even higher had a major
plant not been shut down for over a month because of dollarsdamage caused by flooding
in southeast Texas in mid-October. The shutdown resulted in lost earnings and
higher operating and repair expenses.
MILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Earnings Excluding Special Items $215 $ 31 $36
$117
- -----------------------------------------------------------------------------
Asset Dispositions 130 13 27------------------------------------------------------------------------------
Prior-Year Tax Adjustments - (5) (2)
Asset Dispositions - 130 13
Asset Write-Offs and Revaluations - - 8
Environmental Remediation Provisions (4) - -
Restructurings and Reorganizations (6) (5) (1) -
LIFO Inventory Gains 1 1 7
Asset Write-Offs and Revaluations1
Other - 8 -
Other (9) 34
-
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Special Items (9) 112 53
34
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Reported Earnings $206 $143 $89
$151
- -----------------------------------------------------------------------------
Results in the company's chemicals business reflected the continued depressed
state of the commodity chemicals industry. The industry has suffered several
years of depressed prices and demand due to overcapacity coupled with weak
worldwide economies. In early 1994, the company announced additional measures
to improve profitability and competitiveness of its chemicals business,
including work-force reductions, cost reductions and reorganizations.
Provisions for the expected cost of these measures were recorded in 1993.
FS-9
In 1992, in addition to industry conditions, plant shutdowns for maintenance
and Hurricane Andrew also contributed to the earnings decline from 1991.
Foreign currency transactions, mainly related to Brazil, resulted in losses
of $10 million in 1993 and 1992 compared with losses of $6 million in 1991.==============================================================================
COAL AND OTHER MINERALS earnings, excluding special items, improved 13increased 43 percent
from 1993 and 62 percent from 1992 levels and quadrupled from 1991 results. Operationally, a decline in coal earnings for 1993 was more than offset by
lower non-coal exploration expenses, due to prior-year property dispositions.
Annualimproved as
coal sales in 1993 exceeded 20margins were slightly higher. Sales tonnage, at 20.4 million tons,
forwas down slightly from the first time,prior year, but margins declined on lower prices.
Millionsup from 16.5 million tons in 1992.
Also, earnings benefited from the absence of dollars1993 and 1992 losses from non-coal
minerals activities.
MILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Earnings Excluding Special Items $ 63 $44 $ 39
$11
- -----------------------------------------------------------------------------
Asset Dispositions 5 159 19------------------------------------------------------------------------------
Prior-Year Tax Adjustments - (2) -
(4)Asset Dispositions 48 5 159
Other - (3) -
(19)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total Special Items 48 - 159
(4)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Reported Earnings $111 $44 $198
$ 7
=============================================================================
Operating earnings in 1992 were up more than threefold from 1991 levels,
primarily from higher coal production that increased 10 percent over the
prior year. Additionally, expenses in non-coal minerals operations were
lower as the company continued its withdrawal from those businesses. The
pending sale of lead and zinc deposits in Ireland is expected to be
completed in 1994. The sale will result in a gain.==============================================================================
CORPORATE AND OTHER activities include interest expense, interest income on
cash and marketable securities, real estate and insurance operations, and
other activities of a corporate nature not allocated to the business segments.center costs.
Excluding the effects of special items, the lower costscorporate and other charges in 1994
were $284 million, compared with net charges of $76 million in 1993 and $190
million in 1992.
MILLIONS OF DOLLARS 1994 1993 1992
primarily reflected------------------------------------------------------------------------------
Earnings Excluding Special Items $(284) $ (76) $(190)
------------------------------------------------------------------------------
Prior-Year Tax Adjustments 324 22 82
Asset Write-offs and Revaluations - (13) -
Restructurings and Reorganizations - (1) 7
Other - (82) (21)
------------------------------------------------------------------------------
Total Special Items 324 (74) 68
------------------------------------------------------------------------------
Reported Earnings $ 40 $(150) $(122)
==============================================================================
In 1994, the continuedcompany changed its method of distributing certain corporate
expenses to its business segments. As a result, corporate and other charges for
1994 included $190 million that, under the previous method, would have been
allocated to the business segments. This change had no net income effect.
Amounts that would have been allocated in 1994 to the company's major operating
areas under the prior method are as follows: U.S. Exploration and Production -
$34 million; U.S. Refining and Marketing - $32 million; International
Exploration and Production - $63 million; International Refining and Marketing
- $48 million; Chemicals - $10 million; and Coal and Other Minerals - $3
million.
Higher interest costs in 1994 resulted from the combined effect of higher debt
levels and higher interest rates than in 1993. The decline in 1993 costs
relative to 1992 reflects an $84 million after-tax reduction in interest
expense, due to lower average interest rates and in 1993, lower average debt levels.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Results Excluding Special Items $ (76) $(190) $(214)
- -----------------------------------------------------------------------------
Prior-Year Tax Adjustments 22 82 139
Asset Write-offs and Revaluations (13) - -
Restructurings and Reorganizations (1) 7 (102)
Other (82) (21) (23)
- -----------------------------------------------------------------------------
Total Special Items (74) 68 14
- -----------------------------------------------------------------------------
Reported Earnings $(150) $(122) $(200)
=============================================================================
Reported earnings in 1992 and 1991 included provisions of $41 million and
$102 million for a companywide, voluntary enhanced early retirement program.
In 1992, $65 million of pension settlement gains were recognized in
connection with the program. These amounts were considered to be corporate
items not properly allocable to the company's business segments.
LIQUIDITY AND CAPITAL RESOURCES. Cash, cash equivalents and marketable
securities increased $321decreased $710 million to $2.0$1.3 billion at year-end 1993.1994. Cash
provided by operating activities increased $307 milliondecreased $1.3 billion in 19931994 to $4.2$2.9
billion, compared with $4.2 billion in 1993 and $3.9 billion in 1992 and $3.3 billion in
1991.1992. The 1993 increase1994
decrease reflects higherlower operational earnings, adjusted for non-cash charges,
and decreasedincreased working capital requirements.requirements, including the payment of $675
million to the Internal Revenue Service for the settlement of substantially all
open tax issues for the nine
FS-10
years 1979 through 1987. Cash from operations, and proceeds from asset sales, an
increase in overall debt levels and the draw-down of cash balances were used to
fund the company's capital expenditures and dividend payments to stockholders and retirement of
debt.stockholders.
AT YEAR-END 1993,1994, THE COMPANY CLASSIFIED $1.9$1.8 BILLION OF SHORT-TERM OBLIGATIONS
AS LONG-TERM DEBT. Settlement of these obligations, primarilyconsisting of commercial
paper, is not expected to require the use of working capital in 19941995 because
the company has the intent and the ability, as evidenced by revolving credit
arrangements, to refinance them on a long-term basis. CommercialThe company's practice
has been to continually refinance its commercial paper, not reclassified to long-term
debt also is intendedmaintaining levels it
believes to be reissued continuously or refinanced on a
long-term basis.appropriate.
ON DECEMBER 31, 1993,1994, CHEVRON HAD $3.6$4.4 BILLION IN COMMITTED CREDIT FACILITIES
WITH VARIOUS MAJOR BANKS. These facilities support commercial paper borrowing
and can also can be used for general credit requirements. No borrowings were
outstanding under these facilities during the year or at year-end 1993.
FS-10
1994. 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 approximately $1.05 billion$700 million of debt
securities.
DURING 1993, THE COMPANY PREPAID TWO FIXED-TERM U.S. PUBLICCOMPANY'S DEBT ISSUES
TOTALING $600 MILLION. In earlyAND CAPITAL LEASE OBLIGATIONS TOTALED $8.142 BILLION AT
DECEMBER 31, 1994, an additional $200up $604 million of
fixed-term U.S. public debt was called for early repayment. The debt issues
were refinanced with short-term commercial paper. The company has pursued an
aggressive debt management strategy focused on short-term and variable-rate
financing. This strategy, together with the general decline in interest
rates, has reduced the company's annual average before-tax interest rate
from 7.6 percent in 1991, to 5.7 percent in 1992 and to 4.6 percent in 1993.
The variable-rate component of total debt was 68 percent at the end of 1993.
Chevron's total debt was $7.538 billion at year-end 1993, down $3031993. The
increase is primarily from $466 million from $7.841 billion at year-end 1992.of additional net short-term
borrowings, largely the issuance of commercial paper, the issuance of $350
million of 7.45 percent notes due in the year 2004 and $65 million in capital
lease obligations associated with the delivery of a new vessel. These increases
were partially offset by the first quarter repayment of $200 million of 7.875
percent public debt originally due March 1, 1997. The company also retired $40
million of debt related to the Employee Stock Ownership Plan in January 1994.
THE COMPANY'S FUTURE DEBT LEVEL IS PRIMARILY DEPENDENT ON ITS CAPITAL SPENDING
PROGRAM AND ITS BUSINESS OUTLOOK. While the company does not currently expect
its debt level to increase significantly during 1994,1995, it believes it has
substantial borrowing capacity to meet unanticipated cash requirements.
In light of currently low crude oil prices, the company intends
to monitor its capital spending and may make adjustments as the year
progresses.
FINANCIAL RATIOS
1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------
Current Ratio 0.8 0.90.8 0.9
Interest Coverage Ratio 7.6 7.4 8.2 5.1
Total Debt/Total Debt Plus Equity 35.8% 35.0% 36.4%
34.3%
===============================================================================================================================================
The CURRENT RATIO is the ratio of current assets to current liabilities at
year-end. Two items affect the current ratio negatively, which in the company's
opinion, do not affect its liquidity. Included in current assets in all years
are inventories valued on a LIFO basis, which at year-end 19931994 were lower than
current costs by $671$684 million. Also the company's practice of continually
refinancing its commercial paper, $3.2 billion classified as short-term at
year-end 1993, $2.5 billion1994, results in a large portion of commercial paper includedits short-term debt being
outstanding indefinitely. Chevron's interest coverage ratio increased in current liabilities is planned1994
due to be
refinanced continuously. Chevron'shigher income before tax. The INTEREST COVERAGE RATIO decreased in 1993
due to lower before-tax income. The interest coverage ratio is defined as
income before income tax expense, plus interest and debt expense and
amortization of capitalized interest, divided by before-tax interest costs. The
company's DEBT RATIO (total debt to total debt plus equity) decreased to
35.0 percent, due primarily to a net reduction inincreased slightly,
as total debt of $303 million.increased more than equity did year-to-year.
The company's senior debt is rated AA by Standard & Poor's Corporation and Aa2
by Moody's Investors Service. Chevron's U.S. commercial paper is rated A-1+A-1$PL
by Standard & Poor's and Prime-1 by Moody's, and Chevron's Canadian commercial
paper is rated R-1 (middle) by Dominion Bond Rating Service. All these ratings
denote high-quality, investment-grade securities.
IN JANUARY 1994, THE COMPANY INCREASED ITS QUARTERLY DIVIDEND 5 CENTS PER
SHARE TO $.925, AN ANNUALIZED RATE OF $3.70 PER SHARE, AND PROPOSED A
TWO-FOR-ONE SPLIT OF ITS ISSUED COMMON STOCK. Stockholders will be asked to
approve an increase in the number of authorized shares of common stock from
500 million to 1 billion to accommodate the split and also to approve the
stock split at the annual meeting on May 3, 1994.
CAPITAL AND EXPLORATORY EXPENDITURES
1993 1992 1991
- ---------------------------------- -------------------- ---------------------
Millions Interna- Interna- Interna-
of dollars U.S. tional Total U.S. tional Total U.S. tional Total
- -----------------------------------------------------------------------------
Exploration
and
Production $ 763 $1,599 $2,362 $ 792 $1,458 $2,250 $1,121 $1,408 $2,529
Refining,
Marketing and
Transportation 949 748 1,697 962 749 1,711 974 775 1,749
Chemicals 199 34 233 224 37 261 195 34 229
Coal and
Other Minerals 47 10 57 65 20 85 99 14 113
All Other 91 - 91 116 - 116 166 1 167
- -----------------------------------------------------------------------------
Total $2,049 $2,391 $4,440 $2,159 $2,264 $4,423 $2,555 $2,232 $4,787
- -----------------------------------------------------------------------------
Total
Excluding
Equity in
Affili-
ates $2,029 $1,710 $3,739 $2,136 $1,666 $3,802 $2,540 $1,749 $4,289
=============================================================================
FS-11
WORLDWIDE CAPITAL AND EXPLORATORY EXPENDITURES FOR 1993,1994, INCLUDING THE
COMPANY'S EQUITY SHARE OF AFFILIATES' EXPENDITURES, TOTALED $4.4$4.8 BILLION.
Expenditures for exploration and production accounted for 5357 percent of total
outlays in 1994, 53 percent in 1993 and 51 percent in 1992 and 53 percent in 1991. U.S.1992. International
exploration and production spending declinedincreased to 3271 percent of worldwide
exploration and production expenditures in 1994, up from 68 percent in 1993 down from 35and
65 percent in 1992, and 44 percent
in 1991, reflecting the company's increasingincreased focus on international
exploration and production activities.
FS-11
THE COMPANY PROJECTS 19941995 CAPITAL AND EXPLORATORY EXPENDITURES AT APPROXIMATELY
$4.9$5.1 BILLION, including Chevron's share of spending by affiliates. Excluding
affiliates, spending will be essentially flat at $3.7$3.9 billion. The 19941995 program
provides $2.4$2.7 billion in exploration and production investments, of which about
7570 percent isare for international projects.
The company is participating in several significant oil and gas development
projects. These projects include the development of the Hibernia field off the coast of
Newfoundland; the Tengiz project in Kazakhstan; steamsteam- and waterfloodwater-flood projects
in Indonesia; expansion of the North West Shelf liquefied natural gas project
in Australia; additionalcontinued development of the Britannia natural gas field in the
North Sea,
Nigeria and Angola; continuing enhanced oil recoverySea; expanded production projects in California;Angola; field development and
aexpanded exploration in Congo; new field development in Papua New Guinea; and
the Norphlet Trend natural gas development project in the Norphlet Trend in the Gulf of Mexico.
Refining, marketing and transportation expenditures are estimated at about $2.1$1.9
billion, with $1 billionabout $900 million of that planned for the U.S., including
upgrading U.S. refineries to produce reformulated gasolines needed to comply
with the Clean Air Act.Act and California Air Resources Board regulations. Most of
the balance will be focused on high growth Asia Pacific Rim countries where the
company's Caltex affiliate has several major refinery projects under way to
increase capacity and meet rising demand.demand, including continuing the construction of a new refinery in
Thailand and capacity expansion projects in Japan and Korea.
Projected spending also includes funds for the expansion of the linear
low-density polyethylene manufacturing plant at the Cedar Bayou, Texas,
chemicals facility.
CAPITAL AND EXPLORATORY EXPENDITURES
1994 1993 1992
----------------------------- ----------------------------- -----------------------------
INTER- INTER- INTER-
MILLIONS OF DOLLARS U.S. NATIONAL TOTAL U.S. NATIONAL TOTAL U.S. NATIONAL TOTAL
---------------------------------------------------------------------------------------------------------------------------------
Exploration and Production $ 807 $1,931 $2,738 $ 763 $1,599 $2,362 $ 792 $1,458 $2,250
Refining, Marketing and Transportation 885 890 1,775 949 748 1,697 962 749 1,711
Chemicals 109 29 138 199 34 233 224 37 261
Coal and Other Minerals 39 15 54 47 10 57 65 20 85
All Other 114 - 114 91 - 91 116 - 116
---------------------------------------------------------------------------------------------------------------------------------
Total $1,954 $2,865 $4,819 $2,049 $2,391 $4,440 $2,159 $2,264 $4,423
---------------------------------------------------------------------------------------------------------------------------------
Total Excluding Equity in Affiliates $1,927 $2,046 $3,973 $2,029 $1,710 $3,739 $2,136 $1,666 $3,802
=================================================================================================================================
QUARTERLY RESULTS AND STOCK MARKET DATA
Unaudited
1994 1993
1992
----------------------------------- -------------------------------------- Millions of dollars, except per-share amounts 4thQ 3rdQ 2ndQ 1stQ(1) 4thQ(1) 3rdQ(1) 2ndQ(1) 1stQ(1)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------
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 $8,927 $9,396 $8,702 $8,105 $8,778 $9,097 $9,413 $8,903 $ 9,912 $ 9,990 $9,468 $8,842
Equity in net income of affiliated
companies and other income 330 113 122 159 135 136 441 179
748 271 180 266
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES 9,257 9,509 8,824 8,264 8,913 9,233 9,854 9,082
10,660 10,261 9,648 9,108
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products,
operating and operatingother expenses 6,225 6,695 6,201 5,594 6,467 6,401 7,748 6,385
7,309 7,351 7,104 6,521
Depreciation, depletion and amortization 598 626 615 592 652 615 596 589 639 637 654 664
Taxes other than on income 1,406 1,405 1,403 1,345 1,303 1,219 1,227 1,137
1,193 1,282 1,247 1,177
Interest and debt expense 97 93 83 73 73 76 81 87
96 104 114 122
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS 8,326 8,819 8,302 7,604 8,495 8,311 9,652 8,198
9,237 9,374 9,119 8,484
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAX EXPENSE AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES931 690 522 660 418 922 202 884
1,423 887 529 624
INCOME TAX EXPENSE 308 265 265 272 124 502 152 383
335 420 214 284
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES(1) $ 623 $ 425 $ 257 $ 388 $ 294 $ 420 $ 50 $ 501
$1,088 $ 467 $ 315 $ 340
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES - - - - - - - (641)
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)(2) $ 294 $ 420 $ 50 $ 501 $1,088 $ 467 $ 315 $ (301)
=================================================================================================================================================================================================================================================================
PER SHARE OF COMMON STOCK - -------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES $0.91 $1.29 $0.15 $1.54 $3.30 $1.37 $0.92 $0.99
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES - - - - - - - (1.87)
- -------------------------------------------------------------------------------------------------------------------------------(2)
-----------------------------
NET INCOME (LOSS) PER SHARE(3) $0.91 $1.29 $0.15 $1.54 $3.30 $1.37 $0.92 $(0.88)
===============================================================================================================================SHARE $0.96 $0.65 $0.39 $0.60 $0.45 $0.64 $0.08 $0.77
=================================================================================================================================
DIVIDENDS PAID PER SHARE $0.875 $0.875 $0.875 $0.875 $0.825 $0.825 $0.825 $0.825
===============================================================================================================================$0.4625 $0.4625 $0.4625 $0.4625 $0.4375 $0.4375 $0.4375 $0.4375
=================================================================================================================================
COMMON STOCK PRICE RANGE - HIGH $98$46 1/2 $45 3/8 $97$49 3/16 $47 5/16 $49 3/8 $48 15/16 $45 7/16 $41 3/4
$90- LOW $41 $39 7/8 $41 1/4 $83 1/8 $74 1/4 $75$41 3/8 $7316 $41 3/4 $70 1/$40 5/8 - LOW 84 1/4 82 1/8 81 67$39 3/4 66 3/4 66 3/8 63 1/8 60 1/8
===============================================================================================================================$33 11/16
=================================================================================================================================
(1) To conform to the presentation adopted in the second quarter of 1993, the 1992 quarters and the 1993 first quarter have
been reclassified to net certain offsetting crude oil purchases and sales contracts. The reclassification had no effect
on net income.
(2) Special items included in net income.SPECIAL CREDITS (CHARGES)
INCLUDED IN NET INCOME. $ 45 $ 18 $ (5) $ (36) $ (221) $ (145) $ (515) $ (2)
$ 546 $ 57 $ (39) $ 87
(3) Quarterly amounts do not add to the annual earnings per share for 1992 because of changes in the number of outstanding
shares during the year.
- -------------------------------------------------------------------------------------------------------------------------------
The company's common stock is listed on the New York Stock Exchange (trading symbol:(2) PER-SHARE AMOUNTS FOR 1993 AND FIRST QUARTER 1994 HAVE BEEN RESTATED TO REFLECT A TWO-FOR-ONE STOCK SPLIT IN MAY 1994.
---------------------------------------------------------------------------------------------------------------------------------
THE COMPANY'S COMMON STOCK IS LISTED ON THE NEW YORK STOCK EXCHANGE (TRADING SYMBOL: CHV), as well as the Midwest;
Pacific; Vancouver; London; and Zurich, Basel and Geneva, Switzerland, stock exchanges. It also is traded on the Boston,
Cincinnati, Detroit and Philadelphia stock exchanges. As of February 10, 1994, stockholders of record numbered
approximately 144,000.
There are no restrictions on the company's ability to pay dividends. Chevron has made dividend payments to stockholders
for 82 consecutive years.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 28, 1995, STOCKHOLDERS OF RECORD NUMBERED APPROXIMATELY 141,000.
THERE ARE NO RESTRICTIONS ON THE COMPANY'S ABILITY TO PAY DIVIDENDS. CHEVRON HAS MADE DIVIDEND PAYMENTS TO STOCKHOLDERS FOR
83 CONSECUTIVE YEARS.
FS-12
REPORT OF MANAGEMENT
TO THE STOCKHOLDERS OF CHEVRON CORPORATION
Management of Chevron is responsible for preparing the accompanying financial
statements and for assuring their integrity and objectivity. The statements
were prepared in accordance with generally accepted accounting principles and
fairly represent the transactions and financial position of the company. The
financial statements include amounts that are based on management's best
estimates and judgments.
The company's statements have been audited by Price Waterhouse 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 and Vice President, Finance Vice President
and Chief Executive Officer and Chief Financial Officer and Comptroller
February 25, 199428, 1995
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, 19931994 and 1992,1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993,1994, in conformity with generally accepted accounting principles.
These financial statements are the responsibility of the company's management;
our responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform
the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for the
opinion expressed above.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 1992, the company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes.
/s/ Price Waterhouse LLP
San Francisco, California
February 25, 199428, 1995
FS-13
CONSOLIDATED STATEMENT OF INCOME
Year Ended DecemberYEAR ENDED DECEMBER 31
Millions of dollars, -------------------------------------
except per-share amountsMILLIONS OF DOLLARS, ----------------------------------
EXCEPT PER-SHARE AMOUNTS 1994 1993 1992
(1) 1991 (1)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
REVENUES
Sales and other operating revenues (2)(1) $35,130 $36,191 $38,212 $38,118
Equity in net income
of affiliated companies 440 440 406 491
Other income 284 451 1,059
334
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES 35,854 37,082 39,677
38,943
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products 16,990 18,007 19,872
19,693
Operating expenses 6,314 6,267 6,145 6,933
Provision for U.S. refining
and marketing restructuring 69 837 - -
Exploration expenses 379 360 507 629
Selling, general and administrative expenses 963 1,530 1,761 1,704
Depreciation, depletion and amortization 2,431 2,452 2,594 2,616
Taxes other than on income (2)(1) 5,559 4,886 4,899 4,597
Interest and debt expense 346 317 436
519
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS 33,051 34,656 36,214
36,691
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAX EXPENSE
AND CUMULATIVE EFFECT OF
CHANGES IN ACCOUNTING PRINCIPLES 2,803 2,426 3,463 2,252
INCOME TAX EXPENSE 1,110 1,161 1,253
959
===========================================================================================================================================================
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGES IN ACCOUNTING PRINCIPLES $ 1,693 $ 1,265 $ 2,210 $ 1,293
CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES - - (641)
-
===========================================================================================================================================================
NET INCOME $1,265 $1,569 $1,293
=============================================================================$ 1,693 $ 1,265 $ 1,569
==============================================================================
PER SHARE OF COMMON STOCK: (2)
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGES IN ACCOUNTING PRINCIPLES $3.89 $6.52 $3.69$2.60 $1.94 $3.26
CUMULATIVE EFFECT OF CHANGES
IN ACCOUNTING PRINCIPLES - (1.89) - ---------------------------------(.95)
----------------------------------
NET INCOME PER SHARE OF COMMON STOCK $3.89 $4.63 $3.69$2.60 $1.94 $2.31
WEIGHTED AVERAGE NUMBER
OF SHARES OUTSTANDING 325,478,876 338,977,414 350,174,450
=============================================================================651,672,238 650,957,752 677,954,828
==============================================================================
(1) Reclassified. See Note 1.
(2) Includes consumer excise taxes.INCLUDES CONSUMER EXCISE TAXES. $4,790 $4,068 $3,964
$3,659(2) SHARES AND PER-SHARE AMOUNTS REFLECT A TWO-FOR-ONE STOCK SPLIT IN MAY 1994.
See accompanying notes to consolidated financial statements.
FS-14
CONSOLIDATED BALANCE SHEET
At DecemberAT DECEMBER 31
--------------------
Millions of dollars--------------------------
MILLIONS OF DOLLARS 1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
ASSETS
Cash and cash equivalents $ 1,644413 $ 1,2921,644
Marketable securities at cost893 372 403
Accounts and notes receivable
(less allowance: 1994 - $62; 1993 - $66; 1992 - $66) 3,923 3,808 4,115
Inventories:
Crude oil and petroleum products 1,036 1,108
1,276
Chemicals 391 423 497
Materials and supplies 263 252 292
Other merchandise 20 18
70
----------------------------------------------
1,710 1,801 2,135
Prepaid expenses and other current assets 652 1,057
827
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL CURRENT ASSETS 7,591 8,682 8,772
Long-term receivables 138 94 127
Investments and advances 3,991 3,623 2,451
Properties, plant and equipment, at cost 46,810 44,807 44,010
Less: accumulated depreciation,
depletion and amortization 24,637 22,942
21,822
----------------------------------------------
22,173 21,865 22,188
Deferred charges and other assets 514 472
432
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $34,407 $34,736
$33,970
=============================================================================
- -----------------------------------------------------------------------------==============================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Short-term debt $ 4,014 $ 3,456
Accounts payable $3,325 $3,4692,990 3,325
Accrued liabilities 1,274 2,538 2,009
Short-term debt 3,456 2,888
Federal and other taxes on income 624 782 967
Other taxes payable 490 505
502
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL CURRENT LIABILITIES 9,392 10,606 9,835
Long-term debt and capital lease obligations 4,128 4,082 4,953
Non-current deferred income taxes 2,916 2,894
Reserves for employee benefit plans 1,458 1,400
Deferred credits and other non-current obligations 2,043 1,677
1,160
- -----------------------------------------------------------------------------Non-current deferred income taxes 2,674 2,916
Reserves for employee benefit plans 1,574 1,458
------------------------------------------------------------------------------
TOTAL LIABILITIES 19,811 20,739
20,242
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Preferred stock (authorized 100,000,000 shares,
$1.00 par value, none issued) - -
Common stock (authorized 500,000,0001,000,000,000 shares,
$3.00$1.50 par value, 356,243,534712,487,068 shares issued) * 1,069 1,069
Capital in excess of par value 1,858 1,855 1,840
Deferred compensation - Employee
Stock Ownership Plan (ESOP) (900) (920) (954)
Currency translation adjustment and other 175 108 56
Retained earnings 14,457 13,955 13,814
Treasury stock, at cost (1993(1994 - 30,504,42960,736,435 shares;
19921993 - 31,069,74561,008,858 shares) * (2,063) (2,070)
(2,097)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY 14,596 13,997
13,728
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $34,407 $34,736
$33,970
===========================================================================================================================================================
* SHARES AND PAR VALUE AMOUNTS REFLECT A TWO-FOR-ONE STOCK SPLIT IN MAY 1994.
See accompanying notes to consolidated financial statements.
FS-15
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended DecemberYEAR ENDED DECEMBER 31
----------------------------
Millions of dollars------------------------------
MILLIONS OF DOLLARS 1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $1,265 $1,569 $1,293$ 1,693 $ 1,265 $ 1,569
Adjustments
Depreciation, depletion and amortization 2,431 2,452 2,594 2,616
Dry hole expense related
to prior years' expenditures 53 29 57 35
Distributions less than equity
in affiliates' income (55) (173) (144)
(220)
Net before-tax (gains) losses (gains) on
asset retirements and sales (83) 373 (568) 25
Net currency translation losses (gains) losses40 (27) (66) 4
Deferred income tax provision 110 (160) (176) (183)
Cumulative effect of changes
in accounting principles - - 641
-
Net (increase) decrease (increase) in operating
working capital (1) (1,773) 463 82
(249)
Other (2) 480 (1) (75)
(43)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES (2)(3) 2,896 4,221 3,914
3,278
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (3,405) (3,323) (3,352) (3,693)
Proceeds from asset sales 731 908 1,043
768
Net (purchases) sales of
marketable securities (3)(4) (545) 30 45
18
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES (3,219) (2,385) (2,264)
(2,907)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Net borrowings of short-term obligations 466 293 1,333 1,564
Proceeds from issuance of long-term debt 436 199 23 35
Repayments of long-term debt
and other financing obligations (588) (854) (1,260) (711)
Cash dividends paid (1,206) (1,139) (1,115) (1,139)
Purchases of treasury shares (5) (4) (382)
(286)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
NET CASH USED FOR FINANCING ACTIVITIES (897) (1,505) (1,401)
(537)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
EFFECT OF EXCHANGE RATE CHANGES
ON CASH AND CASH EQUIVALENTS (11) 21 3
(20)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,231) 352 252 (186)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,644 1,292 1,040
1,226
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT YEAR-END $1,644 $1,292 $1,040
=============================================================================$ 413 $ 1,644 $ 1,292
==============================================================================
(1) The "Net decrease (increase) in operating working capital" is composed of
the following:
Decrease in accounts and notes receivableTHE "NET (INCREASE) DECREASE IN OPERATING WORKING CAPITAL" IS COMPOSED OF
THE FOLLOWING:
(INCREASE) DECREASE IN ACCOUNTS
AND NOTES RECEIVABLE $ (44) $ 187 $ 97
$ 692
Decrease in inventories(INCREASE) DECREASE IN INVENTORIES (57) 288 292
312
(Increase) decrease in prepaid expenses
and other current assetsDECREASE (INCREASE) IN PREPAID EXPENSES
AND OTHER CURRENT ASSETS 4 (52) 85
(151)
Increase (decrease) in accounts payable
and accrued liabilities(DECREASE) INCREASE IN ACCOUNTS PAYABLE
AND ACCRUED LIABILITIES (1,510) 214 (567)
(880)
(Decrease) increase in income
and other taxes payable(DECREASE) INCREASE IN INCOME AND
OTHER TAXES PAYABLE (166) (174) 175
(222)
- -----------------------------------------------------------------------------
Net decrease (increase) in operating
working capital------------------------------------------------------------------------------
NET (INCREASE) DECREASE IN
OPERATING WORKING CAPITAL $(1,773) $ 463 $ 82
==============================================================================
(2) IN 1994, "OTHER" OPERATING ACTIVITIES
WERE COMPRISED PRIMARILY OF INCREASES IN
NON-CURRENT OBLIGATIONS WHICH INCLUDED,
IN PART, NON-CASH PROVISIONS FOR
ENVIRONMENTAL REMEDIATION.
(3) "NET CASH PROVIDED BY OPERATING ACTIVITIES"
INCLUDES THE FOLLOWING CASH PAYMENTS FOR
INTEREST AND INCOME TAXES:
INTEREST PAID ON DEBT (NET OF
CAPITALIZED INTEREST) $ (249)
=============================================================================
(2) "Net Cash Provided by Operating Activities" includes the following cash
payments for interest and income taxes:
Interest paid on debt
(net of capitalized interest)310 $ 309 $ 392
INCOME TAXES PAID $ 453
Income taxes paid $1,505 $1,236 $1,460
=============================================================================
(3) "Net sales of marketable securities" consists of the following gross
amounts:
Marketable securities purchased1,147 $ 1,505 $ 1,236
==============================================================================
(4) "NET (PURCHASES) SALES OF MARKETABLE
SECURITIES" CONSISTS OF THE FOLLOWING
GROSS AMOUNTS:
MARKETABLE SECURITIES PURCHASED $(1,943) $(1,855) $(2,633)
$(4,104)
Marketable securities soldMARKETABLE SECURITIES SOLD 1,398 1,885 2,678
4,122
- -----------------------------------------------------------------------------
Net sales of marketable securities------------------------------------------------------------------------------
NET (PURCHASES) SALES OF MARKETABLE SECURITIES $ (545) $ 30 $ 45
$ 18
===========================================================================================================================================================
See accompanying notes to consolidated financial statements.
FS-16
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITYEQUITY*
Number of Shares Millions of dollars
--------------------------- -------------------------------------------------------------------NUMBER OF SHARES MILLIONS OF DOLLARS
------------------------ --------------------------------------------------------------------------
CURRENCY
COMMON COMMON CAPITAL IN DEFERRED TRANSLATION
COMMON STOCK COMMON STOCK IN COMMON EXCESS OF COMPENSATIONCOMPENSA- ADJUSTMENT RETAINED TREASURY
ISSUED IN TREASURY STOCK PAR VALUE - ESOPTION-ESOP AND OTHER EARNINGS STOCK
--------------------------- ------------------------------------------------------------------------------------------- -------------------------------------------------------------------------
BALANCE AT
DECEMBER 31, 1990 356,243,534 (5,443,328)1991 712,487,068 (19,042,538) $1,069 $1,839 $(964) $ 1,069 $1,835 $(979) $5667 $13,349 $ 13,195 $ (340)
Net income - - - - - - 1,293 -
Cash dividends -
$3.25 per share - - - - - - (1,139) -
Foreign currency translation
adjustment - - - - - 13 - -
Pension Plan
minimum liability - - - - - (2) - -
ESOP expense
accrual adjustment - - - - (5) - - -
Reduction of ESOP debt - - - - 20 - - -
Purchase of treasury shares - (4,201,864) - - - - - (286)
Reissuance of treasury shares - 123,923 - 4 - - - 5
-------------------------- -------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1991 356,243,534 (9,521,269) 1,069 1,839 (964) 67 13,349 (621)
Net income - - - - - - 1,569 -
Cash dividends -
$3.30$1.65 per share - - - - - - (1,115) -
Tax benefit from
dividends paid on
unallocated ESOP shares - - - - - - 11 -
Foreign currency
translation adjustment - - - - - (10) - -
Pension Plan
minimum liability - - - - - (1) - -
ESOP expense
accrual adjustment - - - - 10 - - -
Treasury shares acquired
in exchange transaction - (15,750,000)(31,500,000) - - - - - (1,100)
Purchase of treasury shares - (5,934,461)(11,868,922) - - - - - (382)
Reissuance of treasury shares - 135,985271,970 - 1 - - - 6
------------------------- ------------------------------------------------------------------------------------------- -------------------------------------------------------------------------
BALANCE AT
DECEMBER 31, 1992 356,243,534 (31,069,745) 1,069 1,840 (954) 56 13,814 (2,097)712,487,068 (62,139,490) $1,069 $1,840 $(954) $56 $13,814 $(2,097)
Net income - - - - - - 1,265 -
Cash dividends -
$3.50$1.75 per share - - - - - - (1,139) -
Tax benefit from
dividenddividends paid on
unallocated ESOP shares - - - - - - 15 -
Foreign currency
translation adjustment - - - - - 52 - -
ESOP expense
accrual adjustment - - - - 4 - - -
Reduction of ESOP debt - - - - 30 - - -
Purchase of treasury shares - (46,253)(92,506) - - - - - (4)
Reissuance of treasury shares - 611,5691,223,138 - 15 - - - 31
- -------------------------------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------
BALANCE AT
DECEMBER 31, 1993 356,243,534 (30,504,429)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)
======================================================= =========================================================================
* SHARES AND PER-SHARE AMOUNTS REFLECT A TWO-FOR-ONE STOCK SPLIT IN MAY 1994.
See accompanying notes to consolidated financial statements.
FS-17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Millions of dollars
NOTE 1:1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Chevron Corporation and its
consolidated subsidiaries (the company) employ accounting policies that are in
accordance with generally accepted accounting principles in the United States.
SUBSIDIARY AND AFFILIATED COMPANIES. The consolidated financial statements
include the accounts of subsidiary companies more than 50 percent owned.
Investments in and advances to affiliates in which the company has a
substantial ownership interest of approximately 20 to 50 percent, or for which
the company participates in policy decisions, are accounted for by the equity
method. Under this accounting, remaining unamortized cost is increased or
decreased by the company's share of earnings or losses after dividends.
OIL AND GAS ACCOUNTING. The successful efforts method of accounting is used for
oil and gas exploration and production activities.
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 hedged transaction occurs. Gains and losses on
derivatives contracts that do not qualify as hedges are recognized currently in
"Other income."
SHORT-TERM INVESTMENTS. Short-termAll 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 are classified as cash equivalents. These
investments are highly liquid and generally havewith original
maturities of three months or less. All otherless are reported as cash equivalents. The
balance of the short-term investments are classifiedis reported as marketable securities.
INVENTORIES. Crude oil, petroleum products, chemicals and other merchandise are
stated at cost, using a Last-In, First-Out (LIFO) method. In the aggregate,
these costs are below market. Materials and supplies inventories generally are stated at
average cost.
PROPERTIES, PLANT AND EQUIPMENT. All costs for development wells, related plant
and equipment (including carbon dioxide and certain other injected materials
used in enhanced recovery projects), and mineral interests in oil and gas
properties are capitalized. Costs of exploratory wells are capitalized pending
determination of whether the wells found proved reserves. Costs of wells that
are assigned proved reserves remain capitalized. All other exploratory wells
and costs are expensed.
Proved oil and gas properties are regularly assessed for possible impairment on
an aggregate worldwide portfolio basis, applying the informal "ceiling test" of
the Securities and Exchange Commission. Under this method, the possibility of
an impairment may exist if the aggregate net book carrying value of these
properties, net of applicable deferred income taxes, exceeds the aggregate
undiscounted future cash flows, after tax, from the properties, as calculated
in accordance with accounting rules for supplemental information on oil and gas
producing activities. In addition, high-cost, long-lead-time oil and gas
projects are individually assessed prior to production start-up by comparing
the recorded investment in the project with its fair market or economic value,
as appropriate. Economic values are generally based on management's
expectations of discounted future after-tax cash flows from the project at the
time of assessment.
Depreciation and depletion (including provisions for future abandonment and
restoration costs) of all capitalized costs of proved oil and gas producing
properties, except mineral interests, are expensed using the unit-of-production
method by individual fields as the proved developed reserves are produced.
Depletion expenses for capitalized costs of proved mineral interests are
determinedrecognized using the unit-of-production method by individual fields as the
related proved reserves are produced. Periodic valuation provisions for
impairment of capitalized costs of unproved mineral interests are expensed.
Depreciation and depletion expenses for coal and other mineral assets are determined using the
unit-of-production method as the proved reserves are produced. The capitalized
costs of all other plant and equipment are depreciated or amortized over
estimated useful lives. In general, the declining-balance method is used to
depreciate plant and equipment in the United States; the straight-line method
generally is used to depreciate international plant and equipment and to
amortize all capitalized leased assets.
Gains or losses are not recognized for normal retirements of properties, plant
and equipment subject to composite group amortization or depreciation. Gains or
losses from abnormal retirements or sales are included in income.
Expenditures for maintenance, repairs and minor renewals to maintain facilities
in operating condition are expensed. Major replacements and renewals are
capitalized.
ENVIRONMENTAL EXPENDITURES. Environmental expenditures that relate to current
ongoing operations or to an existing conditionconditions 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 coincides withis 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
FS-18
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued
other PRPs when it is probable that they will not be able to pay their share of
the cleanup obligation.
The company records the gross amount of its liability based on its best
estimate of future costs in current dollars and using currently available
technology and applying current regulations as well as the company's own
internal environmental policies. Future amounts are not discounted. Probable
recoveries or reimbursements are recorded as an asset.
FS-18
NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued
CURRENCY TRANSLATION. The U.S. dollar is the functional currency for the
company's consolidated operations as well as for substantially all operations
of its equity method companies. For those operations, all gains or losses from
currency transactions are included in income currently. The cumulative
translation effects for the few equity affiliates using functional currencies
other than the U.S. dollar are included in the currency translation adjustment
in stockholders' equity.
TAXES. Effective 1992, the company accounts for income taxes in accordance
with Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes." In 1991, the company accounted for income taxes in accordance
with Statement No. 96, "Accounting for Income Taxes." Income taxes are accrued for retained earnings of international
subsidiaries and corporate joint ventures intended to be remitted. Income taxes
are not accrued for unremitted earnings of international operations that have
been, or are intended to be, reinvested indefinitely.
RECLASSIFICATION OF CERTAIN REVENUES AND PURCHASES. To conform to the
presentation in 1993, the years 1992 and 1991 in the consolidated income
statement were reclassified to net certain offsetting forward crude oil
purchases and sales contracts. This reclassification had no effect on net
income for any period. Sales and other operating revenues, and purchased
crude oil and products, decreased $3,216 for 1992 and $2,002 for 1991, from
the amounts previously reported.
NOTE 2:2. ADOPTION OF STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS NO. 106,
"EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS" (SFAS
106) AND NO. 109, "ACCOUNTING FOR INCOME TAXES" (SFAS 109) Effective January 1,
1992, the company adopted SFAS 106 and SFAS 109, issued by the Financial
Accounting Standards Board. The effects of these statements on 1992 net income
included a charge of $641, or $1.89$.95 per share, attributable to the cumulative
effect of adoption, including the company's share of equity affiliates. This
net charge was composed of $833, after related tax benefits of $423, for the
recognition of liabilities for retiree benefits (primarily health and life
insurance), partially offset by a credit of $192 for deferred income tax
benefits and other changes stipulated by the new income tax accounting rules.
Apart from the cumulative effect, adoption of the statements increased
earnings for 1992 by $163 after tax, or $.48 per share. Under the new income
tax accounting, benefits of $200 were recorded, largely due to the
strengthening of the dollar in 1992, which resulted in lower foreign
deferred tax liabilities. These benefits were partly offset by $37 of
additional after-tax expense for retiree benefits, when compared to the
previous practice of expensing these costs when paid.
NOTE 3:3. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION Net income is affected by
transactions that are unrelated to or are not representative of the company's
ongoing operations for the periods presented. These transactions, defined by
management and designated "special items," can obscure the underlying results
of operations for a year as well as affect comparability of results between
years.
Listed below are categories of special items and their net increase (decrease)
to net income, after related tax effects:
Year Ended DecemberYEAR ENDED DECEMBER 31
-----------------------------------------------------------
1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Asset dispositions, net
Lead and zinc property in Ireland $ 48 $ - $ -
Ortho lawn and garden products $- 130 $ - $ -
Oil and gas properties - (25) 209 44
Stock exchange with Pennzoil Company - - 376 -
Copper interest in Chile - - 159
Other -
Other 17 13
105
-----------------------------------------------------------
48 122 757
149
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Asset write-offs and revaluations
Oil and gas properties - (31) (110) -
Refining and marketing assets - (24) (31)
(24)
Other - (16) 8
------------------------------
-
----------------------------- (71) (133)
(24)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Prior-year tax adjustments 344 (130) 72
173
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Environmental remediation provisions (304) (90) (44)
(160)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Restructurings and reorganizations
Work-force reductions, net - (11) (40)
(102)
U.S. Refiningrefining and marketing (39) (543) -
(83)
-----------------------------Chemicals (6) - -
------------------------------
(45) (554) (40)
(185)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
LIFO inventory (losses) gainslosses (10) (46) (26)
16
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Other, net
Litigation and regulatory issues (31) (70) (11) (35)
One-time employee bonus - (60) - -
Chemicals products license agreements - - 32
-
OtherInsurance gains and other adjustments 20 16 44
-
-----------------------------------------------------------
(11) (114) 65
(35)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total special items, after tax*tax $ 22 $(883) $651
$(66)
=============================================================================
*Amounts include the company's share of equity affiliates' transactions.==============================================================================
The 1994 U.S. refining and marketing restructuring charge of $543$39 and the
chemicals charge of $6 were net adjustments made to the 1993 charge of $543.
The restructuring reserve was primarily composed of a writedownwritedowns of two
refineries and their related inventories to estimated realizable values. Also included in the charge were provisions for
environmental site assessments and employee severance. The
estimated realizable value of the refineries took into account probablecertain
environmental cleanup obligations. ResponsibilityAlso included in the reserve were amounts
for these obligations will be negotiated
with potential buyers.environmental site assessments and employee severance. The refineries are
located in Port Arthur, Texas, and
Philadelphia, Pennsylvania, and havePort Arthur, Texas.
The Philadelphia refinery was sold in August 1994 and the Port Arthur refinery
was sold in February 1995. The reserve was reduced by the amount of proceeds
received from the sale of the Philadelphia refinery and adjustments were made
to reflect the terms of the sales. These included adjustments to the realizable
values of the assets, primarily inventories, and the recognition of certain
environmental remediation obligations retained by the company. These
adjustments resulted in a combined$45 net increase to the reserve. At year-end 1994,
the reserve balance, before related tax effects, was composed of $491 for loss
on the sale of the Port Arthur refinery capacityand related inventories and $224 for
Port Arthur environmental cleanup obligations.
The company does not expect the environmental cleanup expenditures, most of
about
350,000 barrels per day.which will be made over an approximate
FS-19
NOTE 3:3. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION - Continued
ten-year period, to have any material effect on its liquidity. The costs will
be funded through cash from future operations.
Other financial information is as follows:
Year Ended DecemberYEAR ENDED DECEMBER 31
------------------------------------------------------------
1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total financing interest and debt costs $419 $371 $478 $546
Less: capitalized interest 73 54 42
27
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Interest and debt expense 346 317 436 519
Research and development expenses 179 206 229
250
Currency transaction (losses) gains (losses)* $(64) $ 46 $ 90
$ (4)
=============================================================================
*Includes==============================================================================
* INCLUDES $(24), $18 andAND $24 inIN 1994, 1993 andAND 1992, respectively, for the company's share
of affiliates' currency transaction effects; in 1991 the net effect was zero.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
$684, $671 and $803 at December 31, 1994, 1993 and 1992, respectively.
NOTE 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS The
Consolidated Statement of Cash Flows excludes the following non-cash
transactions:
In 1994, the company took delivery of a new tanker under a capital lease
arrangement. This asset was recorded as a $65 million addition to properties,
plant and equipment and to capital lease obligations.
The company's Employee Stock Ownership Plan (ESOP) repaid $40 and $30 of
matured debt guaranteed by Chevron Corporation in 1994 and 1993, respectively.
The company reflected this payment as reductions in debt outstanding and in
Deferred Compensation - ESOP.
In 1993, the company acquired a 50 percent interest in the Tengizchevroil joint
venture (TCO) in the Republic of Kazakhstan through a series of cash and
non-cash transactions. The company's interest in TCO is accounted for using the
equity method of accounting and is recorded in "Investments and advances" in
the consolidated balance sheet. The cash expended in connection with the
formation of TCO and subsequent advances to TCO have been included in the
consolidated statement of cash flows in "Capital expenditures." The deferred
payment portion of the TCO investment totaled $709 at December 31, 1993, and
$466 at year-end 19931994 and is recorded in "Accrued liabilities" and "Deferred
credits and other non-current obligations" in the consolidated balance sheet.
The timing of
these payments is dependent on the occurrence of certain future events,
including the pace of field developmentPayments in 1993 and the completion and successful
operation of an export pipeline system. During 1993, payments1994 related to the deferred portion of the TCO investment
were classified as Repayments"Repayments of long-term debt and other financing
obligations" in the consolidated statement of cash flows.
The company's Employee Stock Ownership Plan (ESOP) repaid $30 and $20 of
matured debt guaranteed by Chevron Corporation in 1993 and 1991,
respectively. The company reflected this payment as reductions in debt
outstanding and in Deferred Compensation - ESOP.
The company refinanced an aggregate amount of $334 and $57 in tax exempt
long-term debt and capital lease obligations in 1993 and 1992, respectively.
In 1991, the company refinanced $970 of long-term bank notes of the ESOP
with the public issuance of SEC registered long-term notes of a like amount.
These refinancings are not reflected in the consolidated statement of cash
flows.
In 1992, the company received 15,750,00031,500,000 shares of its common stock held by a
stockholder in exchange for the stock of a subsidiary owning certain U.S. oil
and gas producing properties and related facilities, cash and other current
assets and current liabilities. The value attributed to the treasury shares
received was $1,100. The property exchanged consisted of properties, plant and
equipment with a carrying value of $790 and, excluding cash, net current
liabilities of $1. Cash of $57 was included as a reduction of proceeds from
asset sales.
In 1992, the company acquired an additional ownership interest in an affiliate,
accounted for under the equity method, in a non-cash transaction. This increase
in ownership required the consolidation of the affiliate into the company's
financial statements. The principal result of this consolidation was to
increase non-current assets and liabilities by approximately $64.
There have been other non-cash transactions that have occurred during the years
presented. These include the reissuance of treasury shares for management
compensation plans,plans; acquisitions of properties, plant and equipment through
capital lease transactions,transactions; and changes in stockholders' equity, long-term debt
and other liabilities resulting from the accounting for the company's ESOP. The
amounts for these transactions have not been material in the aggregate in
relation to the company's financial position.
The major components of "Capital expenditures," and the reconciliation of this
amount to the capital and exploratory expenditures, excluding equity in
affiliates, presented in "Management's Discussion and Analysis of Financial
Condition and Results of Operations," are presented below:
Year Ended DecemberYEAR ENDED DECEMBER 31
------------------------------------------------------------
1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Additions to properties, plant and equipment * $3,112 $3,214 $3,342 $3,698
Additions to investments 284 179 47 48
Payments for other (liabilities)assets and assets,(liabilities), net 9 (70) (37)
(53)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Capital expenditures 3,405 3,323 3,352 3,693
Expensed exploration expenditures 326 330 450
594
Equipment acquired through a
non-cash capital lease transaction - - 2
RepaymentsPayments of long-term debt
and other financing obligations 242 86 -
-
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Capital and exploratory expenditures,
excluding equity companies $3,973 $3,739 $3,802
$4,289
===========================================================================================================================================================
* 1994 EXCLUDES NON-CASH CAPITAL LEASE ADDITION OF $65.
NOTE 5. STOCKHOLDERS' EQUITY Retained earnings at December 31, 1994 and 1993,
include $2,265 and $2,087, respectively, for the company's share of
undistributed earnings of equity affiliates.
At the company's annual meeting on May 3, 1994, stockholders approved an
increase in the authorized shares of common stock from 500 million to 1 billion
and approved a two-for-one split of the company's issued common stock,
effective May 11, 1994. All share and per-share amounts prior to that date have
been restated to reflect the stock split.
In 1988, the company declared a dividend distribution of one Right for each
outstanding share of common stock. The Rights will be exercisable, unless
redeemed earlier by the company, if a person or group acquires, or obtains the
right to acquire, 10 percent or more of the outstanding shares of common stock
or commences a tender or exchange offer that would result in acquiring 10
percent or more of the outstanding shares of common stock, either event
occurring without the prior consent of the company. Each Right entitles its
holder to purchase stock having a value equal to two times the exercise price
of the
FS-20
NOTE 5. STOCKHOLDERS' EQUITY - Continued
Right. The person or group who had acquired 10 percent
FS-20
NOTE 5. STOCKHOLDERS' EQUITY - Continued or more of the
outstanding shares of common stock without the prior consent of the company
would not be entitled to this purchase opportunity.
The Rights will expire in November 1998, or they may be redeemed by the company
at 5 cents per share prior to that date. The Rights do not have voting or
dividend rights and, until they become exercisable, have no dilutive effect on
the earnings of the company. FiveTwenty 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 19931994 made the Rights exercisable.
The Board of Directors has proposed a two-for-one split of the company's
issued common stock. Stockholders have been asked to approve the split and
an increase in authorized shares of common stock from 500 million to 1
billion to accommodate the split at the annual stockholders' meeting on May
3, 1994. If approved, the split will be effective May 11, 1994 for
stockholders of record on that date.
NOTE 6. FINANCIAL INSTRUMENTS
OFF-BALANCEOFF BALANCE SHEET RISK. The company enters into forward exchange contracts,
generally with terms of 90 days or less, as a hedge against some of its foreign
currency exposures. Offsetting gainsexposures, primarily anticipated purchase transactions forecasted to
occur within 90 days. At December 31, 1994 and 1993, the notional amounts were
$60 and $114, respectively.
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 semi-annually or annually, and are recorded monthly as
"Interest and debt expense." At December 31, 1994, the notional principal
amounts of the swaps held by the company totaled $850, and the contracts have
remaining terms of between two to five years.
The impact of the swaps and forward exchange contracts on the company's results
of operations is not material.
The company utilizes certain derivative financial instruments 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 futures
contracts traded on the International Petroleum Exchange and natural gas swap
contracts, entered into principally with major financial institutions. The
futures contracts hedge anticipated crude oil purchases and sales, generally
forecasted to occur within a ninety-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 twelve months, mirroring the terms of the committed
sales. Gains and losses on these contractsthe instruments offset, and are recognized
concurrently with the exchange gains and losses stemming fromassociated with the associated commitments. At December 31, 1993 and 1992, the company had
not recognized gains or losses on forward contracts with a carrying and
approximate fair value of $114 and $119, respectively.underlying commodities.
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 cash equivalents and marketable securitiesshort-term investments are in high-quality
securities 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 concentrationscredit risk and to concentration of credit risk. Similar standards of
diversity and creditworthiness are applied to the company's counterparties in
derivative financial 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. At December 31, 1993,1994, the company's long-term debt of $2,057$2,155 had an
estimated fair value of $2,238.$2,127. The fair value is based on quoted market prices
at December 31, 1993,1994, or the present value of expected cash flows when a quoted
market price was not available.
At December 31, 1994, the company held crude oil futures contracts and natural
gas swap contracts with approximate negative fair values totaling $(38).
The reported amounts of financialcompany holds cash equivalents and U.S. dollar marketable securities in
domestic and offshore portfolios. Eurodollar bonds and floating rate notes are
the primary instruments such as Cashheld. At December 31, 1994, cash equivalents Marketableand
marketable securities and Short-term debt approximatehad a fair value because of their short maturity.$1,178. Of this balance, $285
classified as cash equivalents had average maturities under 90 days, while the
remainder, classified as marketable securities, had an average maturity of 4
years.
NOTE 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC. At December 31, 1993,1994,
Chevron U.S.A. Inc. was Chevron Corporation's principal operating company,
consisting primarily of the company's U.S. integrated petroleum operations
(excluding most of the domestic pipeline operations). These operations are
conducted by three divisions: Chevron U.S.A. Production Company, Chevron U.S.A.
Products Company and Warren Petroleum Company. Summarized financial
information for Chevron U.S.A. Inc. and its consolidated subsidiaries is
presented below:
Year Ended DecemberYEAR ENDED DECEMBER 31
-----------------------------------------------------------
1994 1993 1992* 1991*
- -----------------------------------------------------------------------------1992
------------------------------------------------------------------------------
Sales and other operating revenues $25,833 $28,092 $29,454 $29,073
Total costs and other deductions 25,367 27,588 28,410 28,861
Income before cumulative effect
of changes in accounting principles 501 325 811 90
Cumulative effect of changes
in accounting principles - - (573) -
Net income 501 325 238
90
=============================================================================
At December==============================================================================
AT DECEMBER 31
----------------------------------
1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Current assets $3,661 $4,200$ 3,341 $ 3,661
Other assets 14,136 14,099 14,587
Current liabilities 6,347 5,936 5,528
Other liabilities 5,599 5,738 6,795
Net equity 5,531 6,086
6,464
=============================================================================
*To conform to the presentation adopted in 1993, the 1992 and 1991 periods
have been reclassified to net certain offsetting crude oil purchases and
sales contracts. The reclassification had no effect on net income. See Note 1.==============================================================================
FS-21
NOTE 8. LITIGATION The company is a defendant in numerous lawsuits, in
addition to those mentioned in this note.lawsuits. Plaintiffs
may seek to recover large and sometimes unspecified amounts, and some matters
may remain unresolved for several years.
In April 1991, a United States District Court in Texas ruled favorably on
claims brought by former employees of Gulf and participants in the Gulf
Pension Plan that a partial termination of the plan had occurred. However,
the court denied plaintiffs' claims to a share of any surplus plan assets.
In October 1991, the district court approved a partial settlement in which
the parties agreed not to appeal the partial termination claims except as
relevant to plaintiffs' claims for a share of surplus plan assets. These
claims are now before the Fifth Circuit Court of Appeals. A second partial
settlement was implemented in 1993, resulting in a charge to earnings of
$48.
A lawsuit brought against the company by OXY USA Inc., the successor in
interest to Cities Service Company, remains pending in an Oklahoma state court.
The suit involves claims for breach of contract and misrepresentation related
to the termination of Gulf Oil Corporation's offer to purchase Cities' stock in
1982. (Gulf was acquired by Chevron in 1984.) FS-21
NOTE 8. LITIGATION - ContinuedOXY also asserts that the company
improperly interfered with a proposed settlement of claims brought against OXY
by the Department of Energy.
Management is of the opinion that resolution of the lawsuits will not result in
any significant liability to the company in relation to its consolidated
financial position or liquidity.
NOTE 9. GEOGRAPHIC AND SEGMENT DATA The geographic and segment distributions of
the company's identifiable assets, operating income and sales and other
operating revenues are summarized in the following tables.
AT DECEMBER 31
------------------------------
1994 1993 1992
------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
United States
Petroleum $15,540 $16,443 $18,508
Chemicals 1,992 2,045 2,165
Coal and Other Minerals 592 744 762
------------------------------------------------------------------------------
Total United States 18,124 19,232 21,435
------------------------------------------------------------------------------
International
Petroleum 12,493 12,202 9,671
Chemicals 411 412 390
Coal and Other Minerals 45 13 10
------------------------------------------------------------------------------
Total International 12,949 12,627 10,071
------------------------------------------------------------------------------
TOTAL IDENTIFIABLE ASSETS 31,073 31,859 31,506
Corporate and Other 3,334 2,877 2,464
------------------------------------------------------------------------------
TOTAL ASSETS $34,407 $34,736 $33,970
==============================================================================
YEAR ENDED DECEMBER 31
------------------------------
1994 1993 1992
------------------------------------------------------------------------------
OPERATING INCOME
United States
Petroleum $ 831 $ 692 $ 1,693
Chemicals 241 162 46
Coal and Other Minerals 60 59 68
------------------------------------------------------------------------------
Total United States 1,132 913 1,807
------------------------------------------------------------------------------
International
Petroleum 1,672 1,772 1,731
Chemicals 81 63 70
Coal and Other Minerals 79 (3) 177
------------------------------------------------------------------------------
Total International 1,832 1,832 1,978
------------------------------------------------------------------------------
TOTAL OPERATING INCOME 2,964 2,745 3,785
Corporate and Other (161) (319) (322)
Income Tax Expense (1,110) (1,161) (1,253)
------------------------------------------------------------------------------
Income before cumulative effect of
changes in accounting principles $ 1,693 $ 1,265 $ 2,210
Cumulative effect of changes in
accounting principles - - (641)
------------------------------------------------------------------------------
NET INCOME $ 1,693 $ 1,265 $ 1,569
==============================================================================
YEAR ENDED DECEMBER 31
------------------------------
1994 1993 1992
------------------------------------------------------------------------------
SALES AND OTHER OPERATING REVENUES
United States
Petroleum-Refined products $11,690 $13,169 $13,964
-Crude oil 3,466 4,086 5,138
-Natural gas 1,755 1,776 1,631
-Natural gas liquids 1,072 1,098 1,075
-Other petroleum revenues 637 682 700
-Excise taxes 2,977 2,554 2,458
-Intersegment 977 924 1,052
------------------------------
Total Petroleum 22,574 24,289 26,018
------------------------------
Chemicals-Products 2,528 2,211 2,409
-Intersegment 273 248 266
------------------------------
Total Chemicals 2,801 2,459 2,675
------------------------------
Coal and Other Minerals-Products 415 447 395
------------------------------
Total United States 25,790 27,195 29,088
------------------------------------------------------------------------------
International
Petroleum-Refined products 2,638 2,920 2,857
-Crude oil 4,783 4,415 4,893
-Natural gas 383 380 364
-Natural gas liquids 108 137 115
-Other petroleum revenues 307 285 227
-Excise taxes 1,797 1,499 1,490
-Intersegment (2) 1 10
------------------------------
Total Petroleum 10,014 9,637 9,956
------------------------------
Chemicals-Products 537 497 463
-Excise taxes 16 15 16
-Intersegment 8 6 5
------------------------------
Total Chemicals 561 518 484
------------------------------
Coal and Other Minerals-Products 1 - 2
------------------------------
Total International 10,576 10,155 10,442
------------------------------------------------------------------------------
Intersegment sales elimination (1,256) (1,179) (1,333)
------------------------------------------------------------------------------
Corporate and Other 20 20 15
------------------------------------------------------------------------------
TOTAL SALES AND OTHER OPERATING REVENUES $35,130 $36,191 $38,212
==============================================================================
Memo: Intergeographic Sales
United States $ 512 $ 266 $ 309
International 1,803 4,418 3,823
==============================================================================
The company's primary business is its integrated petroleum operations.
Secondary operations include chemicals and coal. The company's real estate and
insurance operations and worldwide cash management and financing activities are
in "Corporate and Other."
At December 31
-----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
IDENTIFIABLE ASSETS
United States
Petroleum $16,443 $18,508 $20,056
Chemicals 2,045 2,165 2,210
CoalBeginning 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 Minerals 744 762 767
----------------------------
Total United States 19,232 21,435 23,033
-----------------------------
International
Petroleum 12,202 9,671 9,018
Chemicals 412 390 402
Coal and Other Minerals 13 10 12
- -----------------------------------------------------------------------------
Total International 12,627 10,071 9,432
- -----------------------------------------------------------------------------
TOTAL IDENTIFIABLE ASSETS 31,859 31,506 32,465
Corporate and Other 2,877 2,464 2,171
- -----------------------------------------------------------------------------
TOTAL ASSETS $34,736 $33,970 $34,636
- -----------------------------------------------------------------------------
Year Ended December 31
-----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
OPERATING INCOME
United States
Petroleum $ 692 $ 1,693 $ 289
Chemicals 162 46 149
Coal and Other Minerals 59 68 27
-----------------------------
Total United States 913 1,807 465
-----------------------------
International
Petroleum 1,772 1,731 2,205
Chemicals 63 70 47
Coal and Other Minerals (3) 177 (26)
-----------------------------
Total International 1,832 1,978 2,226
- -----------------------------------------------------------------------------
TOTAL OPERATING INCOME 2,745 3,785 2,691
Corporate and Other (319) (322) (439)
Income Tax Expense (1,161) (1,253) (959)
- -----------------------------------------------------------------------------
Income Before Cumulative Effect of ChangesOther"). Starting in Accounting Principles $ 1,265 $ 2,210 $ 1,293
Cumulative Effect of Changes in
Accounting Principles - (641) -
- -----------------------------------------------------------------------------
NET INCOME $ 1,265 $ 1,569 $ 1,293
=============================================================================
Year Ended December 31
-----------------------------
1993 1992* 1991*
-----------------------------
SALES AND OTHER OPERATING REVENUES
United States
Petroleum-Refined products $13,169 $13,964 $13,921
-Crude oil 4,086 5,138 6,649
-Natural gas 1,776 1,631 1,502
-Natural gas liquids 1,098 1,075 1,043
-Other petroleum revenues 682 700 611
-Excise taxes 2,554 2,458 2,267
-Intersegment 924 1,052 1,226
-----------------------------
Total Petroleum 24,289 26,018 27,219
-----------------------------
Chemicals-Products 2,211 2,409 2,652
-Intersegment 248 266 252
-----------------------------
Total Chemicals 2,459 2,675 2,904
-----------------------------
Coal and Other Minerals-Products 447 395 417
-----------------------------
Total United States 27,195 29,088 30,540
- -----------------------------------------------------------------------------
International
Petroleum-Refined products 2,920 2,857 2,873
-Crude oil 4,415 4,893 3,627
-Natural gas 380 364 367
-Natural gas liquids 137 115 122
-Other petroleum revenues 285 227 201
-Excise taxes 1,499 1,490 1,374
-Intersegment 1 10 13
-----------------------------
Total Petroleum 9,637 9,956 8,577
-----------------------------
Chemicals-Products 497 463 446
-Excise taxes 15 16 18
-Intersegment 6 5 4
-----------------------------
Total Chemicals 518 484 468
-----------------------------
Coal and Other Minerals-Products - 2 10
-----------------------------
Total International 10,155 10,442 9,055
- -----------------------------------------------------------------------------
Intersegment sales elimination (1,179) (1,333) (1,495)
- -----------------------------------------------------------------------------
Corporate and Other 20 15 18
- -----------------------------------------------------------------------------
TOTAL SALES AND OTHER OPERATING REVENUES $36,191 $38,212 $38,118
=============================================================================
Memo: Intergeographic Sales
United States $ 266 $ 309 $ 361
International 4,418 3,823 3,497
- -----------------------------------------------------------------------------
*To conform to the presentation adopted in 1993, the 1992 and 1991 periods
have been reclassified to net certain offsetting crude oil purchases and
sales contracts. The reclassification had no effect on net income. See Note 1.
Operating income1994, segments are billed for the geographic areas includes allocateddirect
corporate overhead. In 1992 and 1991, the operating income for the business segments
excludedservices; unbilled corporate charges of $63 and $154 for a companywide voluntary
enhanced early retirement program. In 1992, $103 of pension settlement gains
were recognized in connection with the program. These amountsexpenses 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.
FS-22
NOTE 9. GEOGRAPHIC AND SEGMENT DATA - Continued
As a result of the change, "Corporate and Other" in 1994 included $232 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, 1994,
"Corporate and Other" included $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 1994 U.S. and International Petroleum
operating income of $101 and $111, respectively. Identifiable assets at
December 31, 1994 for U.S. and International Petroleum were reduced $630 and
$506, respectively. The effect of these changes on 1994 operating income and
year-end 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.
Sales and other operating revenues for the petroleum segment are derived from
the production and sale of crude oil,
FS-22
NOTE 9. GEOGRAPHIC AND SEGMENT DATA - Continued natural gas and natural gas liquids, and
from the refining and marketing of petroleum products. The company also obtains
revenues from the transportation and trading of crude oil and refined products.
Chemicals revenues result primarily from the sale of petrochemicals, plastic
resins, and lube oil and fuel additives. Coal and other minerals revenues
relate primarily to coal sales. During 1994, the company completed its
withdrawal from non-coal minerals activities.
Sales and other operating revenues in the above table include both sales to
unaffiliated customers and sales from the transfer of products between
segments. Sales from the transfer of products between segments and geographic
areas are generally at estimated market prices. Transfers between geographic
areas are presented as memo items below the table.
Equity in earnings of affiliated companies has been associated with the
segments in which the affiliates operate. Sales to the Caltex Group are
included in the International petroleum"International Petroleum" segment. Information on thesethe Caltex
and Tengizchevroil affiliates is presented in Note 11. Other affiliates are
either not material or not vertically integrated with a segment's operations.
NOTE 10. LEASE COMMITMENTS Certain non-cancelable leases are classified as
capital leases, and the leased assets are included as part of properties,"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 DecemberAT DECEMBER 31
-----------------------------------
1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Petroleum
Exploration and Production $ 5045 $ 50
Refining, Marketing and Transportation 618 554
553
- -----------------------------------------------------------------------------
663 604 603
Less: accumulated amortization 398 409 381
-
-----------------------------------------------------------------------------
Net capitalized leased assets $265 $195 $222
=============================================================================
At December 31, 1993,1994, the future minimum lease payments under operating and
capital leases are as follows:
At DecemberAT DECEMBER 31
--------------------
Operating Capital
Year Leases Leases
--------------------
OPERATING CAPITAL
YEAR LEASES LEASES
-----------------------------------------------------------------------------
1994 $1741995 $158 $ 41
1995 143 4864
1996 128 43144 60
1997 110 41131 56
1998 100 42114 52
1999 107 44
Thereafter 220 500
-218 659
-----------------------------------------------------------------------------
Total $875 715
- ------------------------------------------------------------------$872 935
-------------------------------------------------------------------
Less: amounts representing interest and executory costs (292)
-(456)
-----------------------------------------------------------------------------
Net present value 423479
Less: capital lease obligations included in short-term debt (278)
-(306)
-----------------------------------------------------------------------------
Long-term capital lease obligations $145$173
=============================================================================
Future sublease rental income $ 4643 $ -
=============================================================================
Rental expenses incurred for operating leases during 1994, 1993 1992 and 19911992 were
as follows:
At DecemberYEAR ENDED DECEMBER 31
---------------------------------------------------------
1994 1993 1992 1991
-
-----------------------------------------------------------------------------
Minimum rentals $410 $452 $408
$472
Contingent rentals 7 9 10
11
- -----------------------------------------------------------------------------
Total 417 461 418 483
Less: sublease rental income 14 15 14 49
-
-----------------------------------------------------------------------------
Net rental expense $403 $446 $404 $434
=============================================================================
Contingent rentals are based on factors other than the passage of time,
principally sales volumes at leased service stations. Certain leases include
escalation clauses for adjusting rentals to reflect changes in price indices,
renewal options ranging from one to 25 years and/or options to purchase the
leased property during or at the end of the initial lease period for the fair
market value at that time.
FS-23
NOTE 11. INVESTMENTS AND ADVANCES Investments in and advances to companies
accounted for using the equity method, and other investments accounted for at
or below cost, are as follows:
At DecemberAT DECEMBER 31
-----------------------------------
1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Equity Method Affiliatesmethod affiliates
Caltex Group $2,362 $2,147
$1,905Tengizchevroil 1,153 927
Other affiliates 1,353 450
- -----------------------------------------------------------------------------346 426
------------------------------------------------------------------------------
3,861 3,500 2,355
Other, at or below cost 130 123
96
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total investments and advances $3,991 $3,623
$2,451
===========================================================================================================================================================
Chevron owns 50 percent each of P.T. Caltex Pacific Indonesia, an exploration
and production company operating in Indonesia; Caltex Petroleum Corporation,
which, through its subsidiaries and affiliates, conducts refining and marketing
activities in Asia, Africa, Australia and New Zealand; and American Overseas
Petroleum Limited, which, through its subsidiaries, manages certain of the
company's exploration and production operations in Indonesia. These companies
and their subsidiaries and affiliates are collectively called the Caltex Group.
Other affiliates includes Tengizchevroil (TCO) is a 50 percent owned joint venture formed in 1993 with
the Republic of Kazakhstan to develop the Tengiz and Korolev oil field.fields over a
40-year period. The investment in TCO at December 31, 1994 and 1993 included a
deferred payment portion of $466 and $709 respectively, $420 of which is
payable to the Republic of Kazakhstan upon the attainment of a dedicated export
system with the capability of the greater of 260,000 barrels of oil per day or
TCO's production capacity. This 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 1994, 1993 1992 and 1991,1992, are as follows:
Year Ended DecemberYEAR ENDED DECEMBER 31
- ----------------------------------------------------------------------------
Equity in Earnings Dividends
-----------------------------------------------------------------------------
EQUITY IN EARNINGS DIVIDENDS
------------------------- -------------------------
1994 1993 1992 19911994 1993 1992
1991
- ----------------------------------------------------------------------------------------------------------------------------------------------------------
Caltex Group $350 $361 $334* $422$239 $172 $183
$202Tengizchevroil (10) (1) - - - -
Other affiliates 79100 80 72 69146 95 79
68
- ----------------------------------------------------------------------------------------------------------------------------------------------------------
Total $440 $440 $406 $491$385 $267 $262
$270
============================================================================
*Before cumulative effect of changes in accounting principles.
FS-23
NOTE 11. INVESTMENTS AND ADVANCES - Continued==============================================================================
* BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES.
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 followingadjacent table.
Year Ended December 31
----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Sales to Caltex Group $1,739 $1,784 $1,537
Sales to other affiliates 5 5 66
- -----------------------------------------------------------------------------
Total sales to affiliates $1,744 $1,789 $1,603
=============================================================================
Purchases from Caltex Group $ 842 $ 797 $ 821
Purchases from other affiliates 101 56 23
- -----------------------------------------------------------------------------
Total purchases from affiliates $943 $853 $844
- -----------------------------------------------------------------------------
Accounts and notes receivable in the consolidated balance sheet include $156$135
and $215$156 at December 31, 19931994 and 1992,1993, respectively, of amounts due from
affiliated companies. Accounts payable include $35$46 and $33$35 at December 31, 19931994
and 1992,1993, respectively, of amounts due to affiliated companies.
YEAR ENDED DECEMBER 31
------------------------------
1994 1993 1992
------------------------------------------------------------------------------
Sales to Caltex Group $1,166 $1,739 $1,784
Sales to other affiliates 7 5 5
------------------------------------------------------------------------------
Total sales to affiliates $1,173 $1,744 $1,789
==============================================================================
Purchases from Caltex Group $ 800 $ 842 $ 797
Purchases from other affiliates 52 101 56
------------------------------------------------------------------------------
Total purchases from affiliates $ 852 $ 943 $ 853
==============================================================================
The following tables summarize the combined financial information for the
Caltex Group and substantially all of the other equity method companies
together with Chevron's share. Amounts shown for the affiliates are 100
percent.
Caltex Group Other Affiliates Chevron's Share
-----------------------------CALTEX GROUP OTHER AFFILIATES CHEVRON'S SHARE
---------------------------- --------------------------- --------------------------
--------------------------
Year Ended DecemberYEAR ENDED DECEMBER 31 1994 1993 1992 19911994 1993 1992 19911994 1993 1992
1991
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Sales and other operating revenues $14,751 $15,409 $17,281 $15,445$2,237 $1,972 $1,995 $2,085$8,176 $8,229 $9,148 $8,282
Total costs and other deductions 13,860 14,392 16,255 14,2511,815 1,542 1,458 1,6747,500 7,633 8,543
7,587
Net income 689 720 720* 839357 374 416 323440 440 431
491
==============================================================================================================================
*After cumulative effect of=================================================================================================================================
* AFTER CUMULATIVE EFFECT OF $51 benefit from adoption ofBENEFIT FROM ADOPTION OF SFAS 106 andAND 109, of which Chevron's share ofOF WHICH CHEVRON'S SHARE OF $25 is included in
cumulative effect of changes in accounting principles in the consolidated statement of income.
Caltex Group Other Affiliates Chevron's Share
-----------------------------IS INCLUDED IN
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES IN THE CONSOLIDATED STATEMENT OF INCOME.
CALTEX GROUP OTHER AFFILIATES CHEVRON'S SHARE
---------------------------- --------------------------- --------------------------
--------------------------
At DecemberAT DECEMBER 31 1994 1993 1992 19911994 1993 1992 19911994 1993 1992
1991
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Current assets $ 2,421 $ 2,123 $ 2,378 $ 2,494913 $ 766 $ 788 $ 775$1,446 $1,256 $1,375
$1,468
Other assets 7,389 6,266 5,485 4,8694,216 3,871 2,186 2,0655,396 4,731 3,433
3,037
Current liabilities 3,072 2,411 2,453 2,398543 471 540 4091,617 1,332 1,364
1,314
Other liabilities 2,005 1,683 1,591 1,4803,225 2,620 746 7931,364 1,155 1,090
1,006
Net equity 4,733 4,295 3,819 3,4851,361 1,546 1,688 1,6383,861 3,500 2,354
2,185
===============================================================================================================================================================================================================================================================
FS-24
NOTE 12. PROPERTIES, PLANT AND EQUIPMENT
At DecemberAT DECEMBER 31 Year Ended DecemberYEAR ENDED DECEMBER 31
---------------------------------------------------- ----------------------------------------------
Gross Investment at Cost Net Investment Additions at Cost--------------------------------------------------- --------------------------------------------------------
GROSS INVESTMENT AT COST NET INVESTMENT ADDITIONS AT COST (1) Depreciation ExpenseDEPRECIATION EXPENSE
------------------------- ------------------------- ---------------------- ------------------------------------------------ -----------------------------
1994 1993 1992 19911994 1993 1992 19911994 1993 1992 19911994 1993 1992 1991
-
----------------------------------------------------------------------------------------------------------------------------------
UNITED STATES
Petroleum
Exploration and
Production $17,980 $17,608 $17,707 $20,349$ 5,900 $ 6,189 $ 6,703 $ 8,189675 $ 663 $ 609 $ 896983 $1,064 $1,264 $1,413
Refining and
Marketing 11,442 10,693 10,762 10,1486,524 6,187 6,345 5,945899 960 980 989460 460 430
397
Chemicals 1,915 1,899 1,803 1,8781,150 1,225 1,219 1,23589 174 182 176131 124 127 122
Coal and
Other Minerals 869 848 836 819461 488 511 51630 32 58 8854 54 50 48
-
----------------------------------------------------------------------------------------------------------------------------------
Total United States 32,206 31,048 31,108 33,19414,035 14,089 14,778 15,8851,693 1,829 1,829 2,1491,628 1,702 1,871 1,980
-
----------------------------------------------------------------------------------------------------------------------------------
INTERNATIONAL
Petroleum
Exploration and
Production 9,661 8,729 7,892 7,4514,800 4,353 3,980 3,7571,051 1,014 1,000 865578 519 496 427
Refining and
Marketing 2,482 2,385 2,367 2,0931,743 1,686 1,658 1,470218 219 304 450114 106 97
69
Chemicals 330 313 280 254143 148 142 13425 24 26 2927 25 18 19
Coal and
Other Minerals 21 12 11 2019 10 7 812 3 1 (6) - - 7 -
----------------------------------------------------------------------------------------------------------------------------------
Total International 12,494 11,439 10,550 9,8186,705 6,197 5,787 5,3691,306 1,260 1,331 1,338719 650 611 522
-
----------------------------------------------------------------------------------------------------------------------------------
Corporate and
Other (2) 2,110 2,320 2,352 2,2561,433 1,579 1,623 1,596125 96 209 17884 100 112
114
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL $46,810 $44,807 $44,010 $45,268$22,173 $21,865 $22,188 $22,850$3,124 $3,185 $3,369 $3,665$2,431 $2,452 $2,594
$2,616
==================================================================================================================================
(1) Net of dry hole expense related to prior years' expenditures ofNET OF DRY HOLE EXPENSE RELATED TO PRIOR YEARS' EXPENDITURES OF $53, $29 AND $57 and $35 inIN 1994, 1993 AND 1992, and 1991, respectively.RESPECTIVELY.
(2) Includes primarily real estate and management information systems.INCLUDES PRIMARILY REAL ESTATE AND MANAGEMENT INFORMATION SYSTEMS.
Expenses for maintenance and repairs were $928, $875 and $1,045 in 1994, 1993
and $1,229 in1992, respectively.
NOTE 13. TAXES
YEAR ENDED DECEMBER 31
------------------------------
1994 1993 1992
and 1991, respectively.
FS-24
NOTE 13.TAXES
Year Ended December 31
---------------------------
1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Taxes Other Than on Income
United States
Taxes on production $ 102 $ 135 $ 140
$ 153
Import duties 21 21 18 17
Excise taxes on products and merchandise 2,978 2,554 2,458 2,267
Property and other miscellaneous taxes (excluding payroll taxes)374 380 416
428
---------------------------
3,090 3,032 2,865
Payroll taxes 112 122 141
145
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total United States 3,587 3,212 3,173
3,010
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
International
Taxes on production 14 7 30
14
Import duties 11 22 55 50
Excise taxes on products and merchandise 1,812 1,514 1,506 1,392
Property and other miscellaneous taxes (excluding payroll taxes)116 112 114 111
---------------------------
1,655 1,705 1,567
Payroll taxes 19 19 21
20
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total internationalInternational 1,972 1,674 1,726
1,587
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total taxes other than on income $5,559 $4,886 $4,899
$4,597
=============================================================================
Year Ended December------------------------------------------------------------------------------
U.S. federal income tax expense was reduced by $60, $57 and $49 in 1994, 1993
and 1992, respectively, for low-income housing and other business tax credits.
In 1994, before-tax income for U.S. operations was $1,194 compared with $687 in
1993 and $1,592 in 1992. Before-tax income for international operations was
$1,609, $1,739 and $1,871 in 1994, 1993 and 1992, respectively.
YEAR ENDED DECEMBER 31
---------------------------------------------------------
1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Taxes on Income
U.S. federal
Current $ 175 $ 394 $ 329
$ 163
Deferred 43 (241) (129) (185)
Deferred - Adjustment for enacted
changes in tax laws/rates - 54 - -
State and local 10 63 54
16
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total United States 228 270 254
(6)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
International
Current 815 864 1,046
963
Deferred 67 48 (47) 2
Deferred - Adjustment for enacted
changes in tax laws/rates - (21) -
-
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total internationalInternational 882 891 999
965
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total taxes on income $1,110 $1,161 $1,253
$ 959
=============================================================================
U.S. federal income tax expense was reduced by $57, $49 and $27 in 1993, 1992
and 1991, respectively, for low-income housing and other business tax credits.
In 1993, before-tax income for U.S. operations was $687, compared with $1,592
in 1992 and $157 in 1991. Before-tax income for international operations was
$1,739, $1,871 and $2,095 in 1993, 1992 and 1991, respectively.==============================================================================
The deferred income tax provisions included (costs) benefits of $(222), $98 $163 and
$67$163 related to properties, plant and equipment in 1994, 1993 1992 and 1991,1992,
respectively. U.S. benefits were recorded in 1993 related to the U.S. refining
and marketing restructuring provision. The 1991 U.S. deferred tax
provision included benefits accrued from the reserves established for the
Port Arthur reconfiguration and the corporate severance program.
In 1992, the tax related to the cumulative effect of adopting SFAS 106 (Note 2)
was $423, representing deferred income tax benefits approximating the statutory
tax rate.
FS-25
NOTE 13. TAXES - Continued
The company's effective income tax rate varied from the U.S. statutory federal
income tax rate because of the following:
Year Ended DecemberYEAR ENDED DECEMBER 31
---------------------------------------------------------
1994 1993 1992
1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Statutory U.S. federal income tax rate 35.0% 34.0%35.0% 34.0%
Effects of income taxes on international
operations in excess of taxes at the
U.S. statutory rate 18.5 15.6 15.2 23.7
Effects of asset dispositions - (0.6) (8.0) (2.0)
State and local taxes on income,
net of U.S. federal income tax benefit 0.2 2.2 1.1 0.6
Prior-year tax adjustments (4.4) 3.0 (0.6) (4.2)
Effects of enacted changes in tax
laws/rates on deferred tax liabilities - 1.3 - -
Tax credits (2.1) (2.4) (1.4)
(1.2)
All others (3.2) (0.9) (0.9)
(1.8)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Consolidated companies 44.0 53.2 39.4 49.1
Effect of recording equity in income of certain
affiliated companies on an after-tax basis (4.4) (5.3) (3.2)
(6.5)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Effective tax rate 39.6% 47.9% 36.2%
42.6%
===========================================================================================================================================================
The company records its deferred taxes on a tax jurisdiction basis and
classifies those net amounts as current or noncurrent based on the balance
sheet classification of the related assets or liabilities.
At December 31, 19931994 and 1992,1993, deferred taxes were classified in the
consolidated balance sheet, as follows:
Year Ended DecemberAT DECEMBER 31
----------------------------------------
1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Prepaid expenses and other current assets $ (495)(112) $ (313)(495)
Deferred charges and other assets (148) (146) (132)
Federal and other taxes on income 18 27 24
Non-current deferred income taxes 2,674 2,916
2,894
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total deferred taxes, net $2,432 $2,302
$2,473
- -----------------------------------------------------------------------------==============================================================================
The reported deferred tax balances are composed of the following deferred tax
liabilities (assets):
Year Ended DecemberAT DECEMBER 31
----------------------
1993 1992
- -----------------------------------------------------------------------------------------------
1994 1993*
------------------------------------------------------------------------------
Properties, plant and equipment $3,933 $3,869$4,451 $4,201
Inventory 240 293
318
Miscellaneous 254 237
195
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities 4,463 4,382
- -----------------------------------------------------------------------------4,945 4,731
------------------------------------------------------------------------------
Abandonment/environmental reserves (1,066) (910) (792)
Employee benefits (564) (535) (492)
AMT/other tax credits (711) (486) (580)
Other accrued liabilities (299) (472)
(338)
Miscellaneous (255) (159)
- -----------------------------------------------------------------------------(523) (523)
------------------------------------------------------------------------------
Deferred tax assets (2,658) (2,361)
- -----------------------------------------------------------------------------(3,163) (2,926)
------------------------------------------------------------------------------
Deferred tax assets valuation allowance 650 497
452
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total deferred taxes, net $2,432 $2,302
$2,473
=============================================================================
FS-25
NOTE 13. TAXES - Continued==============================================================================
* CERTAIN 1993 AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE 1994
PRESENTATION.
It is the company's policy for subsidiaries included in the U.S. consolidated
tax return to record income tax expense as though they filed separately, with
the parent recording the adjustment to income tax expense for the effects of
consolidation.
Undistributed earnings of international consolidated subsidiaries and
affiliates for which no deferred income tax provision has been made for
possible future remittances totaled approximately $3,300$3,815 at December 31, 1993.1994.
Substantially all of this amount represents earnings reinvested as part of the
company's ongoing business. It is not practical to estimate the amount of taxes
that might be payable on the eventual remittance of such earnings. On
remittance, certain countries impose withholding taxes that, subject to certain
limitations, are then available for use as tax credits against a U.S. tax
liability, if any. The company estimates withholding taxes of approximately
$247$258 would be payable upon remittance of these earnings.
NOTE 14. SHORT-TERM DEBT
At DecemberAT DECEMBER 31
-----------------
1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Commercial paper (1) $5,036 $4,391 $4,023
Current maturities of long-term debt 134 167 89
Current maturities of long-term capital leases 33 23 24
Redeemable long-term obligations
Long-term debt 315 297 320
Capital leases 255273 255
Notes payable 23 203
277
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Subtotal (2) 5,814 5,336 4,988
Reclassified to long-term debt (1,800) (1,880)
(2,100)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total short-term debt $4,014 $3,456
$2,888
===========================================================================================================================================================
(1) WEIGHTED AVERAGE INTEREST RATES AT DECEMBER 31, 1994 AND 1993 WERE 6.0%
AND 3.3%, RESPECTIVELY.
(2) WEIGHTED AVERAGE INTEREST RATES AT DECEMBER 31, 1994 AND 1993 WERE 5.8%
AND 3.4%, RESPECTIVELY.
Redeemable long-term obligations consist primarily of tax-exempt variable-rate
put bonds that are included as current liabilities because they become
redeemable at the option of the bondholders during the year following the
balance sheet date.
Selected data on the company's commercial paper activities are shown below:
Weighted Weighted
Average Maximum Average
Interest Outstanding Average Interest
Balance at Rate at at Any Amount Rate for
Year December 31 December 31 Month End Outstanding the Year
- -----------------------------------------------------------------------------
1993 $4,390 3.3% $4,891 $4,445 3.1%
1992 $4,023 3.5% $4,441 $3,958 3.6%
1991 $2,748 4.8% $2,748 $1,863 5.7%
=============================================================================
The average amounts outstanding and weighted average interest rates during
each year are based on average daily balances outstanding. Amounts used in
the above computations include amounts that have been classified as long-term
debt during 1993, 1992 and 1991.
NOTE 15. LONG-TERM DEBT
At DecemberAT DECEMBER 31
-----------------
1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
8.11% amortizing notes due 2004 (1) $ 750 $ 750
8.25%7.45% notes due 1996 (2)2004 348 - 301
8.75% notes due 1996 (2) - 300
9.375% sinking-fund debentures due 2016 278 292
6.76% serial notes due 1994-1997 (1), (3) 190 220
7.875% notes due 1997 (4) 200 199278
5.6% notes due 1998 190 -190
9.75% sinking-fund debentures due 2017 180 179 190
4.625% 200 million Swiss franc issue due 1997 152 136
1376.90% serial notes due 1994-1997 (1),(2) 150 190
7.875% notes due 1997 (3) - 200
Other long-term obligations (6.88%(7.02%) (3)(2)
(less than $50 individually) 183 223 318
Other foreign currency obligations (6.81%(5.45%) (3)(2) 58 78
66
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total including debt due within one year 2,289 2,224 2,773
Debt due within one year (134) (167) (89)
Reclassified from short-term debt (3.17%(6.0%) (3)(2) 1,800 1,880
2,100
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt $3,955 $3,937
$4,784
===========================================================================================================================================================
(1) Guarantee ofGUARANTEE OF ESOP debt.DEBT.
(2) Debt retired before maturity date.WEIGHTED AVERAGE INTEREST RATE AT DECEMBER 31, 1994.
(3) Weighted average interest rate at December 31, 1993.
(4) Called in early 1994.DEBT RETIRED BEFORE MATURITY DATE.
FS-26
NOTE 15. LONG-TERM DEBT - Continued
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 $1,050$700 of debt securities pursuant to Rule
415 of the Securities Act of 1933.
At year-end 1993,1994, the company had $3,595$4,425 of committed credit facilities with
banks worldwide, $1,880$1,800 of which had termination dates beyond one year. These
credit agreements provide commitments for term loans of up to $3,280 and
revolving credit for short-term advances of up to $315. The
facilities also support the company's commercial paper borrowings. Interest on any
borrowings under the agreements is based on either the London Interbank Offered
Rate or the Reserve Adjusted Domestic Certificate of Deposit Rate. No amounts
were outstanding under these credit agreements during the year nor at year-end.
At December 31, 19931994 and 1992,1993, the company classified $1,880$1,800 and $2,100,$1,880,
respectively, of short-term debt as long-term. Settlement of these obligations
is not expected to require the use of working capital in 1994,1995, as the company
has both the intent and ability to refinance this debt on a long-term basis.
Consolidated long-term debt maturing in each of the five years after December
31, 1993,1994, is as follows: 1994-$167, 1995-$89,134, 1996-$93,98, 1997-$435246, 1998-$276 and
1998-1999-$198.94.
NOTE 16. EMPLOYEE BENEFIT PLANS
PENSION PLANS. The company has defined benefit pension plans for most
employees. The principal plans provide for automatic membership on a
non-contributory basis. The retirement benefits provided by these plans are
based primarily on years of service and on average career earnings or the
highest consecutive three years' average earnings. The company's policy is to
fund at least the minimum necessary to satisfy requirements of the Employee
Retirement Income Security Act.
FS-26
NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
The net pension expense (credit) for all of the company's pension plans for the
years 1994, 1993 and 1992 consisted of:
1994 1993 1992
and 1991 consisted of:
1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Cost of benefits earned during the year $ 97 $103 $106 $100
Interest cost on projected benefit obligations 263 276 302 295
Actual return on plan assets (62) (472) (309) (799)
Net amortization and deferral (294) 101 (134)
346
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Net pension expense (credits) $ 4 $ 8 $(35)
$(58)
===========================================================================================================================================================
Settlement gains in 1994, related to lump-sum payments, totaled $17. In
addition to the net pension expense in 1993, the company recognized a net
settlement loss of $63 and a curtailment loss of $4 reflecting the termination
of a former Gulf pension plan and lump-sum payments from other company pension
plans. In 1992, the company recorded charges of $65 and a curtailment loss of
$7, offset by net lump-sum settlement gains of $101 related to an early
retirement program offered to employees of its U.S. and certain Canadian
subsidiaries.
In 1991, charges of $154 related to the early
retirement programs and lump sum settlement gains of $25 were recognized.
At December 31, 19931994 and 1992,1993, 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:
1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Assumed discount rates 8.8% 7.4% 8.1%
Assumed rates for compensation increases 5.1% 5.5%5.1%
Expected return on plan assets 10.1% 9.1%
9.2%
- -----------------------------------------------------------------------------==============================================================================
The pension plans' assets consist primarily of common stocks, bonds, cash
equivalents and interests in real estate investment funds. The funded status
for the company's combined plans at December 31, 19931994 and 1992,1993, was as follows:
Plans with
Plans with Assets Accumulated
in Excess of Benefits
Accumulated in Excess of
Benefits Plan Assets
-------------------PLANS WITH
PLANS WITH ASSETS ACCUMULATED
IN EXCESS OF BENEFITS
ACCUMULATED IN EXCESS OF
BENEFITS PLAN ASSETS
----------------- At December-----------------
AT DECEMBER 31 1994 1993 19921994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Actuarial present value of:
Vested benefit obligations $(2,596) $(2,854) $(2,869) $(183) $(161)
=============================================================================$ (186) $ (183)
==============================================================================
Accumulated benefit obligations $(2,680) $(2,949) $(2,947) $(194) $(168)
=============================================================================$ (194) $ (194)
==============================================================================
Projected benefit obligations $(3,053) $(3,456) $(3,395) $(229) $(184)$ (222) $ (229)
Plan assets at fair values 3,626 3,831 3,893- 1
6
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Plan assets greater (less) than
projected benefit obligations 573 375 498(222) (228) (178)
Unrecognized net transition
(assets) liabilities (294) (349) (426)18 20 22
Unrecognized net (gains) losses (178) 41 1754 74 34
Unrecognized prior service costs 113 84 856 7 -
Minimum liability adjustment - - (80) (52)
(52)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Net pension cost prepaid (accrued) $ 214 $ 151 $ 174 $(179) $(174)
- -----------------------------------------------------------------------------(224) $ (179)
==============================================================================
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 $75, $95 and $84 in 1994, 1993 and $104 in 1993, 1992, and 1991,
respectively.
EMPLOYEE STOCK OWNERSHIP PLAN (ESOP). In December 1989, the company established
an ESOP as part of the Profit Sharing/Savings Plan. The ESOP Trust Fund
borrowed $1,000 and purchased 14.128.2 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,Plan, which will
result in annual income tax savings for the company. As interest
and principal payments are made on the ESOP debt, shares are released from a
suspense account and allocated to profit sharing accounts of plan participants. The ESOP is expected to
satisfy most of the company's obligations to the profit sharing part of the
Profit Sharing/Savings Plan during the next 1110 years.
OtherFS-27
NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
As allowed by AICPA Statement of Position (SOP) 93-6, the company obligationshas elected
to continue its current 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 profit sharing partESOP 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 the plan will
be satisfied by cash contributions.retained earnings. All ESOP shares are considered outstanding for
earnings-per-share computations.
The company recorded expense for the ESOP of $42, $60 and $50 in 1994, 1993 and
$44 in 1993, 1992, and 1991, respectively, including $71, $74 $75
and $69$75 of interest expense related to
the ESOP loan.debt. All dividends paid on the shares held by the ESOP will beare used to
service the ESOP debt. The dividends used were $50, $47 and $35 in 1994, 1993
and $401992, respectively.
The company made contributions to the ESOP of $63, $57 and $18 in 1994, 1993
and 1992, 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 1991,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 $(10), $(17) and $(35) in 1994, 1993 and 1992,
respectively. The ESOP shares as of December 31 were as follows:
THOUSANDS 1994 1993
------------------------------------------------------------------------------
Allocated shares 5,969 5,010
Unallocated shares 21,208 22,452
------------------------------------------------------------------------------
Total ESOP shares 27,177 27,462
==============================================================================
MANAGEMENT INCENTIVE PLANS. The company has two incentive plans, the Management
Incentive Plan (MIP) and the Long-Term Incentive Plan (LTIP) for officers and
other regular salaried employees of the company and its subsidiaries who hold
positions of significant responsibility. The MIP makes outright distributions
of cash for services rendered or deferred awards in the form of stock units.
Awards under LTIP may take the form of, but are not limited to, stock options,
restricted stock, stock units and non-stock grants. Stock options become
exercisable not earlier than one year and not later than 10 years from the date
of grant.
The maximum number of shares of common stock that may be granted each year is 1
percent of the total outstanding shares of common stock as of January 1 of such
year. As of December 31, 1993, 2,151,5051994, 5,845,260 shares were under option at exercise
prices ranging from $63.875$31.9375 to $87.75$43.875 per share. Stock option transactions
for 19931994 and 19921993 are as follows:
FS-27
NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
At DecemberAT DECEMBER 31
----------------
Thousands of shares------------------
THOUSANDS OF SHARES 1994 1993
1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Outstanding January 1 1,967 1,2654,303 3,934
Granted 706 7251,770 1,413
Exercised (509) (6)(140) (1,019)
Forfeited (12) (17)
- -----------------------------------------------------------------------------(88) (25)
------------------------------------------------------------------------------
Outstanding December 31 2,152 1,967
=============================================================================5,845 4,303
------------------------------------------------------------------------------
Exercisable December 31 1,456 1,250
=============================================================================4,152 2,912
==============================================================================
Charges to expense for the combined management incentive plans were $31, $36
and $20 in 1994, 1993 and $37 in 1993, 1992, and 1991, respectively.
OTHER BENEFIT PLANS. In addition to providing pension benefits, the company
makes contributions toward certain health care and life insurance plans for
active and qualifying retired employees. Substantially all employees in the
United States and in certain international locations may become eligible for
coverage under these benefit plans. The company's annual contributions for
medical and dental benefits are limited to the lesser of actual medical and
dental claims or a defined fixed per capita amount. Life insurance benefits are
paid by the company and annual contributions are based on actual plan
experience.
Under SFAS 106, adopted effective January 1, 1992, the company's net
postretirement benefits expense was as follows:
1993 1992
--------------------- --------------------
Health Life Total Health Life Total
- -----------------------------------------------------------------------------
Cost of benefits earned
during the year $23 $ 3 $ 26 $23 $ 4 $ 27
Interest cost
on benefit obligation 76 30 106 70 30 100
- -----------------------------------------------------------------------------
Net postretirement
benefits expense $99 $33 $132 $93 $34 $127
=============================================================================
1991 expense under the cash method was $60.
Non-pension postretirement benefits are funded by the company when incurred. A
reconciliation of the funded status of these benefit plans is as follows:
At DecemberAT DECEMBER 31, 1994 AT DECEMBER 31, 1993
At December 31, 1992
------------------------ -----------------------
Health Life Total Health Life Total
- ------------------------------------------------------------------------------------------------------- --------------------------
HEALTH LIFE TOTAL HEALTH LIFE TOTAL
------------------------------------------------------------------------------
Accumulated
postretirement
benefit
obligation (APBO)
Retirees $(480) $(262) $ (593)(742) $(593) $(320) $ (913) $(598) $(281) $ (879)
Fully eligible
active
participants (120) (57) (177) (139) (64) (203)
(109) (47) (156)
Other active
participants (190) (37) (227) (271) (56) (327)
(272) (49) (321)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Total APBO (790) (356) (1,146) (1,003) (440) (1,443) (979) (377) (1,356)
Fair value
of plan assets - - - - - -
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
APBO (greater) than
plan assets (790) (356) (1,146) (1,003) (440) (1,443)
(979) (377) (1,356)
Unrecognized
net (gain) loss (gain)(195) (66) (261) 63 25 88
69 (12) 57
- -----------------------------------------------------------------------------------------------------------------------------------------------------------
Accrued
postretirement
benefit costs $ (940)$(985) $(422) $(1,407) $(940) $(415) $(1,355)
$(910) $(389) $(1,299)
===========================================================================================================================================================
FS-28
NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
The company's net postretirement benefits expense was as follows:
1994 1993 1992
----------------- ----------------- -----------------
HEALTH LIFE TOTAL HEALTH LIFE TOTAL HEALTH LIFE TOTAL
------------------------------------------------------------------------------
Cost of benefits
earned during
the year $23 $ 4 $ 27 $23 $ 3 $ 26 $23 $ 4 $ 27
Interest cost on
benefit obligation 71 31 102 76 30 106 70 30 100
------------------------------------------------------------------------------
Net post-retirement
benefits expense $94 $35 $129 $99 $33 $132 $93 $34 $127
==============================================================================
For measurement purposes, separate health care cost-trend rates were utilized
for pre-age 65 and post-age 65 retirees. The 19941995 annual rates of increase were
assumed to be 8.04.0 percent and 8.94.3 percent, respectively, increasing to 8.5
percent and 7.7 percent in 1996 and gradually decreasing thereafter to the
average ultimate rates of 5.96.0 percent in 19972000 for pre-age 65 and 5.45.0 percent in
19972000 for post-age 65. An increase in the assumed health care cost-trend rates
of 1 percent in each year would increase the aggregate of service and interest
cost for the year 19931994 by $19$13 and would increase the December 31, 19931994
accumulated postretirement benefit obligation (APBO) by $166.$105.
At December 31, 19931994, the weighted average discount rate was 7.258.75 percent and
the assumed rate of compensation increase related to the measurement of the
life insurance benefit was 5.0 percent.
FS-28
NOTE 17. OTHER CONTINGENT LIABILITIES AND COMMITMENTS The U.S. federal income
tax and California franchise tax liabilities of the company have been settled
through 1976 and 1987, respectively. 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. The
Indonesia issue applies only to years after 1982. Settlement of open tax
matters is not expected to have a material effect on the consolidated financial positionnet
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.
The Internal Revenue Service (IRS) has asserted
tax deficiencies against the other three stockholders of Arabian American Oil
Co. (Aramco) regarding the pricing of crude oil purchased from Saudi Arabia
during the period 1979 through 1981. In December 1993, the U.S. Tax Court
ruled in favor of Exxon and Texaco on this issue. It is not known if the IRS
will appeal this decision. The IRS may have until late 1995 to appeal since
other tax issues related to the 1979-81 period must be resolved. Chevron has
not received any proposed tax deficiency concerning this issue. In July 1991,
the IRS issued a "Designated Summons" that requires Chevron to produce
additional documents in connection with the Saudi pricing issue. The
Designated Summons extends the statutory period for assessing additional tax.
As directed by the District Court, Chevron completed production of documents
before year-end 1993. Further motions regarding compliance with the Summons
are expected in 1994. After Chevron complies with the Summons, the IRS may
propose tax deficiencies similar to those asserted against other Aramco
stockholders. The company believes that it properly accounted for the Saudi
crude in its tax return and that it owes no additional U.S. taxes.
At December 31, 1993,1994, the company and its subsidiaries, as direct or indirect
guarantors, had contingent liabilities of $234$249 for notes of affiliated
companies and $45$55 for notes of others.
The company and its subsidiaries have certain other contingent liabilities with
respect to guaranteeslong-term unconditional purchase obligations and claimscommitments,
throughput agreements and has long-termtake-or-pay agreements, some of which relate to
suppliers' financing arrangements. The aggregate amount of required payments
under these various commitments are: 1995-$141; 1996-$137; 1997-$102; 1998-$89;
1999-$86; 2000 and after-$497. Total payments under variousthe agreements the paymentswere $154 in
1994, $142 in 1993 and future commitments for which are not
material$128 in the aggregate.
In September 1990, the Minerals Management Service of the U.S. Department of
the Interior (the Service) issued a preliminary determination letter to the
effect that the company owed additional royalty payments on natural gas the
company produced from federal leasehold interests and sold under long-term
supply contracts. The company made royalty payments based on the contract
price received, rather than on the basis of published weighted average gas
prices, which were higher. The company has submitted an answer refuting the
preliminary determination. The Service has the matter under review and has
not rendered an order directing payment. However, the parties are continuing
to explore settlement.1992.
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 claimsPRO claimed the company
overrecouped under the regulations by $125 during the period in question.
Including interest through December 1993,1994, the total claim amounted to $273.$295. The
DOE is seeking to increase the claim by an additional $42, plus interest, of
alleged over-recovery. The company asserts that in fact it incurred a loss
through participation in the DOE program. TheDiscovery has been completed and
evidentiary hearings are in progress before the Office of Hearings and Appeals has granted Chevron's
motion for evidentiary hearing and discovery. No date has yet been set for the
evidentiary hearing.Appeals.
The company is subject to loss contingencies pursuant to environmental laws and
regulations that in the future may require the company to take action to
correct or ameliorate the effects on the environment of prior disposal or
release of chemical or petroleum substances by the company or other parties.
Such contingencies may exist for various sites including, but not limited to:
Superfund sites operating refineries, closedand refineries, oil fields, service stations, terminals and
land development areas.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 insurance.third parties. While the company provides 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's operations, particularly oil and gas exploration and production,
can be affected by changing economic, regulatory and political environments in
the various countries, including the United States, in which it operates. In
certain locations, host governments have imposed restrictions, controls and
taxes, and, in others, political conditions have existed that may threaten the
safety of employees and the company's continued presence in those countries.
Internal unrest or strained relations between a host government and the company
or other governments may affect the company's operations. Those developments
have, at times, significantly affected the company's related operations and
results, and are carefully considered by management when evaluating the level
of current and future activity in such countries.
Areas in which the company has significant operations include the United
States, Australia, United Kingdom, Canada, Nigeria, Angola, Congo, Papua New
Guinea, China, Indonesia and Zaire. The company's Caltex affiliates have
significant operations in Indonesia, Japan, Korea, Australia, the Philippines,
Thailand and South Africa. The company's Tengizchevroil affiliate operates in
Kazakhstan.
FS-29
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
Unaudited
In accordance with Statement of Financial Accounting Standards No. 69,
"Disclosures about Oil and Gas Producing Activities" (SFAS 69), this section
provides supplemental information on oil and gas exploration and producing
activities of the company in six separate tables. The first three tables
provide historical cost information pertaining to costs incurred in
exploration, property acquisitions and development; capitalized costs; and
results of operations. Tables IV through VI present information on the
company's estimated net proved reserve quantities, standardized measure of
estimated discounted future net cash flows related to proved reserves, and
changes in estimated discounted future net cash flows. The Africa geographic
area includes activities in Nigeria, Angola, Zaire, Congo and other countries.
The "Other" geographic category includes activities in Australia, the United
Kingdom North Sea, Canada, Papua New Guinea Australia and other countries. Amounts
shown for affiliated companies are Chevron's 50 percent equity share in each
of P.T. Caltex Pacific Indonesia (CPI), an exploration and production company
operating in Indonesia, and Tengizchevroil (TCO), an exploration and
production company operating in the Republic of Kazakhstan, which began
operations in April 1993.
TABLE I - COSTS INCURRED IN EXPLORATION,
PROPERTY ACQUISITIONS AND DEVELOPMENT (1)
Consolidated Companies
- ------------------------------------------------------
Millions of Affiliated
dollars U.S. Africa Other Total Companies Worldwide
- -----------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1993
Exploration
Wells $ 123 $ 57 $126 $ 306 $ 1 $ 307
Geological and
geophysical 12 40 40 92 9 101
Rentals and other 48 7 70 125 - 125
- -----------------------------------------------------------------------------
Total exploration 183 104 236 523 10 533
- -----------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) 12 - 14 26 276 302
Unproved 11 9 10 30 420 450
- -----------------------------------------------------------------------------
Total property
acquisitions 23 9 24 56 696 752
- -----------------------------------------------------------------------------
Development 475 239 566 1,280 171 1,451
- -----------------------------------------------------------------------------
Total Costs
Incurred $ 681 $352 $826 $1,859 $877(4) $2,736
=============================================================================
YEAR ENDED DECEMBER 31, 1992
Exploration
Wells $ 96 $ 59 $ 83 $ 238 $ 1 $ 239
Geological and
geophysical 84 48 137 269 8 277
Rentals and other 9 1 21 31 - 31
- -----------------------------------------------------------------------------
Total exploration 189 108 241 538 9 547
- -----------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) 19 - 36 55 - 55
Unproved 16 1 10 27 - 27
- -----------------------------------------------------------------------------
Total property
acquisitions 35 1 46 82 - 82
- -----------------------------------------------------------------------------
Development 483 189 682 1,354 171 1,525
- -----------------------------------------------------------------------------
Total Costs
Incurred $ 707 $298 $969 $1,974 $180 $2,154
=============================================================================
YEAR ENDED DECEMBER 31, 1991
Exploration
Wells $ 205 $ 65 $150 $ 420 $ 1 $ 421
Geological and
geophysical 98 45 164 307 8 315
Rentals and other 18 2 8 28 2 30
- -----------------------------------------------------------------------------
Total exploration 321 112 322 755 11 766
- -----------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) - 1 4 5 - 5
Unproved 59 8 33 100 - 100
- -----------------------------------------------------------------------------
Total property
acquisitions 59 9 37 105 - 105
- -----------------------------------------------------------------------------
Development 665 152 569 1,386 164 1,550
- -----------------------------------------------------------------------------
Total Costs
Incurred $1,045 $273 $928 $2,246 $175 $2,421
- -----------------------------------------------------------------------------
(1) Includes costs incurred whether capitalized or charged to earnings.
Excludes support equipment expenditures.
(2) Proved amounts include wells, equipment and facilities associated
with proved reserves; unproved represents amounts for equipment
and facilities not associated with the production of proved reserves.
(3) Does not include properties acquired through property exchanges.
(4) In 1993, Total Costs Incurred for affiliated companies includes
$146 for CPI.
CONSOLIDATED COMPANIES AFFILIATED COMPANIES
-------------------------------------------- --------------------
MILLIONS OF DOLLARS U.S. AFRICA OTHER TOTAL CPI TCO WORLDWIDE
---------------------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 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 31, 1993
Exploration
Wells $123 $ 57 $126 $ 306 $ 1 $ - $ 307
Geological and geophysical 12 40 40 92 9 - 101
Rentals and other 48 7 70 125 - - 125
---------------------------------------------------------------------------------------------------------------------------------
Total exploration 183 104 236 523 10 - 533
---------------------------------------------------------------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) 12 - 14 26 - 276 302
Unproved 11 9 10 30 - 420 450
---------------------------------------------------------------------------------------------------------------------------------
Total property acquisitions 23 9 24 56 - 696 752
---------------------------------------------------------------------------------------------------------------------------------
Development 475 239 566 1,280 136 35 1,451
---------------------------------------------------------------------------------------------------------------------------------
Total Costs Incurred $681 $352 $826 $1,859 $146 $731 $2,736
=================================================================================================================================
YEAR ENDED DECEMBER 31, 1992
Exploration
Wells $ 96 $ 59 $ 83 $ 238 $ 1 $ - $ 239
Geological and geophysical 84 48 137 269 8 - 277
Rentals and other 9 1 21 31 - - 31
---------------------------------------------------------------------------------------------------------------------------------
Total exploration 189 108 241 538 9 - 547
---------------------------------------------------------------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) 19 - 36 55 - - 55
Unproved 16 1 10 27 - - 27
---------------------------------------------------------------------------------------------------------------------------------
Total property acquisitions 35 1 46 82 - - 82
---------------------------------------------------------------------------------------------------------------------------------
Development 483 189 682 1,354 171 - 1,525
---------------------------------------------------------------------------------------------------------------------------------
Total Costs Incurred $707 $298 $969 $1,974 $180 $ - $2,154
=================================================================================================================================
(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-30
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued
Unaudited
TABLE II - CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
Consolidated Companies
- -------------------------------------------------------
Affiliated
Millions of dollars U.S. Africa Other Total Companies Worldwide
- -----------------------------------------------------------------------------
AT DECEMBER 31, 1993
Unproved properties $ 404 $ 31 $ 206 $ 641 $ 420 $ 1,061
Proved properties
and related
producing assets 15,655 1,528 4,646 21,829 1,005 22,834
Support equipment 750 105 303 1,158 546 1,704
Deferred
exploratory wells 139 23 60 222 - 222
Other uncompleted
projects 269 296 879 1,444 466 1,910
- -----------------------------------------------------------------------------
Gross capitalized
costs 17,217 1,983 6,094 25,294 2,437 27,731
- -----------------------------------------------------------------------------
Unproved properties
valuation 280 20 103 403 - 403
Proved producing
properties -
Depreciation and
depletion 9,645 799 2,467 12,911 386 13,297
Future abandonment
and restoration 1,002 195 276 1,473 13 1,486
Support equipment
depreciation 338 52 149 539 238 777
- -----------------------------------------------------------------------------
Accumulated
provisions 11,265 1,066 2,995 15,326 637 15,963
- -----------------------------------------------------------------------------
Net Capitalized
Costs $ 5,952 $ 917 $3,099 $ 9,968 $1,800* $11,768
=============================================================================
AT DECEMBER 31, 1992
Unproved properties $ 481 $ 23 $ 217 $ 721 $ - $ 721
Proved properties
and related
producing assets 15,682 1,358 4,087 21,127 622 21,749
Support equipment 685 92 270 1,047 374 1,421
Deferred
exploratory wells 100 30 66 196 1 197
Other uncompleted
projects 443 203 910 1,556 368 1,924
- -----------------------------------------------------------------------------
Gross capitalized
costs 17,391 1,706 5,550 24,647 1,365 26,012
- -----------------------------------------------------------------------------
Unproved properties
valuation 327 17 110 454 - 454
Proved producing
properties -
Depreciation and
depletion 9,276 700 2,225 12,201 335 12,536
Future abandonment
and restoration 967 168 226 1,361 13 1,374
Support equipment
depreciation 296 50 133 479 218 697
- -----------------------------------------------------------------------------
Accumulated
provisions 10,866 935 2,694 14,495 566 15,061
- -----------------------------------------------------------------------------
Net Capitalized
Costs $ 6,525 $ 771 $ 2,856 $10,152 $ 799 $10,951
=============================================================================
AT DECEMBER 31, 1991
Unproved properties $ 658 $ 24 $ 389 $ 1,071 $ - $ 1,071
Proved properties
and related
producing assets 18,088 1,212 3,925 23,225 534 23,759
Support equipment 658 90 212 960 347 1,307
Deferred
exploratory wells 109 50 124 283 1 284
Other uncompleted
projects 528 179 656 1,363 322 1,685
- -----------------------------------------------------------------------------
Gross capitalized
costs 20,041 1,555 5,306 26,902 1,204 28,106
- -----------------------------------------------------------------------------
Unproved properties
valuation 429 12 110 551 - 551
Proved producing
properties -
Depreciation and
depletion 10,322 613 2,166 13,101 299 13,400
Future abandonment
and restoration 1,024 147 216 1,387 12 1,399
Support equipment
depreciation 262 60 117 439 203 642
- -----------------------------------------------------------------------------
Accumulated
Provisions 12,037 832 2,609 15,478 514 15,992
- -----------------------------------------------------------------------------
Net Capitalized
Costs $ 8,004 $ 723 $2,697 $11,424 $ 690 $12,114
=============================================================================
*At December 31, 1993, Net Capitalized Costs for affiliated companies
includes $860 for CPI.
CONSOLIDATED COMPANIES AFFILIATED COMPANIES
-------------------------------------------- --------------------
MILLIONS OF DOLLARS U.S. AFRICA OTHER TOTAL CPI TCO WORLDWIDE
---------------------------------------------------------------------------------------------------------------------------------
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
=================================================================================================================================
AT DECEMBER 31, 1992
Unproved properties $ 481 $ 23 $ 217 $ 721 $ - $ - $ 721
Proved properties and
related producing assets 15,682 1,358 4,087 21,127 622 - 21,749
Support equipment 685 92 270 1,047 374 - 1,421
Deferred exploratory wells 100 30 66 196 1 - 197
Other uncompleted projects 443 203 910 1,556 368 - 1,924
---------------------------------------------------------------------------------------------------------------------------------
Gross capitalized costs 17,391 1,706 5,550 24,647 1,365 - 26,012
---------------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation 327 17 110 454 - - 454
Proved producing properties -
Depreciation and depletion 9,276 700 2,225 12,201 335 - 12,536
Future abandonment and restoration 967 168 226 1,361 13 - 1,374
Support equipment depreciation 296 50 133 479 218 - 697
---------------------------------------------------------------------------------------------------------------------------------
Accumulated provisions 10,866 935 2,694 14,495 566 - 15,061
---------------------------------------------------------------------------------------------------------------------------------
Net Capitalized Costs $ 6,525 $ 771 $2,856 $10,152 $ 799 $ - $10,951
=================================================================================================================================
FS-31
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued
Unaudited
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1)
The company's results of operations from oil and gas producing activities for
the years 1994, 1993 1992 and 19911992 are shown below.
Net income from exploration and production activities as reported on Page
FS-6 includes the allocation of corporate overhead andpage FS-7
reflects income taxes computed on an effective rate basis. In accordance with
SFAS 69, allocated corporate overhead is excluded from
the results below, and income taxes 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 and 1992 reported on
page FS-7 includes allocated corporate overhead, but 1994 does not. Interest
expense is excluded from boththe results reported results.
Consolidated Companies
- -------------------------------------------------------
Affiliated
Millions of dollars U.S. Africa Other Total Companies Worldwide
- -----------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1993
Revenuesbelow and from the net production
Sales $1,539 $ 247 $ 779 $2,565 $ 63 $2,628
Transfers 1,912 1,040 661 3,613 487 4,100
- -----------------------------------------------------------------------------
Total 3,451 1,287 1,440 6,178 550 6,728
Production expenses (1,274) (208) (402) (1,884) (204) (2,088)
Proved producing
properties
depreciation,
depletion and
abandonment
provision (958) (126) (311) (1,395) (58) (1,453)
Exploration expenses (99) (79) (174) (352) (9) (361)
Unproved properties
valuation (31) (4) (12) (47) - (47)
Other income
(expense) (2) 20 - 8 28 6 34
- -----------------------------------------------------------------------------
Results before
income taxes 1,109 870 549 2,528 285 2,813
Income tax expense (422) (625) (243) (1,290) (152) (1,442)
- -----------------------------------------------------------------------------
RESULTS OF PRODUCING
OPERATIONS $ 687 $ 245 $ 306 $1,238 $133* $1,371
=============================================================================
YEAR ENDED DECEMBER 31, 1992
Revenues from net
production
Sales $1,558 $ 365 $ 816 $2,739 $ 19 $2,758
Transfers 2,301 1,097 580 3,978 519 4,497
- -----------------------------------------------------------------------------
Total 3,859 1,462 1,396 6,717 538 7,255
Production expenses (1,477) (194) (508) (2,179) (153) (2,332)
Proved producing
properties
depreciation,
depletion and
abandonment
provision (1,126) (110) (301) (1,537) (38) (1,575)
Exploration expenses (182) (79) (226) (487) (8) (495)
Unproved properties
valuation (38) (5) (17) (60) - (60)
Other income
(expense) (2) 431 27 72 530 (15) 515
- -----------------------------------------------------------------------------
Results before
income taxes 1,467 1,101 416 2,984 324 3,308
Income tax expense (420) (856) (231) (1,507) (170) (1,677)
- -----------------------------------------------------------------------------
Results of Producing
Operations $1,047 $ 245 $ 185 $1,477 $154 $1,631
=============================================================================
YEAR ENDED DECEMBER 31, 1991
Revenues from net
production
Sales $1,609 $ 268 $ 694 $2,571 $ 20 $2,591
Transfers 2,364 1,138 778 4,280 563 4,843
- -----------------------------------------------------------------------------
Total 3,973 1,406 1,472 6,851 583 7,434
Production expenses (1,870) (149) (439) (2,458) (148) (2,606)
Proved producing
properties
depreciation,
depletion and
abandonment
provision (1,259) (100) (252) (1,611) (35) (1,646)
Exploration expenses (220) (92) (298) (610) (10) (620)
Unproved properties
valuation (77) (3) (21) (101) - (101)
Other income
(expense) (2) 107 (5) 117 219 (15) 204
- -----------------------------------------------------------------------------
Results before
income taxes 654 1,057 579 2,290 375 2,665
Income tax expense (246) (894) (403) (1,543) (212) (1,755)
- -----------------------------------------------------------------------------
Results of Producing
Operations $ 408 $ 163 $ 176 $ 747 $163 $ 910
=============================================================================
*For 1993, Results of Producing Operations for affiliated companies
includes $134 for CPI.amounts on page FS-7.
CONSOLIDATED COMPANIES AFFILIATED COMPANIES
-------------------------------------------- --------------------
MILLIONS OF DOLLARS U.S. AFRICA OTHER TOTAL CPI TCO WORLDWIDE
---------------------------------------------------------------------------------------------------------------------------------
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 (2) (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) (3) 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) (3) 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
=================================================================================================================================
YEAR ENDED DECEMBER 31, 1992
Revenues from net production
Sales $1,558 $ 365 $ 816 $ 2,739 $ 19 $ - $ 2,758
Transfers 2,301 1,097 580 3,978 519 - 4,497
---------------------------------------------------------------------------------------------------------------------------------
Total 3,859 1,462 1,396 6,717 538 - 7,255
Production expenses (1,477) (194) (508) (2,179) (153) - (2,332)
Proved producing properties depreciation,
depletion and abandonment provision (1,126) (110) (301) (1,537) (38) - (1,575)
Exploration expenses (182) (79) (226) (487) (8) - (495)
Unproved properties valuation (38) (5) (17) (60) - - (60)
Other income (expense) (3) 431 27 72 530 (15) - 515
---------------------------------------------------------------------------------------------------------------------------------
Results before income taxes 1,467 1,101 416 2,984 324 - 3,308
Income tax expense (420) (856) (231) (1,507) (170) - (1,677)
---------------------------------------------------------------------------------------------------------------------------------
Results of Producing Operations $1,047 $ 245 $ 185 $ 1,477 $ 154 $ - $ 1,631
=================================================================================================================================
FS-32
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued
Unaudited
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING
ACTIVITIES (1) - Continued
Per Unit Average Consolidated Companies
Sales Price and ------------------------------
Production Affiliated
Cost (1), (3) U.S. Africa Other Total Companies Worldwide
- -----------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1993
Average sales prices
Liquids,
per barrel $14.48 $16.21 $16.06 $15.33 $13.06 $15.05
Natural gas,
per thousand
cubic feet 1.98 - 2.08 2.00 .13 1.99
Average production
costs, per barrel 4.91 2.62 4.22 4.34 4.77 4.38
=============================================================================
YEAR ENDED DECEMBER 31, 1992
Average sales prices
Liquids,
per barrel $16.02 $18.40 $17.66 $17.00 $14.87 $16.77
Natural gas,
per thousand
cubic feet 1.69 - 1.96 1.73 - 1.73
Average production
costs, per barrel 5.11 2.44 5.85 4.78 4.23 4.74
=============================================================================
YEAR ENDED DECEMBER 31, 1991
Average sales prices
Liquids,
per barrel $16.73 $19.00 $18.36 $17.63 $15.25 $17.36
Natural gas,
per thousand
cubic feet 1.53 - 2.24 1.63 - 1.63
Average production
costs, per barrel 6.29 2.01 5.10 5.37 3.87 5.26
=============================================================================
Average sales price
for liquids
($/bbl.)
DECEMBER 1993 $10.73 $12.94 $13.63 $12.05 $10.46 $11.82
December 1992 15.22 17.60 17.26 16.35 14.15 16.07
December 1991 15.08 17.39 18.76 16.43 14.38 16.19
=============================================================================
Average sales price
for natural gas
($/MCF)
DECEMBER 1993 $ 2.19 $ - $ 2.34 $ 2.21 $ .26 $ 2.20
December 1992 2.17 - 1.99 2.14 - 2.14
December 1991 1.93 - 2.51 2.00 - 2.00
=============================================================================
(1) The value of owned production consumed as fuel has been eliminated
from revenues and production expenses, and the related volumes have
been deducted from net production in calculating the per unit average
sales price and production cost. This has no effect on the amount of
Results of Producing Operations.
(2) Includes gas-processing fees, net sulfur income, natural gas contract
settlements, currency transaction gains and losses, miscellaneous
expenses, etc. In 1993, the United States includes before-tax losses
on property dispositions and other special charges totaling $150.
In 1992, before-tax gains on property dispositions of $326 in the
United States were offset partially by net charges of $44 for
severance programs, regulatory issues and other adjustments; Other
includes $192 of before-tax gains on sales of producing and
nonproducing properties, partially offset by a before-tax charge of
$165 for the write-down of Beaufort Sea properties. In 1991, losses
and property dispositions in the United States were offset by
favorable adjustments to litigation and other reserves; the Other
geographic segment included $89 of before-tax gains on property
dispositions.
(3) Natural gas converted to crude oil equivalent gas (OEG) barrels at a
rate of 6 MCF=1 OEG barrel.
CONSOLIDATED COMPANIES AFFILIATED COMPANIES
PER UNIT AVERAGE SALES PRICE AND -------------------------------------------- --------------------
PRODUCTION COST (1),(4) U.S. AFRICA OTHER TOTAL CPI TCO WORLDWIDE
---------------------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1994
Average sales prices
Liquids, per barrel $13.55 $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
=================================================================================================================================
YEAR ENDED DECEMBER 31, 1992
Average sales prices
Liquids, per barrel $16.02 $18.40 $17.66 $17.00 $14.87 $ - $16.77
Natural gas, per thousand cubic feet 1.69 - 1.96 1.73 - - 1.73
Average production costs, per barrel 5.11 2.44 5.85 4.78 4.23 - 4.74
=================================================================================================================================
Average sales price for liquids ($/bbl.)
DECEMBER 1994 $13.80 $15.20 $14.35 $14.36 $13.10 $10.54 $14.12
December 1993 10.73 12.94 13.63 12.05 10.72 8.58 11.82
December 1992 15.22 17.60 17.26 16.35 14.15 - 16.07
=================================================================================================================================
Average sales price for natural gas ($/MCF)
DECEMBER 1994 $ 1.62 $ - $ 1.73 $ 1.64 $ - $ .57 $ 1.63
December 1993 2.19 - 2.34 2.21 - .26 2.20
December 1992 2.17 - 1.99 2.14 - - 2.14
=================================================================================================================================
(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) PRODUCTION EXPENSE IN THE U.S. IN 1994 INCLUDES $13 FOR COSTS THAT IN PRIOR YEARS WERE CONSIDERED CORPORATE OVERHEAD AND
EXCLUDED FROM THE RESULTS OF PRODUCING OPERATIONS.
(3) INCLUDES GAS-PROCESSING FEES, NET SULFUR INCOME, NATURAL GAS CONTRACT SETTLEMENTS, CURRENCY TRANSACTION GAINS AND LOSSES,
MISCELLANEOUS EXPENSES, ETC. IN 1994, THE UNITED STATES INCLUDES 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. IN 1992, BEFORE-TAX GAINS ON PROPERTY
DISPOSITIONS OF $326 IN THE UNITED STATES WERE OFFSET PARTIALLY BY NET CHARGES OF $44 FOR SEVERANCE PROGRAMS, REGULATORY
ISSUES AND OTHER ADJUSTMENTS; OTHER INCLUDES $192 OF BEFORE-TAX GAINS ON SALES OF PRODUCING AND NONPRODUCING PROPERTIES,
PARTIALLY OFFSET BY A BEFORE-TAX CHARGE OF $165 FOR THE WRITE-DOWN OF BEAUFORT SEA PROPERTIES.
(4) 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 1994, 1993 1992 and 19911992 are shown in the following table.
These quantities are estimated by the company's reserves engineers and reviewed
by the company's Reserves Advisory Committee using reserve definitions
prescribed by the Securities and Exchange Commission.
Proved reserves are the estimated quantities that geologic and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Due to the
inherent uncertainties and the limited nature of reservoir data, estimates of
underground reserves are subject to change over time as additional information
becomes available.
Proved reserves do not include additional quantities recoverable beyond the
term of lease or contract unless renewal is reasonably certain, or that may
result from extensions of currently proved areas, or from application of
secondary or tertiary recovery processes not yet tested and determined to be
economic.
Proved developed reserves are the quantities expected to be recovered through
existing wells with existing equipment and operating methods.
"Net" reserves exclude royalties and interests owned by others and reflect
contractual arrangements and royalty obligations in effect at the time of the
estimate.
Upon formation ofProved reserves for Tengizchevroil (TCO), the Tengizchevroil joint venture in April 1993, the
company recognized 1.1 billion barrels of net proved crude oil and natural
gas liquids reserves and 1.5 trillion cubic feet of net natural gas
reserves, which represented itscompany's 50 percent ownership.owned
affiliate in Kazakhstan, do not include reserves that will be produced when a
dedicated export system is in place.
FS-33
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued
Unaudited
TABLE IV - RESERVE QUANTITIES INFORMATION - Continued
NET PROVED RESERVES OF CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET PROVED RESERVES OF NATURAL GAS
Millions of barrels Billions of cubic feet
------------------------------------------------------ ----------------------------------------------------
Consolidated Companies
------------------------------- Consolidated Companies
Affiliated ------------------------------ AffiliatedAND NATURAL GAS LIQUIDS MILLIONS OF BARRELS BILLIONS OF CUBIC FEET
--------------------------------------------------- ---------------------------------------------------
CONSOLIDATED COMPANIES AFFILIATES CONSOLIDATED COMPANIES AFFILIATES
--------------------------- ------------- WORLD- ----------------------------- ------------- WORLD-
U.S. Africa Other Total Companies WorldwideAFRICA OTHER TOTAL CPI TCO WIDE U.S. Africa Other Total Companies Worldwide
- ----------------------------------------------------------------------------- ---------------------------------------------------AFRICA OTHER TOTAL CPI TCO WIDE
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