ITEM 1. BUSINESS
(a) GENERAL DEVELOPMENT OF BUSINESS
SUMMARY DESCRIPTION OF CHEVRON - ------------------------------ Chevron Corporation (1), a Delaware corporation, is a major international oil company. It provides administrative, financial and management support for, and manages its investments in, domestic and foreign subsidiaries and affiliates, which engage in fully integrated petroleum operations, chemical operations, real estate development and other mineral and energy related activities in the United States and approximately 100 other countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; transporting crude oil, natural gas and petroleum products by pipelines, marine vessels and motor equipment; refining crude oil into finished petroleum products; and marketing crude oil, natural gas and the many products derived from petroleum. Chemical operations include the manufacture and marketing of a wide range of chemicals for industrial uses.
Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984. Domestic integrated petroleum operations are conducted primarily through three divisions of the company's wholly owned Chevron U.S.A. Inc. subsidiary. Exploration and production operations in the United States are carried out through Chevron U.S.A. Production Company. U.S. refining and marketing activities are performed by Chevron U.S.A. Products Company. Warren Petroleum Company engages in all phases of the domestic natural gas liquids business. A list of the company's major subsidiaries is presented on page 40 of this Annual Report on Form 10-K. As of December 31, 1993, Chevron had 47,576 employees, 78 percent of whom were employed in U.S. operations.
OVERVIEW OF PETROLEUM INDUSTRY - ------------------------------ Petroleum industry operations and profitability are influenced by a large number of factors, over some of which individual oil and gas companies have little control. Governmental attitudes and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on petroleum activities, regulating where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil and natural gas, petroleum products and petrochemicals are determined by supply and demand for these commodities. OPEC member countries are the world's swing producers of crude oil and their production levels are the primary driver in determining worldwide supply. Demand for crude oil and its products is largely driven by the health of local, national and worldwide economies, although weather patterns and taxation relative to other energy sources also play a significant part. Natural gas is generally produced and consumed on a country or regional basis. Its largest use is for electrical generation, where it competes with other energy fuels.
CURRENT OPERATING ENVIRONMENT - ----------------------------- Crude oil prices rose slightly in the first quarter of 1993 and remained steady through the second quarter before trending downward for the remainder of the year. The decline was particularly prominent during the last two months of 1993, with prices reaching their lowest level in five years by year end. The weak global economy has dampened the demand for petroleum and petroleum related products. Increased production from non-OPEC countries, particularly from the North Sea, and OPEC's failure to adjust their production levels accordingly has further exacerbated the decline in crude oil prices. Partially mitigating the effects of
- ------------------ (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.
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lower crude oil prices were higher natural gas prices. Unseasonable weather patterns, low gas storage levels, the loss of three nuclear power plants in the Southeast for a portion of the year, and the environmentally preferred attributes of natural gas all contributed to the stronger natural gas prices. In the United States, the Henry Hub, Louisiana spot price for natural gas, a common benchmark for natural gas prices, averaged $2.21 per thousand cubic feet (MCF) in 1993, an increase of $.41 per MCF over 1992. Strong refined product prices, which did not decline as rapidly as crude oil prices, also helped to dampen the effects of lower crude oil prices. However, product prices in the United States fell late in the year and have remained low into 1994. If both crude oil and refined product prices continue at their low levels, the company's earnings and cash flow from ongoing operations may be negatively affected. Widely fluctuating prices have become characteristic of the petroleum industry for the past several years.
Chevron's average realization from U.S. crude oil production declined from $16.50 per barrel in 1992 to $14.58 per barrel in 1993 while average liquids realizations from international liftings, including equity affiliates, declined by $1.84 per barrel to $16.09 per barrel. Average U.S. natural gas realizations from production increased to $1.99 per MCF in 1993 from $1.70 per MCF in 1992.
The following table compares the high, low and average company posted prices for West Texas Intermediate (WTI), an industry benchmark light crude oil, for each of the quarters during 1993 and for the full years of 1993, 1992, and 1991:
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WEST TEXAS INTERMEDIATE CRUDE OIL CHEVRON POSTED PRICES (Dollars per Barrel)
------------------------------------- 1st Q 2nd Q 3rd Q 4th Q Year 1992 1991 ----- ----- ----- ----- ----- ----- ----- High 20.25 19.75 18.00 18.00 20.25 21.75 29.50 Low 17.50 18.00 16.00 13.00 13.00 16.50 16.75 Average 19.09 19.10 17.01 15.58 17.68 19.71 20.20 - ----------------------------------------------------------------------
For the first two months of 1994, average natural gas realizations for the company's U.S. operations were $2.14 per MCF. During this period, the company's posted price for WTI ranged from $13.00 per barrel to $15.00 with an average of $13.86. On March 21, 1994, the company's posted price for WTI was $14.25 per barrel.
CHEVRON STRATEGIC DIRECTION - --------------------------- To improve financial performance and to compete more effectively, Chevron developed and began implementing seven "strategic intents" in 1992. These are to:
- - SHIFT EXPLORATION AND PRODUCTION EMPHASIS TO INTERNATIONAL OPPORTUNITIES. The company believes opportunities to discover and develop major new reserves in the United States are limited due to regulatory barriers and drilling prohibitions on many of the most promising areas of development. In 1993, 68 percent of the exploration and production capital spending, including affiliates, was allocated to international operations. In 1994, that number is expected to increase to 75 percent. As recently as 1990, U.S. exploration and production capital spending was approximately 50 percent of the total. As an important example of this new emphasis, in April 1993, the company entered into a joint venture agreement with the Republic of Kazakhstan to develop the massive Tengiz oil field in that country.
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- - GENERATE $1 BILLION IN CASH ANNUALLY FROM U.S. EXPLORATION AND PRODUCTION OPERATIONS. Chevron is emphasizing a steady cash flow from a core group of approximately 400 oil and gas fields concentrated in California, Texas, the Rocky Mountains and the Gulf of Mexico. In 1993, net cash flow after capital and exploratory expenditures for U.S. exploration and production operations was more than $1.2 billion. Lower operating expenses and an improved natural gas market helped to mitigate the effects of lower crude oil prices. If crude oil prices do not rebound, this goal may be difficult to achieve in 1994.
- - RESHAPE THE U.S. REFINING AND MARKETING COMPANY INTO A TOP COMPETITOR. Chevron is currently the leading U.S. marketer of refined products and has the largest refining capacity in the nation. The company is seeking to strengthen its competitive position by investing in core refineries, reducing the size of its refining system and concentrating on specific marketing regions. Major projects are continuing at the company's Richmond and El Segundo, California refineries in order to produce reformulated fuels to meet the January 1995 emission requirements of the Clean Air Act Amendments of 1990 and the 1996 requirements of the California Air Resources Board. The company expects to complete the sale of its Philadelphia, Pennsylvania and Port Arthur, Texas refineries in 1994, thereby reducing its refining capacity about 25 percent.
- - GROW CALTEX IN ATTRACTIVE MARKETS. Management believes that the demand for petroleum products will continue to grow in the Asia Pacific region and Chevron's 50 percent owned Caltex affiliate, a leading competitor in these areas, has made significant capital investments to expand and upgrade its refining capacity. Refinery upgrade projects are currently underway in Singapore and Korea, as well as the construction of a new refinery in Thailand.
- - EXPLOIT COMPETITIVE STRENGTHS IN CHEMICALS. The petrochemical industry is highly cyclical. In order to improve its competitive position, the company is concentrating on areas of the petrochemical business in which it holds a competitive advantage, such as in its proprietary Aromax (R) process used to produce high value benzene from low value by-products of the oil refining process. The first Aromax (R) plant in the U.S., located at the company's Pascagoula, Mississippi, refinery, was completed in 1993. The company also announced, in January 1994, a cost reduction plan intended to reduce annual operating expense by approximately $100 million by 1996. An integral part of the plan is to divest or close non-core assets and sharpen the company's focus on the remaining core businesses.
- - BE SELECTIVE IN NON-CORE BUSINESSES. In 1993, Chevron continued to dispose of marginally performing or non-strategic assets, including various oil and gas properties located in the United States and Indonesia. The company also divested its ORTHO lawn and garden products business, retail marketing operations in Guatemala, Nicaragua and El Salvador, certain undeveloped coal properties in the U.S., and its Vinwood Cellars Winery in California. Properties currently for sale include the company's 52.5 percent interest in some zinc-lead prospects in Ireland, refineries located in Philadelphia, Pennsylvania and Port Arthur, Texas, and the company's headquarters building located in San Francisco, California.
- - FOCUS ON REDUCING COSTS ACROSS ALL ACTIVITIES. Chevron undertook an extensive cost-cutting and work force reduction program in early 1992. These efforts, in combination with the company's continuing program to dispose of non-core or underperforming assets, reduced 1993 operating costs, adjusted for special items, by approximately 5 percent or 40 cents a barrel from 1992 levels. When compared to the base year of 1991, ongoing operating, selling and administrative expenses have dropped by 11 percent, or 94 cents a barrel. To remain competitive, the company's management has set a number of new goals, including a new cost-reduction target of an additional 25 cents a barrel by the end of 1994.
In 1993, the company established a new "strategic intent:"
- - BUILD A COMMITTED TEAM TO ACCOMPLISH THE CORPORATE MISSION. The company believes the success of the other seven strategic intents is dependent on the commitment and dedication that Chevron employees bring to their jobs. In a 1992 employee survey and a 1993 update, Chevron measured employee
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commitment using a model that assesses employee's willingness to expend discretionary effort on the job, combined with how strongly they feel the company deserves that effort. The surveys highlighted employee concerns on issues that the company is addressing. Due, in part, to the results of the survey, the company has initiated a number of work and family programs to help employees improve their productivity and commitment, such as flexible schedules, part-time work, job sharing and various leave programs. The company also presented commemorative wristwatches to its employees and a one time cash bonus equal to 5 percent of their annual salaries in appreciation for their efforts in meeting the company's five year goal, established in 1989, to be number one in stockholders' return among five peer U.S. oil companies. In February 1994, the company took delivery of a new vessel, the Chevron Employee Pride, named in honor of its worldwide workforce.
(b) INDUSTRY SEGMENT AND GEOGRAPHIC AREA INFORMATION
The company's primary business is its integrated petroleum operations. Secondary operations include chemicals and minerals. The petroleum activities of the company are widely distributed geographically, with major operations in the United States, Australia, United Kingdom, Canada, Nigeria, Angola, Papua New Guinea, China, Indonesia and Zaire. The company's Caltex affiliate, through its subsidiaries and affiliates, conducts exploration and production operations in Indonesia and refining and marketing activities in the Eastern Hemisphere, with major operations in Japan, Korea, Australia, the Philippines, Thailand and South Africa. Tengizchevroil (TCO), a 50/50 joint venture with a subsidiary of the national oil company of the Republic of Kazakhstan conducts production activities in Kazakhstan, a former Soviet republic.
The company's and its affiliates' chemicals operations are concentrated in the United States, but include operating facilities in France, Japan and Brazil. The company's and its affiliates' principal minerals activities include both coal and platinum and palladium operations in the United States.
Tabulations setting forth three years' identifiable assets, operating income, sales and other operating revenues for the company's three industry segments, by United States and International geographic areas, may be found in Note 9 to the Consolidated Financial Statements beginning on page FS-22 of this Annual Report on Form 10-K.
(c) DESCRIPTION OF BUSINESS AND PROPERTIES
The petroleum industry is highly competitive in the United States and throughout most of the world. This industry also competes with other industries in supplying the energy needs of various types of consumers.
The company's operations can be affected significantly by changing economic, regulatory and political environments in the various countries, including the United States, in which it operates. The company evaluates the economic and political risk of initiating, maintaining or expanding operations in any geographical area.
In the United States, environmental regulations and federal, state and local actions and policies concerning economic development, energy and taxation may have a significant effect on the company's operations.
Internationally, the company is monitoring closely the civil unrest in Angola and the political uncertainty in Nigeria and Zaire and the possible threat these may pose to the company's oil and gas exploration and production operations and the safety of the company's employees located in those countries.
The company attempts to avoid unnecessary involvement in partisan politics in the communities in which it operates but participates in the political process to safeguard its assets and to ensure that the community benefits from its operations and remains receptive to its continued presence.
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CAPITAL AND EXPLORATORY EXPENDITURES
Chevron's capital and exploratory expenditures during 1993 and 1992 are summarized in the following table:
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CAPITAL AND EXPLORATORY EXPENDITURES (Millions of Dollars) 1993 1992 ------ ------ Exploration and Production $2,217 $2,097 Refining, Marketing and Transportation 1,166 1,263 Chemicals 224 251 Coal and Other Minerals 42 79 All Others 90 112 ------ ------ Total Consolidated Companies 3,739 3,802 Equity in Affiliates 701 621 ------ ------ Total Including Affiliates $4,440 $4,423 ====== ====== -------------------------------------------------------
Total consolidated expenditures in 1993 were essentially flat when compared to 1992, declining less than 2 percent between periods. An increase in exploration and production (E&P) expenditures of $120 million was more than offset by lower expenditures in the company's other operations.
Exploration and production expenditures amounted to 59 percent of the company's consolidated expenditures, a 4 percent increase over 1992 levels. The increase was due solely to increased expenditures in international E&P as U.S. E&P expenditures continued to decline, down 4 percentage points to 34 percent of consolidated E&P expenditures in 1993. This decrease reflects the continued shift in the company's emphasis from U.S. exploration and production activities to international opportunities. Major international E&P expenditures in 1993 included development of the Alba Field in the U.K. North Sea, the North West Shelf Project in Australia, the Hibernia Project offshore Newfoundland, the Duri steamflood project in Indonesia, Areas B and C in Angola and the Tengiz project in Kazakhstan. Refining, marketing and transportation outlays in 1993 included expenditures for upgrading U.S. refineries to produce fuels, such as low aromatics and ultra low sulfur diesel fuel and reformulated gasoline, to comply with current and future federal, state and local air quality regulations.
In 1994, the company expects to spend approximately $4.9 billion, including its share of equity affiliates' expenditures, an increase of approximately 11 percent over 1993 levels. Equity affiliate spending, primarily Caltex expenditures in the high growth Pacific Rim areas, account for this increase as consolidated expenditures in 1994 are expected to remain flat at $3.7 billion. E&P expenditures are expected to total $2.4 billion, of which approximately 75 percent will be for international projects such as the continued development of the Hibernia Field, expansion of the North West Shelf Project, enhanced recovery projects in Indonesia, the Tengiz project in Kazakhstan, and other development projects in West Africa. Refining, marketing and transportation expenditures are estimated at $2.1 billion, with U.S. expenditures of about $1 billion, including continued upgrades to U.S. refineries to produce reformulated gasoline in order to comply with the Clean Air Act Amendments of 1990 and California Air Resources Board regulations.
The actual expenditures for 1994 will depend on various conditions affecting the company's operations and may differ significantly from the company's forecast. If low oil prices persist, expenditures, particularly for exploration and production, may be lower than forecast. Significant expenditures are expected over the next few years at the company's manufacturing facilities to comply with federal, state and local environmental regulations and to enable these facilities to produce cleaner fuels for industrial and consumer use.
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PETROLEUM - EXPLORATION
The following table summarizes the company's net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 1993. "Exploratory wells" include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir beyond the proved area. "Wells drilling" include wells temporarily suspended.
- ----------------------------------------------------------------------------- EXPLORATORY WELL ACTIVITY
NET WELLS COMPLETED (1) WELLS DRILLING --------------------------------------- AT 12/31/93 1993 1992 1991 ------------------- ----------- ---------- ----------- GROSS (2) NET (2) PROD. DRY PROD. DRY PROD. DRY --------- ------- ---- ---- ---- ---- ---- ---- United States 37 33 32 14 42 16 39 25 --------- ------- ---- ---- ---- ---- ---- ----
Canada 13 11 27 26 10 - 24 21 Africa 13 5 3 4 3 3 2 5 Other International 35 10 - 9 5 4 1 5 --------- ------- ---- ---- ---- ---- ---- ---- Total International 61 26 30 39 18 7 27 31 --------- ------- ---- ---- ---- ---- ---- ---- Total Consolidated Companies 98 59 62 53 60 23 66 56 Equity in Affiliate - - 1 1 1 - 1 1 --------- ------- ---- ---- ---- ---- ---- ---- Total Including Affiliates 98 59 63 54 61 23 67 57 ========= ======= ==== ==== ==== ==== ==== ====
(1) Indicates the number of wells completed during the year regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of oil or gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. (2) Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company's fractional interests in gross wells. - -----------------------------------------------------------------------------
At December 31, 1993, the company owned or had under lease or similar agree- ments undeveloped and developed oil and gas properties located throughout the world. Undeveloped acreage includes undeveloped proved acreage. The geo- graphical distribution of the company's acreage is shown in the next table.
- ----------------------------------------------------------------------------- ACREAGE* AT DECEMBER 31, 1993 (Thousands of Acres) DEVELOPED UNDEVELOPED DEVELOPED AND UNDEVELOPED ---------------- -------------- ---------------- GROSS NET GROSS NET GROSS NET ------- ------ ----- ----- ------- ------ United States 3,994 3,123 4,626 2,841 8,620 5,964 ------- ------ ----- ----- ------- ------ Canada 18,213 10,374 528 383 18,741 10,757 Africa 17,147 12,726 135 53 17,282 12,779 Asia 54,297 23,944 61 21 54,358 23,965 Europe 3,231 1,195 58 11 3,289 1,206 Other International 9,656 3,257 57 16 9,713 3,273 ------- ------ ----- ----- ------- ------ Total International 102,544 51,496 839 484 103,383 51,980 ------- ------ ----- ----- ------- ------ Total Consolidated Companies 106,538 54,619 5,465 3,325 112,003 57,944 Equity in Affiliates 3,202 1,601 233 116 3,435 1,717 ------- ------ ----- ----- ------- ------ Total Including Affiliates 109,740 56,220 5,698 3,441 115,438 59,661 ======= ====== ===== ===== ======= ======
* Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage is the sum of the company's fractional interests in gross acreage. - ----------------------------------------------------------------------------- - 6 -
The company had $222 million of suspended exploratory wells included in properties, plant and equipment at year-end 1993. The wells are suspended pending drilling of additional wells to determine if commercially producible quantities of oil or gas reserves are present. The ultimate disposition of these well costs is dependent on the results of this future activity.
During 1993, the company explored for oil and gas in the United States and about 21 other countries. The company's 1993 exploratory expenditures, including affiliated companies' expenditures but excluding unproved property acquisitions, were $533 million compared with $547 million in 1992, a 3 percent decrease. Domestic expenditures represented approximately 34 percent of the consolidated companies' worldwide exploration expenditures, essentially unchanged from the prior year. Significant activities in Chevron's exploration program during 1993 include the following (number of wells are on a "gross" basis):
UNITED STATES: Domestic exploratory expenditures, excluding unproved property acquisitions, were $183 million in 1993, compared to $189 million spent in 1992. In addition, the company incurred costs of $11 million for unproved property acquisitions in 1993. The company continued to focus its 1993 exploratory efforts in the Gulf of Mexico and in other areas where it has existing production. Fifteen exploratory wells were initiated in 1993. Seven of these exploratory wells were completed in 1993, resulting in two discoveries located in the Houston Salt Basin and in the Gulf of Mexico. Plans to spud a well in the Norphlet Trend prospect in Destin Dome 97, located in the Gulf of Mexico, were deferred until March 1994 due to delays in the permit process.
Exploration efforts in high-potential areas, including Alaska's Arctic National Wildlife Refuge (ANWR) and parts of offshore Florida, California and North Carolina have been blocked by legal restrictions and drilling moratoria.
Chevron and other oil companies have sued the Department of Interior to recover bonus payments, lease rentals and certain geophysical costs for federal offshore leases that remain undrilled due to state, federal, and private objections to drilling. The company is seeking to recover approximately $126 million, plus interest, spent on leases off Florida, North Carolina and Alaska.
AFRICA: In Africa, the company spent $104 million during 1993 on exploratory efforts, excluding the acquisition of unproved properties, compared with $108 million in 1992. The company also acquired $9 million of unproved properties in 1993. In Nigeria, the company drilled six exploratory and appraisal wells in 1993, with all six either having proved reserves assigned or assignment deferred pending further exploration or evaluation work. The company also acquired 3-D seismic data covering Nigerian acreage of 1,410 square kilometers in 1993 and separately entered into a farm-in arrangement for the exploration of three offshore concessions. In Angola, the company is the operator of a 7,000 square kilometer concession off the coast of Angola's Cabinda exclave. The concession is divided into Areas A, B, and C, with Area A generating all current production. One successful exploration well was drilled in Area A during 1993 resulting in the discovery of the Numbi South East field which was brought on stream in 1993 by linking it to the existing Numbi Field facilities. Two exploratory wells were drilled in Areas B and C and a third was drilled at the end of the year. These resulted in the discovery of the M'Bili Field in Area C and a non-commercial accumulation in Area B. The third well was tested in Area B as a discovery well, N'Sangui, in January 1994. Options for the development of M'Bili are currently being evaluated. The current Exploration Period for Areas B and C was to expire at the end of February 1994 with a provision to fulfill all obligations by the end of August 1994. The company has requested an extension of the Exploration Period. Under the existing agreement, two exploratory wells will be drilled in Areas B and C in 1994. An additional well may be drilled if the extension is granted. Chevron (operator) and its partners are currently negotiating a Production Sharing Agreement for the recently awarded Deepwater Block 14, located due west of Areas B and C. The agreement is expected to be completed and signed in 1994. In the Congo, a regional 3-D survey was acquired in 1993 covering the southern part of the Marine VII Block which includes both the Kitina and Kitina South discoveries, as well as several additional exploration prospects. In Namibia, the company has been conducting a detailed seismic evaluation of the offshore Namibia Block 2815, where Chevron is the operator. In 1993, Chevron farmed-out a portion of its interest in the concession, reducing its share from 60 percent to 40 percent. - 7 -
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Exploration expenditures, excluding unproved property acquisitions, were $246 million in 1993, a decrease of $4 million from the 1992 amount of $250 million. In addition, unproved properties of $430 million, primarily related to the company's investment in Tengizchevroil (TCO), were acquired in 1993.
In the North Sea, Chevron participated in four wildcat wells in the U.K. sector in 1993. A discovery was made in the Paleocene Parliament prospect, to the northeast of Alba and Britannia, thereby establishing area potential. During the U.K.'s 14th licensing round, the company was awarded operatorship of four blocks in the coastal waters to the west of Britain.
In Canada, exploration efforts in 1993 continued to be concentrated in the western part of the country. A total of 23 wildcat wells were drilled in 1993 which reflected an increase in drilling activity as a share of total exploratory expenditures.
In Indonesia, Chevron and its partners drilled nine exploratory wells in 1993, three of which resulted in oil discoveries.
In Australia, Chevron and its partners in West Australia Petroleum Pty., Ltd. (WAPET) participated in the drilling of the North West Shelf exploration well West Dixon-1, which proved unsuccessful. A preliminary interpretation of the Gorgon 3-D seismic survey was completed in 1993 and WAPET has approved the exploratory drilling for gas of North Gorgon-2 in 1994. WAPET also acquired a 519,000 acre block north of Gorgon in 1993. The new permit, WA-253-P, will be issued to WAPET in early 1994.
In Papua New Guinea, the government has agreed to grant Chevron and its partners an extension of its exploratory license. The extension significantly extends the time remaining for exploration of a large area of the Papuan Fold and Thrust Belt. Exploration efforts continue to be concentrated near the Kutubu project facilities and export system. The Gobe 4X well was drilled before year-end at a location approximately 15 kilometers northwest of the SE Gobe field, resulting in an additional oil and gas discovery on this 40 kilometer-long anticline.
In China, Chevron was awarded sole interest in Block 33/08 in the East China Sea in December. Seismic studies are planned for the second quarter 1994 to determine the optimum location for exploratory drilling. All exploration and drilling activities will be coordinated from Chevron's newly-opened Shanghai office. The HZ/32-4-1 exploratory well in the Pearl River Mouth Basin of the South China Sea was abandoned as a dry hole in 1993.
Other areas where exploration activities occurred in 1993 include Bolivia where the first exploratory well (Cuevo West) was completed in March 1994 as a dry hole, Trinidad and Tobago where the first of four exploratory wells (Rocky Palace #1) was spudded in late 1993, Colombia where evaluation of the Rio Blanco Block in the Llanos foothills continued in 1993 with the acquisition of a seismic program, Yemen where the exploratory well Al Harsh #1 was unsuccessful, and Azerbaijan where Chevron and the State Oil Company of the Azerbaijan Republic (SOCAR) signed an agreement to jointly study oil and gas reserve potential in the southern third of the Caspian Sea.
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PETROLEUM - OIL AND NATURAL GAS PRODUCTION
The following table summarizes the company's and its affiliate's 1993 net production of crude oil, natural gas liquids and natural gas.
- ----------------------------------------------------------------------------- 1993 NET PRODUCTION* OF CRUDE OIL AND NATURAL GAS LIQUIDS AND NATURAL GAS
CRUDE OIL & NATURAL GAS NATURAL GAS LIQUIDS (THOUSANDS OF (BARRELS PER DAY) CUBIC FEET PER DAY) ----------------- ------------------- United States -California 130,330 139,110 -Gulf of Mexico 127,500 1,134,910 -Texas 73,420 403,620 -Louisiana 5,790 30,060 -Wyoming 10,610 155,120 -Colorado 16,560 - -New Mexico 8,630 94,720 -Other States 21,380 98,460 ------- --------- Total United States 394,220 2,056,000 ------- ---------
Africa 217,600 - Canada 49,510 217,650 United Kingdom (North Sea) 49,430 27,670 Indonesia 31,730 1,050 Australia 17,780 163,580 Papua New Guinea 31,040 - China 8,200 - Other International 7,750 6,110 ------- --------- Total International 413,040 416,060 ------- --------- Total Consolidated Companies 807,260 2,472,060 ------- --------- Equity in Affiliates 142,890 53,370 ------- --------- Total Including Affiliates 950,150 2,525,430 ======= ========= * Net production excludes royalties owned by others. - -----------------------------------------------------------------------------
PRODUCTION LEVELS:
In 1993, net crude oil and natural gas liquids production, including affiliates, increased by about one percent to 950,150 barrels per day from 943,940 barrels per day in 1992. Production increases were noted in Papua New Guinea due to full year production and additional wells being brought on stream in 1993 from the Kutubu project, in Kazakhstan due to the startup of a new joint venture partnership in April 1993, and in Indonesia due to production increases as the result of application of enhanced recovery methods in certain fields. These production increases were partially offset by production declines in the United States due to divestments of producing properties in 1992 and normal field declines.
Net production of natural gas, including affiliates, declined 250,920 thousand cubic feet per day, or 9 percent, in 1993 from 1992. The decrease was primarily due to normal field declines and 1992 divestitures of producing properties in the United States and the Netherlands. The decline was partially offset by production from the startup of the company's new joint venture in Kazakhstan.
In the United States, natural gas producers have traditionally sold their production to pipeline companies, who in turn distribute the product to their customers. As a result of FERC Order 636, producers now can sell directly to customers and provide many of the services previously provided by the pipeline companies. Chevron has concentrated its natural gas marketing efforts on the longer term contract market. These customers, which include local distribution companies and industrials, require premium bearing services and marketing arrangements that Chevron can fulfill. The company's sales to these customers have risen significantly, while sales to pipeline companies have correspondingly declined.
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Data on the company's average sales price per unit of oil and gas produced, as well as the average production cost per unit for 1993, 1992 and 1991 are reported in Table III on pages FS-32 to FS-33 of this Annual Report on Form 10-K. The following table summarizes the company's and its affiliates' gross and net productive wells at year-end 1993.
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PRODUCTIVE OIL AND GAS WELLS AT DECEMBER 31, 1993
PRODUCTIVE (1) PRODUCTIVE (1) OIL WELLS GAS WELLS ------------------ ------------------- GROSS (2) NET(2) GROSS (2) NET (2) --------- ------ --------- ------- United States 27,155 12,460 3,164 1,569 --------- ------ --------- ------- Canada 2,042 1,017 330 146 Africa 830 320 4 2 United Kingdom (North Sea) 180 24 - - Other International 968 350 54 15 --------- ------ --------- ------- Total International 4,020 1,711 388 163 --------- ------ --------- ------- Total Consolidated Companies 31,175 14,171 3,552 1,732
Equity in Affiliates 4,311 2,156 28 14
Total Including Affiliates 35,486 16,327 3,580 1,746 ========= ====== ========= ======= Multiple completion wells included above: 388 183 20 14
(1) Includes wells producing or capable of producing. Wells that produce both oil and gas are classified as oil wells. (2) Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company's fractional interests in gross wells.
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DEVELOPMENT ACTIVITIES:
The company's development expenditures, including affiliated companies but excluding proved property acquisitions, were $1,451 million in 1993 and $1,525 million in 1992.
The table below summarizes the company's net interest in productive and dry development wells completed in each of the past three years and the status of the company's developmental wells drilling at December 31, 1993. (A "development well" is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. "Wells drilling" include wells temporarily suspended.)
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DEVELOPMENT WELL ACTIVITY
NET WELLS COMPLETED (1) WELLS DRILLING -------------------------------------- AT 12/31/93 1993 1992 1991 ------------------- ----------- ---------- ----------- GROSS (2) NET (2) PROD. DRY PROD. DRY PROD. DRY --------- ------- ---- ---- ---- ---- ---- ---- United States 97 80 293 11 217 5 445 6 --------- ------- ---- ---- ---- ---- ---- ---- Canada 14 12 41 12 45 4 66 5 Africa 6 2 10 - 10 1 13 1 Other International 51 16 16 - 10 - 17 1 --------- ------- ---- ---- ---- ---- ---- ---- Total International 71 30 67 12 65 5 96 7 --------- ------- ---- ---- ---- ---- ---- ---- Total Consolidated Companies 168 110 360 23 282 10 541 13
Equity in Affiliates 45 22 93 - 159 5 171 10 --------- ------- ---- ---- ---- ---- ---- ---- Total Including Affiliates 213 132 453 23 441 15 712 23 ========= ======= ==== ==== ==== ==== ==== ====
(1) Indicates the number of wells completed during the year regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of oil or gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. (2) Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company's fractional interests in gross wells. - ----------------------------------------------------------------------------- - 10 -
Significant 1993 development activities include the following:
UNITED STATES: Chevron's U.S. development expenditures were $475 million in 1993, a decrease of $8 million from the 1992 figure of $483 million. Additions to proved reserves during 1993 from extensions, discoveries and improved recovery, before revisions, were 98 million barrels of crude oil and natural gas liquids and 356 billion cubic feet of natural gas.
The development of the San Joaquin Valley diatomite reserves in California continued in 1993. Forty one new wells were drilled and 45 older wells were reworked using reservoir fracturing techniques. A four year water injection project, initiated in 1992, to sustain reservoir pressure and further boost production continued into its second year with the drilling of 42 injection wells and the conversion of 18 producing wells to injection. The combination of reservoir fracturing and water injection is expected to increase both the production rate and the amount of oil ultimately recoverable from this resource.
Production in the Point Arguello project, offshore California, averaged 74,000 barrels of oil per day in 1993. Chevron owns approximately 25 percent of the project and operates two offshore platforms (Hermosa and Hidalgo), the onshore Gaviota oil and gas plant and the interconnecting pipelines. A workover and drilling program, designed to add proved reserves and abate the decline in production rate, commenced in August 1993 on the two offshore platforms. Five workovers and two new wells, improving Chevron's lease production by 4,300 barrels of oil per day, were completed in 1993. Three additional wells are planned to be drilled in 1994. Chevron and its partners began double-hulled tankering to Los Angeles of some 250,000 barrels of oil three to four times per month from the field's processing plant at Gaviota in August 1993 under an agreement with the California Coastal Commission. Previously, production was limited to approximately 60,000 barrels per day or 70 percent of full capacity of 85,000 barrels per day due to limited onshore pipeline capacity. Fourth quarter production averaged 80,700 barrels per day. The terms of the permit granted by the California Coastal Commission allowed tankering to continue until January 1, 1996 but required suspension of tankering from February 1, 1994 until such time that Chevron and its partners sign an agreement with a pipeline developer that the developer could use to finance construction of a new line. In late January 1994, Chevron approached the California Coastal Commission to permit short-term tankering beyond February 1 due to damage to a key crude oil pipeline system to Los Angeles caused by the Northridge earthquake. The request was not acted upon by January 31 and short-term tankering was subsequently suspended on February 1. Although production was initially maintained by routing to alternate markets, the shortage of adequate transportation facilities has subsequently resulted in reduced production. In March 1994, the company announced that an agreement had been reached on building a new 130 mile pipeline in Southern California that would carry Point Arguello oil production to Los Angeles. The company anticipates construction on the Pacific Pipeline will commence in early 1995 and be operational in early 1996. Pending the construction of this new pipeline, the company is seeking to resume limited tanker shipments through 1995.
Natural gas production from Garden Banks Block 191 in the Gulf of Mexico started in late 1993. Daily production should reach 150 million cubic feet per day during the first quarter of 1994. During 1994, six additional wells will be drilled under simultaneous drilling and production operations. Chevron is the operator and holds a 50 percent interest in this block.
In the Gulf of Mexico's Norphlet Trend, which stretches some 80 miles from the Destin Dome area (offshore Florida) to the Mobile Block 861 area (offshore Mississippi), two wells, Mobile Block 861 #8 (Chevron 50 percent interest) and Mobile Block 917 #2 (Chevron 91.3 percent interest), were completed and tested in 1993. Production from 861 #8, which tested at 57 million cubic feet per day (total), commenced in February 1994 while production from 917 #2, which tested at 46 million cubic feet per day (total), will commence in 1995. The company and its partners are currently drilling or planning to drill additional exploratory wells in Mobile Blocks 863, 864, and 916 and Destin Dome 97 in 1994.
A new platform was installed in Chevron's wholly owned Main Pass 299 Field in July 1993. Ten development wells are planned with three wells having been completed and placed in production in December 1993. Production is expected to peak at 3,000 barrels per day late in 1994.
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Chevron continued to aggressively develop "tight gas" (gas which is produced from a tight, low-permeability formation) in the Laredo, Texas area. In 1993, twenty-five wells were drilled with twenty-three successes, adding net proved reserves of 70 billion cubic feet of gas. Production averaged 135 million cubic feet of gas per day in 1993. The S. Uribe No. 11 well was completed in 1993 with a sustained flow rate of 23 million cubic feet of gas per day.
AFRICA: Developmental expenditures in Africa were $239 million in 1993, compared to $189 million in 1992. Additions to proved reserves were 105 million barrels of crude oil and natural gas liquids. In Angola, where Chevron's equity interest is 39 percent, ten development wells were added in Area A fields in 1993. In order to sustain production, six existing wells in Area A were reworked and three offshore processing platforms in the Malongo and Takula Fields were revamped and modernized in 1993. Production from the N'Sano Field, discovered in 1992, was tied back to existing Takula facilities. A new production platform to fully develop N'Sano reserves is under construction for installation later this year. Areas B and C continued to be the major focus of development programs in 1993. The first phase of development in these areas involves the installation of two integrated drilling and production platforms in the Kokongo Field. The East Kokongo platform will also be the hub for future phases of development for Areas B and C. A thirty-eight mile pipeline linking the platforms to onshore terminal facilities was completed in the fourth quarter of 1993. Platform construction will be completed in Brazil and delivered to Angola with oil production scheduled to begin in late 1994. The second phase of development is scheduled for the Sanha and N'Dola fields and will consist of two production platforms and related pipelines and facilities for which contracts were awarded in 1993. Commencement of work has been delayed by partner financing issues. Preliminary development plans for the third phase involving development of the Nemba and Lomba fields have been submitted for governmental approval.
In Nigeria, Chevron is operator and has a 40 percent interest in concessions totalling 2.3 million acres in onshore and offshore regions in the Niger Delta. Producing facilities for three new fields, Opuekeba, Idama and Inda, were completed and the fields came on stream during the second half of 1993. Combined production from these new fields, along with production from the Belma and Belma North unitized field development which began in October 1993, is expected to add 60,000 barrels per day to the total production capacity in 1994. Upgrade construction work on two production platforms, Tapa and Delta South, were completed in 1993. This is the beginning of a multi-year program which will include all existing platforms in order to extend the useful life of these facilities and also enhance safety and environmental performance. Work on the Escravos Gas Project, Phase I, continued in 1993. This first phase will utilize gas that is currently being flared in the Okan and Mefa fields. The project will include offshore gas compression facilities, an onshore Liquified Petroleum Gas (LPG) extraction plant, and a floating LPG storage unit anchored offshore. The project will sell gas under a long term contract to the Nigerian Gas Company in addition to producing approximately fifteen thousand barrels per day of hydrocarbon liquids for export. The project is scheduled for start-up in 1997. At year-end, discussions were underway on the assignment of Chevron as the developer of a West African Gas Pipeline which would deliver gas to Ghana via Benin and Togo. The company has an additional subsidiary in Nigeria that holds a 20 percent interest in five offshore oil fields operated by another partner.
In Zaire, where the company has a 50 percent interest in a 390 square mile concession off the coast, development and exploration activities resumed in 1993 as political unrest subsided. Two developmental wells and four well workovers in the Mibale, Motoba and Libwa fields were completed in 1993.
In the Congo, where Chevron has a 29.3 percent interest, the 1991 Kitina discovery in the offshore Marine VII Block was successfully delineated with a second appraisal well. Engineering studies are currently underway to determine the optimal development and reservoir management plan for this field.
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Development expenditures in 1993 were $737 million compared to $853 million in 1992. Additions to proved reserves from extensions, discoveries and improved
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recoveries were 66 million barrels of crude oil and natural gas liquids and 46 billion cubic feet of natural gas. Additions to proved reserves from acquisitions were approximately 1.1 billion barrels of crude oil and natural gas liquids and 1.5 trillion cubic feet of natural gas.
In the United Kingdom, the company has interests in over 50 blocks on the U.K. Continental Shelf which totals approximately 1.7 million gross acres. Chevron held interests, varying from 4.9 to 33.3 percent, in five producing fields in the North Sea during 1993. A sixth field, Alba, started production in January 1994. At the Ninian Field in the U.K. North Sea, Chevron increased its interest by 6.5 percent to 23.6 percent in December 1993. Chevron and its partners began processing third party oil and gas in 1992 using available processing capacity at the Ninian facilities. The Ninian partners receive tariffs for processing and exporting the production from three subsea produced satellite fields - Staffa, Lyell and Strathspey. Staffa production was brought on stream in 1992, followed by production from Lyell (Chevron owns a 33.3 percent interest) in March 1993 and Strathspey in December 1993. Lyell production peaked at 31,000 barrels per day and has stabilized at a daily average of 19,000 barrels per day. Strathspey production is currently averaging 17,000 barrels per day, with an expected peak of 41,000 barrels per day. In 1993, Chevron and its partners announced a commercial framework for bringing on future satellite fields through Ninian. Direct drilling from Ninian Northern platform into the first of four potential satellite prospects began in December. At the Alba Field in the North Sea, development of the first phase of that project was successfully completed with the installation and hook-up of the Alba Northern platform and the Alba floating storage unit (FSU) in November. Initial production, expected to peak at 70,000 barrels per day later this year, began in January 1994 after the FSU was fully commissioned. Work also began in 1993 on plans for the second phase of Alba which will develop the southern area of the reservoir. The Alba Field, in which Chevron has a 33 percent interest, is estimated to contain up to 400 million barrels of recoverable reserves. At the Britannia Field in the North Sea, a 3-D seismic survey was completed in 1992 and analyzed in 1993 as a guide for field mapping and development drilling. Delineation drilling results and technical studies indicate that approximately two and one-half trillion cubic feet of gas, 175 million barrels of condensate and up to 30 million barrels of crude oil will be recoverable, with Chevron's share equating to approximately 30 percent. Preliminary facility engineering studies are nearing completion and a firm decision on development options and commercial arrangements is expected in 1994.
In Canada, the company continues to concentrate its development efforts in six core producing areas in Alberta and one in Manitoba where operating efficiencies and lower operating costs can be realized using existing infrastructure.
Chevron increased its ownership in the Hibernia Field, located approximately 200 miles offshore Newfoundland, by 5 percent to about 27 percent in January 1993 after one of the four original project partners withdrew. In 1993, construction on the project continued with the awarding of the supermodule fabrication contracts, the pouring of the base slab for the Gravity Base Structure, and the completion of supermodule and hook-up engineering. Hibernia investment is projected to be about $200 million in 1994, an increase of $54 million over 1993 levels. Initial production is scheduled for 1997. The company's capitalized investment in this project was $375 million at year-end 1993.
In Indonesia, Chevron's interests in 14 contract areas are managed by its 50 percent owned P.T. Caltex Pacific Indonesia and Amoseas Indonesia affiliates. The Duri Steamflood project, begun in 1985 to assist the difficult production process for the relatively heavy, waxy Duri crude, is being completed in 12 stages (Areas 1-12). Development of Area 7 is currently underway. More than three billion additional barrels of oil are expected to be recovered from the Duri Field as a result of steamflooding. Total production at Duri averaged 247,000 barrels per day in 1993 and is expected to peak at just over 300,000 barrels per day by the late 1990s. A waterflood project involving 21 fields in Central Sumatra, including the Minas field, continued in 1993. Water injection at Minas was initiated in December 1993 as part of the conversion of the peripheral waterflood to a pattern waterflood which is designed to improve oil recovery. Chevron sold its 17.5 percent share in the South Natuna Sea Block B effective January 1, 1994. Chevron's net share of production from this block averaged approximately 11,300 barrels of oil and natural gas liquids per day in 1993.
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In Kazakhstan, the company formed a 50/50 joint venture with Tengizmunaigaz, a subsidiary of Kazakhstanmunaigaz - the national oil company of the Republic of Kazakhstan, to develop the Tengiz and Korolev oil fields on the northeast coast of the Caspian Sea. This joint venture affiliate, Tengizchevroil (TCO), began operations in April 1993, adding net proved reserves to Chevron of 1.1 billion barrels of crude oil and natural gas liquids and 1.5 trillion cubic feet of natural gas. Current production has averaged about 30,000 barrels per day, which is approximately 46 percent of the rated crude oil production capacity of 65,000 barrels per day. Production is restricted by limited treatment and transportation facilities currently available to TCO to bring the oil to world markets. Tengiz crude oil production is currently exchanged for Russian crude which is then exported from Russia to world markets. Natural gas, natural gas liquids and sulfur are being sold into local markets. Over the next three to five years, plans call for TCO to spend about $1.5 billion on expanding production capacity and infrastructure. Current capacity is expected to double to 130,000 barrels per day by 1995 and could reach 260,000 barrels per day by the late 1990s. The pace of field development from 130,000 to 260,000 barrels per day is predicated on the construction of an export pipeline system capable of handling the full production from the fields. Negotiations to agree on terms for a pipeline project, which would be separate from the TCO joint venture's Tengiz development project, have proved to be very difficult, and it is currently impossible to predict the eventual outcome or its impact on the joint venture.
In Australia, the Goodwyn Field, being developed as part of the North West Shelf Project in which Chevron holds a one-sixth interest, is scheduled to start production in 1994. Completion of the offshore platform, originally scheduled for 1993, was delayed due to repair work on the piles. Upon completion of the repair work, in first quarter 1994, the topside modules will be installed and commissioned. Production will flow by a 30 inch diameter pipeline to the nearby North Rankin platform and then by trunkline to shore. The participants in the North West Shelf Project approved, in 1993, the development of the Wanaea Field, the Cossack Field, and an LPG extraction and export project. Combined initial production from the two oilfields is forecast at 115,000 barrels per day starting in late 1995. The liquids-rich gas from Wanaea will be combined with gas from the North Rankin and Goodwyn fields and processed at the onshore gas plant at Karratha, which is being modified to allow the export sale of LPG. Two new LPG storage tanks and a second product loading jetty are currently under construction to handle the extra production. Following start-up in early 1996, LPG exports are expected to average 25,000 barrels per day. Drilling and construction for the Roller/Skate oilfield development progressed according to schedule in 1993. Production is scheduled to commence in 1994 at a peak rate of 32,000 barrels per day. Associated gas from the Roller/Skate and Saladin fields will be piped to shore and either sold in the Perth market or stored in the Dongara field for future sales. The Roller/Skate development, in which Chevron holds about a 26 percent interest, is a project of the West Australian Petroleum Pty., Ltd.
In Papua New Guinea, Chevron (19 percent interest) and its partners are reviewing the feasibility of developing the SE Gobe Field with possible production commencing in 1994.
In China, projects to develop the HZ/32-2 and HZ/32-3 Fields in the South China Sea were initiated in 1993 with the awarding of the major contract. The plan includes two platforms, 12 additional wells and a tie-in to the existing production facility at the HZ/21-1 Field. Initial production, expected to peak at 45,000 barrels per day, is scheduled for 1995. Chevron holds a 16 percent interest in the venture.
Other development projects included the completion of the expanded development of the Chichimene Field in the Llanos Basin area of Colombia. The project included development drilling, production facilities and a 35 kilometer pipeline. Expected peak production of 10,000 barrels of oil per day is expected in 1994. Chevron holds a 50 percent interest in the field.
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PETROLEUM - NATURAL GAS LIQUIDS
Chevron's wholly owned Warren Petroleum Company is engaged in all phases of the domestic natural gas liquids (NGL's) business and is the largest U.S. wholesale marketer of natural gas liquids, selling to customers in 46 states. Warren also conducts Chevron's international liquefied petroleum gas (LPG) trading and sales activities. Sales in 1993 totaled 287 thousand barrels per day (includes sales of 79,000 barrels per day to Chevron subsidiaries). Warren's business encompasses:
EXTRACTION - Warren operates 18 gas processing plants in Oklahoma, Texas, Louisiana and New Mexico and holds equity interests in another 25 plants. Natural gas from Chevron's and other producers' wells is piped to these plants, where the various liquids are extracted. Gas liquids production from these plants was 64,000 barrels per day in 1993.
FRACTIONATION - Raw natural gas liquids are collected from Warren's processing plants, third-party purchases and Warren's gas liquids import facility on the Houston Ship Channel and transported via pipelines to Warren's fractionation plant at Mont Belvieu, Texas. The 220,000 barrel per day capacity facility fractionates raw NGL's into ethane, propane, normal butane, iso-butane and natural gasoline products. The Mont Belvieu complex includes a 45 million barrel capacity underground gas liquids storage facility.
DISTRIBUTION - Gas liquids are distributed to refineries, chemical producers and independent distributors via terminals supplied by pipelines, barges, tank cars and trucks. NGL imports and exports are handled at Warren's marine terminal, the Warrengas Terminal, located on the Houston Ship Channel and linked to the Mont Belvieu complex by dedicated pipelines.
In 1993, Warren continued its activities in international LPG business development, marketing LPG for other Chevron companies in Canada, West Africa, the U.K., and Australia. International sales more than doubled from 13,000 barrels per day in 1992 to 28,000 barrels per day in 1993.
Warren completed the construction of an underground natural gas salt dome storage facility at Hattiesburg, Mississippi, on behalf of Chevron U.S.A. Production Company. The five billion cubic feet storage terminal began receiving gas deliveries in December 1993. A major expansion of the Mont Belvieu fractionator was also completed in 1993. A new butane hydrotreating and isomerization unit was added, increasing its fractionation capacity by 20,000 barrels per day.
The company's total third-party natural gas liquids sales volumes over the last three years are reported in the following table.
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NATURAL GAS LIQUIDS SALES VOLUMES (Thousands of barrels per day) 1993 1992 1991 ---- ---- ---- United States - Warren 208 191 172 United States - Other 3 3 3 ---- ---- ---- Total United States 211 194 175 Canada 30 26 21 Other International 7 7 8 ---- ---- ---- Total Consolidated Companies 248 227 204 ==== ==== ====
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PETROLEUM - RESERVES AND CONTRACT OBLIGATIONS
Table IV on pages FS-33 to FS-34 of this Annual Report on Form 10-K sets forth the company's net proved oil and gas reserves, by geographic area, as of December 31, 1993, 1992, and 1991. During 1993, the company filed estimates of oil and gas reserves with the Department of Energy, Energy Information Agency. These estimates were consistent with the reserve data reported on page FS-34 of this Annual Report on Form 10-K.
The quantities of crude oil that the company is obligated to deliver in the future under existing contracts in the United States and internationally, which specify delivery of fixed and determinable quantities, are not significant in relation to the quantities available from production of the company's proved developed reserves in those areas.
The company sells gas from its producing operations under a variety of contractual arrangements. Most contracts generally commit the company to sell quantities based on production from specified properties but certain gas sales contracts specify delivery of fixed and determinable quantities. In the United States, the quantities of natural gas the company is obligated to deliver in the future under existing contracts is not significant in relation to the quantities available from the production of the company's proved developed U.S. reserves in these areas. Outside the United States, the company has contracts, principally with the State Energy Commission of Western Australia, which have remaining obligations to deliver 269 billion cubic feet of natural gas through 2005. The company believes it can satisfy these contracts from quantities available from production of the company's proved developed Australian natural gas reserves.
PETROLEUM - REFINING
The daily refinery inputs over the last three years for the company's and its affiliate's refineries are shown in the following table.
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PETROLEUM REFINERIES: LOCATIONS, CAPACITIES AND INPUTS (Inputs and Capacities are in Thousands of Barrels Per Day)
DECEMBER 31, 1993 ------------------ REFINERY INPUTS OPERABLE -------------------- LOCATIONS NUMBER CAPACITY 1993 1992 1991 - ---------------------------- ------ -------- ---- ---- ---- Pascagoula, Mississippi 1 295 283 294 306 Port Arthur, Texas 1 185 177 189 195 Richmond, California 1 235 228 228 221 El Segundo, California 1 226 233 235 180 Philadelphia, Pennsylvania 1 172 184 164 162 Other* 6 282 202 201 214 -- ----- ----- ----- ----- Total United States 11 1,395 1,307 1,311 1,278 -- ----- ----- ----- -----
Burnaby, B.C., Canada 1 45 43 41 41 Milford Haven, Wales United Kingdom 1 115 120 103 107 -- ----- ----- ----- ----- Total International 2 160 163 144 148 -- ----- ----- ----- ----- Total Consolidated Companies 13 1,555 1,470 1,455 1,426
Equity in Various Affiliate Locations 14 492 435 399 369 -- ----- ----- ----- ----- Total Including Affiliate 27 2,047 1,905 1,854 1,795 == ===== ===== ===== =====
* Refineries in El Paso, Texas; Barber's Point, Hawaii; Salt Lake City, Utah; Perth Amboy, New Jersey; Willbridge, Oregon; and Richmond Beach, Washington. Inputs for the company's Nikiski, Alaska, refinery, closed in 1991, are included in the above data for 1991.
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Based on refinery statistics published in the December 20, 1993 issue of The Oil and Gas Journal, Chevron had the largest U.S. refining capacity and had the fifth largest worldwide refining capacity including its share of affiliate's refining capacity. The company wholly owns and operates 11 refineries in the United States and one each in Canada and the United Kingdom. The company's Caltex Petroleum Corporation affiliate owns or has interests in 14 operating refineries in Japan (4), Korea, the Philippines, Australia, New Zealand, Bahrain, Singapore, Pakistan, Thailand, Kenya and South Africa.
The company also owns closed refineries in Nikiski, Alaska; Cincinnati, Ohio; and Baltimore, Maryland. Excluded from the affiliate's refineries are 3 closed refineries in Japan.
Production records were set at all locations in 1993 as refineries focused on maximizing unit utilization. In 1993, distillation operating capacity utilization averaged 94 percent in the United States and 95 percent worldwide (including affiliate), compared with 90 percent in the United States and 92 percent worldwide in 1992. Chevron's capacity utilization of its domestic cracking and coking facilities, which are the primary facilities used to convert heavier products to gasoline and other light products, averaged 88 percent in 1993, unchanged from 1992.
During 1993, the company completed the first facility to use Chevron's patented Aromax (R) technology at the Pascagoula, Mississippi refinery. This process produces high value benzene from lower valued refining feed stock and will facilitate the company's ability to comply with the requirement to reduce the benzene content in motor gasoline mandated by the Clean Air Act Amendments of 1990. At the El Paso, Texas refinery, the company entered into an operating agreement with a neighboring refinery which allowed Chevron, as operator, to combine the most efficient units from each refinery in order to lower costs and increase yields. The company also completed a $40 million facility at the Salt Lake City, Utah refinery which will allow the company to economically manufacture ultra low sulfur diesel fuel, one of the few such facilities in that area.
In August 1993, the company installed its proprietary Isodewaxing (R) technology at the Richmond lube oil refining plant. This process, which uses a new catalyst developed by the company, boosted lube oil production by 1,500 barrels per day.
The U.S. downstream industry is going through massive recapitalization in order to meet stringent new environmental regulations. This led to the 1993 announcement of a major restructuring of the company's downstream operations. An integral part of this plan is to divest refineries in Philadelphia, Pennsylvania and Port Arthur, Texas since these refineries no longer fit in Chevron's long term plans to have a more strategically focused U.S. refining operation and will reduce the capital expenditures that would have been required under the 1990 amendments to the Clean Air Act. In 1993, the company established an $837 million pre-tax provision for the divestment of these two refineries. This charge was composed primarily of a write-down of the refineries' facilities and related inventories to their estimated realizable values. Also included in the charges were provisions for environmental site assessments and employee severance. The company has taken into account probable environmental cleanup obligations in estimating the realizable value of the refineries. Responsibility for these obligations will be negotiated with potential buyers. While negotiations for the refinery sales are ongoing, it is expected that the reserve will be sufficient to complete the restructuring. In late February 1994, the company signed a letter of intent with Sun Company, Inc. for the sale of the Philadelphia refinery. In late March 1994, the company announced it has entered into exclusive negotiations with Clark Refining & Marketing, Inc. regarding the sale of its Port Arthur, Texas, refinery.
The company will invest nearly $1 billion in its Richmond and El Segundo, California refineries over the next three years to produce reformulated gasoline. In addition, a $300 million investment to upgrade key processing units to improve yields of high value light products is underway at the Richmond refinery.
At the company's Milford Haven, Wales refinery, a new isomerization unit was brought on stream in 1993. This $54 million unit will enable the refinery to produce a higher octane blend stock in response to increased demand for lead-free gasoline and anticipated benzene reduction in European gasoline.
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In March 1994, the company announced that it will license technology and provide engineering design for a major upgrade to the Kirishi Refinery, operated by Kirishinefteexport, in Russia. The key refining process unit covered by the agreement is a new hydrocracker, scheduled for startup in mid-1999, which will use Chevron's Isocracking technology to maximize production of middistillates such as diesel fuel and jet fuel. The company will also provide technology to remove ammonia and hydrogen sulfide from water used in the refining process, yielding clean water for reuse.
Caltex and its partners completed front-end engineering design of a grassroots, 130,000 barrels per day refinery in Thailand. The engineering, procurement and construction contract was awarded in October and the project is on target for completion in 1996. Work continued on the expansion/upgrade project at the Singapore export refinery. Completion of the project, scheduled for mid-1995, will increase refining capacity by 60,000 barrels per day, increase yield of light products by 33,000 barrels per day, and enable the refinery to produce oxygenated unleaded gasoline and low sulfur diesel fuel. A Japanese affiliate of Caltex placed a new residuum desulfurizer into service at the Negishi, Japan refinery. This unit, along with the cracker unit installed last year, will allow the refinery to increase yields of higher-value products and reduce dependence on low sulfur crudes.
PETROLEUM - REFINED PRODUCTS MARKETING
PRODUCT SALES: The company and its affiliates, primarily Caltex Petroleum Corporation, sell petroleum products throughout much of the world. The principal trademarks for identifying these products are "Chevron", "Gulf" (principally in the United Kingdom) and "Caltex". Domestic sales volumes of refined products by the company during 1993 amounted to 1,423 thousand barrels per day, equivalent to approximately nine percent of total U.S. consumption. Worldwide sales volumes, including the company's share of affiliates' sales, averaged 2,346 thousand barrels per day in 1993, an increase of about one percent over 1992.
The following table shows the company's and its affiliates' refined product sales volumes, excluding intercompany sales, over the past three years.
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REFINED PRODUCTS SALES VOLUMES (Thousands of Barrels Per Day) 1993 1992 1991 ----- ----- ----- UNITED STATES Gasolines 652 646 632 Gas Oils and Kerosene 325 347 312 Jet Fuel 247 252 249 Residual Fuel Oil 94 110 145 Other Petroleum Products* 105 115 106 ----- ----- ----- Total United States 1,423 1,470 1,444 ----- ----- -----
INTERNATIONAL United Kingdom 111 108 110 Canada 50 39 38 Other International 168 147 142 ----- ----- ----- Total International 329 294 290 ----- ----- ----- Total Consolidated Companies 1,752 1,764 1,734
Equity in Affiliate 594 565 533 ----- ----- ----- Total Including Affiliate 2,346 2,329 2,267 ===== ===== =====
* Principally naphtha, lubes, asphalt and coke.
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The company's Canadian sales volumes consist of refined product sales in British Columbia and Alberta by the company's Chevron Canada Ltd. subsidiary. In the United Kingdom, the sales volumes reported comprise a full range of product sales by the company's Gulf Oil (Great Britain) Ltd. subsidiary. The 1993 volumes reported for "Other International" relate primarily to international sales of aviation, marine fuels, and refined products in Latin America, the Far East and elsewhere. The equity in affiliates' sales in 1993 consist primarily of the company's interest in Caltex Petroleum Corporation, which operates in 63 countries including Australia, the Philippines, New Zealand, South Africa and, through Caltex affiliates, in Japan and Korea.
The company introduced several new products in 1993. In September, the company began delivering JP-8, a kerosene-based jet fuel, to the U.S. military. Over the next two years, JP-8, a safer and more versatile fuel, capable of powering tanks, trucks and other military vehicles, will phase out naphtha-based JP-4. In October, low aromatics diesel fuel in California and ultra low sulfur diesel fuel in the rest of the country were introduced to comply with various federal and state air quality regulations. Reformulated heavy duty motor oils that meet the needs of low sulfur diesel fuel users were also introduced nationwide in October.
RETAIL OUTLETS: In the United States, the company supplies, directly or through jobbers, over 9,000 motor vehicle, aircraft and marine retail outlets, including more than 2,400 company-owned or -leased motor vehicle service stations. The company's gasoline market area is concentrated in the Southeastern, South Central and Western states. Chevron is among the top three marketers in 16 states. During 1993, the company completed the acquisition and brand conversion of 55 service stations in south Florida that were acquired from Exxon in exchange for comparable properties in the Baltimore-Washington D.C.-Eastern Virginia areas. Chevron branded retail fuel sales in Arkansas, Western Kentucky and Western Tennessee were discontinued in 1993.
In 1993, Chevron introduced a "Direct Mail Marketing" and a "Premium Card" program to credit card customers. The company also expanded its "Fast Pay" system by approximately 400 stations in 1993, to a total of over 1,300 stations nationwide. This automated system allows credit card customers to pay at the pump with credit approvals processed in about five seconds using satellite data transmission. During 1993, the company outsourced purchasing, warehousing and distribution responsibilities for its Tire, Batteries and Accessories business (TBA).
Internationally, the company's branded products are sold in 214 owned or leased stations in British Columbia, Canada and in 467 (230 owned or leased) stations in the United Kingdom. In 1993, the company completed the sale of its retail marketing operations in Guatemala, El Salvador and Nicaragua.
PETROLEUM - TRANSPORTATION
TANKERS: Chevron's controlled seagoing fleet at December 31, 1993 is summarized in the following table. All controlled tankers were utilized in 1993.
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CONTROLLED TANKERS AT DECEMBER 31, 1993
U.S. FLAG FOREIGN FLAG ----------------------------- ------------------------------ CARGO CAPACITY CARGO CAPACITY NUMBER (millions of barrels) NUMBER (millions of barrels) ------ --------------------- ------ --------------------- Owned - - 26 27 Bareboat Charter 7 2 6 11 Time Charter - - 9 5 ---- ---- ---- ---- Total 7 2 41 43 ==== ==== ==== ====
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Federal law requires that cargo transported between domestic ports be carried in ships built and registered in the United States, owned and operated by U.S. entities and manned by U.S. crews. At year-end 1993, the company's U.S. flag fleet was engaged primarily in transporting crude oil from Alaska and California terminals to refineries on the West Coast and Hawaii, refined products between the Gulf Coast and East Coast, and refined products from California refineries to terminals on the West Coast, Alaska and Hawaii.
At year-end 1993, two of the company's controlled international flag vessels were being used for floating storage. The remaining international flag vessels were engaged primarily in transporting crude oil from the Middle East, Indonesia, Mexico, West Africa and the North Sea to ports in the United States, Europe, the United Kingdom, and Asia. Refined products also were transported worldwide.
In addition to the tanker fleet summarized in the table on page 19, the company owns a one-sixth undivided interest in each of five liquefied natural gas (LNG) ships that are bareboat chartered to the Australian North West Shelf Project. These ships, along with two time chartered LNG vessels, transport LNG from Australia to eight Japanese gas and electric utilities. One additional LNG ship has been ordered with delivery expected in late 1994.
In 1993, the company took delivery of one 1.1 million and two 1.0 million barrel capacity, double hull tankers and sold two 1.2 million and two 3.2 million barrel capacity tankers. The company also took delivery of a 1.0 million barrel capacity tanker, the Chevron Employee Pride, in February 1994 and expects to take delivery of an additional 1.0 million barrel capacity tanker in October 1994. During 1993, the company reduced its time chartered fleet by a net one tanker and 1.0 million barrels of capacity.
Page 24 of this Annual Report on Form 10-K contains a discussion of the effects of the Federal Oil Pollution Act on the company's shipping operations.
PIPELINES: Chevron owns and operates an extensive system of domestic crude oil, refined products and natural gas pipelines. The company also has direct or indirect interests in other domestic and international pipelines. The company's ownership interests in pipelines are summarized in the following table:
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PIPELINE MILEAGE AT DECEMBER 31, 1993
WHOLLY PARTIALLY OWNED OWNED (1) TOTAL ----- ----- ------ UNITED STATES: Crude oil (2) 5,696 624 6,320 Natural gas 569 44 613 Petroleum products 3,709 1,610 5,319 ----- ----- ------ Total United States 9,974 2,278 12,252 ----- ----- ------
INTERNATIONAL: Crude oil (2) - 747 747 Natural gas - 197 197 Petroleum products 12 130 142 ----- ----- ------ Total International 12 1,074 1,086 ----- ----- ------ Worldwide 9,986 3,352 13,338 ===== ===== ======
(1) Reflects equity interest in lines. (2) Includes gathering lines related to the transportation function. Excludes gathering lines related to the production function.
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CHEMICALS
The company's Chevron Chemical Company subsidiary manufactures and markets chemical products for industrial use. The chemical industry, historically, has been cyclical and is highly competitive. Since its last peak in the late 1980s, industry conditions have deteriorated as ample supplies, caused by production overcapacity, have exerted downward pressure on prices. In the past four years, weak demand due to U.S. and worldwide recessions has further weakened prices.
At year-end 1993, Chevron Chemical Company owned and operated 24 U.S. manufacturing facilities in 12 states, owned manufacturing facilities in Brazil and France, and owned a majority interest in a manufacturing facility in Japan. The principal domestic plants are located at Cedar Bayou, Orange and Port Arthur, Texas; St. James and Belle Chasse, Louisiana; Philadelphia, Pennsylvania; Marietta, Ohio; Pascagoula, Mississippi; St. Helens, Oregon; and Richmond, California. The following table shows, by chemical division, 1993 revenues and the number of owned or majority owned chemical manufacturing facilities and combined operating capacities as of December 31, 1993.
- ----------------------------------------------------------------------------- CHEMICAL OPERATIONS
MANUFACTURING FACILITIES 1993 ------------------- ANNUAL REVENUE (1) DIVISION U.S. INTERNATIONAL CAPACITY ($ MILLIONS) - --------------------- ---- ------------- ------------------- ------------ Olefins and Derivatives 12 - 6,990 million lbs. $1,003 Aromatics and Derivatives 7 - 6,570 million lbs. 718 Oronite Additives 2 3 160 million gal. 746 Fertilizers 2 - (2) 86 Consumer Products 1 - (2) 133 Other (including excise taxes) - - (2) 37 -- - ------ Totals 24 3 $2,723 == = ======
(1) Excludes intercompany sales. (2) No meaningful common measurement. - -----------------------------------------------------------------------------
The company divested its last major asset in the agricultural-related chemical business with the sale of its ORTHO consumer products division, a leading supplier of lawn and garden products in the United States, to Monsanto Company in 1993. The sale was the result of studies that concluded that the company's agricultural-related businesses were non-competitive or were non-core. The company decided to divest those businesses and focus its attention on areas of strength - petrochemicals, plastics and additives.
Construction was completed during 1993 on the first U.S. benzene manufacturing plant using the company's proprietary Aromax (R) technology at the Pascagoula, Mississippi refinery. This technology will enable Chevron to produce high-value benzene from certain low-value by-products of the oil refining process. Benzene is a prime building block for a wide range of consumer products such as sporting goods, nylon, laundry detergent, children's toys and automobile tires.
In March 1993, the company announced that a letter of intent had been signed with the Saudi Venture Capital Group, a consortium of Saudi Arabian business leaders, to develop an aromatics facility in Jubail, Saudi Arabia, if necessary Saudi government approval can be obtained. The planned facility would be owned and operated by a newly formed joint venture company. This joint company, owned on an equal basis by Chevron and the Saudi group, would market within Saudi Arabia, while Chevron would market all products outside Saudi Arabia. The facility will utilize Chevron's patented Aromax (R) reforming technology and have a capacity of 420,000 tons of benzene per year and 270,000 tons of cyclohexanes per year. The project is currently delayed while the Saudi government revises its petrochemical investment policy. The company is also in the early stages of examining opportunities to employ the Aromax (R) technology in Asia, where chemical demand is growing rapidly.
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In January 1994, the company announced a cost-reduction plan intended to reduce annual operating expense by approximately $100 million by 1996. Major elements of the plan include completing the divestiture of the company's agricultural businesses, including the closing of the consumer products plant in Maryland Heights, Missouri and the sale of the fertilizer plant in St. Helens, Oregon; the sale of Chevron's asphalt business in Brazil; closing of the company's oil-field chemical business; reorganizing the Oronite Additives Division into global regions; and streamlining and reducing costs at the company's three largest plants in Cedar Bayou and Orange, Texas, and Belle Chasse, Louisiana.
An agreement was reached in March 1994 with Institut Francais du Petrole to jointly develop a new high-purity paraxylene technology called Eluxyl. If the demonstration unit using this new technology, to be constructed and operated at Chevron's Pascagoula, Mississippi, refinery, proves successful, the company plans to integrate the technology at Pascagoula and expand its paraxylene activities worldwide.
COAL AND OTHER MINERALS
COAL: The company's wholly-owned coal mining and marketing subsidiary, The Pittsburg and Midway Coal Mining Co. (P&M), owned and operated four surface and three underground mines at year-end 1993. Three of the mines are located in New Mexico and one each in Alabama, Wyoming, Kentucky and Colorado. All of the mines produce steam coal used primarily for electric power generation. P&M's strategy is to focus on regional markets in the United States, capitalizing on major utility growth markets in the West and Southeast. Approximately 88 percent of P&M's coal sales are made to electric utilities. Sales of coal from P&M's wholly-owned mines and from its 50 percent interest in Black Beauty Coal Company were 20.8 million tons in 1993, an increase of 26 percent over 1992. About 57 percent of these sales came from two mines, the McKinley Mine in New Mexico and the Kemmerer Mine in Wyoming. The average selling price for coal from mines owned and operated by P&M was $24.62 per ton in 1993, contributing $426 million to Chevron's consolidated sales and other operating revenues. At year-end 1993, P&M controlled approximately 560 million tons of developed and undeveloped coal reserves.
Demand growth for coal in the U.S. remains largely dependent on the demand for electric power, which in turn depends on regional and national economic conditions and on competition from other fuel sources. Although coal-fired generation of electricity grew during 1993, competition among coal producers kept downward pressure on regional coal prices during much of the year. However, in the East, a prolonged strike by United Mine Workers of America restricted coal production, tightening coal supplies and driving up spot market prices in the latter half of the year. P&M sells about 88 percent of its coal production under multi-year supply agreements, so it is not particularly exposed to short-term fluctuations in market prices.
P&M controls a significant inventory of low-sulfur coal reserves, and the company expects demand for this type of coal to grow as utilities start to implement programs to comply with the air quality emission standards of the Clean Air Act Amendments of 1990. In addition, P&M anticipates that the Energy Policy Act of 1992 will increase competition in the electric power market and will provide new market opportunities for low-cost coal producers.
OTHER MINERALS: P&M manages the company's investments in non-coal minerals. The company expressed its long-term intention to exit the non-coal minerals business, and most such assets have been sold in recent years. The principal assets remaining are a 50 percent interest in the Stillwater Mining Company, a Montana platinum-palladium mining operation, and a 52.5 percent interest in some zinc-lead prospects in Ireland. The company's share of sales and other revenues from non-coal operations was approximately $21 million in 1993. The sale of the company's 52.5 percent holding in the Irish zinc-lead prospects has been delayed due to legal challenges. The company expects these challenges to be resolved and the sale completed during 1994.
REAL ESTATE
The company's real estate activities are carried out primarily through its wholly owned subsidiaries, Chevron Land and Development Company and Huntington Beach Company (collectively, Chevron Land).
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Their activities have concentrated on converting Chevron's surplus fee production properties in California into residential and commercial real estate. After making major infrastructure improvements, the properties are sold to third parties or jointly developed. At the end of 1993, Chevron Land managed over 26,000 acres of real estate in California.
Chevron Land participates in residential developments through partnerships with home builders. During 1993, the company sold approximately 160 homes in California. Although this represents a 78 percent increase from the 90 homes sold in 1992, the California housing market continues to be weak as California lags the rest of the nation in realizing significant renewed economic growth. The company anticipates that the California real estate market will not begin to recover until late 1994 at the earliest and is currently positioning itself to take advantage of the recovery when it occurs by developing properties at a pace that meets market demand while preserving current real estate development entitlements. Ten residential housing projects were actively being developed at year-end, eight through joint venture partnerships.
Although Chevron's current development emphasis is on the residential sector, the Company also participates in commercial real estate investment and development activities. The Montebello Town Square in Southern California, a 250,000 square foot community shopping center situated on 20 acres of a former oil field, was sold by the company in 1993. The company also leases approximately 70,000 acres of irrigated farmland and 160,000 acres of rangeland to local growers and ranchers in California's San Joaquin Valley. In 1993, Chevron Land restructured its organization by reducing its workforce 20 percent and closing or consolidating 5 of its offices. Currently, Chevron Land's activities are predominately handled by the company's offices in Newport Beach and San Francisco, California.
RESEARCH AND ENVIRONMENTAL PROTECTION
RESEARCH: The company's principal research laboratories are at Richmond and La Habra, California. The Richmond facility engages in research on new and improved refinery processes, develops petroleum and chemical products, and provides technical services for the company and its customers. The La Habra facility conducts research and provides technical support in geology, geophysics and other exploration science, as well as oil production methods such as hydraulics, assisted recovery programs and drilling, including offshore drilling. Employees in subsidiaries engaged primarily in research activities at year-end 1993 numbered approximately 2,400.
In January 1994, the company signed an agreement with China National Petroleum Corporation to provide enhanced oil recovery technology for testing in Daqing, China's largest oil field. The technology, called "microbial profile modification," consists of pumping bacterial spores and nutrients into a reservoir to plug off highly permeable zones in order to improve the sweep efficiency of a waterflood. The agreement calls for 15 months of testing in Chevron Petroleum Technology Company's labs in La Habra, California, followed by a two year pilot program in Daqing.
Chevron's research and development expenses were $206, $229, and $250 million for the years 1993, 1992, and 1991, respectively.
The company owns, controls, or is licensed under numerous patents, but its business is not dependent upon patents. Licenses under the company's patents are generally made available to others in the petroleum and chemical industries.
ENVIRONMENTAL PROTECTION: One of Chevron's ongoing corporate strategies is to give high priority to environmental, public and governmental concerns. Chevron's revised corporate policy on Health, Environment and Safety was approved by the Stockholders in 1991. In 1992, a comprehensive series of 101 management practices was approved by senior management to strengthen the implementation of the policy. The program is called "Protecting People and the Environment" and is modeled after the Chemical Manufacturers Associations' program called "Responsible Care." It is also similar to the American Petroleum Institute's program called "Strategies for Today's Environmental Partnership." The program also encompasses previous company programs to control pollution such as the SMART (Save Money and Reduce Toxics) program which focuses on routine, process related, hazardous waste.
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The company's oil and gas exploration activities, along with many other petroleum companies, have been hampered by drilling moratoria, imposed because of environmental concerns, in areas where the company has leasehold interests, particularly Alaska, offshore Florida and offshore California. Difficulties and delays in obtaining necessary permits because of environmental concerns, such as those experienced by Chevron and its partners in the Point Arguello Field offshore California, can delay or restrict oil and gas development projects. While events such as these can impact current and future earnings, either directly or through lost opportunities, the company does not believe they will have a material effect on the company's consolidated financial position, its liquidity, or its competitive position relative to other domestic or international petroleum concerns. The situation has, however, been a factor, among others, in the shift of the company's exploration efforts to areas outside of the United States.
The company will spend an estimated $1.1 billion in capital expenditures over the next 5 years on its refining facilities in order to comply with federal and state clean air regulations and to provide consumers with fuels that reduce air pollution and air toxicity. The Clean Air Act Amendments of 1990 (CAAA) requires the production of reformulated gasoline (RFG). Beginning in January 1995, only RFG may be sold in the nine worst ozone areas in the United States. In addition, the California Air Resources Board (CARB) requires a more stringent reformulated gasoline to be sold statewide beginning in March 1996. CAAA required a significant decrease in the sulfur content of diesel fuel sold in U.S. markets beginning October 1993. CARB, in addition to the federal requirements, also mandated a reduction in the aromatics content of diesel fuel sold in California. Chevron introduced low aromatics diesel fuel in California and ultra low sulfur diesel fuel in the rest of the nation in October 1993.
The Federal Oil Pollution Act of 1990 (OPA) expanded federal authority to direct responses to oil spills to improve preparedness and response capabilities and to impose penalties on spillers for restoration costs and loss of use of the resources during restoration. OPA also requires the phase out of single hull tankers and the phase in of double hull tankers for trading to U.S. ports. Many of the coastal states have enacted or are preparing legislation in these same areas. In 1990, the company began a fleet modernization program, which included seven double hull tankers for delivery during the 1992-1994 period. Six of these tankers have been delivered through the first week of March 1994. The company has been actively involved in the Marine Preservation Association, a non-profit organization that funds the Marine Spill Recovery Corporation (MSRC). MSRC owns the largest stockpile of oil spill response equipment in the nation and operates five strategically located U.S. coastal regional centers.
The company expects the enactment of additional federal and state regulations addressing the issue of waste management and disposal and effluent emission limitations for offshore oil and gas operations. While the costs of operating in an environmentally responsible manner and complying with existing and anticipated environmental legislation and regulations, including loss contingencies for prior operations, are expected to be significant, the company anticipates that these costs will not have a material impact on its consolidated financial position, its liquidity, or its competitive position in the industry.
During 1993, the company's U.S. capitalized environmental expenditures were $620 million, representing approximately 31 percent of the company's total consolidated U.S. capital and exploratory expenditures. The company's U.S. capitalized environmental expenditures were $430 million and $284 million in 1992 and 1991, respectively. These environmental expenditures include capital outlays to retrofit existing facilities, as well as those associated with new facilities. The expenditures are predominantly in the petroleum segment and relate mostly to air and water quality projects and activities at the company's refineries, oil and gas producing facilities and service stations. For 1994, the company estimates that capital expenditures for environmental control facilities will be approximately $637 million. The actual expenditures for 1994 will depend on various conditions affecting the company's operations and may differ significantly from the company's forecast. The company is committed to protecting the environment wherever it operates, including strict compliance with all governmental regulations. The future annual capital costs of fulfilling this commitment are uncertain, but for the next several years are expected to continue at current levels.
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Under provisions of the Superfund law, Chevron has been designated as a potentially responsible party (PRP) for remediation of a portion of 223 hazardous waste sites. Since remediation costs will vary from site to site as well as the company's share of responsibility for each site, the number of sites in which the company has been identified as a PRP should not be used as a relevant measure of total liability. At year-end 1993, the company's environmental remediation reserve related to Superfund sites amounted to $56 million. The largest of these sites, located in California, accounts for approximately 20 percent of the reserve.
The company's 1993 environmental expenditures, remediation provisions and year-end environmental reserves are discussed on pages FS-3 through FS-4 of this Annual Report on Form 10-K. These pages also contain additional discussion of the company's liabilities and exposure under the Superfund law and additional discussion of the effects of the Clean Air Act Amendments of 1990.
ITEM 2.


ITEM 2. PROPERTIES
The location and character of the company's oil and gas and minerals and real estate properties and its refining, marketing, transportation and chemical facilities are described above under Item 1. Business and Properties. Information in response to the Securities Exchange Act Industry Guide No. 2 ("Disclosure of Oil and Gas Operations") is also contained in Item 1 and in Tables I through VI on pages FS-30 to FS-35 of this Annual Report on Form 10-K. Note 12 "Properties, Plant and Equipment" to the company's financial statements contained on page FS-24 of this Annual Report on Form 10-K presents information on the company's gross and net properties, plant and equipment, and related additions and depreciation expenses, by geographic area and industry segment, for 1993, 1992 and 1991.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
A. Cities Service Tender Offer Cases.
The complaint by Cities Service Co. ("Cities Services") and two individual plaintiffs was originally filed in August 1982 in Oklahoma state court in Tulsa. Prior proceedings have effectively eliminated the two individual plaintiffs as parties. The defendants were initially Gulf Oil Corporation and GOC Acquisition Corporation. Subsequent filings have identified Chevron U.S.A. Inc. as the successor in interest to Gulf Oil Corporation. In the original complaint Cities Service pleaded for damages of not less than $2.7 billion together with legal interest for breach of contract and misrepresentation. The great bulk of the damages were related to claims on behalf of shareholders of Cities Service. All of the claims by Cities Service shareholders have now been resolved and will ultimately be dismissed.
Plaintiff Cities Service has now made new claims by way of a motion to amend the petition, which motion was submitted for ruling on February 28, 1994, but has not yet been ruled on by the court. The amended pleading adds Oxy U.S.A. as the successor to plaintiff Cities Service, adds Chevron U.S.A. Inc. (as successor to Gulf Oil Corporation) and adds Chevron Corporation as a new defendant. In addition to the existing claims for breach of contract and fraud, the amendments add the following causes of action: for willful and malicious breach of contract, negligent misrepresentation, interference with prospective economic advantage in connection with the 1989 proposed Oxy-Cities DOE settlement, and adds the claimed DOE liability as additional contract damages and as additional fraud damages. The proposed amendment also adds a claim for punitive damages based upon the alleged fraud, negligent misrepresentation, willful breach and interference claims. The new claim requests not less than $100 million on each of the several claims, together with pre-judgment interest and punitive damages. It also requests $12 million plus prejudgment interest for Cities' costs in defending against DOE proceedings since 1989, and an order entitling Cities Services to recover such "restitutionary obligation" amounts ultimately paid by Oxy U.S.A. to the DOE in excess of its proposed 1989 DOE settlement, and punitive damages.
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B. In re Gulf Pension Litigation.
In two lawsuits, which were commenced on December 2, 1986 and April 24, 1987 and consolidated on July 17, 1987 in the U.S. District Court for the Southern District of Texas as In re Gulf Pension Litigation, former employees of Gulf Oil Corporation who were participants in the Gulf Pension Plan contend that a partial termination of the Gulf Pension Plan has occurred and they are entitled to immediate vesting and distribution of plan benefits and to distribution of alleged excess plan assets, which it is alleged have been unlawfully seized by Gulf or Chevron. The action is brought under the Employee Retirement Income Security Act of 1974 and common law, and is primarily an action for damages. Defendants have filed an answer denying plaintiffs' allegations. On August 21, 1987, the Court certified a class on these issues consisting of "all former members of the Gulf Pension Plan and the spouses or the beneficiaries of such members." On January 4, 1990, the Court certified a subclass of plaintiffs who also contend that Chevron unlawfully denied them benefits due upon their alleged involuntary termination. A partial settlement agreement was reached during trial on November 19, 1990 and approved by the court at a January 25, 1991 hearing.
On April 10, 1991, the Court issued its opinion on the remaining issues in the case. The Court ruled that partial terminations of the Gulf Pension Plan occurred, and ordered all participants in the plan as of July 1, 1986 to be vested in their benefits under the plan. The Court also ruled that participants in the Gulf Contributory Retirement Plan ("CRP") and the Supplemental Annuity Plan of Mene Grande Oil Company ("SAP") were entitled to the surplus assets of those plans. However, the Court ruled that Chevron, otherwise, has the right to retain surplus funds remaining in the Gulf Pension Plan after all obligations to the Plan Participants have been satisfied. Accordingly, the Court found no impropriety in the merger of the Gulf Pension Plan into the Chevron Retirement Plan or the use of plan assets to fund a special early retirement program and pension supplement. However, the Court did rule that Gulf and Chevron had incorrectly paid certain investment management fees out of plan assets and had incorrectly received a benefit from the use of pension plan assets in the negotiation of a divestiture sale agreement.
On October 15, 1991, the court approved the terms of a second partial settlement agreement. As a part of the second partial settlement, the parties agreed not to appeal the partial termination issues except as relevant to plaintiff's claim that they are entitled to surplus Gulf Pension Plan assets that are not attributable to CRP/SAP. The second partial settlement does not affect the court's ruling that the plaintiffs are not entitled to approximately $620 million in surplus funds in the Gulf Pension Plan. Plaintiffs have appealed this part of the case to the Fifth Circuit Court of Appeals. Chevron has appealed the ruling that it incorrectly paid management fees out of the plan's assets and that it received a benefit from the use of pension funds. On April 29, 1993 Chevron reached a settlement with the Internal Revenue Service regarding these issues, which included a payment to the Chevron Retirement Plan and a payment of excise taxes. Subsequently, Chevron's appeal was dismissed by the court, although the underlying judgement was not vacated.
C. Clean Water Act Violations.
On September 23, 1993, the Environmental Protection Agency (EPA) instituted an administrative proceeding seeking civil penalties in excess of $100,000 from the company for its self-reported violations of the Clean Water Act since July 1986 at production facilities located on the Outer Continental Shelf of the Gulf of Mexico. The company has agreed with the EPA to settle this matter for $121,000.
D. Premanufacture Notifications for Detergent Additives.
On September 30, 1993, the EPA instituted an administrative proceeding seeking civil penalties of about $17 million from the company for alleged violations of the Toxic Substances Control Act (TSCA). The EPA contends that the company was required to file Premanufacture Notifications (PMNs) with regard to six chemical substances manufactured or imported since 1990. The company believes that no PMNs were required because the chemicals were within the scope of existing TSCA inventory listings. Nevertheless, the company reported the situation to the EPA when it was advised by a third party that the EPA may, without public notice, have revised its interpretation of TSCA regulations to require PMNs to be filed in such circumstances. Thereafter, under protest, the company suspended the production and importation of the
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chemicals and filed PMNs for them, continuing the suspension for the 90-day period contemplated by TSCA. The detergents in question are very similar to common detergents and intermediates used in their production, and the EPA does not appear to claim that failure to file a PMN resulted in any health or safety risk. The EPA permitted the company to dispose of its current stocks of the chemicals during the period that the company suspended their production and importation.
E. El Segundo Refinery Reformulated Gasoline Project.
On September 22, 1993, the EPA instituted an administrative proceeding contending that the company had not received a permit required under the Clean Air Act Amendments of 1990 (CAAA) for field activities at the El Segundo refinery relating to the production of reformulated gasolines, which will be federally mandated by 1995 under other provisions of the CAAA. All company activities had been conducted in accordance with authorization by the South Coast Air Quality Management District (SCAQMD), the primary enforcing agency of the rule that the EPA contends the company violated. EPA efforts to cause the company to cease all construction activities were stayed by the Ninth Circuit Court of Appeals, and SCAQMD has since issued the company a formal permit to construct. However, the EPA may continue to seek civil penalties from the company for activities conducted prior to the issuance of the permit.
Other previously reported legal proceedings have been settled or the issues resolved so as not to merit further reporting.
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ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of 1993 to a vote of security holders through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT AT MARCH 1, 1994
MAJOR AREA OF NAME AND AGE EXECUTIVE OFFICE HELD RESPONSIBILITY - ------------------- -------------------------------- ---------------------- K.T. Derr 57 Chairman of the Board since 1989 Chief Executive Director since 1981 Officer Executive Committee Member since 1986
J.D. Bonney 63 Vice-Chairman of the Board Worldwide Exploration since 1987 and Production Director and Executive Activities, Pipe- Committee Member since 1986 lines, Coal and Other Minerals, Administrative Services, Aircraft Services
J.N. Sullivan 56 Vice-Chairman of the Board Worldwide Refining, since 1989 Marketing and Trans- Director since 1988 portation Activities, Executive Committee Member Chemicals, since 1986 Real Estate, Environmental, Human Resources, Research
W.E. Crain 64 Vice-President since 1986 Worldwide Exploration Director and Executive and Production Committee Member since 1988
R.E. Galvin 62 Vice-President since 1988 U.S. Exploration President of Chevron U.S.A. and Production Production Company since 1992 Executive Committee Member since 1993
D.R. Hoyer 62 Vice-President since 1987 U.S. Refining, President of Chevron U.S.A. Marketing and Products Company since 1992 Supply Executive Committee Member since 1993
M.R. Klitten 49 Vice-President since 1989 Finance Executive Committee Member since 1989
R.H. Matzke 57 Vice-President since 1990 Overseas Exploration President of Chevron Overseas and Production Petroleum Inc. since 1989 Executive Committee Member since 1993
J.E. Peppercorn 56 Vice-President since 1990 Chemicals President of Chevron Chemical Company since 1989 Executive Committee Member since 1993
H.D. Hinman 53 Vice-President and General Law Counsel since 1993 Executive Committee Member since 1993
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The Executive Officers of the Corporation consist of the Chairman of the Board, the Vice-Chairmen of the Board, and such other officers of the Corporation who are either Directors or members of the Executive Committee, or are chief executive officers of principal business units. Except as noted below, all of the Corporation's Executive Officers have held one or more of such positions for more than five years. Messrs. Galvin, Hoyer, Matzke and Peppercorn are rotating members of the Executive Committee, with two serving at any one time.
R.E. Galvin - Regional Vice-President, Exploration, Land and Production, Chevron U.S.A. Inc. - 1985 - Vice-President, Chevron Corporation and Senior Vice-President, Exploration, Land and Production, Chevron U.S.A. Inc. - 1988 - President, Chevron U.S.A. Production Company (a Division of Chevron U.S.A. Inc.) - 1992
H.D. Hinman - Partner, Law Firm of Pillsbury Madison & Sutro - 1973 - Vice-President and General Counsel, Chevron Corporation - 1993
M.R. Klitten - Comptroller, Chevron U.S.A. Inc. - 1985 - President, Chevron Information Technology Company - 1987 - Vice-President for Finance, Chevron Corporation - 1989
R.H. Matzke - President, Chevron Canada Resources Limited - 1986 - President, Chevron Overseas Petroleum Inc. - 1989 - Vice-President, Chevron Corporation and President, Chevron Overseas Petroleum Inc. - 1990
J.E. Peppercorn - Senior Vice-President, Chevron Chemical Company - 1986 - President, Chevron Chemical Company - 1989 - Vice-President, Chevron Corporation and President, Chevron Chemical Company - 1990
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PART II
ITEM 5.
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.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data for years 1989 through 1993 are presented on page FS-36 of this Annual Report on Form 10-K.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Indexes to Financial Statements, Supplementary Data and Management's Discussion and Analysis of Financial Condition and Results of Operations are presented on page 41 of this Annual Report on Form 10-K.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Indexes to Financial Statements, Supplementary Data and Management's Discussion and Analysis of Financial Condition and Results of Operations are presented on page 41 of this Annual Report on Form 10-K.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information on Directors on page 4 through 6 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 25, 1994, is incorporated herein by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 28 and 29 of this Annual Report on Form 10-K for information about executive officers of the company. There was no late filing or failure by an insider to file a report required by section 16 of the Exchange Act.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information on pages 15 through 17 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 25, 1994, is incorporated herein by reference in this Annual Report on Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information on pages 2 and 3 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 25, 1994, is incorporated herein by reference in this Annual Report on Form 10-K.
ITEM 13.
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There were no relationships or related transactions requiring disclosure under Item 404 of Regulation S-K.
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PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT: (1) FINANCIAL STATEMENTS: PAGE (S) -------- Report of Independent Accountants FS-13
Consolidated Statement of Income for the three years ended December 31, 1993 FS-14
Consolidated Balance Sheet at December 31, 1993 and 1992 FS-15
Consolidated Statement of Cash Flows for the three years ended December 31, 1993 FS-16
Consolidated Statement of Stockholders' Equity for the three years ended December 31, 1993 FS-17
Notes to Consolidated Financial Statements FS-18 to FS-29
(2) FINANCIAL STATEMENT SCHEDULES:
Report of Independent Accountants on Financial Statement Schedules 35
Schedule V - Property, Plant and Equipment 36
Schedule VI - Accumulated Depreciation, 37 Depletion and Amortization of Property, Plant and Equipment
Caltex Group of Companies Combined Financial Statements and Schedules C-1 to C-21
The Combined Financial Statements and Schedules of the Caltex Group of Companies are filed as part of this report and follow the Five-Year Financial Summary (page FS-36). All other schedules are omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.
(3) EXHIBITS:
The Exhibit Index on pages 33 and 34 of this Annual Report on Form 10-K lists the exhibits that are filed as part of this report.
(b) REPORTS ON FORM 8-K:
The company filed no reports on Form 8-K during the fourth quarter of 1993 and through March 30, 1994.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 30th day of March 1994.
Chevron Corporation
By KENNETH T. DERR* ------------------------------------ Kenneth T. Derr, Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 30th day of March 1994.
PRINCIPAL EXECUTIVE OFFICERS DIRECTORS (AND DIRECTORS)
KENNETH T. DERR* SAMUEL H. ARMACOST* - ------------------------------------- -------------------------------------- Kenneth T. Derr, Samuel H. Armacost Chairman of the Board
J. DENNIS BONNEY* WILLIAM E. CRAIN* - ------------------------------------- -------------------------------------- J. Dennis Bonney, William E. Crain Vice-Chairman of the Board
JAMES N. SULLIVAN* SAM GINN* - ------------------------------------- -------------------------------------- James N. Sullivan, Sam Ginn Vice-Chairman of the Board
CONDOLEEZZA RICE* -------------------------------------- PRINCIPAL FINANCIAL OFFICER Condoleezza Rice
MARTIN R. KLITTEN* S. BRUCE SMART, JR.* - ------------------------------------- -------------------------------------- Martin R. Klitten, S. Bruce Smart, Jr. Vice-President, Finance
JOHN A. YOUNG* -------------------------------------- John A. Young PRINCIPAL ACCOUNTING OFFICER
DONALD G. HENDERSON* GEORGE H. WEYERHAEUSER* - ------------------------------------- -------------------------------------- Donald G. Henderson, George H. Weyerhaeuser Vice-President and Comptroller
*By: MALCOLM J. McAULEY -------------------------------- Malcolm J. McAuley, Attorney-in-Fact
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EXHIBIT INDEX EXHIBIT NO. DESCRIPTION - ------- -------------------------------------------------------------------- 3.1 Restated Certificate of Incorporation of Chevron Corporation, dated November 23, 1988, filed as Exhibit 3.1 to Chevron Corporation's Annual Report on Form 10-K for 1989, and incorporated herein by reference.
3.2 By-Laws of Chevron Corporation, as amended December 7, 1989, including provisions giving attorneys-in-fact authority to sign on behalf of officers of the corporation, filed as Exhibit 3.2 to Chevron Corporation's Annual Report on Form 10-K for 1989, and incorporated herein by reference.
4.1 Rights Agreement dated as of November 22, 1988 between Chevron Corporation and Manufacturers Hanover Trust Company of California, as Rights Agent, filed as Exhibit 4.0 to Chevron Corporation's Current Report on Form 8-K dated November 22, 1988, and incorporated herein by reference.
4.2 Amendment No. 1 dated as of December 7, 1989 to Rights Agreement dated as of November 22, 1988 between Chevron Corporation and Manufacturers Hanover Trust Company of California, as Rights Agent, filed as Exhibit 4.0 to Chevron Corporation's Current Report on Form 8-K dated December 7, 1989, and incorporated herein by reference.
Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the corporation and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.
10.1 Management Incentive Plan of Chevron Corporation, as amended and restated effective January 1, 1990, filed as Exhibit 10.1 to Chevron Corporation's Annual Report on Form 10-K for 1990, and incorporated herein by reference.
10.2 Management Contingent Incentive Plan of Chevron Corporation, as amended May 2, 1989, filed as Exhibit 10.2 to Chevron Corporation's Annual Report on Form 10-K for 1989, and incorporated herein by reference.
10.3 Chevron Corporation Excess Benefit Plan, amended and restated as of July 1, 1990, filed as Exhibit 10.3 to Chevron Corporation's Annual Report on Form 10-K for 1990, and incorporated herein by reference.
10.4 Supplemental Pension Plan of Gulf Oil Corporation, amended as of June 30, 1986, filed as Exhibit 10.4 to Chevron Corporation's Annual Report on Form 10-K for 1986 and incorporated herein by reference.
10.5 Chevron Restricted Stock Plan for Non-Employee Directors, as amended and restated effective January 29, 1992, filed as Appendix A to Chevron Corporation's Notice of Annual Meeting of Stockholders and Proxy Statement dated March 16, 1992, and incorporated herein by reference.
10.6 Chevron Corporation Long-Term Incentive Plan, filed as Appendix A to Chevron Corporation's Notice of Annual Meeting of Stockholders and Proxy Statement dated March 19, 1990, and incorporated herein by reference.
12.1 Definitions of Selected Financial Terms (page 38).
12.2 Computation of Ratio of Earnings to Fixed Charges (page 39).
22.1 Subsidiaries of Chevron Corporation (page 40).
24.1 Consent of Price Waterhouse (page 35).
24.2 Consent of KPMG Peat Marwick (page C-5 of financial statements for the Caltex Group of Companies).
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EXHIBIT INDEX (continued)
EXHIBIT NO. DESCRIPTION - ------- -------------------------------------------------------------------- 25.1 Powers of Attorney for directors and certain officers of Chevron Corporation, authorizing, among other things, the signing of reports on their behalf, filed as Exhibit 25.1 to Chevron Corporation's Annual Report on Form 10-K for 1988 and incorporated herein by reference.
25.2 Power of Attorney for a certain director of Chevron Corporation, authorizing, among other things, the signing of reports on his behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, and incorporated herein by reference.
25.3 Power of Attorney for a certain officer of Chevron Corporation, authorizing, among other things, the signing of reports on his behalf, filed as Exhibit 25.3 to Chevron Corporation's Annual Report on Form 10-K for 1989 and incorporated herein by reference.
25.4 Power of Attorney for a certain director of Chevron Corporation, authorizing, among other things, the signing of reports on her behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, and incorporated herein by reference.
25.5 Power of Attorney for a certain director of Chevron Corporation, authorizing, among other things, the signing of reports on her behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1993, and incorporated herein by reference.
Copies of above exhibits not contained herein are available, at a fee of $2 per document, to any security holder upon written request to the Secretary's Department, Chevron Corporation, 225 Bush Street, San Francisco, California 94104.
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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
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SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING CAPITAL LEASES) (Millions of Dollars)
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SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT (INCLUDING CAPITAL LEASES) (1)
(Millions of Dollars)
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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.
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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.
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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.
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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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
KEY FINANCIAL RESULTS Millions of dollars, except per-share amounts 1993 1992 1991 - ----------------------------------------------------------------------------- Sales and Other Operating Revenues $36,191 $38,212 $38,118 Income Before Cumulative Effect of Changes in Accounting Principles $ 1,265 $ 2,210 $ 1,293 Cumulative Effect of Changes in Accounting Principles - $ (641) - Net Income $ 1,265 $ 1,569 $ 1,293 Special (Charges) Credits Included in Income* $ (883) $ 651 $ (66) Per Share: Income Before Cumulative Effect of Changes in Accounting Principles $ 3.89 $ 6.52 $ 3.69 Net Income $ 3.89 $ 4.63 $ 3.69 Dividends $ 3.50 $ 3.30 $ 3.25 ============================================================================= *Before cumulative effect of changes in accounting principles
Chevron's worldwide net income for 1993 was $1.265 billion, down 19 and 2 percent from 1992 and 1991, respectively. However, special items in all years and the cumulative effect of adopting two new accounting standards in 1992 affected the comparability of the company's reported results. Special items, after related tax effects, decreased 1993 earnings $883 million, increased 1992 earnings $651 million and decreased 1991 earnings $66 million. Also, the cumulative effect of adopting the two new accounting standards reduced 1992 earnings $641 million. Excluding the effects of special items and the accounting changes, 1993 earnings of $2.148 billion were up 38 percent from $1.559 billion in 1992 and increased 58 percent from $1.359 billion in 1991.
OPERATING ENVIRONMENT AND OUTLOOK. Crude oil prices began trending downward at midyear. The decline accelerated during the last two months of 1993, with prices reaching their lowest level in over five years by year-end. During the year, Chevron's posted price for West Texas Intermediate (WTI), a benchmark crude, declined $5.50 per barrel to $13.25 at year-end 1993. Worldwide demand for crude oil has been dampened by the weak global economy; production in the non-OPEC countries has increased, particularly in the North Sea; and the OPEC producers have not adjusted their production levels accordingly. On the other hand, natural gas prices in the United States remained strong in 1993, with the company's average realization of $1.99 per thousand cubic feet nearly 30 cents higher than in 1992. For most of 1993, refined product prices did not decline as quickly as crude oil prices, resulting in strong worldwide sales margins. However, late in the year, the decline accelerated in the United States and product prices have remained at lower levels into early 1994.
Economic indicators show evidence that the U.S. economy is improving; however, recessionary conditions continue in other major countries. Bitter cold weather in the U.S. Midwest and East strengthened crude oil prices somewhat in early 1994 but by February 25 Chevron's posted price for WTI had fallen back to the year-end 1993 level. Natural gas prices remained firm, with average U.S. natural gas realizations in January 1994 of $2.03 per thousand cubic feet.
If both crude oil and refined product prices continue at their low levels, the company's earnings from ongoing operations may be negatively affected. Widely fluctuating prices have become characteristic of the petroleum industry for the past several years. The company has made significant progress in streamlining its businesses and reducing costs in recent years and believes it has improved its ability to operate more competitively and profitably.
YEAR-END 1993 MARKED THE END OF A FIVE-YEAR PERIOD, FOR WHICH AGGRESSIVE MANAGEMENT PERFORMANCE OBJECTIVES HAD BEEN SET IN EARLY 1989. The company declared its mission was to provide superior financial results for the company's stockholders. The objective was set to have a higher total stockholder return - stock appreciation plus reinvested dividends - than five other major U.S. oil companies against which the company measures its performance. To achieve this, the company embarked upon an aggressive program to restructure its businesses, improve management decision making and accountability, shed marginal and non-core assets, reduce operating costs, improve work processes, and through selective investments, position the company for long-term growth. Over the 1989-1993 period, Chevron's total annual stockholder return averaged 18.9 percent, the best among its peer group. The company disposed of marginal and non-core assets, generating almost $4 billion in cash proceeds during this period, and reduced its annual cost structure by about $1 billion in 1993 from
FS-1
1991 levels. Using the company's method of measuring cost performance, costs were reduced from $7.45 per barrel in 1991 to $6.51 in 1993, a reduction of $.94 per barrel, or nearly 13 percent.
IN EARLY 1994, THE COMPANY ANNOUNCED A NEW FIVE-YEAR GOAL OF MAINTAINING ITS POSITION AS THE NO. 1 MAJOR U.S. OIL COMPANY IN TOTAL STOCKHOLDER RETURN. Key elements include targeting a further $.25 per barrel reduction in operating and administrative costs by the end of 1994; attaining a 12 percent return on capital employed, after adjusting for special items; and pursuing growth opportunities - particularly in international exploration and production and, through its Caltex affiliate, in refining and marketing activities in the fast growing Asia-Pacific region.
UNITED STATES REFINING AND MARKETING DEVELOPMENTS. The company announced a major restructuring of its U.S. refining and marketing business in May 1993. The company's refineries at Port Arthur, Texas, and Philadelphia, Pennsylvania, will be sold and investments in retail marketing activities in the East will be concentrated in the Gulf Coast states. As a result, the company's U.S. refining capacity will decrease about 350,000 barrels per day, or 25 percent, and U.S. refined product sales volumes may decline about 250,000 barrels per day, or about 17 percent from 1993 volumes. However, the new refining organization, while smaller, is expected to be more efficient, with improved cash flow and return on capital employed. It will also eliminate the large capital investments that would have been required for these facilities under the Clean Air Act and other environmental regulations. A provision of $543 million was recorded for the financial effects of the restructuring. In late February 1994, the company signed a letter of intent to sell the Philadelphia refinery to Sun Company, Inc. While negotiations for the refinery sales are ongoing, it is expected that the reserve will be sufficient to complete the restructuring.
UNITED STATES EXPLORATION AND PRODUCTION DEVELOPMENTS. The interim tankering permit issued by the California Coastal Commission required the Point Arguello partners to have signed an agreement by February 1, 1994 that would allow a pipeline developer to secure financing for construction of a pipeline to the Los Angeles area. Because of ongoing negotiations, the deadline was not met and tankering was suspended. With tankering, the project had been producing over 80,000 barrels per day. The partners have thus far maintained production volumes by routing the oil to alternate markets, pending resolution of the negotiations and resumption of tankering. Chevron is operator and owns approximately 25 percent of the project.
INTERNATIONAL EXPLORATION AND PRODUCTION DEVELOPMENTS. Tengizchevroil (TCO), the company's joint venture with the Republic of Kazakhstan to develop the Tengiz and Korolev oil fields on the northeastern coast of the Caspian Sea, began operations in April 1993. The oil is being exported into world markets under a transportation/exchange agreement with Russia, whereby TCO receives and exports crude oil from Russia in exchange for providing Russia with comparable amounts of Tengiz crude. Natural gas, natural gas liquids and sulfur are being sold into local markets. Upon formation of the joint venture, Chevron's net proved reserves of crude oil and natural gas liquids increased 1.1 billion barrels and net proved reserves of natural gas increased 1.5 trillion cubic feet, representing the company's share of TCO's current net proved reserves.
Crude oil production capacity is 65,000 barrels per day; however, because of pipeline transportation constraints, production has averaged approximately 30,000 barrels per day since April. At year-end 1993, the company's cash investment in TCO was about $220 million. In addition, the company has accrued future field development obligations and amounts payable after completion and demonstrated operability of an export pipeline system. Over the next three to five years, plans call for TCO to spend about $1.5 billion to reach a production capacity of 260,000 barrels per day by the late 1990s. Current capacity is expected to double to 130,000 barrels per day by 1995. The pace of field development from 130,000 to 260,000 barrels per day is dependent on the ability to export the full production capacity. This will ultimately require the construction of an export pipeline system, which is separate from the TCO joint venture's Tengiz development project. Negotiations to agree on terms for a pipeline project have proved to be very difficult, and it is currently impossible to predict the eventual outcome or its impact on the joint venture.
In January 1994, production began from the Alba oil field in the United Kingdom North Sea. Chevron is operator and owns one-third of this project. Production should peak at about 70,000 barrels per day later in 1994.
FS-2
Chevron has significant oil and gas exploration and production operations in Nigeria and in the Angolan exclave of Cabinda, where its share of net production is about 100,000 barrels of crude oil per day from each of these countries. Angola has experienced civil unrest following its 1992 elections; separately, elements seeking independence of Cabinda from Angola have periodically created civil unrest in the area of the company's operations. Also, the nullification of the Nigerian elections in 1993 has been followed by a period of political uncertainty. To date, none of these events has had a significant impact on the company's operations, but the company is closely monitoring developments.
ENVIRONMENTAL MATTERS. Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity and govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with myriad laws and regulations pertaining to its operations and products are embedded in the normal costs of conducting its business. Using definitions and guidelines established by the American Petroleum Institute, Chevron estimates its worldwide environmental spending in 1993 was nearly $1.5 billion, of which $675 million were capital expenditures. These amounts do not include non-cash provisions recorded for environmental remediation programs, but include spending charged against such reserves.
In addition to the various federal, state and local environmental laws and regulations governing its ongoing operations and products, the company (as well as other companies engaged in the petroleum or chemicals industries) is required to incur expenses for corrective actions at various facilities and waste disposal sites. An obligation to take remedial action may be incurred as a result of the enactment of laws, such as the federal Superfund law, or the issuance of new regulations or as the result of accidental leaks and spills in the ordinary course of business. In addition, an obligation may arise when a facility is closed or sold. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable under regulations existing at the time performed, but now will require investigatory and/or remedial work to ensure adequate protection to the environment.
During 1993, the company recorded $215 million of before-tax provisions to provide for environmental remediation efforts, including Superfund sites. Actual expenditures charged against these provisions and other previously established reserves amounted to $183 million in 1993. At year-end 1993, the company's environmental remediation reserve was $746 million, including $56 million related to Superfund sites. Receivables of $18 million have been recorded for expected reimbursements of expenditures for environmental cleanup.
Under provisions of the Superfund law, the Environmental Protection Agency (EPA), as well as certain state agencies, have designated Chevron a potentially responsible party (PRP) for remediation of a portion of 223 hazardous waste sites. At year-end 1993, the company's cumulative share of costs and settlements for approximately 145 of these sites, for which payments or provisions have been made in 1993 and prior years, was about $89 million, including a provision of $6 million during 1993. For the remaining sites, investigations are not yet at a stage where the company is able to quantify a probable liability or determine a range of possible exposure. The Superfund law provides for joint and several liability. Any future actions by the EPA and other regulatory agencies to require Chevron to assume other responsible parties' costs at designated hazardous waste sites are not expected to have a material effect on the company's consolidated financial position or liquidity.
Provisions are recorded for work at identified sites where an assessment or remediation plan has been developed and for which costs can reasonably be estimated. It is likely the company will continue to incur additional charges for environmental programs relating to past operations. These future costs are indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties and the extent to which such costs are recoverable from insurance or other sources. While the amounts of future costs may be material to the company's results of operations in the period in which they are recognized, the company does not expect these costs to have a material effect on Chevron's consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had or will have any significant impact on the company's competitive position relative to other domestic or
FS-3
international petroleum or chemicals concerns. Although environmental compliance costs are substantial, the company has no reason to believe they vary significantly from similar costs incurred by other companies engaged in similar businesses in similar areas. The company believes that such costs ultimately are reflected in the petroleum and chemicals industries' prices for products and services.
The 1990 amendments to the Clean Air Act will require significant capital expenditures for the industry to meet clean-air regulations. The company's capital expenditures related to air quality were $434 million in 1993. Estimated 1994 total capital environmental expenditures are $686 million, of which $478 million will be spent to meet federal and state clean-air regulations for its products and facilities. This is in addition to the ongoing costs of complying with other environmental regulations.
In addition to the reserves for environmental remediation discussed above, the company maintains reserves for dismantlement, abandonment and restoration of its worldwide oil, gas and mineral properties at the end of their productive lives. Most such costs are environmentally related. Provisions are recognized through depreciation expense as the properties are produced. The amount of these reserves at year-end 1993 was about $1.5 billion.
For the company's other ongoing operating assets, such as refineries, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives.
OTHER CONTINGENCIES. At year-end 1993 the company had $222 million of suspended exploratory wells included in properties, plant and equipment. The wells are suspended pending drilling of additional wells to determine if commercially producible quantities of oil or gas reserves are present. The ultimate disposition of these well costs is dependent on the results of this future activity.
The company is the subject of various lawsuits and claims and other contingent liabilities. These are discussed in the notes to the accompanying consolidated financial statements. The company believes that the resolution of these matters will not materially affect its financial position or liquidity.
NEW ACCOUNTING STANDARDS. In November 1992, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 112, "Employers' Accounting for Postemployment Benefits," which established accounting standards for employers who provide benefits to former or inactive employees after termination but before retirement. In May 1993, the FASB issued SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." The company's current accounting practices are substantially in compliance with the new standards. Accordingly, the adoption of these two standards in the first quarter of 1994 will not have a material effect on the company's consolidated financial statements and will not affect its liquidity.
SPECIAL ITEMS. Net income is affected by transactions that are unrelated to, or are not representative of, the company's ongoing operations for the periods presented. These transactions, defined by management and designated "special items," can obscure the underlying results of operations for a year as well as affect comparability between years. The adjacent table summarizes the (losses) gains, on an after-tax basis, from special items included in the company's reported net income.
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Asset Dispositions $ 122 $757 $149 Restructurings and Reorganizations (554) (40) (185) Prior-Year Tax Adjustments (130) 72 173 Environmental Remediation Provisions (90) (44) (160) Asset Write-Offs and Revaluations (71) (133) (24) LIFO Inventory (Losses) Gains (46) (26) 16 Other (114) 65 (35) - ----------------------------------------------------------------------------- Total Special Items $(883) $651 $(66) =============================================================================
ASSET DISPOSITIONS in 1993 resulted from the company's continuing program to dispose of marginal and non-strategic assets. The Ortho lawn and garden products business was the major asset sold in 1993, generating a $130 million gain. In addition, oil and gas properties in the United States and Indonesia, undeveloped coal properties in the United States and marketing assets in Central America were sold during the year resulting in a net loss of $8 million. In 1992, assets sold included oil and gas properties in the United States, United Kingdom, Canada and Sudan; a U.S. fertilizer business; and a copper interest in Chile. In addition, the stock of a U.S. oil and gas subsidiary was exchanged with Pennzoil Company for 15,750,000 shares of Chevron stock, a transaction valued at $1.1 billion. The
FS-4
combination of these and other smaller sales resulted in after-tax gains of $757 million. In 1991, sales of producing properties in the United States, Oman and Spain; non-producing properties in the United Kingdom; certain U.S. geothermal properties; an agricultural chemicals interest, together with the company's share of the gain on an asset sale by its Caltex affiliate, resulted in net gains of $149 million.
RESTRUCTURINGS AND REORGANIZATIONS charges in 1993 amounted to $554 million, primarily the second quarter provision to restructure Chevron's U.S. refining and marketing business. This charge, totaling $543 million, was composed primarily of a write-down of the refineries' facilities and related inventories to their estimated realizable values. Also included in the charges were provisions for environmental site assessments and employee severance. The company has taken into account probable environmental cleanup obligations in estimating the realizable value of the refineries. Responsibility for these obligations will be negotiated with potential buyers. In 1992, Chevron recorded a net charge of $40 million associated with restructuring and work-force reductions - provisions of $105 million for work-force reductions were offset by $65 million of pension settlement gains in connection with the company's enhanced early retirement program. During 1991, charges of $185 million were recorded for the reconfiguration of the Port Arthur refinery and companywide work-force reductions.
PRIOR-YEAR TAX ADJUSTMENTS are generally the result of issues in open tax years being settled with taxing authorities or being re-evaluated by the company as a result of new developments. Also, adjustments are required for the effect on deferred income taxes of changes in statutory tax rates.
ENVIRONMENTAL REMEDIATION PROVISIONS pertain to estimated future costs for environmental remediation programs at certain of the company's U.S. service stations, marketing terminals, refineries, chemical plants and other locations; divested operations in which Chevron has liability for future remediation costs; and sites, commonly referred to as Superfund sites, for which the company is a PRP. In addition to an amount included in the 1993 restructuring charge discussed above, such provisions amounted to $90 million in 1993, $44 million in 1992 and $160 million in 1991.
ASSET WRITE-OFFS AND REVALUATIONS in 1993 comprised certain U.S. refinery assets, U.S. and Canadian production assets, and miscellaneous corporate assets. Asset write-offs in 1992 consisted of a $110 million write-down of the company's Canadian Beaufort Sea properties and a net $23 million charge related to certain U.S. refining, marketing and chemical fertilizer assets. Certain U.S. refinery assets of $24 million were written off in 1991.
LIFO INVENTORY GAINS AND LOSSES result from the reduction of inventories in certain inventory pools valued under the Last-In, First-Out (LIFO) accounting method. LIFO losses decreased 1993 net income $46 million and 1992 net income $26 million. However, drawdowns of LIFO-valued inventories increased net income in 1991 by $16 million as low-cost inventories, relative to then-current costs, were liquidated. These amounts include the company's equity share of Caltex LIFO inventory effects. Chevron's consolidated petroleum inventories were 99 million barrels at year-end 1993, 105 million barrels at year-end 1992 and 121 million barrels at year-end 1991.
OTHER SPECIAL ITEMS in 1993 included net additions of $70 million to reserves for various litigation and regulatory issues and a one-time cash bonus award to employees totaling $60 million, offset by a favorable inventory adjustment of $16 million. In 1992, insurance recoveries and chemical products licensing agreements of $76 million were partially offset by $11 million of net additions to reserves for various litigation and regulatory issues. In 1991, additions of $35 million were made to litigation and regulatory reserves.
RESULTS OF OPERATIONS. Strong worldwide refined product sales margins and higher U.S. natural gas prices mitigated the effects of lower crude oil prices in 1993, but the most important contributor to the company's improved operating performance was the large reduction in its operating and administrative costs. Also, lower interest and exploration expenses helped earnings. Chemicals operations continued at depressed levels.
Similar to 1993, the increase in 1992 operating earnings from 1991 levels reflected reduced operating and administrative costs, higher U.S. natural gas prices and improved U.S. refined product sales margins. These benefits were partly offset by lower earnings in international refining and marketing and worldwide chemicals operations as weak global economic conditions held down product prices, shrinking sales margins.
FS-5
SALES AND OTHER OPERATING REVENUES were $36.2 billion, down from $38.2 billion in 1992 and $38.1 billion in 1991. Revenues declined from 1992 and 1991 levels primarily due to lower crude oil and refined products prices partly offset by higher natural gas prices.
The $.6 billion decline in OTHER INCOME in 1993 was due to lower asset sales gains.
OPERATING EXPENSES, adjusted for special items, declined significantly as a result of the company's extensive cost-reduction programs initiated in early 1992. Operating expenses and administrative costs in 1993, adjusted for special items, declined $358 million from 1992. Coupled with the $512 million reduction in 1992 from 1991 levels, the two-year reduction in costs totaled $870 million, an 11 percent decrease from 1991. The company believes it has achieved a significant reduction in its cost structure and that most of the cost savings will be sustainable.
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Reported Operating Expenses* $6,267 $6,145 $6,933 Reported Selling, General and Administrative Expenses 1,530 1,761 1,704 - ----------------------------------------------------------------------------- Total Operational Costs 7,797 7,906 8,637 Eliminate Special Charges Before Tax (531) (282) (501) - ----------------------------------------------------------------------------- Adjusted Ongoing Operational Costs $7,266 $7,624 $8,136 ============================================================================= *Operations are charged at market rates for consumption of the company's own fuel. These "costs" are eliminated in the consolidated financial statements. For cost performance measurement, such costs are included and amounted to $1,017, $1,251 and $1,272 in 1993, 1992 and 1991, respectively.
TAXES on income were $1.2 billion in 1993, $1.3 billion in 1992 and $959 million in 1991, equating to effective income tax rates of 47.9 percent, 36.2 percent and 42.6 percent for each of the three years, respectively. The increase in the 1993 tax rate is due primarily to unfavorable prior-year tax adjustments, including an increase in deferred income taxes resulting from the 1 percent increase in the U.S. corporate income tax rate. The lower effective tax rate for 1992 is primarily attributable to a low overall tax cost on property dispositions, primarily the tax-free exchange with Pennzoil. Partially offsetting these effects were lower favorable prior-year tax adjustments in 1992 and proportionately lower equity affiliate income that is recorded on an after-tax basis. The 1991 effective tax rate benefited from favorable prior-year tax adjustments.
CURRENCY TRANSACTIONS increased net income $46 million in 1993 and $90 million in 1992 compared with a decrease of $4 million in 1991. These amounts include the company's share of affiliates' currency transactions. The gain on currency transactions in 1993 resulted primarily from fluctuations in the value of Nigerian currency relative to the U.S. dollar. In 1992, gains resulted from fluctuations in currencies in the United Kingdom, Canada, Australia and Nigeria.
RESULTS BY MAJOR OPERATING AREAS Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Exploration and Production United States $ 566 $1,043 $ 285 International 580 594 717 - ----------------------------------------------------------------------------- Total Exploration and Production 1,146 1,637 1,002 - ----------------------------------------------------------------------------- Refining, Marketing and Transportation United States (170) 297 (153) International 252 111 486 - ----------------------------------------------------------------------------- Total Refining, Marketing and Transportation 82 408 333 - ----------------------------------------------------------------------------- Total Petroleum 1,228 2,045 1,335 Chemicals 143 89 151 Coal and Other Minerals 44 198 7 Corporate and Other (150) (122) (200) - ----------------------------------------------------------------------------- Income Before Cumulative Effect of Changes in Accounting Principles $1,265 $2,210 $1,293 Cumulative Effect of Changes in Accounting Principles - (641) - - ----------------------------------------------------------------------------- Net Income $1,265 $1,569 $1,293 =============================================================================
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SPECIAL ITEMS BY MAJOR OPERATING AREAS
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Exploration and Production United States $(136) $413 $(46) International (61) 14 138 - ----------------------------------------------------------------------------- Total Exploration and Production (197) 427 92 - ----------------------------------------------------------------------------- Refining, Marketing and Transportation United States (725) (53) (335) International 1 (3) 133 - ----------------------------------------------------------------------------- Total Refining, Marketing and Transportation (724) (56) (202) - ----------------------------------------------------------------------------- Total Petroleum (921) 371 (110) Chemicals 112 53 34 Coal and Other Minerals - 159 (4) Corporate and Other (74) 68 14 - ----------------------------------------------------------------------------- Total Special Items Included in Net Income $(883) $651 $(66) =============================================================================
U.S. EXPLORATION AND PRODUCTION earnings in 1993, excluding special items, improved 11 percent from 1992 levels and more than doubled from 1991 results.
In 1993, the effects of lower average crude oil prices and lower crude oil and natural gas production volumes were more than offset by lower operating expenses and higher natural gas prices. Also, natural gas contract settlements contributed to the earnings improvement. While the company's average crude oil realization declined $1.92 per barrel to $14.58 in 1993, average natural gas prices increased to $1.99 per thousand cubic feet compared with $1.70 for 1992. Because of the company's extensive cost cutting efforts and disposition of higher-cost oil and gas properties, 1993 earnings per equivalent barrel, excluding special items, increased $.18 to $.95.
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Earnings Excluding Special Items $702 $ 630 $331 - ----------------------------------------------------------------------------- Asset Dispositions (54) 419 (49) Prior-Year Tax Adjustments (40) 5 (50) Environmental Remediation Provisions (13) (2) (3) Asset Write-Offs and Revaluations (13) - - Restructurings and Reorganizations (2) (35) - LIFO Inventory Gains 1 5 1 Other (15) 21 55 - ----------------------------------------------------------------------------- Total Special Items (136) 413 (46) - ----------------------------------------------------------------------------- Reported Earnings $566 $1,043 $285 =============================================================================
Cost cutting efforts and higher natural gas prices were also the major factors in 1992's earnings improvement over 1991, offsetting lower crude oil prices and lower production levels. Exploration expense declined over the three-year period, and depreciation expense dropped in line with lower production volumes.
Net liquids production for 1993 averaged 394,000 barrels per day, down from 432,000 in 1992 and 454,000 in 1991. Net natural gas production for 1993 was about 2.1 billion cubic feet per day, down from approximately 2.3 billion cubic feet per day in 1992 and 1991. The production declines in liquids and natural gas were due primarily to the disposition of producing properties in late 1992.
INTERNATIONAL EXPLORATION AND PRODUCTION earnings, excluding special items, improved 11 percent over the levels of 1992 and 1991 when crude oil prices were much higher. Because of the terms of the operating agreements in some of the countries in which the company produces, fluctuations in crude oil prices have less impact on earnings than in the United States. Contributing factors to the higher 1993 earnings included lower operating expenses, lower exploration expenses and higher production volumes.
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Earnings Excluding Special Items $641 $580 $579 - ----------------------------------------------------------------------------- Prior-Year Tax Adjustments (63) (27) 45 Asset Dispositions 29 166 93 Asset Write-Offs and Revaluations (19) (110) - Restructurings and Reorganizations (2) (9) - LIFO Inventory Losses (1) (1) - Other (5) (5) - - ----------------------------------------------------------------------------- Total Special Items (61) 14 138 - ----------------------------------------------------------------------------- Reported Earnings $580 $594 $717 =============================================================================
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Both net liquids and natural gas production have increased steadily over the three-year period. Ongoing development projects in Indonesia and West Africa, the mid-1992 start up of production in Papua New Guinea and the second quarter 1993 start up of the Tengiz joint venture all contributed to the increase in net liquids production. Increases in net natural gas production have occurred primarily in Australia's North West Shelf Project and in Canada. Net liquids production in 1993 was 10 percent higher than in 1991, and net natural gas production increased 5 percent over this same three-year period. Foreign currency transaction gains were $57 million in 1993, compared with $80 million in 1992 and $19 million in 1991.
SELECTED OPERATING DATA 1993 1992 1991 - ----------------------------------------------------------------------------- U.S. EXPLORATION AND PRODUCTION Net Crude Oil and Natural Gas Liquids Production (MBPD) 394 432 454 Net Natural Gas Production (MMCFPD) 2,056 2,313 2,359 Natural Gas Liquids Sales (MBPD) 211 194 175 Revenues from Net Production Crude Oil ($/bbl.) $14.58 $16.50 $17.10 Natural Gas ($/MCF) $ 1.99 $ 1.70 $ 1.53
INTERNATIONAL EXPLORATION AND PRODUCTION (1) Net Crude Oil and Natural Gas Liquids Production (MBPD) 556 512 504 Net Natural Gas Production (MMCFPD) 469 463 447 Natural Gas Liquids Sales (MBPD) 37 33 29 Revenues from Liftings Liquids ($/bbl.) $16.09 $17.93 $18.36 Natural Gas ($/MCF) $ 2.08 $ 2.07 $ 2.28
U.S. REFINING AND MARKETING Gasoline Sales (MBPD) 652 646 632 Other Refined Product Sales (MBPD) 771 824 812 Refinery Input (MBPD) 1,307 1,311 1,278 Average Refined Product Sales Price ($/bbl.) $25.35 $25.96 $26.40
INTERNATIONAL REFINING AND MARKETING (1) Refined Product Sales (MBPD) 923 859 823 Refinery Input (MBPD) 598 543 517
CHEMICALS SALES AND OTHER OPERATING REVENUES (2) United States $2,694 $2,929 $3,217 International 602 566 550 -------------------------------- Worldwide $3,296 $3,495 $3,767 ============================================================================= (1) Includes equity in affiliates for all years. Per unit revenues from net production for 1992 and 1991 have been restated to include equity affiliates. Refinery input in 1993 includes South Africa, where local government restrictions prohibited this disclosure in 1992 and prior years. (2) Millions of dollars. Includes sales to other Chevron companies.
MBPD=thousands of barrels per day; MMCFPD=millions of cubic feet per day; bbl.=barrel; MCF=thousands of cubic feet
U.S. REFINING AND MARKETING earnings, excluding special items, improved 59 percent from 1992 levels and more than tripled from 1991 results when weak demand and ample supplies depressed refined products margins.
Although average product prices in 1993 declined from the prior year, lower crude oil prices, lower operating costs and stronger markets resulted in higher average sales margins compared with 1992. Late in 1993, margins declined somewhat as product prices fell faster than crude oil prices. Total product sales volumes declined 3 percent from 1992's level, although sales of higher-valued motor fuels increased about 1 percent.
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Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Earnings Excluding Special Items $ 555 $350 $ 182 - ----------------------------------------------------------------------------- Restructurings and Reorganizations (543) (1) (83) Environmental Remediation Provisions (77) (42) (157) LIFO Inventory (Losses) Gains (44) (22) 10 Prior-Year Tax Adjustments (38) 7 (33) Asset Write-Offs and Revaluations (25) (31) (24) Asset Dispositions (1) - - Other 3 36 (48) - ----------------------------------------------------------------------------- Total Special Items (725) (53) (335) - ----------------------------------------------------------------------------- Reported Earnings $(170) $297 $(153) =============================================================================
Industry conditions and operating problems that plagued the company's U.S. refining and marketing business in 1991 largely turned around in 1992. Cost-cutting programs, operating efficiencies generated by downsizing the Port Arthur refinery and improved operations at other refineries all contributed to the improved earnings in 1992. Sales of refined products increased 2 percent over 1991 levels. Refinery operating problems in 1991 reduced product yields while increasing maintenance costs and the requirement for outside product purchases.
INTERNATIONAL REFINING AND MARKETING earnings include international marine results and equity earnings of the company's Caltex Petroleum Corporation affiliate. Excluding special items, 1993 earnings more than doubled from the weak level of 1992, but were still below 1991's strong results.
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Earnings Excluding Special Items $251 $114 $353 - ----------------------------------------------------------------------------- Asset Dispositions 13 - 59 Prior-Year Tax Adjustments (4) 7 76 LIFO Inventory Losses (3) (9) (2) Asset Write-Offs and Revaluations (1) - - Restructurings and Reorganizations (1) (1) - Other (3) - - - ----------------------------------------------------------------------------- Total Special Items 1 (3) 133 - ----------------------------------------------------------------------------- Reported Earnings $252 $111 $486 - -----------------------------------------------------------------------------
International downstream operations improved significantly as product sales margins recovered from the prior year's weak levels in all the company's marketing areas - Canada, the United Kingdom and in the Caltex areas of operations, especially South Africa and Singapore. Lower crude oil and operating costs coupled with stronger markets boosted sales margins in 1993. Also, the company's international trading results improved significantly.
Equity earnings of Caltex were $227 million, $180 million and $259 million for 1993, 1992, and 1991, respectively. In 1993, earnings were reduced $52 million for Chevron's share of Caltex ongoing adjustments to the carrying value of its petroleum inventories to reflect market values; earnings in 1991 included a special gain of $59 million from an asset sale. Total refined product sales volumes increased 7 percent from 1992 and 12 percent from 1991. Caltex volumes increased 6 percent in each year, continuing its average annual 6 percent growth of the past several years.
Earnings in 1992 fell from 1991 levels as weak global economic conditions held down product prices, shrinking sales margins in all the company's areas of operations. In 1991, operating earnings benefited from strong sales margins, particularly in the first quarter of that year when product prices did not fall as quickly as crude oil prices in the aftermath of the Persian Gulf War.
CHEMICALS earnings, excluding special items, fell 14 percent from 1992 levels and 74 percent from 1991 results.
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Earnings Excluding Special Items $ 31 $36 $117 - ----------------------------------------------------------------------------- Asset Dispositions 130 13 27 Prior-Year Tax Adjustments (5) (2) - Restructurings and Reorganizations (5) (1) - LIFO Inventory Gains 1 1 7 Asset Write-Offs and Revaluations - 8 - Other (9) 34 - - ----------------------------------------------------------------------------- Total Special Items 112 53 34 - ----------------------------------------------------------------------------- Reported Earnings $143 $89 $151 - -----------------------------------------------------------------------------
Results in the company's chemicals business reflected the continued depressed state of the commodity chemicals industry. The industry has suffered several years of depressed prices and demand due to overcapacity coupled with weak worldwide economies. In early 1994, the company announced additional measures to improve profitability and competitiveness of its chemicals business, including work-force reductions, cost reductions and reorganizations. Provisions for the expected cost of these measures were recorded in 1993.
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In 1992, in addition to industry conditions, plant shutdowns for maintenance and Hurricane Andrew also contributed to the earnings decline from 1991. Foreign currency transactions, mainly related to Brazil, resulted in losses of $10 million in 1993 and 1992 compared with losses of $6 million in 1991.
COAL AND OTHER MINERALS earnings, excluding special items, improved 13 percent from 1992 levels and quadrupled from 1991 results.
Operationally, a decline in coal earnings for 1993 was more than offset by lower non-coal exploration expenses, due to prior-year property dispositions. Annual coal sales in 1993 exceeded 20 million tons for the first time, but margins declined on lower prices.
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Earnings Excluding Special Items $44 $ 39 $11 - ----------------------------------------------------------------------------- Asset Dispositions 5 159 19 Prior-Year Tax Adjustments (2) - (4) Other (3) - (19) - ----------------------------------------------------------------------------- Total Special Items - 159 (4) - ----------------------------------------------------------------------------- Reported Earnings $44 $198 $ 7 =============================================================================
Operating earnings in 1992 were up more than threefold from 1991 levels, primarily from higher coal production that increased 10 percent over the prior year. Additionally, expenses in non-coal minerals operations were lower as the company continued its withdrawal from those businesses. The pending sale of lead and zinc deposits in Ireland is expected to be completed in 1994. The sale will result in a gain.
CORPORATE AND OTHER activities include interest expense, interest income on cash and marketable securities, real estate and insurance operations, and other activities of a corporate nature not allocated to the business segments.
Excluding the effects of special items, the lower costs in 1993 and 1992 primarily reflected the continued decline in interest expense, due to lower average interest rates and, in 1993, lower average debt levels.
Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- Results Excluding Special Items $ (76) $(190) $(214) - ----------------------------------------------------------------------------- Prior-Year Tax Adjustments 22 82 139 Asset Write-offs and Revaluations (13) - - Restructurings and Reorganizations (1) 7 (102) Other (82) (21) (23) - ----------------------------------------------------------------------------- Total Special Items (74) 68 14 - ----------------------------------------------------------------------------- Reported Earnings $(150) $(122) $(200) =============================================================================
Reported earnings in 1992 and 1991 included provisions of $41 million and $102 million for a companywide, voluntary enhanced early retirement program. In 1992, $65 million of pension settlement gains were recognized in connection with the program. These amounts were considered to be corporate items not properly allocable to the company's business segments.
LIQUIDITY AND CAPITAL RESOURCES. Cash, cash equivalents and marketable securities increased $321 million to $2.0 billion at year-end 1993. Cash provided by operating activities increased $307 million in 1993 to $4.2 billion, compared with $3.9 billion in 1992 and $3.3 billion in 1991. The 1993 increase reflects higher operational earnings, adjusted for non-cash charges, and decreased working capital requirements. Cash from operations and proceeds from asset sales were used to fund the company's capital expenditures, dividend payments to stockholders and retirement of debt.
AT YEAR-END 1993, THE COMPANY CLASSIFIED $1.9 BILLION OF SHORT-TERM OBLIGATIONS AS LONG-TERM DEBT. Settlement of these obligations, primarily commercial paper, is not expected to require the use of working capital in 1994 because the company has the intent and the ability to refinance them on a long-term basis. Commercial paper not reclassified to long-term debt also is intended to be reissued continuously or refinanced on a long-term basis.
ON DECEMBER 31, 1993, CHEVRON HAD $3.6 BILLION IN COMMITTED CREDIT FACILITIES WITH VARIOUS MAJOR BANKS. These facilities support commercial paper borrowing and also can be used for general credit requirements. No borrowings were outstanding under these facilities during the year or at year-end 1993.
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Chevron and one of its subsidiaries each have existing "shelf" registrations on file with the Securities and Exchange Commission that would permit registered offerings of up to approximately $1.05 billion of debt securities.
DURING 1993, THE COMPANY PREPAID TWO FIXED-TERM U.S. PUBLIC DEBT ISSUES TOTALING $600 MILLION. In early 1994, an additional $200 million of fixed-term U.S. public debt was called for early repayment. The debt issues were refinanced with short-term commercial paper. The company has pursued an aggressive debt management strategy focused on short-term and variable-rate financing. This strategy, together with the general decline in interest rates, has reduced the company's annual average before-tax interest rate from 7.6 percent in 1991, to 5.7 percent in 1992 and to 4.6 percent in 1993. The variable-rate component of total debt was 68 percent at the end of 1993. Chevron's total debt was $7.538 billion at year-end 1993, down $303 million from $7.841 billion at year-end 1992.
THE COMPANY'S FUTURE DEBT LEVEL IS PRIMARILY DEPENDENT ON ITS CAPITAL SPENDING PROGRAM AND ITS BUSINESS OUTLOOK. While the company does not currently expect its debt level to increase significantly during 1994, it believes it has substantial borrowing capacity to meet unanticipated cash requirements. In light of currently low crude oil prices, the company intends to monitor its capital spending and may make adjustments as the year progresses.
FINANCIAL RATIOS 1993 1992 1991 - ----------------------------------------------------------------------------- Current Ratio 0.8 0.9 0.9 Interest Coverage Ratio 7.4 8.2 5.1 Total Debt/Total Debt Plus Equity 35.0% 36.4% 34.3% =============================================================================
The CURRENT RATIO is the ratio of current assets to current liabilities at year-end. Two items affect the current ratio negatively, which in the company's opinion do not affect its liquidity. Included in current assets in all years are inventories valued on a LIFO basis, which at year-end 1993 were lower than current costs by $671 million. Also at year-end 1993, $2.5 billion of commercial paper included in current liabilities is planned to be refinanced continuously. Chevron's INTEREST COVERAGE RATIO decreased in 1993 due to lower before-tax income. The interest coverage ratio is defined as income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. The company's DEBT RATIO (total debt to total debt plus equity) decreased to 35.0 percent, due primarily to a net reduction in debt of $303 million.
The company's senior debt is rated AA by Standard & Poor's Corporation and Aa2 by Moody's Investors Service. Chevron's U.S. commercial paper is rated A-1+ by Standard & Poor's and Prime-1 by Moody's, and Chevron's Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All these ratings denote high-quality, investment-grade securities.
IN JANUARY 1994, THE COMPANY INCREASED ITS QUARTERLY DIVIDEND 5 CENTS PER SHARE TO $.925, AN ANNUALIZED RATE OF $3.70 PER SHARE, AND PROPOSED A TWO-FOR-ONE SPLIT OF ITS ISSUED COMMON STOCK. Stockholders will be asked to approve an increase in the number of authorized shares of common stock from 500 million to 1 billion to accommodate the split and also to approve the stock split at the annual meeting on May 3, 1994.
CAPITAL AND EXPLORATORY EXPENDITURES
1993 1992 1991 - ---------------------------------- -------------------- --------------------- Millions Interna- Interna- Interna- of dollars U.S. tional Total U.S. tional Total U.S. tional Total - ----------------------------------------------------------------------------- Exploration and Production $ 763 $1,599 $2,362 $ 792 $1,458 $2,250 $1,121 $1,408 $2,529
Refining, Marketing and Transportation 949 748 1,697 962 749 1,711 974 775 1,749
Chemicals 199 34 233 224 37 261 195 34 229
Coal and Other Minerals 47 10 57 65 20 85 99 14 113
All Other 91 - 91 116 - 116 166 1 167 - ----------------------------------------------------------------------------- Total $2,049 $2,391 $4,440 $2,159 $2,264 $4,423 $2,555 $2,232 $4,787 - ----------------------------------------------------------------------------- Total Excluding Equity in Affili- ates $2,029 $1,710 $3,739 $2,136 $1,666 $3,802 $2,540 $1,749 $4,289 =============================================================================
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WORLDWIDE CAPITAL AND EXPLORATORY EXPENDITURES FOR 1993, INCLUDING THE COMPANY'S EQUITY SHARE OF AFFILIATES' EXPENDITURES, TOTALED $4.4 BILLION. Expenditures for exploration and production accounted for 53 percent of total outlays in 1993, 51 percent in 1992 and 53 percent in 1991. U.S. exploration and production spending declined to 32 percent of worldwide exploration and production expenditures in 1993, down from 35 percent in 1992 and 44 percent in 1991, reflecting the company's increasing focus on international exploration and production activities.
THE COMPANY PROJECTS 1994 CAPITAL AND EXPLORATORY EXPENDITURES AT APPROXIMATELY $4.9 BILLION, including Chevron's share of spending by affiliates. Excluding affiliates, spending will be essentially flat at $3.7 billion. The 1994 program provides $2.4 billion in exploration and production investments, of which about 75 percent is for international projects.
The company is participating in several significant oil and gas development projects. These projects include the development of the Hibernia field off the coast of Newfoundland; the Tengiz project in Kazakhstan; steam and waterflood projects in Indonesia; expansion of the North West Shelf liquefied natural gas project in Australia; additional development in the North Sea, Nigeria and Angola; continuing enhanced oil recovery projects in California; and a natural gas development project in the Norphlet Trend in the Gulf of Mexico.
Refining, marketing and transportation expenditures are estimated at about $2.1 billion, with $1 billion of that planned for the U.S., including upgrading U.S. refineries to produce reformulated gasolines needed to comply with the Clean Air Act. Most of the balance will be focused on high growth Asia Pacific Rim countries, where the company's Caltex affiliate has several major refinery projects under way to increase capacity and meet rising demand.
QUARTERLY RESULTS AND STOCK MARKET DATA Unaudited
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REPORT OF MANAGEMENT TO THE STOCKHOLDERS OF CHEVRON CORPORATION
Management of Chevron is responsible for preparing the accompanying financial statements and for assuring their integrity and objectivity. The statements were prepared in accordance with generally accepted accounting principles and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management's best estimates and judgments.
The company's statements have been audited by Price Waterhouse, independent accountants, selected by the Audit Committee and approved by the stockholders. Management has made available to Price Waterhouse all the company's financial records and related data, as well as the minutes of stockholders' and directors' meetings.
Management of the company has established and maintains a system of internal accounting controls that is designed to provide reasonable assurance that assets are safeguarded, transactions are properly recorded and executed in accordance with management's authorization, and the books and records accurately reflect the disposition of assets. The system of internal controls includes appropriate division of responsibility. The company maintains an internal audit department that conducts an extensive program of internal audits and independently assesses the effectiveness of the internal controls.
The Audit Committee is composed of directors who are not officers or employees of the company. It meets regularly with members of management, the internal auditors and the independent accountants to discuss the adequacy of the company's internal controls, financial statements and the nature, extent and results of the audit effort. Both the internal auditors and the independent accountants have free and direct access to the Audit Committee without the presence of management.
Kenneth T. Derr Martin R. Klitten Donald G. Henderson Chairman of the Board and Vice President, Finance Vice President and Chief Executive Officer Comptroller
February 25, 1994
REPORT OF INDEPENDENT ACCOUNTANTS TO THE STOCKHOLDERS AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders' equity and cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 1992, the company changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
Price Waterhouse
San Francisco, California February 25, 1994
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CONSOLIDATED STATEMENT OF INCOME
Year Ended December 31 Millions of dollars, ------------------------------------- except per-share amounts 1993 1992 (1) 1991 (1) - ----------------------------------------------------------------------------- REVENUES Sales and other operating revenues (2) $36,191 $38,212 $38,118 Equity in net income of affiliated companies 440 406 491 Other income 451 1,059 334 - ----------------------------------------------------------------------------- TOTAL REVENUES 37,082 39,677 38,943 - ----------------------------------------------------------------------------- COSTS AND OTHER DEDUCTIONS Purchased crude oil and products 18,007 19,872 19,693 Operating expenses 6,267 6,145 6,933 Provision for U.S. refining and marketing restructuring 837 - - Exploration expenses 360 507 629 Selling, general and administrative expenses 1,530 1,761 1,704 Depreciation, depletion and amortization 2,452 2,594 2,616 Taxes other than on income (2) 4,886 4,899 4,597 Interest and debt expense 317 436 519 - ----------------------------------------------------------------------------- TOTAL COSTS AND OTHER DEDUCTIONS 34,656 36,214 36,691 - ----------------------------------------------------------------------------- INCOME BEFORE INCOME TAX EXPENSE AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 2,426 3,463 2,252 INCOME TAX EXPENSE 1,161 1,253 959 ============================================================================= INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES $ 1,265 $ 2,210 $ 1,293 CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES - (641) - ============================================================================= NET INCOME $1,265 $1,569 $1,293 ============================================================================= PER SHARE OF COMMON STOCK: INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES $3.89 $6.52 $3.69 CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES - (1.89) - --------------------------------- NET INCOME PER SHARE OF COMMON STOCK $3.89 $4.63 $3.69 WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING 325,478,876 338,977,414 350,174,450 ============================================================================= (1) Reclassified. See Note 1. (2) Includes consumer excise taxes. $4,068 $3,964 $3,659
See accompanying notes to consolidated financial statements.
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CONSOLIDATED BALANCE SHEET
At December 31 -------------------- Millions of dollars 1993 1992 - ----------------------------------------------------------------------------- ASSETS Cash and cash equivalents $ 1,644 $ 1,292 Marketable securities, at cost 372 403 Accounts and notes receivable (less allowance: 1993 - $66; 1992 - $66) 3,808 4,115 Inventories: Crude oil and petroleum products 1,108 1,276 Chemicals 423 497 Materials and supplies 252 292 Other merchandise 18 70 -------------------- 1,801 2,135 Prepaid expenses and other current assets 1,057 827 - ----------------------------------------------------------------------------- TOTAL CURRENT ASSETS 8,682 8,772 Long-term receivables 94 127 Investments and advances 3,623 2,451
Properties, plant and equipment, at cost 44,807 44,010 Less: accumulated depreciation, depletion and amortization 22,942 21,822 -------------------- 21,865 22,188 Deferred charges and other assets 472 432 - ----------------------------------------------------------------------------- TOTAL ASSETS $34,736 $33,970 ============================================================================= - ----------------------------------------------------------------------------- LIABILITIES AND STOCKHOLDERS' EQUITY Accounts payable $3,325 $3,469 Accrued liabilities 2,538 2,009 Short-term debt 3,456 2,888 Federal and other taxes on income 782 967 Other taxes payable 505 502 - ----------------------------------------------------------------------------- TOTAL CURRENT LIABILITIES 10,606 9,835 Long-term debt and capital lease obligations 4,082 4,953 Non-current deferred income taxes 2,916 2,894 Reserves for employee benefit plans 1,458 1,400 Deferred credits and other non-current obligations 1,677 1,160 - ----------------------------------------------------------------------------- TOTAL LIABILITIES 20,739 20,242 - ----------------------------------------------------------------------------- Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued) - - Common stock (authorized 500,000,000 shares, $3.00 par value, 356,243,534 shares issued) 1,069 1,069 Capital in excess of par value 1,855 1,840 Deferred compensation - Employee Stock Ownership Plan (ESOP) (920) (954) Currency translation adjustment and other 108 56 Retained earnings 13,955 13,814 Treasury stock, at cost (1993 - 30,504,429 shares; 1992 - 31,069,745 shares) (2,070) (2,097) - ----------------------------------------------------------------------------- TOTAL STOCKHOLDERS' EQUITY 13,997 13,728 - ----------------------------------------------------------------------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $34,736 $33,970 ============================================================================= See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENT OF CASH FLOWS Year Ended December 31 ---------------------------- Millions of dollars 1993 1992 1991 - ----------------------------------------------------------------------------- OPERATING ACTIVITIES Net income $1,265 $1,569 $1,293 Adjustments Depreciation, depletion and amortization 2,452 2,594 2,616 Dry hole expense related to prior years' expenditures 29 57 35 Distributions less than equity in affiliates' income (173) (144) (220) Net before-tax losses (gains) on asset retirements and sales 373 (568) 25 Net currency translation (gains) losses (27) (66) 4 Deferred income tax provision (160) (176) (183) Cumulative effect of changes in accounting principles - 641 - Net decrease (increase) in operating working capital (1) 463 82 (249) Other (1) (75) (43) - ----------------------------------------------------------------------------- NET CASH PROVIDED BY OPERATING ACTIVITIES (2) 4,221 3,914 3,278 - ----------------------------------------------------------------------------- INVESTING ACTIVITIES Capital expenditures (3,323) (3,352) (3,693) Proceeds from asset sales 908 1,043 768 Net sales of marketable securities (3) 30 45 18 - ----------------------------------------------------------------------------- NET CASH USED FOR INVESTING ACTIVITIES (2,385) (2,264) (2,907) - ----------------------------------------------------------------------------- FINANCING ACTIVITIES Net borrowings of short-term obligations 293 1,333 1,564 Proceeds from issuance of long-term debt 199 23 35 Repayments of long-term debt and other financing obligations (854) (1,260) (711) Cash dividends paid (1,139) (1,115) (1,139) Purchases of treasury shares (4) (382) (286) - ----------------------------------------------------------------------------- NET CASH USED FOR FINANCING ACTIVITIES (1,505) (1,401) (537) - ----------------------------------------------------------------------------- EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS 21 3 (20) - ----------------------------------------------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS 352 252 (186) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,292 1,040 1,226 - ----------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT YEAR-END $1,644 $1,292 $1,040 =============================================================================
(1) The "Net decrease (increase) in operating working capital" is composed of the following: Decrease in accounts and notes receivable $ 187 $ 97 $ 692 Decrease in inventories 288 292 312 (Increase) decrease in prepaid expenses and other current assets (52) 85 (151) Increase (decrease) in accounts payable and accrued liabilities 214 (567) (880) (Decrease) increase in income and other taxes payable (174) 175 (222) - ----------------------------------------------------------------------------- Net decrease (increase) in operating working capital $ 463 $ 82 $ (249) ============================================================================= (2) "Net Cash Provided by Operating Activities" includes the following cash payments for interest and income taxes: Interest paid on debt (net of capitalized interest) $ 309 $ 392 $ 453 Income taxes paid $1,505 $1,236 $1,460 ============================================================================= (3) "Net sales of marketable securities" consists of the following gross amounts: Marketable securities purchased $(1,855) $(2,633) $(4,104) Marketable securities sold 1,885 2,678 4,122 - ----------------------------------------------------------------------------- Net sales of marketable securities $ 30 $ 45 $ 18 ============================================================================= See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Millions of dollars
NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Chevron Corporation and its consolidated subsidiaries (the company) employ accounting policies that are in accordance with generally accepted accounting principles in the United States.
SUBSIDIARY AND AFFILIATED COMPANIES. The consolidated financial statements include the accounts of subsidiary companies more than 50 percent owned. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 to 50 percent, or for which the company participates in policy decisions, are accounted for by the equity method. Under this accounting, remaining unamortized cost is increased or decreased by the company's share of earnings or losses after dividends.
OIL AND GAS ACCOUNTING. The successful efforts method of accounting is used for oil and gas exploration and production activities.
SHORT-TERM INVESTMENTS. Short-term investments that are part of the company's cash management portfolio are classified as cash equivalents. These investments are highly liquid and generally have original maturities of three months or less. All other short-term investments are classified as marketable securities.
INVENTORIES. Crude oil, petroleum products, chemicals and other merchandise are stated at cost, using a Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. Materials and supplies inventories generally are stated at average cost.
PROPERTIES, PLANT AND EQUIPMENT. All costs for development wells, related plant and equipment (including carbon dioxide and certain other injected materials used in enhanced recovery projects), and mineral interests in oil and gas properties are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. All other exploratory wells and costs are expensed.
Proved oil and gas properties are regularly assessed for possible impairment on an aggregate worldwide portfolio basis, applying the informal "ceiling test" of the Securities and Exchange Commission. Under this method, the possibility of an impairment may exist if the aggregate net book carrying value of these properties, net of applicable deferred income taxes, exceeds the aggregate undiscounted future cash flows, after tax, from the properties, as calculated in accordance with accounting rules for supplemental information on oil and gas producing activities. In addition, high-cost, long-lead-time oil and gas projects are individually assessed prior to production start-up by comparing the recorded investment in the project with its fair market or economic value, as appropriate. Economic values are generally based on management's expectations of discounted future after-tax cash flows from the project at the time of assessment.
Depreciation and depletion (including provisions for future abandonment and restoration costs) of all capitalized costs of proved oil and gas producing properties, except mineral interests, are expensed using the unit-of-production method by individual fields as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are determined using the unit-of-production method by individual fields as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed.
Depreciation and depletion expenses for coal and other mineral assets are determined using the unit-of-production method as the proved reserves are produced. The capitalized costs of all other plant and equipment are depreciated or amortized over estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method generally is used to depreciate international plant and equipment and to amortize all capitalized leased assets.
Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements or sales are included in income.
Expenditures for maintenance, repairs and minor renewals to maintain facilities in operating condition are expensed. Major replacements and renewals are capitalized.
ENVIRONMENTAL EXPENDITURES. Environmental expenditures that relate to current ongoing operations or to an existing condition caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when environmental assessments and/or cleanups are probable, and the costs can be reasonably estimated. Other than for assessments, the timing of these accruals coincides with the company's commitment to a formal plan of action, such as an approved remediation plan or the sale or disposal of an asset. For oil and gas and coal producing properties, a provision is made through depreciation expense for anticipated abandonment and restoration costs at the end of the property's useful life.
For Superfund sites, the company records a liability for its share of costs when it has been named as a Potentially Responsible Party (PRP) and when an assessment or cleanup plan has been developed. This liability includes the company's own portion of the costs and also the company's portion of amounts for other PRPs when it is probable that they will not be able to pay their share of the cleanup obligation.
The company records the gross amount of its liability based on its best estimate of future costs in current dollars and using currently available technology and applying current regulations as well as the company's own internal environmental policies. Future amounts are not discounted. Probable recoveries or reimbursements are recorded as an asset.
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NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued
CURRENCY TRANSLATION. The U.S. dollar is the functional currency for the company's consolidated operations as well as for substantially all operations of its equity method companies. For those operations, all gains or losses from currency transactions are included in income currently. The cumulative translation effects for the few equity affiliates using functional currencies other than the U.S. dollar are included in the currency translation adjustment in stockholders' equity.
TAXES. Effective 1992, the company accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes." In 1991, the company accounted for income taxes in accordance with Statement No. 96, "Accounting for Income Taxes." Income taxes are accrued for retained earnings of international subsidiaries and corporate joint ventures intended to be remitted. Income taxes are not accrued for unremitted earnings of international operations that have been, or are intended to be, reinvested indefinitely.
RECLASSIFICATION OF CERTAIN REVENUES AND PURCHASES. To conform to the presentation in 1993, the years 1992 and 1991 in the consolidated income statement were reclassified to net certain offsetting forward crude oil purchases and sales contracts. This reclassification had no effect on net income for any period. Sales and other operating revenues, and purchased crude oil and products, decreased $3,216 for 1992 and $2,002 for 1991, from the amounts previously reported.
NOTE 2: ADOPTION OF STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS NO. 106, "EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS" (SFAS 106) AND NO. 109, "ACCOUNTING FOR INCOME TAXES" (SFAS 109) Effective January 1, 1992, the company adopted SFAS 106 and SFAS 109, issued by the Financial Accounting Standards Board. The effects of these statements on 1992 net income included a charge of $641, or $1.89 per share, attributable to the cumulative effect of adoption, including the company's share of equity affiliates. This net charge was composed of $833, after related tax benefits of $423, for the recognition of liabilities for retiree benefits (primarily health and life insurance), partially offset by a credit of $192 for deferred income tax benefits and other changes stipulated by the new income tax accounting rules.
Apart from the cumulative effect, adoption of the statements increased earnings for 1992 by $163 after tax, or $.48 per share. Under the new income tax accounting, benefits of $200 were recorded, largely due to the strengthening of the dollar in 1992, which resulted in lower foreign deferred tax liabilities. These benefits were partly offset by $37 of additional after-tax expense for retiree benefits, when compared to the previous practice of expensing these costs when paid.
NOTE 3: SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION Net income is affected by transactions that are unrelated to or are not representative of the company's ongoing operations for the periods presented. These transactions, defined by management and designated "special items," can obscure the underlying results of operations for a year as well as affect comparability of results between years.
Listed below are categories of special items and their net increase (decrease) to net income, after related tax effects:
Year Ended December 31 ----------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- Asset dispositions, net Ortho lawn and garden products $ 130 $ - $ - Oil and gas properties (25) 209 44 Stock exchange with Pennzoil Company - 376 - Copper interest in Chile - 159 - Other 17 13 105 ----------------------------- 122 757 149 - ----------------------------------------------------------------------------- Asset write-offs and revaluations Oil and gas properties (31) (110) - Refining and marketing assets (24) (31) (24) Other (16) 8 - ----------------------------- (71) (133) (24) - ----------------------------------------------------------------------------- Prior-year tax adjustments (130) 72 173 - ----------------------------------------------------------------------------- Environmental remediation provisions (90) (44) (160) - ----------------------------------------------------------------------------- Restructurings and reorganizations Work-force reductions, net (11) (40) (102) U.S. Refining and marketing (543) - (83) ----------------------------- (554) (40) (185) - ----------------------------------------------------------------------------- LIFO inventory (losses) gains (46) (26) 16 - ----------------------------------------------------------------------------- Other, net Litigation and regulatory issues (70) (11) (35) One-time employee bonus (60) - - Chemicals products license agreements - 32 - Other adjustments 16 44 - ----------------------------- (114) 65 (35) - ----------------------------------------------------------------------------- Total special items, after tax* $(883) $651 $(66) ============================================================================= *Amounts include the company's share of equity affiliates' transactions.
The U.S. refining and marketing restructuring charge of $543 was primarily composed of a writedown of two refineries and their related inventories to estimated realizable values. Also included in the charge were provisions for environmental site assessments and employee severance. The estimated realizable value of the refineries took into account probable environmental cleanup obligations. Responsibility for these obligations will be negotiated with potential buyers. The refineries are located in Port Arthur, Texas, and Philadelphia, Pennsylvania, and have a combined refinery capacity of about 350,000 barrels per day.
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NOTE 3: SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION - Continued
Other financial information is as follows:
Year Ended December 31 ----------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- Total financing interest and debt costs $371 $478 $546 Less: capitalized interest 54 42 27 - ----------------------------------------------------------------------------- Interest and debt expense 317 436 519 Research and development expenses 206 229 250 Currency transaction gains (losses)* $ 46 $ 90 $ (4) ============================================================================= *Includes $18 and $24 in 1993 and 1992, respectively, for the company's share of affiliates' currency transaction effects; in 1991 the net effect was zero.
The excess of current cost (based on average acquisition costs for the year) over the carrying value of inventories for which the LIFO method is used was $671 and $803 at December 31, 1993 and 1992, respectively.
NOTE 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS The Consolidated Statement of Cash Flows excludes the following non-cash transactions:
In 1993, the company acquired a 50 percent interest in the Tengizchevroil joint venture (TCO) in the Republic of Kazakhstan through a series of cash and non-cash transactions. The company's interest in TCO is accounted for using the equity method of accounting and is recorded in "Investments and advances" in the consolidated balance sheet. The cash expended in connection with the formation of TCO and subsequent advances to TCO have been included in the consolidated statement of cash flows in "Capital expenditures." The deferred payment portion of the TCO investment totaled $709 at year-end 1993 and is recorded in "Accrued liabilities" and "Deferred credits and other non-current obligations" in the consolidated balance sheet. The timing of these payments is dependent on the occurrence of certain future events, including the pace of field development and the completion and successful operation of an export pipeline system. During 1993, payments related to the deferred portion of the TCO investment were classified as Repayments of long-term debt and other financing obligations" in the consolidated statement of cash flows.
The company's Employee Stock Ownership Plan (ESOP) repaid $30 and $20 of matured debt guaranteed by Chevron Corporation in 1993 and 1991, respectively. The company reflected this payment as reductions in debt outstanding and in Deferred Compensation - ESOP.
The company refinanced an aggregate amount of $334 and $57 in tax exempt long-term debt and capital lease obligations in 1993 and 1992, respectively. In 1991, the company refinanced $970 of long-term bank notes of the ESOP with the public issuance of SEC registered long-term notes of a like amount. These refinancings are not reflected in the consolidated statement of cash flows.
In 1992, the company received 15,750,000 shares of its common stock held by a stockholder in exchange for the stock of a subsidiary owning certain U.S. oil and gas producing properties and related facilities, cash and other current assets and current liabilities. The value attributed to the treasury shares received was $1,100. The property exchanged consisted of properties, plant and equipment with a carrying value of $790 and, excluding cash, net current liabilities of $1. Cash of $57 was included as a reduction of proceeds from asset sales.
In 1992, the company acquired an additional ownership interest in an affiliate, accounted for under the equity method, in a non-cash transaction. This increase in ownership required the consolidation of the affiliate into the company's financial statements. The principal result of this consolidation was to increase non-current assets and liabilities by approximately $64.
There have been other non-cash transactions that have occurred during the years presented. These include the reissuance of treasury shares for management compensation plans, acquisitions of properties, plant and equipment through capital lease transactions, and changes in stockholders' equity, long-term debt and other liabilities resulting from the accounting for the company's ESOP. The amounts for these transactions have not been material in the aggregate in relation to the company's financial position.
The major components of "Capital expenditures," and the reconciliation of this amount to the capital and exploratory expenditures, excluding equity in affiliates, presented in "Management's Discussion and Analysis of Financial Condition and Results of Operations," are presented below:
Year Ended December 31 ----------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- Additions to properties, plant and equipment $3,214 $3,342 $3,698 Additions to investments 179 47 48 Payments for other (liabilities) and assets, net (70) (37) (53) - ----------------------------------------------------------------------------- Capital expenditures 3,323 3,352 3,693 Expensed exploration expenditures 330 450 594 Equipment acquired through a non-cash capital lease transaction - - 2 Repayments of long-term debt and other financing obligations 86 - - - ----------------------------------------------------------------------------- Capital and exploratory expenditures, excluding equity companies $3,739 $3,802 $4,289 =============================================================================
NOTE 5. STOCKHOLDERS' EQUITY Retained earnings at December 31, 1993, include $2,087 for the company's share of undistributed earnings of equity affiliates.
In 1988, the company declared a dividend distribution of one Right for each outstanding share of common stock. The Rights will be exercisable, unless redeemed earlier by the company, if a person or group acquires, or obtains the right to acquire, 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer that would result in acquiring 10 percent or more of the outstanding shares of common stock, either event occurring without the prior consent of the company. Each Right entitles its holder to purchase stock having a value equal to two times the exercise price of the Right. The person or group who had acquired 10 percent
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NOTE 5. STOCKHOLDERS' EQUITY - Continued
or more of the outstanding shares of common stock without the prior consent of the company would not be entitled to this purchase opportunity.
The Rights will expire in November 1998, or they may be redeemed by the company at 5 cents per share prior to that date. The Rights do not have voting or dividend rights and, until they become exercisable, have no dilutive effect on the earnings of the company. Five million shares of the company's preferred stock have been designated Series A participating preferred stock and reserved for issuance upon exercise of the Rights.
No event during 1993 made the Rights exercisable.
The Board of Directors has proposed a two-for-one split of the company's issued common stock. Stockholders have been asked to approve the split and an increase in authorized shares of common stock from 500 million to 1 billion to accommodate the split at the annual stockholders' meeting on May 3, 1994. If approved, the split will be effective May 11, 1994 for stockholders of record on that date.
NOTE 6. FINANCIAL INSTRUMENTS
OFF-BALANCE SHEET RISK. The company enters into forward exchange contracts, generally with terms of 90 days or less, as a hedge against some of its foreign currency exposures. Offsetting gains and losses on these contracts are recognized concurrently with the exchange gains and losses stemming from the associated commitments. At December 31, 1993 and 1992, the company had not recognized gains or losses on forward contracts with a carrying and approximate fair value of $114 and $119, respectively.
CONCENTRATIONS OF CREDIT RISK. The company's financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities and trade receivables.
The company's cash equivalents and marketable securities are in high-quality securities placed with a wide array of institutions with high credit ratings. This investment policy limits the company's exposure to concentrations of credit risk.
The trade receivable balances, reflecting the company's diversified sources of revenue, are dispersed among the company's broad customer base worldwide. As a consequence, concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. Letters of credit are the principal security obtained to support lines of credit or negotiated contracts when the financial strength of a customer is not considered sufficient.
FAIR VALUE. At December 31, 1993, the company's long-term debt of $2,057 had an estimated fair value of $2,238. The fair value is based on quoted market prices at December 31, 1993, or the present value of expected cash flows when a quoted market price was not available.
The reported amounts of financial instruments such as Cash equivalents, Marketable securities and Short-term debt approximate fair value because of their short maturity.
NOTE 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC. At December 31, 1993, Chevron U.S.A. Inc. was Chevron Corporation's principal operating company, consisting primarily of the company's U.S. integrated petroleum operations (excluding most of the domestic pipeline operations). These operations are conducted by three divisions: Chevron U.S.A. Production Company, Chevron U.S.A. Products Company and Warren Petroleum Company. Summarized financial information for Chevron U.S.A. Inc. and its consolidated subsidiaries is presented below:
Year Ended December 31 ----------------------------- 1993 1992* 1991* - ----------------------------------------------------------------------------- Sales and other operating revenues $28,092 $29,454 $29,073 Total costs and other deductions 27,588 28,410 28,861 Income before cumulative effect of changes in accounting principles 325 811 90 Cumulative effect of changes in accounting principles - (573) - Net income 325 238 90 =============================================================================
At December 31 ---------------- 1993 1992 - ----------------------------------------------------------------------------- Current assets $3,661 $4,200 Other assets 14,099 14,587 Current liabilities 5,936 5,528 Other liabilities 5,738 6,795 Net equity 6,086 6,464 ============================================================================= *To conform to the presentation adopted in 1993, the 1992 and 1991 periods have been reclassified to net certain offsetting crude oil purchases and sales contracts. The reclassification had no effect on net income. See Note 1.
NOTE 8. LITIGATION The company is a defendant in numerous lawsuits, in addition to those mentioned in this note. Plaintiffs may seek to recover large and sometimes unspecified amounts, and some matters may remain unresolved for several years.
In April 1991, a United States District Court in Texas ruled favorably on claims brought by former employees of Gulf and participants in the Gulf Pension Plan that a partial termination of the plan had occurred. However, the court denied plaintiffs' claims to a share of any surplus plan assets. In October 1991, the district court approved a partial settlement in which the parties agreed not to appeal the partial termination claims except as relevant to plaintiffs' claims for a share of surplus plan assets. These claims are now before the Fifth Circuit Court of Appeals. A second partial settlement was implemented in 1993, resulting in a charge to earnings of $48.
A lawsuit brought against the company by OXY USA Inc., the successor in interest to Cities Service Company, remains pending in an Oklahoma state court. The suit involves claims for breach of contract and misrepresentation related to the termination of Gulf Oil Corporation's offer to purchase Cities' stock in 1982. (Gulf was acquired by Chevron in 1984.)
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NOTE 8. LITIGATION - Continued
Management is of the opinion that resolution of the lawsuits will not result in any significant liability to the company in relation to its consolidated financial position or liquidity.
NOTE 9. GEOGRAPHIC AND SEGMENT DATA The geographic and segment distributions of the company's identifiable assets, operating income and sales and other operating revenues are summarized in the following tables. The company's primary business is its integrated petroleum operations. Secondary operations include chemicals and coal. The company's real estate and insurance operations and worldwide cash management and financing activities are in "Corporate and Other."
At December 31 ----------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- IDENTIFIABLE ASSETS United States Petroleum $16,443 $18,508 $20,056 Chemicals 2,045 2,165 2,210 Coal and Other Minerals 744 762 767 ---------------------------- Total United States 19,232 21,435 23,033 ----------------------------- International Petroleum 12,202 9,671 9,018 Chemicals 412 390 402 Coal and Other Minerals 13 10 12 - ----------------------------------------------------------------------------- Total International 12,627 10,071 9,432 - ----------------------------------------------------------------------------- TOTAL IDENTIFIABLE ASSETS 31,859 31,506 32,465 Corporate and Other 2,877 2,464 2,171 - ----------------------------------------------------------------------------- TOTAL ASSETS $34,736 $33,970 $34,636 - -----------------------------------------------------------------------------
Year Ended December 31 ----------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- OPERATING INCOME United States Petroleum $ 692 $ 1,693 $ 289 Chemicals 162 46 149 Coal and Other Minerals 59 68 27 ----------------------------- Total United States 913 1,807 465 ----------------------------- International Petroleum 1,772 1,731 2,205 Chemicals 63 70 47 Coal and Other Minerals (3) 177 (26) ----------------------------- Total International 1,832 1,978 2,226 - ----------------------------------------------------------------------------- TOTAL OPERATING INCOME 2,745 3,785 2,691 Corporate and Other (319) (322) (439) Income Tax Expense (1,161) (1,253) (959) - ----------------------------------------------------------------------------- Income Before Cumulative Effect of Changes in Accounting Principles $ 1,265 $ 2,210 $ 1,293 Cumulative Effect of Changes in Accounting Principles - (641) - - ----------------------------------------------------------------------------- NET INCOME $ 1,265 $ 1,569 $ 1,293 =============================================================================
Year Ended December 31 ----------------------------- 1993 1992* 1991* ----------------------------- SALES AND OTHER OPERATING REVENUES United States Petroleum-Refined products $13,169 $13,964 $13,921 -Crude oil 4,086 5,138 6,649 -Natural gas 1,776 1,631 1,502 -Natural gas liquids 1,098 1,075 1,043 -Other petroleum revenues 682 700 611 -Excise taxes 2,554 2,458 2,267 -Intersegment 924 1,052 1,226 ----------------------------- Total Petroleum 24,289 26,018 27,219 ----------------------------- Chemicals-Products 2,211 2,409 2,652 -Intersegment 248 266 252 ----------------------------- Total Chemicals 2,459 2,675 2,904 ----------------------------- Coal and Other Minerals-Products 447 395 417 ----------------------------- Total United States 27,195 29,088 30,540 - ----------------------------------------------------------------------------- International Petroleum-Refined products 2,920 2,857 2,873 -Crude oil 4,415 4,893 3,627 -Natural gas 380 364 367 -Natural gas liquids 137 115 122 -Other petroleum revenues 285 227 201 -Excise taxes 1,499 1,490 1,374 -Intersegment 1 10 13 ----------------------------- Total Petroleum 9,637 9,956 8,577 ----------------------------- Chemicals-Products 497 463 446 -Excise taxes 15 16 18 -Intersegment 6 5 4 ----------------------------- Total Chemicals 518 484 468 ----------------------------- Coal and Other Minerals-Products - 2 10 ----------------------------- Total International 10,155 10,442 9,055 - ----------------------------------------------------------------------------- Intersegment sales elimination (1,179) (1,333) (1,495) - ----------------------------------------------------------------------------- Corporate and Other 20 15 18 - ----------------------------------------------------------------------------- TOTAL SALES AND OTHER OPERATING REVENUES $36,191 $38,212 $38,118 ============================================================================= Memo: Intergeographic Sales United States $ 266 $ 309 $ 361 International 4,418 3,823 3,497 - ----------------------------------------------------------------------------- *To conform to the presentation adopted in 1993, the 1992 and 1991 periods have been reclassified to net certain offsetting crude oil purchases and sales contracts. The reclassification had no effect on net income. See Note 1.
Operating income for the geographic areas includes allocated corporate overhead. In 1992 and 1991, the operating income for the business segments excluded corporate charges of $63 and $154 for a companywide voluntary enhanced early retirement program. In 1992, $103 of pension settlement gains were recognized in connection with the program. These amounts are included in "Corporate and Other."
Identifiable assets include all assets associated with operations in the indicated geographic areas, including investments in affiliates.
Sales and other operating revenues for the petroleum segment are derived from the production and sale of crude oil,
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NOTE 9. GEOGRAPHIC AND SEGMENT DATA - Continued
natural gas and natural gas liquids, and from the refining and marketing of petroleum products. The company also obtains revenues from the transportation and trading of crude oil and refined products. Chemicals revenues result primarily from the sale of petrochemicals, plastic resins, and lube oil and fuel additives. Coal and other minerals revenues relate primarily to coal sales.
Sales and other operating revenues in the above table include both sales to unaffiliated customers and sales from the transfer of products between segments. Sales from the transfer of products between segments and geographic areas are generally at estimated market prices. Transfers between geographic areas are presented as memo items below the table.
Equity in earnings of affiliated companies has been associated with the segments in which the affiliates operate. Sales to the Caltex Group are included in the International petroleum segment. Information on these affiliates is presented in Note 11. Other affiliates are either not material or not vertically integrated with a segment's operations.
NOTE 10. LEASE COMMITMENTS Certain non-cancelable leases are classified as capital leases, and the leased assets are included as part of properties, plant and equipment. Other leases are classified as operating leases and are not capitalized. Details of the capitalized leased assets are as follows:
At December 31 ----------------- 1993 1992 - ----------------------------------------------------------------------------- Petroleum Exploration and Production $ 50 $ 50 Refining, Marketing and Transportation 554 553 - ----------------------------------------------------------------------------- 604 603 Less: accumulated amortization 409 381 - ----------------------------------------------------------------------------- Net capitalized leased assets $195 $222 =============================================================================
At December 31, 1993, the future minimum lease payments under operating and capital leases are as follows: At December 31 -------------------- Operating Capital Year Leases Leases - ----------------------------------------------------------------------------- 1994 $174 $ 41 1995 143 48 1996 128 43 1997 110 41 1998 100 42 Thereafter 220 500 - ----------------------------------------------------------------------------- Total $875 715 - ------------------------------------------------------------------ Less: amounts representing interest and executory costs (292) - ----------------------------------------------------------------------------- Net present value 423 Less: capital lease obligations included in short-term debt (278) - ----------------------------------------------------------------------------- Long-term capital lease obligations $145 ============================================================================= Future sublease rental income $ 46 $ - =============================================================================
Rental expenses incurred for operating leases during 1993, 1992 and 1991 were as follows: At December 31 ----------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- Minimum rentals $452 $408 $472 Contingent rentals 9 10 11 - ----------------------------------------------------------------------------- Total 461 418 483 Less: sublease rental income 15 14 49 - ----------------------------------------------------------------------------- Net rental expense $446 $404 $434 =============================================================================
Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging from one to 25 years and/or options to purchase the leased property during or at the end of the initial lease period for the fair market value at that time.
NOTE 11. INVESTMENTS AND ADVANCES Investments in and advances to companies accounted for using the equity method, and other investments accounted for at or below cost, are as follows: At December 31 ----------------- 1993 1992 - ----------------------------------------------------------------------------- Equity Method Affiliates Caltex Group $2,147 $1,905 Other affiliates 1,353 450 - ----------------------------------------------------------------------------- 3,500 2,355 Other, at or below cost 123 96 - ----------------------------------------------------------------------------- Total investments and advances $3,623 $2,451 =============================================================================
Chevron owns 50 percent each of P.T. Caltex Pacific Indonesia, an exploration and production company operating in Indonesia; Caltex Petroleum Corporation, which, through its subsidiaries and affiliates, conducts refining and marketing activities in Asia, Africa, Australia and New Zealand; and American Overseas Petroleum Limited, which, through its subsidiaries, manages certain of the company's exploration and production operations in Indonesia. These companies and their subsidiaries and affiliates are collectively called the Caltex Group.
Other affiliates includes Tengizchevroil, a 50 percent owned joint venture formed in 1993 with the Republic of Kazakhstan, to develop the Tengiz oil field.
Equity in earnings of companies accounted for by the equity method, together with dividends and similar distributions received from equity method companies for the years 1993, 1992 and 1991, are as follows:
Year Ended December 31 - ---------------------------------------------------------------------------- Equity in Earnings Dividends ------------------------ ------------------------- 1993 1992 1991 1993 1992 1991 - ---------------------------------------------------------------------------- Caltex Group $361 $334* $422 $172 $183 $202 Other affiliates 79 72 69 95 79 68 - ---------------------------------------------------------------------------- Total $440 $406 $491 $267 $262 $270 ============================================================================ *Before cumulative effect of changes in accounting principles.
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NOTE 11. INVESTMENTS AND ADVANCES - Continued
The company's transactions with affiliated companies, primarily for the purchase of Indonesian crude oil from P.T. Caltex Pacific Indonesia and the sale of crude oil and products to Caltex Petroleum Corporation's refining and marketing companies, are summarized in the following table.
Year Ended December 31 ---------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- Sales to Caltex Group $1,739 $1,784 $1,537 Sales to other affiliates 5 5 66 - ----------------------------------------------------------------------------- Total sales to affiliates $1,744 $1,789 $1,603 ============================================================================= Purchases from Caltex Group $ 842 $ 797 $ 821 Purchases from other affiliates 101 56 23 - ----------------------------------------------------------------------------- Total purchases from affiliates $943 $853 $844 - -----------------------------------------------------------------------------
Accounts and notes receivable in the consolidated balance sheet include $156 and $215 at December 31, 1993 and 1992, respectively, of amounts due from affiliated companies. Accounts payable include $35 and $33 at December 31, 1993 and 1992, respectively, of amounts due to affiliated companies.
The following tables summarize the combined financial information for the Caltex Group and substantially all of the other equity method companies together with Chevron's share. Amounts shown for the affiliates are 100 percent.
NOTE 12. PROPERTIES, PLANT AND EQUIPMENT
Expenses for maintenance and repairs were $875, $1,045 and $1,229 in 1993, 1992 and 1991, respectively.
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NOTE 13.TAXES Year Ended December 31 --------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- Taxes Other Than on Income United States Taxes on production $ 135 $ 140 $ 153 Import duties 21 18 17 Excise taxes on products and merchandise 2,554 2,458 2,267 Property and other miscellaneous taxes (excluding payroll taxes) 380 416 428 --------------------------- 3,090 3,032 2,865 Payroll taxes 122 141 145 - ----------------------------------------------------------------------------- Total United States 3,212 3,173 3,010 - ----------------------------------------------------------------------------- International Taxes on production 7 30 14 Import duties 22 55 50 Excise taxes on products and merchandise 1,514 1,506 1,392 Property and other miscellaneous taxes (excluding payroll taxes) 112 114 111 --------------------------- 1,655 1,705 1,567 Payroll taxes 19 21 20 - ----------------------------------------------------------------------------- Total international 1,674 1,726 1,587 - ----------------------------------------------------------------------------- Total taxes other than on income $4,886 $4,899 $4,597 =============================================================================
Year Ended December 31 --------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- Taxes on Income U.S. federal Current $ 394 $ 329 $ 163 Deferred (241) (129) (185) Deferred - Adjustment for enacted changes in tax laws/rates 54 - - State and local 63 54 16 - ----------------------------------------------------------------------------- Total United States 270 254 (6) - ----------------------------------------------------------------------------- International Current 864 1,046 963 Deferred 48 (47) 2 Deferred - Adjustment for enacted changes in tax laws/rates (21) - - - ----------------------------------------------------------------------------- Total international 891 999 965 - ----------------------------------------------------------------------------- Total taxes on income $1,161 $1,253 $ 959 =============================================================================
U.S. federal income tax expense was reduced by $57, $49 and $27 in 1993, 1992 and 1991, respectively, for low-income housing and other business tax credits.
In 1993, before-tax income for U.S. operations was $687, compared with $1,592 in 1992 and $157 in 1991. Before-tax income for international operations was $1,739, $1,871 and $2,095 in 1993, 1992 and 1991, respectively.
The deferred income tax provisions included benefits of $98, $163 and $67 related to properties, plant and equipment in 1993, 1992 and 1991, respectively. U.S. benefits were recorded in 1993 related to the U.S. refining and marketing restructuring provision. The 1991 U.S. deferred tax provision included benefits accrued from the reserves established for the Port Arthur reconfiguration and the corporate severance program.
In 1992, the tax related to the cumulative effect of adopting SFAS 106 (Note 2) was $423, representing deferred income tax benefits approximating the statutory tax rate.
The company's effective income tax rate varied from the U.S. statutory federal income tax rate because of the following:
Year Ended December 31 --------------------------- 1993 1992 1991 - ----------------------------------------------------------------------------- Statutory U.S. federal income tax rate 35.0% 34.0% 34.0% Effects of income taxes on international operations in excess of taxes at the U.S. statutory rate 15.6 15.2 23.7 Effects of asset dispositions (0.6) (8.0) (2.0) State and local taxes on income, net of U.S. federal income tax benefit 2.2 1.1 0.6 Prior-year tax adjustments 3.0 (0.6) (4.2) Effects of enacted changes in tax laws/rates on deferred tax liabilities 1.3 - - Tax credits (2.4) (1.4) (1.2) All others (0.9) (0.9) (1.8) - ----------------------------------------------------------------------------- Consolidated companies 53.2 39.4 49.1 Effect of recording equity in income of certain affiliated companies on an after-tax basis (5.3) (3.2) (6.5) - ----------------------------------------------------------------------------- Effective tax rate 47.9% 36.2% 42.6% =============================================================================
The company records its deferred taxes on a tax jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities.
At December 31, 1993 and 1992, deferred taxes were classified in the consolidated balance sheet, as follows:
Year Ended December 31 ---------------------- 1993 1992 - ----------------------------------------------------------------------------- Prepaid expenses and other current assets $ (495) $ (313) Deferred charges and other assets (146) (132) Federal and other taxes on income 27 24 Non-current deferred income taxes 2,916 2,894 - ----------------------------------------------------------------------------- Total deferred taxes, net $2,302 $2,473 - -----------------------------------------------------------------------------
The reported deferred tax balances are composed of the following deferred tax liabilities (assets):
Year Ended December 31 ---------------------- 1993 1992 - ----------------------------------------------------------------------------- Properties, plant and equipment $3,933 $3,869 Inventory 293 318 Miscellaneous 237 195 - ----------------------------------------------------------------------------- Deferred tax liabilities 4,463 4,382 - ----------------------------------------------------------------------------- Abandonment/environmental reserves (910) (792) Employee benefits (535) (492) AMT/other tax credits (486) (580) Other accrued liabilities (472) (338) Miscellaneous (255) (159) - ----------------------------------------------------------------------------- Deferred tax assets (2,658) (2,361) - ----------------------------------------------------------------------------- Deferred tax assets valuation allowance 497 452 - ----------------------------------------------------------------------------- Total deferred taxes, net $2,302 $2,473 =============================================================================
FS-25
NOTE 13. TAXES - Continued
It is the company's policy for subsidiaries included in the U.S. consolidated tax return to record income tax expense as though they filed separately, with the parent recording the adjustment to income tax expense for the effects of consolidation.
Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $3,300 at December 31, 1993. Substantially all of this amount represents earnings reinvested as part of the company's ongoing business. It is not practical to estimate the amount of taxes that might be payable on the eventual remittance of such earnings. On remittance, certain countries impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any. The company estimates withholding taxes of approximately $247 would be payable upon remittance of these earnings.
NOTE 14. SHORT-TERM DEBT
At December 31 ----------------- 1993 1992 - ----------------------------------------------------------------------------- Commercial paper $4,391 $4,023 Current maturities of long-term debt 167 89 Current maturities of long-term capital leases 23 24 Redeemable long-term obligations Long-term debt 297 320 Capital leases 255 255 Notes payable 203 277 - ----------------------------------------------------------------------------- 5,336 4,988 Reclassified to long-term debt (1,880) (2,100) - ----------------------------------------------------------------------------- Total short-term debt $3,456 $2,888 =============================================================================
Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.
Selected data on the company's commercial paper activities are shown below:
Weighted Weighted Average Maximum Average Interest Outstanding Average Interest Balance at Rate at at Any Amount Rate for Year December 31 December 31 Month End Outstanding the Year - ----------------------------------------------------------------------------- 1993 $4,390 3.3% $4,891 $4,445 3.1% 1992 $4,023 3.5% $4,441 $3,958 3.6% 1991 $2,748 4.8% $2,748 $1,863 5.7% =============================================================================
The average amounts outstanding and weighted average interest rates during each year are based on average daily balances outstanding. Amounts used in the above computations include amounts that have been classified as long-term debt during 1993, 1992 and 1991.
NOTE 15. LONG-TERM DEBT At December 31 ----------------- 1993 1992 - ----------------------------------------------------------------------------- 8.11% amortizing notes due 2004 (1) $ 750 $ 750 8.25% notes due 1996 (2) - 301 8.75% notes due 1996 (2) - 300 9.375% sinking-fund debentures due 2016 278 292 6.76% serial notes due 1994-1997 (1), (3) 190 220 7.875% notes due 1997 (4) 200 199 5.6% notes due 1998 190 - 9.75% sinking-fund debentures due 2017 179 190 4.625% 200 million Swiss franc issue due 1997 136 137 Other long-term obligations (6.88%) (3) (less than $50 individually) 223 318 Other foreign currency obligations (6.81%) (3) 78 66 - ----------------------------------------------------------------------------- Total including debt due within one year 2,224 2,773 Debt due within one year (167) (89) Reclassified from short-term debt (3.17%) (3) 1,880 2,100 - ----------------------------------------------------------------------------- Total long-term debt $3,937 $4,784 ============================================================================= (1) Guarantee of ESOP debt. (2) Debt retired before maturity date. (3) Weighted average interest rate at December 31, 1993. (4) Called in early 1994.
Chevron and one of its wholly owned subsidiaries have "shelf" registrations on file with the Securities and Exchange Commission (SEC) that would permit the issuance of $1,050 of debt securities pursuant to Rule 415 of the Securities Act of 1933.
At year-end 1993, the company had $3,595 of committed credit facilities with banks worldwide, $1,880 of which had termination dates beyond one year. These credit agreements provide commitments for term loans of up to $3,280 and revolving credit for short-term advances of up to $315. The facilities also support the company's commercial paper borrowings. Interest on any borrowings under the agreements is based on either the London Interbank Offered Rate or the Reserve Adjusted Domestic Certificate of Deposit Rate. No amounts were outstanding under these credit agreements during the year nor at year-end.
At December 31, 1993 and 1992, the company classified $1,880 and $2,100, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 1994, as the company has both the intent and ability to refinance this debt on a long-term basis.
Consolidated long-term debt maturing in each of the five years after December 31, 1993, is as follows: 1994-$167, 1995-$89, 1996-$93, 1997-$435 and 1998-$198.
NOTE 16. EMPLOYEE BENEFIT PLANS
PENSION PLANS. The company has defined benefit pension plans for most employees. The principal plans provide for automatic membership on a non-contributory basis. The retirement benefits provided by these plans are based primarily on years of service and on average career earnings or the highest consecutive three years' average earnings. The company's policy is to fund at least the minimum necessary to satisfy requirements of the Employee Retirement Income Security Act.
FS-26
NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
The net pension expense (credit) for all of the company's pension plans for the years 1993, 1992 and 1991 consisted of:
1993 1992 1991 - ----------------------------------------------------------------------------- Cost of benefits earned during the year $103 $106 $100 Interest cost on projected benefit obligations 276 302 295 Actual return on plan assets (472) (309) (799) Net amortization and deferral 101 (134) 346 - ----------------------------------------------------------------------------- Net pension expense (credits) $ 8 $(35) $(58) =============================================================================
In addition to the net pension expense in 1993, the company recognized a net settlement loss of $63 and a curtailment loss of $4 reflecting the termination of a former Gulf pension plan and lump-sum payments from other company pension plans. In 1992, the company recorded charges of $65 and a curtailment loss of $7, offset by net lump-sum settlement gains of $101 related to an early retirement program offered to employees of its U.S. and certain Canadian subsidiaries. In 1991, charges of $154 related to the early retirement programs and lump sum settlement gains of $25 were recognized.
At December 31, 1993 and 1992, the weighted average discount rates and long-term rates for compensation increases used for estimating the benefit obligations and the expected rates of return on plan assets were as follows:
1993 1992 - ----------------------------------------------------------------------------- Assumed discount rates 7.4% 8.1% Assumed rates for compensation increases 5.1% 5.5% Expected return on plan assets 9.1% 9.2% - -----------------------------------------------------------------------------
The pension plans' assets consist primarily of common stocks, bonds, cash equivalents and interests in real estate investment funds. The funded status for the company's combined plans at December 31, 1993 and 1992, was as follows:
Plans with Plans with Assets Accumulated in Excess of Benefits Accumulated in Excess of Benefits Plan Assets ------------------- ----------------- At December 31 1993 1992 1993 1992 - ----------------------------------------------------------------------------- Actuarial present value of: Vested benefit obligations $(2,854) $(2,869) $(183) $(161) ============================================================================= Accumulated benefit obligations $(2,949) $(2,947) $(194) $(168) ============================================================================= Projected benefit obligations $(3,456) $(3,395) $(229) $(184) Plan assets at fair values 3,831 3,893 1 6 - ----------------------------------------------------------------------------- Plan assets greater (less) than projected benefit obligations 375 498 (228) (178) Unrecognized net transition (assets) liabilities (349) (426) 20 22 Unrecognized net losses 41 17 74 34 Unrecognized prior service costs 84 85 7 - Minimum liability adjustment - - (52) (52) - ----------------------------------------------------------------------------- Net pension cost prepaid (accrued) $ 151 $ 174 $(179) $(174) - -----------------------------------------------------------------------------
The net transition assets and liabilities generally are being amortized by the straight-line method over 15 years.
PROFIT SHARING/SAVINGS PLAN AND SAVINGS PLUS PLAN. Eligible employees of the company and certain of its subsidiaries who have completed one year of service may participate in the Profit Sharing/Savings Plan and the Savings Plus Plan.
Charges to expense for the profit sharing part of the Profit Sharing/Savings Plan and the Savings Plus Plan were $95, $84 and $104 in 1993, 1992 and 1991, respectively.
EMPLOYEE STOCK OWNERSHIP PLAN (ESOP). In December 1989, the company established an ESOP as part of the Profit Sharing/Savings Plan. The ESOP Trust Fund borrowed $1,000 and purchased 14.1 million previously unissued shares of the company's common stock. The ESOP provides a partial pre-funding of the company's future commitments to the profit sharing part of the plan, which will result in annual income tax savings for the company. As interest and principal payments are made on the ESOP debt, shares are released from a suspense account and allocated to profit sharing accounts of plan participants.
The ESOP is expected to satisfy most of the company's obligations to the profit sharing part of the Profit Sharing/Savings Plan during the next 11 years. Other company obligations to the profit sharing part of the plan will be satisfied by cash contributions. The company recorded expense for the ESOP of $60, $50 and $44 in 1993, 1992 and 1991, respectively, including $74, $75 and $69 of interest expense related to the ESOP loan. All dividends paid on the shares held by the ESOP will be used to service the ESOP debt. The dividends used were $47, $35 and $40 in 1993, 1992 and 1991, respectively.
MANAGEMENT INCENTIVE PLANS. The company has two incentive plans, the Management Incentive Plan (MIP) and the Long-Term Incentive Plan (LTIP) for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. The MIP makes outright distributions of cash for services rendered or deferred awards in the form of stock units. Awards under LTIP may take the form of, but are not limited to, stock options, restricted stock, stock units and non-stock grants. Stock options become exercisable not earlier than one year and not later than 10 years from the date of grant.
The maximum number of shares of common stock that may be granted each year is 1 percent of the total outstanding shares of common stock as of January 1 of such year. As of December 31, 1993, 2,151,505 shares were under option at exercise prices ranging from $63.875 to $87.75 per share. Stock option transactions for 1993 and 1992 are as follows:
FS-27
NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
At December 31 ---------------- Thousands of shares 1993 1992 - -----------------------------------------------------------------------------
Outstanding January 1 1,967 1,265 Granted 706 725 Exercised (509) (6) Forfeited (12) (17) - ----------------------------------------------------------------------------- Outstanding December 31 2,152 1,967 ============================================================================= Exercisable December 31 1,456 1,250 =============================================================================
Charges to expense for the combined management incentive plans were $36, $20 and $37 in 1993, 1992 and 1991, respectively.
OTHER BENEFIT PLANS. In addition to providing pension benefits, the company makes contributions toward certain health care and life insurance plans for active and qualifying retired employees. Substantially all employees in the United States and in certain international locations may become eligible for coverage under these benefit plans. The company's annual contributions for medical and dental benefits are limited to the lesser of actual medical and dental claims or a defined fixed per capita amount. Life insurance benefits are paid by the company and annual contributions are based on actual plan experience.
Under SFAS 106, adopted effective January 1, 1992, the company's net postretirement benefits expense was as follows:
1993 1992 --------------------- --------------------
Health Life Total Health Life Total - ----------------------------------------------------------------------------- Cost of benefits earned during the year $23 $ 3 $ 26 $23 $ 4 $ 27 Interest cost on benefit obligation 76 30 106 70 30 100 - ----------------------------------------------------------------------------- Net postretirement benefits expense $99 $33 $132 $93 $34 $127 =============================================================================
1991 expense under the cash method was $60.
Non-pension postretirement benefits are funded by the company when incurred. A reconciliation of the funded status of these benefit plans is as follows:
At December 31, 1993 At December 31, 1992 ------------------------ ----------------------- Health Life Total Health Life Total - -----------------------------------------------------------------------------
Accumulated postretirement benefit obligation (APBO) Retirees $ (593) $(320) $ (913) $(598) $(281) $ (879) Fully eligible active participants (139) (64) (203) (109) (47) (156) Other active participants (271) (56) (327) (272) (49) (321) - ----------------------------------------------------------------------------- Total APBO (1,003) (440) (1,443) (979) (377) (1,356) Fair value of plan assets - - - - - - - ----------------------------------------------------------------------------- APBO (greater) than plan assets (1,003) (440) (1,443) (979) (377) (1,356) Unrecognized net loss (gain) 63 25 88 69 (12) 57 - ----------------------------------------------------------------------------- Accrued postretirement benefit costs $ (940) $(415) $(1,355) $(910) $(389) $(1,299) =============================================================================
For measurement purposes, separate health care cost-trend rates were utilized for pre-age 65 and post-age 65 retirees. The 1994 annual rates of increase were assumed to be 8.0 percent and 8.9 percent, respectively, decreasing to average ultimate rates of 5.9 percent in 1997 for pre-age 65 and 5.4 percent in 1997 for post-age 65. An increase in the assumed health care cost-trend rates of 1 percent in each year would increase the aggregate of service and interest cost for the year 1993 by $19 and would increase the December 31, 1993 accumulated postretirement benefit obligation (APBO) by $166.
At December 31, 1993 the weighted average discount rate was 7.25 percent and the assumed rate of compensation increase related to the measurement of the life insurance benefit was 5.0 percent.
FS-28
NOTE 17. OTHER CONTINGENT LIABILITIES AND COMMITMENTS The U.S. federal income tax and California franchise tax liabilities of the company have been settled through 1976 and 1987, respectively. Settlement of open tax matters is not expected to have a material effect on the consolidated financial position of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years either under examination or subject to future examination. The Internal Revenue Service (IRS) has asserted tax deficiencies against the other three stockholders of Arabian American Oil Co. (Aramco) regarding the pricing of crude oil purchased from Saudi Arabia during the period 1979 through 1981. In December 1993, the U.S. Tax Court ruled in favor of Exxon and Texaco on this issue. It is not known if the IRS will appeal this decision. The IRS may have until late 1995 to appeal since other tax issues related to the 1979-81 period must be resolved. Chevron has not received any proposed tax deficiency concerning this issue. In July 1991, the IRS issued a "Designated Summons" that requires Chevron to produce additional documents in connection with the Saudi pricing issue. The Designated Summons extends the statutory period for assessing additional tax. As directed by the District Court, Chevron completed production of documents before year-end 1993. Further motions regarding compliance with the Summons are expected in 1994. After Chevron complies with the Summons, the IRS may propose tax deficiencies similar to those asserted against other Aramco stockholders. The company believes that it properly accounted for the Saudi crude in its tax return and that it owes no additional U.S. taxes.
At December 31, 1993, the company and its subsidiaries, as direct or indirect guarantors, had contingent liabilities of $234 for notes of affiliated companies and $45 for notes of others.
The company and its subsidiaries have certain other contingent liabilities with respect to guarantees and claims and has long-term commitments under various agreements, the payments and future commitments for which are not material in the aggregate.
In September 1990, the Minerals Management Service of the U.S. Department of the Interior (the Service) issued a preliminary determination letter to the effect that the company owed additional royalty payments on natural gas the company produced from federal leasehold interests and sold under long-term supply contracts. The company made royalty payments based on the contract price received, rather than on the basis of published weighted average gas prices, which were higher. The company has submitted an answer refuting the preliminary determination. The Service has the matter under review and has not rendered an order directing payment. However, the parties are continuing to explore settlement.
In March 1992, an agency within the Department of Energy (DOE) issued a Proposed Remedial Order (PRO) claiming Chevron failed to comply with DOE regulations in the course of its participation in the Tertiary Incentive Program. Although the DOE regulations involved were rescinded in March 1981, following decontrol of crude oil prices in January 1981, and the statute authorizing the regulations expired in September 1981, the PRO purports to be for the period April 1980 through April 1990. The DOE claims the company overrecouped under the regulations by $125 during the period in question. Including interest through December 1993, the total claim amounted to $273. The company asserts that in fact it incurred a loss through participation in the DOE program. The Office of Hearings and Appeals has granted Chevron's motion for evidentiary hearing and discovery. No date has yet been set for the evidentiary hearing.
The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior disposal or release of chemical or petroleum substances by the company or other parties. Such contingencies may exist for various sites including, but not limited to: Superfund sites, operating refineries, closed refineries, oil fields, service stations, terminals and land development areas. The amount of such future cost is indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties and the extent to which such costs are recoverable from insurance.
The company's operations, particularly oil and gas exploration and production, can be affected by changing economic, regulatory and political environments in the various countries, including the United States, in which it operates. In certain locations, host governments have imposed restrictions, controls and taxes, and, in others, political conditions have existed that may threaten the safety of employees and the company's continued presence in those countries. Internal unrest or strained relations between a host government and the company or other governments may affect the company's operations. Those developments have, at times, significantly affected the company's related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries.
Areas in which the company has significant operations include the United States, Australia, United Kingdom, Canada, Nigeria, Angola, Papua New Guinea, China, Indonesia and Zaire. The company's Caltex affiliates have significant operations in Indonesia, Japan, Korea, Australia, the Philippines, Thailand and South Africa. The company's Tengizchevroil affiliate operates in Kazakhstan.
FS-29
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
Unaudited
In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities" (SFAS 69), this section provides supplemental information on oil and gas exploration and producing activities of the company in six separate tables. The first three tables provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the company's estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The other geographic category includes activities in the United Kingdom North Sea, Canada, Papua New Guinea, Australia and other countries. Amounts shown for affiliated companies are Chevron's 50 percent equity share in each of P.T. Caltex Pacific Indonesia (CPI), an exploration and production company operating in Indonesia, and Tengizchevroil (TCO), an exploration and production company operating in the Republic of Kazakhstan, which began operations in April 1993.
TABLE I - COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT (1)
Consolidated Companies - ------------------------------------------------------ Millions of Affiliated dollars U.S. Africa Other Total Companies Worldwide - ----------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 1993 Exploration Wells $ 123 $ 57 $126 $ 306 $ 1 $ 307 Geological and geophysical 12 40 40 92 9 101 Rentals and other 48 7 70 125 - 125 - ----------------------------------------------------------------------------- Total exploration 183 104 236 523 10 533 - ----------------------------------------------------------------------------- Property acquisitions (2) Proved (3) 12 - 14 26 276 302 Unproved 11 9 10 30 420 450 - ----------------------------------------------------------------------------- Total property acquisitions 23 9 24 56 696 752 - ----------------------------------------------------------------------------- Development 475 239 566 1,280 171 1,451 - ----------------------------------------------------------------------------- Total Costs Incurred $ 681 $352 $826 $1,859 $877(4) $2,736 ============================================================================= YEAR ENDED DECEMBER 31, 1992 Exploration Wells $ 96 $ 59 $ 83 $ 238 $ 1 $ 239 Geological and geophysical 84 48 137 269 8 277 Rentals and other 9 1 21 31 - 31 - ----------------------------------------------------------------------------- Total exploration 189 108 241 538 9 547 - ----------------------------------------------------------------------------- Property acquisitions (2) Proved (3) 19 - 36 55 - 55 Unproved 16 1 10 27 - 27 - ----------------------------------------------------------------------------- Total property acquisitions 35 1 46 82 - 82 - ----------------------------------------------------------------------------- Development 483 189 682 1,354 171 1,525 - ----------------------------------------------------------------------------- Total Costs Incurred $ 707 $298 $969 $1,974 $180 $2,154 ============================================================================= YEAR ENDED DECEMBER 31, 1991 Exploration Wells $ 205 $ 65 $150 $ 420 $ 1 $ 421 Geological and geophysical 98 45 164 307 8 315 Rentals and other 18 2 8 28 2 30 - ----------------------------------------------------------------------------- Total exploration 321 112 322 755 11 766 - ----------------------------------------------------------------------------- Property acquisitions (2) Proved (3) - 1 4 5 - 5 Unproved 59 8 33 100 - 100 - ----------------------------------------------------------------------------- Total property acquisitions 59 9 37 105 - 105 - ----------------------------------------------------------------------------- Development 665 152 569 1,386 164 1,550 - ----------------------------------------------------------------------------- Total Costs Incurred $1,045 $273 $928 $2,246 $175 $2,421 - ----------------------------------------------------------------------------- (1) Includes costs incurred whether capitalized or charged to earnings. Excludes support equipment expenditures. (2) Proved amounts include wells, equipment and facilities associated with proved reserves; unproved represents amounts for equipment and facilities not associated with the production of proved reserves. (3) Does not include properties acquired through property exchanges. (4) In 1993, Total Costs Incurred for affiliated companies includes $146 for CPI.
FS-30
TABLE II - CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
Consolidated Companies - ------------------------------------------------------- Affiliated Millions of dollars U.S. Africa Other Total Companies Worldwide - ----------------------------------------------------------------------------- AT DECEMBER 31, 1993 Unproved properties $ 404 $ 31 $ 206 $ 641 $ 420 $ 1,061 Proved properties and related producing assets 15,655 1,528 4,646 21,829 1,005 22,834 Support equipment 750 105 303 1,158 546 1,704 Deferred exploratory wells 139 23 60 222 - 222 Other uncompleted projects 269 296 879 1,444 466 1,910 - ----------------------------------------------------------------------------- Gross capitalized costs 17,217 1,983 6,094 25,294 2,437 27,731 - ----------------------------------------------------------------------------- Unproved properties valuation 280 20 103 403 - 403 Proved producing properties - Depreciation and depletion 9,645 799 2,467 12,911 386 13,297 Future abandonment and restoration 1,002 195 276 1,473 13 1,486 Support equipment depreciation 338 52 149 539 238 777 - ----------------------------------------------------------------------------- Accumulated provisions 11,265 1,066 2,995 15,326 637 15,963 - ----------------------------------------------------------------------------- Net Capitalized Costs $ 5,952 $ 917 $3,099 $ 9,968 $1,800* $11,768 ============================================================================= AT DECEMBER 31, 1992 Unproved properties $ 481 $ 23 $ 217 $ 721 $ - $ 721 Proved properties and related producing assets 15,682 1,358 4,087 21,127 622 21,749 Support equipment 685 92 270 1,047 374 1,421 Deferred exploratory wells 100 30 66 196 1 197 Other uncompleted projects 443 203 910 1,556 368 1,924 - ----------------------------------------------------------------------------- Gross capitalized costs 17,391 1,706 5,550 24,647 1,365 26,012 - ----------------------------------------------------------------------------- Unproved properties valuation 327 17 110 454 - 454 Proved producing properties - Depreciation and depletion 9,276 700 2,225 12,201 335 12,536 Future abandonment and restoration 967 168 226 1,361 13 1,374 Support equipment depreciation 296 50 133 479 218 697 - ----------------------------------------------------------------------------- Accumulated provisions 10,866 935 2,694 14,495 566 15,061 - ----------------------------------------------------------------------------- Net Capitalized Costs $ 6,525 $ 771 $ 2,856 $10,152 $ 799 $10,951 ============================================================================= AT DECEMBER 31, 1991 Unproved properties $ 658 $ 24 $ 389 $ 1,071 $ - $ 1,071 Proved properties and related producing assets 18,088 1,212 3,925 23,225 534 23,759 Support equipment 658 90 212 960 347 1,307 Deferred exploratory wells 109 50 124 283 1 284 Other uncompleted projects 528 179 656 1,363 322 1,685 - ----------------------------------------------------------------------------- Gross capitalized costs 20,041 1,555 5,306 26,902 1,204 28,106 - ----------------------------------------------------------------------------- Unproved properties valuation 429 12 110 551 - 551 Proved producing properties - Depreciation and depletion 10,322 613 2,166 13,101 299 13,400 Future abandonment and restoration 1,024 147 216 1,387 12 1,399 Support equipment depreciation 262 60 117 439 203 642 - ----------------------------------------------------------------------------- Accumulated Provisions 12,037 832 2,609 15,478 514 15,992 - ----------------------------------------------------------------------------- Net Capitalized Costs $ 8,004 $ 723 $2,697 $11,424 $ 690 $12,114 ============================================================================= *At December 31, 1993, Net Capitalized Costs for affiliated companies includes $860 for CPI.
FS-31
Unaudited
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1)
The company's results of operations from oil and gas producing activities for the years 1993, 1992 and 1991 are shown below.
Net income from exploration and production activities as reported on Page FS-6 includes the allocation of corporate overhead and income taxes computed on an effective rate basis.
In accordance with SFAS 69, allocated corporate overhead is excluded from the results below, and income taxes are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest expense is excluded from both reported results.
Consolidated Companies - ------------------------------------------------------- Affiliated Millions of dollars U.S. Africa Other Total Companies Worldwide - ----------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 1993 Revenues from net production Sales $1,539 $ 247 $ 779 $2,565 $ 63 $2,628 Transfers 1,912 1,040 661 3,613 487 4,100 - ----------------------------------------------------------------------------- Total 3,451 1,287 1,440 6,178 550 6,728 Production expenses (1,274) (208) (402) (1,884) (204) (2,088) Proved producing properties depreciation, depletion and abandonment provision (958) (126) (311) (1,395) (58) (1,453) Exploration expenses (99) (79) (174) (352) (9) (361) Unproved properties valuation (31) (4) (12) (47) - (47) Other income (expense) (2) 20 - 8 28 6 34 - ----------------------------------------------------------------------------- Results before income taxes 1,109 870 549 2,528 285 2,813 Income tax expense (422) (625) (243) (1,290) (152) (1,442) - ----------------------------------------------------------------------------- RESULTS OF PRODUCING OPERATIONS $ 687 $ 245 $ 306 $1,238 $133* $1,371 ============================================================================= YEAR ENDED DECEMBER 31, 1992 Revenues from net production Sales $1,558 $ 365 $ 816 $2,739 $ 19 $2,758 Transfers 2,301 1,097 580 3,978 519 4,497 - ----------------------------------------------------------------------------- Total 3,859 1,462 1,396 6,717 538 7,255 Production expenses (1,477) (194) (508) (2,179) (153) (2,332) Proved producing properties depreciation, depletion and abandonment provision (1,126) (110) (301) (1,537) (38) (1,575) Exploration expenses (182) (79) (226) (487) (8) (495) Unproved properties valuation (38) (5) (17) (60) - (60) Other income (expense) (2) 431 27 72 530 (15) 515 - ----------------------------------------------------------------------------- Results before income taxes 1,467 1,101 416 2,984 324 3,308 Income tax expense (420) (856) (231) (1,507) (170) (1,677) - ----------------------------------------------------------------------------- Results of Producing Operations $1,047 $ 245 $ 185 $1,477 $154 $1,631 ============================================================================= YEAR ENDED DECEMBER 31, 1991 Revenues from net production Sales $1,609 $ 268 $ 694 $2,571 $ 20 $2,591 Transfers 2,364 1,138 778 4,280 563 4,843 - ----------------------------------------------------------------------------- Total 3,973 1,406 1,472 6,851 583 7,434 Production expenses (1,870) (149) (439) (2,458) (148) (2,606) Proved producing properties depreciation, depletion and abandonment provision (1,259) (100) (252) (1,611) (35) (1,646) Exploration expenses (220) (92) (298) (610) (10) (620) Unproved properties valuation (77) (3) (21) (101) - (101) Other income (expense) (2) 107 (5) 117 219 (15) 204 - ----------------------------------------------------------------------------- Results before income taxes 654 1,057 579 2,290 375 2,665 Income tax expense (246) (894) (403) (1,543) (212) (1,755) - ----------------------------------------------------------------------------- Results of Producing Operations $ 408 $ 163 $ 176 $ 747 $163 $ 910 ============================================================================= *For 1993, Results of Producing Operations for affiliated companies includes $134 for CPI.
FS-32
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1) - Continued
Per Unit Average Consolidated Companies Sales Price and ------------------------------ Production Affiliated Cost (1), (3) U.S. Africa Other Total Companies Worldwide - ----------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 1993 Average sales prices Liquids, per barrel $14.48 $16.21 $16.06 $15.33 $13.06 $15.05 Natural gas, per thousand cubic feet 1.98 - 2.08 2.00 .13 1.99 Average production costs, per barrel 4.91 2.62 4.22 4.34 4.77 4.38 ============================================================================= YEAR ENDED DECEMBER 31, 1992 Average sales prices Liquids, per barrel $16.02 $18.40 $17.66 $17.00 $14.87 $16.77 Natural gas, per thousand cubic feet 1.69 - 1.96 1.73 - 1.73 Average production costs, per barrel 5.11 2.44 5.85 4.78 4.23 4.74 ============================================================================= YEAR ENDED DECEMBER 31, 1991 Average sales prices Liquids, per barrel $16.73 $19.00 $18.36 $17.63 $15.25 $17.36 Natural gas, per thousand cubic feet 1.53 - 2.24 1.63 - 1.63 Average production costs, per barrel 6.29 2.01 5.10 5.37 3.87 5.26 ============================================================================= Average sales price for liquids ($/bbl.) DECEMBER 1993 $10.73 $12.94 $13.63 $12.05 $10.46 $11.82 December 1992 15.22 17.60 17.26 16.35 14.15 16.07 December 1991 15.08 17.39 18.76 16.43 14.38 16.19 ============================================================================= Average sales price for natural gas ($/MCF) DECEMBER 1993 $ 2.19 $ - $ 2.34 $ 2.21 $ .26 $ 2.20 December 1992 2.17 - 1.99 2.14 - 2.14 December 1991 1.93 - 2.51 2.00 - 2.00 ============================================================================= (1) The value of owned production consumed as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the per unit average sales price and production cost. This has no effect on the amount of Results of Producing Operations. (2) Includes gas-processing fees, net sulfur income, natural gas contract settlements, currency transaction gains and losses, miscellaneous expenses, etc. In 1993, the United States includes before-tax losses on property dispositions and other special charges totaling $150. In 1992, before-tax gains on property dispositions of $326 in the United States were offset partially by net charges of $44 for severance programs, regulatory issues and other adjustments; Other includes $192 of before-tax gains on sales of producing and nonproducing properties, partially offset by a before-tax charge of $165 for the write-down of Beaufort Sea properties. In 1991, losses and property dispositions in the United States were offset by favorable adjustments to litigation and other reserves; the Other geographic segment included $89 of before-tax gains on property dispositions. (3) Natural gas converted to crude oil equivalent gas (OEG) barrels at a rate of 6 MCF=1 OEG barrel.
TABLE IV - RESERVE QUANTITIES INFORMATION
The company's estimated net proved underground oil and gas reserves and changes thereto for the years 1993, 1992 and 1991 are shown in the following table. These quantities are estimated by the company's reserves engineers and reviewed by the company's Reserves Advisory Committee using reserve definitions prescribed by the Securities and Exchange Commission.
Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change over time as additional information becomes available.
Proved reserves do not include additional quantities recoverable beyond the term of lease or contract unless renewal is reasonably certain, or that may result from extensions of currently proved areas, or from application of secondary or tertiary recovery processes not yet tested and determined to be economic.
Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.
"Net" reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.
Upon formation of the Tengizchevroil joint venture in April 1993, the company recognized 1.1 billion barrels of net proved crude oil and natural gas liquids reserves and 1.5 trillion cubic feet of net natural gas reserves, which represented its 50 percent ownership.
FS-33
Unaudited
TABLE IV - RESERVE QUANTITIES INFORMATION - Continued
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES
The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of SFAS 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10 percent midperiod discount factors. This discounting requires a year-by-year estimate of when the future expenditures will be incurred and when the reserves will be produced.
The information provided does not represent management's estimate of the company's expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under SFAS 69 requires assumptions as to the timing of future production from proved reserves and the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company's future cash flows or value of its oil and gas reserves.
FS-34
Unaudited
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES - CONTINUED
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
FS-35
FIVE-YEAR FINANCIAL SUMMARY (1)
FS-36
CALTEX GROUP OF COMPANIES COMBINED FINANCIAL STATEMENTS AND SCHEDULES
December 31, 1993
C-1
CALTEX GROUP OF COMPANIES COMBINED FINANCIAL STATEMENTS AND SCHEDULES DECEMBER 31, 1993
INDEX
SCHEDULE NUMBER PAGE(S) -------- -----------
General Information . . . . . . . . . . . . . . . . . . C-3 to C-4
Independent Auditors' Report . . . . . . . . . . . . . C-5
Combined Balance Sheet . . . . . . . . . . . . . . . . C-6 to C-7
Combined Statement of Income . . . . . . . . . . . . . C-8
Combined Statement of Retained Earnings . . . . . . . C-9
Combined Statement of Cash Flows . . . . . . . . . . . C-9
Notes to Combined Financial Statements . . . . . . . . C-10 to C-19
Property, Plant and Equipment . . . . . . . . . . . . V C-20
Accumulated Depreciation, Depletion and Amortization . VI C-21
NOTE: All other schedules are omitted as permitted by Rule 4.03 and Rule 5.04 of Regulation S-X.
C-2
CALTEX GROUP OF COMPANIES GENERAL INFORMATION
The Caltex Group of Companies (Group) is jointly owned 50% each by Chevron Corporation and Texaco Inc. The private joint venture was created in Bahrain in 1936 by its two owners to produce, refine and market crude oil and refined products. Headquartered in Irving, Texas, the Group is comprised of the following companies:
Caltex Petroleum Corporation, a company incorporated in Delaware, that through its many subsidiaries and affiliates, conducts refining and marketing activities in the Eastern Hemisphere;
P. T. Caltex Pacific Indonesia, an exploration and production company incorporated and operating in Indonesia;
American Overseas Petroleum Limited, a company incorporated in the Bahamas, that, through its subsidiaries, manages certain exploration and production operations in Indonesia in which Chevron and Texaco have interests, but not necessarily jointly nor in the same properties.
A brief description of each company's operations and the Group's environmental activities follows:
CALTEX PETROLEUM CORPORATION (CALTEX) - -------------------------------------
Through its subsidiaries and affiliates, Caltex operates in 63 countries with some of the highest economic and petroleum growth rates in the world, principally in Africa, Asia, the Middle East, New Zealand and Australia. Certain refining and marketing operations are conducted through joint ventures, with equity interests in 14 refineries in 11 countries. Caltex' share of refinery inputs approximated 869,000 barrels per day in 1993. Caltex continues to improve its refineries with investments designed to provide higher yields and meet environmental regulations. Construction of a new 130,000 barrels per day refinery in Thailand is progressing with completion anticipated in 1996. At year end 1993, Caltex had over 7,800 employees, of which about 3% were located in the United States.
With a strong presence in its principal operating areas, Caltex has an average market share of 17.3% with refined product sales of approximately 1.3 million barrels per day in 1993. Caltex built 130 new branded retail outlets during 1993 and refurbished 294 existing locations in its aim to upgrade its retail distribution network.
Caltex conducts international crude oil and refined product logistics and trading operations from a subsidiary in Singapore. Other offices are located in London, Bahrain and Tokyo. The company has an interest in a fleet of vessels and owns or has equity interests in numerous pipelines, terminals and depots. Currently, Caltex is active in the petrochemical business, particularly in Japan and South Korea.
P. T. CALTEX PACIFIC INDONESIA (CPI) - ------------------------------------
CPI holds a Production Sharing Contract in Central Sumatra for which the Indonesian government granted an extension to the year 2021 during 1992. CPI also acts as operator for four other petroleum contract areas in Sumatra, which are jointly held by Chevron and Texaco. Exploration is pursued throughout an area comprising 2.446 million acres with production established in the giant Minas and Duri fields, along with more than 80 smaller fields. Gross production from fields operated by CPI for 1993 was 674,000 barrels per day. CPI entitlements are sold to its shareholders, who use it in their systems or sell it to third parties. In addition, during 1993 CPI began gas exploration activities in the Nias block held jointly by Chevron and Texaco. At year end 1993, CPI had over 6,400 employees, all located in Indonesia.
C-3
CALTEX GROUP OF COMPANIES GENERAL INFORMATION
AMERICAN OVERSEAS PETROLEUM LIMITED (AOPL) - ------------------------------------------
In addition to coordinating the CPI activities, AOPL, through its subsidiary Amoseas Indonesia Inc., manages Texaco's and Chevron's undivided interest holdings which include ten contract areas in Indonesia, excluding Sumatra. Production is currently established in two contract areas, while exploration is being pursued in seven others. One in Darajat in West Java contains geothermal reserves sufficient to supply a 55-megawatt power generating plant for over 30 years. Production of the geothermal reserves is expected to begin in 1994 while the state owned utility company completes construction of an associated power station. AOPL's 1993 share of production amounted to 38,400 barrels per day. At year end, AOPL had 281 employees, of which about 15% were located in the United States.
ENVIRONMENTAL ACTIVITIES - ------------------------
The Group's activities are subject to environmental, health and safety regulations in each of the countries in which it operates. Such regulations vary significantly in degree of scope, standards and enforcement. The Group's policy is to comply with all applicable environmental, health and safety laws and regulations. The Group has an active program to ensure its environmental standards are maintained, which includes closely monitoring applicable statutory and regulatory requirements, as well as enforcement policies, in each of the countries in which it operates, and conducting periodic environmental compliance audits. At December 31, 1993, the Group had accrued $12 million for various remediation activities. The environmental guidelines and definitions promulgated by the American Petroleum Institute provide the basis for reporting the Group's expenditures. For the year ended December 31, 1993, the Group, including its equity share of nonsubsidiary companies, incurred capital costs of $147 million and nonremediation related operating expenses of $92 million. The major component of the Group's expenditures is for the prevention of air pollution. Based upon existing statutory and regulatory requirements, investment and operating plans and known exposures, the Group believes environmental expenditures will not materially affect its liquidity, financial position or results of operations.
C-4
INDEPENDENT AUDITORS' REPORT
TO THE STOCKHOLDERS THE CALTEX GROUP OF COMPANIES:
We have audited the accompanying combined balance sheets of the Caltex Group of Companies as of December 31, 1993 and 1992, and the related combined statements of income, retained earnings, and cash flows for each of the years in the three-year period ended December 31, 1993. In connection with our audits of the combined financial statements, we also have audited the financial statement schedules as listed in the accompanying index. These combined financial statements and financial statement schedules are the responsibility of the Group's management. Our responsibility is to express an opinion on these combined financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Caltex Group of Companies as of December 31, 1993 and 1992 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 1993, in conformity with generally accepted accounting principles. Also in our opinion, the related financial statement schedules, when considered in relation to the basic combined financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Notes 1 and 6 to the combined financial statements, effective January 1, 1992, the Group adopted the provisions of the Financial Accounting Standards Board's Statements of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" and No. 109, "Accounting for Income Taxes."
KPMG PEAT MARWICK
Dallas, Texas February 15, 1994
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses constituting part of the Registration Statements on Form S-3 (No. 2-98466) and Form S-8 (Nos. 33-3899, 33-34039 and 33-35283) of Chevron Corporation, and to the incorporation by reference in the Prospectus constituting part of the Registration Statement on Form S-3 (No. 33-14307) of Chevron Capital U.S.A. Inc. and Chevron Corporation, and to the incorporation by reference in the Registration Statement on Form S-3 (No. 33-58838) of Chevron Canada Finance Limited and Chevron Corporation, and to the incorporation by reference in the Registration Statement on Form S-8 (No. 2-90907) of Caltex Petroleum Corporation of our report dated February 15, 1994, relating to the combined balance sheets of the Caltex Group of Companies as of December 31, 1993 and 1992 and the related combined statements of income, retained earnings and cash flows and related financial statement schedules for each of the years in the three-year period ended December 31, 1993, which report appears in the December 31, 1993 Annual Report on Form 10-K of Chevron Corporation.
KPMG PEAT MARWICK
Dallas, Texas March 25, 1994 C-5
CALTEX GROUP OF COMPANIES COMBINED BALANCE SHEET - DECEMBER 31, 1993 AND 1992 (MILLIONS OF DOLLARS)
ASSETS 1993 1992 CURRENT ASSETS: ------ ------ Cash and cash equivalents (including time deposits of $64 in 1993 and $121 in 1992) $ 166 $ 239
Notes and accounts receivable, less allowance for doubtful accounts of $14 in 1993 and $15 in 1992: Trade 950 1,020 Other 155 115 Nonsubsidiary companies 112 173 ------ ------ 1,217 1,308
Inventories: Crude oil 148 239 Refined products 532 512 Materials and supplies 56 55 ------ ------ 736 806
Deferred income taxes 4 25 ------ ------
Total current assets 2,123 2,378
INVESTMENTS AND ADVANCES:
Nonsubsidiary companies at equity 1,796 1,427 Miscellaneous investments and long-term receivables, less allowance of $7 in 1993 and 1992 195 173 ------ ------ 1,991 1,600
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Producing 3,027 2,783 Refining 1,483 1,259 Marketing 2,252 2,107 Marine 35 35 Capitalized leases 119 113 ------ ------ 6,916 6,297
Less: Accumulated depreciation, depletion and amortization 2,878 2,628 ------ ------ 4,038 3,669
PREPAID AND DEFERRED CHARGES 237 216 ------ ------ Total assets $8,389 $7,863 ====== ======
See accompanying Notes to Combined Financial Statements.
C-6
CALTEX GROUP OF COMPANIES COMBINED BALANCE SHEET - DECEMBER 31, 1993 AND 1992 (MILLIONS OF DOLLARS)
LIABILITIES AND STOCKHOLDERS' EQUITY
1993 1992 ------ ------ CURRENT LIABILITIES:
Notes payable to banks and other financial institutions $ 966 $ 830
Long-term debt due within one year 51 51
Accounts payable: Trade and other 967 1,081 Stockholder companies 87 229 Nonsubsidiary companies 149 76 ------ ------ 1,203 1,386
Accrued liabilities 86 91
Estimated income taxes 105 95 ------ ------
Total current liabilities 2,411 2,453
LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS 530 486
ACCRUED LIABILITY FOR EMPLOYEE BENEFITS 98 92
DEFERRED CREDITS 646 605
DEFERRED INCOME TAXES 263 270
MINORITY INTEREST IN SUBSIDIARY COMPANIES 146 138
STOCKHOLDERS' EQUITY:
Common stock 355 355 Additional paid-in capital 2 2 Retained earnings 3,688 3,310 Currency translation adjustment 250 152 ------ ------ Total stockholders' equity 4,295 3,819
COMMITMENTS AND CONTINGENT LIABILITIES ------ ------
Total liabilities and stockholders' equity $8,389 $7,863 ====== ======
See accompanying Notes to Combined Financial Statements.
C-7
CALTEX GROUP OF COMPANIES COMBINED STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (MILLIONS OF DOLLARS)
1993 1992 1991 ------- ------- ------- SALES AND OTHER OPERATING REVENUES (1) $15,409 $17,281 $15,445
OPERATING CHARGES: Cost of sales and operating expenses (2) 13,431 15,348 13,394 Selling, general and administrative expenses 496 479 444 Depreciation, depletion and amortization 295 263 257 Maintenance and repairs 170 165 156 ------- ------- ------- 14,392 16,255 14,251 ------- ------- -------
Operating income 1,017 1,026 1,194
OTHER INCOME (DEDUCTIONS): Equity in net income of nonsubsidiary companies 140 163 188 Dividends, interest and other income 99 83 288 Foreign exchange, net 23 21 (5) Interest expense (93) (102) (131) Minority interest in subsidiary companies (8) (13) (8) ------- ------- ------- 161 152 332 ------- ------- -------
Income before provision for income taxes and cumulative effects of changes in accounting principles 1,178 1,178 1,526 ------- ------- -------
PROVISION FOR INCOME TAXES: Current 433 456 649 Deferred 25 53 38 ------- ------- ------- Total provision for income taxes 458 509 687 ------- ------- -------
Income before cumulative effects of changes in accounting principles 720 669 839 Cumulative effects of changes in accounting principles - 51 - ------- ------- -------
Net income $ 720 $ 720 $ 839 ======= ======= =======
(1) Includes sales to: Stockholder companies $ 907 $ 835 $1,124 Nonsubsidiary companies $2,684 $3,075 $2,610
(2) Includes purchases from: Stockholder companies $3,333 $3,917 $3,181 Nonsubsidiary companies $2,618 $2,198 $2,217
See accompanying Notes to Combined Financial Statements.
C-8
CALTEX GROUP OF COMPANIES COMBINED STATEMENT OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (MILLIONS OF DOLLARS)
1993 1992 1991 ------- ------- -------
Balance at beginning of year $3,310 $2,955 $2,518 Net income 720 720 839 Cash dividends (342) (365) (402) ------- ------- ------- Balance at end of year $3,688 $3,310 $2,955 ======= ======= =======
COMBINED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (MILLIONS OF DOLLARS)
1993 1992 1991 ------- ------- ------- OPERATING ACTIVITIES: Net income $ 720 $ 720 $ 839 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effects of changes in accounting principles - (51) - Depreciation, depletion and amortization 295 263 257 Dividends from nonsubsidiary companies, less than equity in net income (103) (133) (162) Asset sales (4) (4) (200) Deferred income taxes 25 53 38 Prepaid charges and deferred credits (41) 25 45 Changes in operating working capital 31 (58) 127 Other 10 (46) 5 ------- ------- ------- Net cash provided by operating activities 933 769 949 ------- ------- -------
INVESTING ACTIVITIES: Capital expenditures (763) (711) (640) Investments in and advances to nonsubsidiary companies (149) (17) (1) Net purchases of investment instruments (21) (11) (14) Proceeds from asset sales 73 144 85 ------- ------- ------- Net cash used in investing activities (860) (595) (570) ------- ------- -------
FINANCING ACTIVITIES: Proceeds from borrowings having original terms in excess of three months 745 831 643 Repayments of borrowings having original terms in excess of three months (704) (857) (553) Net increase (decrease) in other borrowings 140 94 (37) Dividends paid, including minority interest (342) (365) (407) ------- ------- ------- Net cash used in financing activities (161) (297) (354) ------- ------- -------
Effect of exchange rate changes on cash and cash equivalents 15 (8) (17) ------- ------- ------- NET CHANGE IN CASH AND CASH EQUIVALENTS (73) (131) 8 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 239 370 362 ------- ------- ------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 166 $ 239 $ 370 ======= ======= =======
See accompanying Notes to Combined Financial Statements.
C-9
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF COMBINATION
The combined financial statements of the Caltex Group of Companies (Group) include the accounts of Caltex Petroleum Corporation and subsidiaries, American Overseas Petroleum Limited and subsidiaries and P.T. Caltex Pacific Indonesia after the elimination of intercompany balances and transactions. A subsidiary of Chevron Corporation and two subsidiaries of Texaco Inc. (stockholders) each own 50% of the outstanding common shares. The Group is primarily engaged in exploring, producing, refining and marketing crude oil and refined products in the Eastern Hemisphere. The Group employs accounting policies that are in accordance with generally accepted accounting principles in the United States.
TRANSLATION OF FOREIGN CURRENCIES
The U.S. dollar is the functional currency for all principal subsidiary operations. Nonsubsidiary companies in Japan and Korea use the local currency as the functional currency.
INVENTORIES
Crude oil and refined product inventories are stated at the lower of cost (primarily determined on the last-in, first-out (LIFO) method) or current market value. Costs include applicable purchase and refining costs, duties, import taxes, freight, etc. Materials and supplies are valued at average cost.
INVESTMENTS AND ADVANCES
Investments in and advances to nonsubsidiary companies in which 20% to 50% of the voting stock is owned by the Group, or in which the Group has the ability to exercise significant influence, are accounted for by the equity method. Under this method, the Group's equity in the earnings or losses of these companies is included in current results, and the related investments reflect the equity in the book value of underlying net assets. Investments in other nonsubsidiary companies are carried at cost and related dividends are reported as income.
PROPERTY, PLANT AND EQUIPMENT
Exploration and production activities are accounted for under the "successful efforts" method. Depreciation, depletion and amortization expenses for capitalized costs relating to the producing area, including intangible development costs, are computed using the unit-of-production method.
All other assets are depreciated by class on a uniform straight line basis. Depreciation rates are based upon the estimated useful life of each class of property. In view of the numerous depreciation classifications, it is not practical to provide a schedule of depreciation rates.
Maintenance and repairs necessary to maintain facilities in operating condition are charged to income as incurred. Additions and betterments that materially extend the life of properties are capitalized. Upon disposal of properties, any net gain or loss is included in other income.
C-10
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
DEFERRED INCOME TAXES
Effective January 1, 1992, deferred income taxes are recognized according to the asset and liability method specified in Statement of Financial Accounting Standards (SFAS) No. 109 "Accounting for Income Taxes" by applying individual jurisdiction tax rates applicable to future years to differences between the financial statement and tax basis carrying amounts of assets and liabilities. The effect of tax rate changes on previously recorded deferred taxes is recognized in the current year. Deferred income taxes for 1991 were recognized under the method specified in SFAS No. 96.
No provision has been made for possible income taxes that might be payable if accumulated earnings of subsidiary companies and nonsubsidiary companies accounted for by the equity method were distributed, since such earnings have been or are intended to be indefinitely reinvested.
ENVIRONMENTAL MATTERS
Compliance with environmental regulations is determined in relation to the existing laws in each of the countries in which the Group operates and the Group's own internal standards. The Group capitalizes expenditures that create future benefits or contribute to future revenue generation. Remediation costs are accrued based on estimates of known environmental exposure even if uncertainties exist about the ultimate cost of the remediation. Such accruals are based on the best available nondiscounted estimated costs using data developed by third party experts. Costs of environmental compliance for past and ongoing operations, including maintenance and monitoring, are expensed as incurred. Recoveries from third parties are recorded as assets when realization is determined to be probable.
RECLASSIFICATIONS
Certain amounts have been reclassified for preceding periods to conform with the current year's presentation.
(2) INVENTORIES
The excess of current cost over the stated value of inventory maintained on the LIFO basis was approximately $40 million and $91 million at December 31, 1993 and 1992, respectively. The reduction of LIFO inventories in certain countries resulted in an increase in the earnings of consolidated subsidiaries and nonsubsidiary companies at equity of approximately $1 million in 1993. Previous reductions in LIFO inventories resulted in a decrease in earnings of $2 million in 1992 and an increase in earnings of $4 million in 1991.
Charges of $104 million and $25 million reduced income in 1993 and 1991, respectively, to reflect a market value of certain inventories lower than their LIFO carrying value. Earnings of $14 million were recorded in 1992 to reflect a partial recovery of the 1991 charge.
C-11
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(3) NONSUBSIDIARY COMPANIES AT EQUITY
Investments in and advances to nonsubsidiary companies at equity at December 31 include the following (in millions):
Equity Share 1993 1992 ------------ ------ ------ Nippon Petroleum Refining Company, Ltd. 50% $ 829 $ 727 Koa Oil Company, Ltd. 50% 310 268 Honam Oil Refinery Company, Ltd. 50% 423 357 All other Various 234 75 ------ ------ $1,796 $1,427 ====== ======
Shown below is summarized combined financial information for these non- subsidiary companies (in millions):
100% Equity Share ---------------- ----------------- 1993 1992 1993 1992 ------ ------ ------ ------
Current assets $4,680 $5,149 $2,316 $2,564 Other assets 6,147 4,851 2,975 2,410
Current liabilities 4,900 4,946 2,349 2,470 Other liabilities 2,306 2,173 1,146 1,078
Net worth 3,621 2,881 1,796 1,426
100% Equity Share ------------------------- ---------------------- 1993 1992 1991 1993 1992 1991 ------- ------- ------- ------ ------ ------ Operating revenues $10,679 $10,502 $10,267 $5,304 $5,216 $5,102 Operating income 494 645 839 242 319 416 Net income 281 326 380 140 163 188
Retained earnings at December 31, 1993, includes $1.2 billion representing the Group's share of undistributed earnings of nonsubsidiary companies at equity.
Cash dividends received from these nonsubsidiary companies were $37 million, $30 million, and $26 million in 1993, 1992 and 1991, respectively.
Sales to the other 50 percent owner of Nippon Petroleum Refining Company, Ltd. of products refined by Nippon Petroleum Refining Company, Ltd. and Koa Oil Company, Ltd. were approximately $1.9 billion, $2 billion, and $2.1 billion in 1993, 1992, and 1991, respectively.
C-12
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(4) NOTES PAYABLE
Information regarding short-term financing, consisting primarily of demand loans, promissory notes, acceptance credits and overdrafts, is shown below (dollars in millions):
Weighted Maximum Weighted Average Average Outstanding Average Interest Rate Borrowings At Interest Rate At Any Amount On Average Year End At Year End Month End Outstanding Outstanding ------------- ------------- ---------- ----------- -------------- 1993 $966 4.7% $1,041 $902 4.6% 1992 830 5.0 1,063 898 5.7 1991 907 7.2 996 875 9.9
Unutilized lines of credit available for short-term financing totaled $814 million at December 31, 1993.
(5) LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
Long-term debt and capital lease obligations, with related interest rates at December 31, 1993, consist of the following (in millions):
1993 1992 U.S. dollars: ---- ---- Variable interest rate term loans $173 $155 Fixed interest rate term loans with 7.6% average rate 220 205 Australian dollars: Debentures with interest rates at 12.5% due 1995 - 1996 8 11 Promissory notes payable with 4.9% average rate 76 65 Capital lease obligations 33 33 New Zealand dollars: Term loans with interest rates 6 - 6.35% due 1996-1997 14 - Other 6 17 ---- ---- $530 $486 ==== ====
At December 31, 1993 and 1992, $101 million and $110 million, respectively, of notes payable were classified as long-term debt. Settlement of these obligations is not expected to require the use of working capital in 1994, as the Group has both the intent and ability to refinance this debt on a long- term basis. At December 31, 1993 and 1992, $101 million and $110 million, respectively, of long-term committed credit facilities were available with major banks to support notes payable classified as long-term debt.
Maturities subsequent to December 31, 1993 follow (in millions): 1994 - $51 (included on the combined balance sheet as a current liability); 1995 - $151; 1996 - $147; 1997 - $37; 1998 - $86; 1999 and thereafter - $109.
C-13
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(6) EMPLOYEE BENEFITS
The Group has retirement plans covering substantially all eligible employees. Generally, these plans provide defined benefits based on final or final average pay, as defined. The benefit levels, vesting terms and funding practices vary among plans.
The funded status of retirement plans, primarily foreign and inclusive of nonsubsidiary companies at equity, at December 31 follows (in millions):
Assets Exceed Accumulated Accumulated Benefits FUNDING STATUS Benefits Exceed Assets ------------ ------------- 1993 1992 1993 1992 ---- ---- ---- ---- Actuarial present value of: Vested benefit obligation $280 $240 $117 $100 Accumulated benefit obligation 309 264 137 117 Projected benefit obligation 484 432 195 170
Amount of assets available for benefits: Funded assets at fair value $450 $403 $ 39 $ 26 Net pension (asset) liability recorded (11) (8) 128 123 ---- ---- ---- ---- Total assets $439 $395 $167 $149 ==== ==== ==== ====
Assets less than projected benefit obligation $(45) $(37) $(28) $(21)
Consisting of: Unrecognized transition net assets (liabilities) 31 38 (2) (4) Unrecognized net losses (44) (42) (23) (16) Unrecognized prior service costs (32) (33) (3) (1)
Weighted average rate assumptions: Discount rate 9.5% 11.1% 6.5% 6.5% Rate of increase in compensation 7.4% 9.0% 4.7% 4.7% Expected return on plan assets 10.3% 11.4% 5.5% 4.9%
EXPENSES (Funded & Unfunded Combined) 1993 1992 1991 ---- ---- ---- Cost of benefits earned during the year $ 27 $ 26 $ 21 Interest cost on projected benefit obligation 58 54 49 Actual return on plan assets (59) (9) (64) Net amortization and deferral 16 (38) 22 ---- ---- ---- $ 42 $ 33 $ 28 ==== ==== ====
The Group adopted SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" effective January 1, 1992, using the immediate recognition option. SFAS No. 106 requires accrual, during the employees' service with the Group, of the cost of their retiree health and life insurance benefits. Prior to 1992, postretirement benefits were included in expense as the benefits were paid.
C-14
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(6) EMPLOYEE BENEFITS - Continued
Certain companies within the Group provide health care and life insurance benefits to retired employees. The plans which provide these benefits are unfunded. As of December 31, 1993 and 1992, the accumulated postretirement benefit obligation amounted to $47 million and $43 million, respectively, with related accruals of $44 million and $43 million, respectively. The net periodic postretirement benefit costs amounted to $6 million for each of the years ending December 31, 1993 and 1992.
In November 1992 the Financial Accounting Standards Board issued SFAS No. 112 "Employers' Accounting for Postemployment Benefits." This new standard requires companies to accrue, no later than 1994, for the cost for benefits provided to former or inactive employees after employment but prior to retirement. Adoption of this new standard is not expected to materially impact the combined financial statements of the Group.
(7) OPERATING LEASES
The Group has various operating leases involving service stations, equipment and other facilities for which net rental expense was $110 million, $95 million, and $53 million in 1993, 1992 and 1991, respectively.
Future net minimum rental commitments under operating leases having noncancelable terms in excess of one year are as follows (in millions): 1994 - $42; 1995 - $42; 1996 - $42; 1997 - $37; 1998 - $31; 1999 and thereafter - $146.
(8) CONTINGENT LIABILITIES
On January 25, 1990, Caltex Petroleum Corporation and certain of its subsidiaries were named as defendants, along with privately held Philippine ferry and shipping companies and the shipping company's insurer, in a lawsuit filed in Houston, Texas State Court. After removal to Federal District Court in Houston, the litigation's disposition turned on questions of federal court jurisdiction and whether the case should be dismissed for forum non conveniens. The plaintiffs' petition purported to be a class action on behalf of at least 3,350 parties, who were either survivors of, or next of kin of persons deceased in a collision in Philippine waters on December 20, 1987. One vessel involved in the collision was carrying Group products in connection with a freight contract. Although the Group had no direct or indirect ownership or operational responsibility for either vessel, various theories of liability were alleged against the Group. No specific monetary recovery was sought although the petition contained a variety of demands for various categories of compensatory as well as punitive damages. These issues were resolved in the Group's favor by the Federal District Court in March 1992, and that decision is now final. However, the plaintiffs had separately filed another lawsuit, alleging the same causes of action as in the Texas litigation, in Louisiana State Court in New Orleans in late 1988 but never served the Group until late December of 1993, after the decision in the Texas litigation became final. Subsequent to receipt of the service, the Group has removed this case to Federal District Court in New Orleans and has moved for its dismissal. Management is contesting this case vigorously. It is not possible to estimate the amount of damages involved, if any.
The Group may be subject to loss contingencies pursuant to environmental laws and regulations in each of the countries in which it operates that, in the future, may require the Group to take action to correct or remediate the effects on the environment of prior disposal or release of petroleum substances by the Group. The amount of such future cost is indeterminable due to such factors as the nature of the new regulations, the unknown magnitude of any possible contamination, the unknown timing and extent of the corrective actions that may be required, and the extent to which such costs are recoverable from third party insurance.
C-15
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(8) CONTINGENT LIABILITIES - Continued
The Group is also involved in certain other litigation and Internal Revenue Service tax audits that could involve significant payments if such items are all ultimately resolved adversely to the Group.
While it is impossible to ascertain the ultimate legal and financial liability with respect to the above mentioned contingent liabilities, the aggregate amount that may arise from such liabilities is not anticipated to be material in relation to the Group's combined financial position, results of operations, or liquidity.
(9)FINANCIAL INSTRUMENTS
Certain Group companies are parties to financial instruments with off-balance sheet credit and market risk, principally interest rate risk. As of December 31, the Group had commitments outstanding for interest rate swaps and foreign currency transactions for which the notional or contractual amounts are as follows (in millions):
1993 1992 ---- ---- Interest rate swaps $344 $317 Commitments to purchase foreign currencies $338 $141 Commitments to sell foreign currencies $ 89 $ 20
The interest rate swaps are intended to hedge against fluctuations in interest rates on debt, and their effects are recognized in the statement of income at the same time as the interest expense on the debt to which they relate.
Commitments to purchase and sell foreign currencies are made to provide exchange rate protection for specific transactions and to maximize economic benefit based on expected currency movements. The above purchase and sale commitments are at year end exchange rates and mature during the following year. These commitments are marked to market and the resulting gains and losses are recognized in current year income unless the contract is a specific hedge of an identifiable transaction. There were no material differences between the notional and estimated fair value for these commitments.
The Group's long-term debt, excluding capital lease obligations, of $497 million and $453 million at December 31, 1993 and 1992, respectively, had fair values of $511 million and $462 million at December 31, 1993 and 1992, respectively. The fair value estimates were based on the present value of expected cash flows discounted at current market rates for similar obligations. The reported amounts of financial instruments such as Cash and cash equivalents, Notes and accounts receivable, and all current liabilities approximate fair value because of their short maturity.
Certain Group companies were contingently liable as guarantors for $7 million and $12 million at December 31, 1993 and 1992, respectively. The Group also had commitments of $36 million and $96 million at December 31, 1993 and 1992, respectively, in the form of letters of credit which have been issued on behalf of Group companies to facilitate either the Group's or other parties' ability to trade in the normal course of business.
Financial instruments exposed to credit risk consist primarily of trade receivables. These receivables are dispersed among the countries in which the Group operates, thus limiting concentrations of such risk.
The Group performs ongoing credit evaluations of its customers and generally does not require collateral. Letters of credit are the principal security obtained to support lines of credit when the financial strength of a customer or country is not considered sufficient. Credit losses have been historically within management's expectations.
C-16
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(10) OTHER INCOME/DEDUCTIONS
In 1991, dividends, interest and other income included gains from asset sales on a before and after tax basis of $200 million and $120 million, respectively. Asset sales in 1993 and 1992 were not significant.
Net foreign exchange (exclusive of the currency translation adjustment) for consolidated subsidiaries and nonsubsidiary companies at equity, after applicable income taxes, amounted to gains of $32 million and $43 million in 1993 and 1992, respectively. The gain in 1991 was less than $1 million.
(11) TAXES
Taxes charged to income consist of the following (in millions):
1993 1992 1991 ------ ------ ------ Taxes other than income taxes: Duties, import and excise taxes $1,978 $1,891 $1,802 Other 29 29 29 ------ ------ ------ Total taxes other than income taxes 2,007 1,920 1,831 Provision for income taxes 458 509 687 ------ ------ ------ $2,465 $2,429 $2,518 ====== ====== ======
The provision for income taxes, substantially all foreign, has been computed on an individual company basis at rates in effect in the various countries of operation. The actual tax expense differs from the "expected" tax expense (computed by applying the U.S. Federal corporate tax rate to income before provision for income taxes) as follows:
1993 1992 1991 ----- ----- -----
Computed "expected" tax expense 35.0% 34.0% 34.0%
Effect of recording equity in net income of nonsubsidiary companies on an after tax basis (4.2) (4.9) (4.2)
Effect of dividends received from subsidiary and nonsubsidiary companies 4.2 3.8 3.3
Foreign income subject to foreign taxes in excess of U.S. statutory tax rate 7.4 11.6 10.4
Decrease in deferred tax asset valuation allowance (3.1) (.4) -
Other (.4) (.9) 1.5 ----- ----- ----- 38.9% 43.2% 45.0% ===== ===== =====
C-17
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(11) TAXES - Continued
Deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of assets and liabilities. Temporary differences and tax loss carryforwards which give rise to deferred tax assets and liabilities at December 31, 1993 and 1992 are as follows (in millions):
Deferred Deferred Tax Assets Tax Liabilities --------------- -------------- 1993 1992 1993 1992 ---- ---- ---- ---- Inventory $ 10 $ 27 $ 18 $ 17 Depreciation - - 298 275 Retirement plans 33 28 3 2 Tax loss carryforwards 29 36 - - Other 28 30 34 30 ---- ---- ---- ---- 100 121 353 324 Valuation allowance (6) (42) - - ---- ---- ---- ---- Total deferred taxes $ 94 $ 79 $353 $324 ==== ==== ==== ====
The valuation allowance has been established to record deferred tax assets at amounts where recoverability is more likely than not. Net income was increased by $36 million and $5 million for changes in the deferred tax asset valuation allowance during 1993 and 1992, respectively.
Undistributed earnings for which no deferred income tax provision has been made approximated $3.6 billion at December 31, 1993. Such earnings have been or are intended to be indefinitely reinvested. These earnings would become taxable in the U.S. only upon remittance as dividends. It is not practical to estimate the amount of tax that might be payable on the eventual remittance of such earnings. On remittance, certain foreign countries impose withholding taxes which, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.
(12) CASH FLOWS
For purposes of the statement of cash flows, all highly liquid debt instruments with original maturities of three months or less are considered cash equivalents.
The "Changes in Operating Working Capital" consists of the following (in millions):
1993 1992 1991 ---- ---- ---- Notes and accounts receivable $ 82 $(45) $418 Inventories 66 (114) 62 Accounts payable (147) 212 (317) Accrued liabilities 16 (27) (2) Estimated income taxes 14 (84) (34) ---- ---- ---- Total $ 31 $(58) $127 ==== ==== ====
C-18
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(12) CASH FLOWS - Continued
"Net Cash Provided by Operating Activities" includes the following cash payments for interest and income taxes (in millions):
1993 1992 1991 ---- ---- ---- Interest paid (net of capitalized interest) $ 92 $106 $132
Income taxes paid $391 $528 $662
In 1991, an asset sale was funded with receivables of $120 million, which were subsequently collected in 1992. No other significant non-cash investing or financing transactions occurred in 1993, 1992 or 1991.
(13) INVESTMENTS IN DEBT AND EQUITY SECURITIES
In May 1993, the Financial Accounting Standards Board issued SFAS No. 115 "Accounting For Certain Investments in Debt and Equity Securities." This new standard requires companies, no later than 1994, to classify debt and equity securities into one of three categories: held-to-maturity, available-for-sale, or trading. Debt which will be held to maturity will be carried at amortized cost. Certain securities considered available-for-sale shall be carried at fair value and unrealized holding gains and losses shall be carried as a net amount in a separate component of stockholders' equity until realized. Securities classified as trading shall be carried at fair value and unrealized holding gains and losses shall be included in earnings.
Adoption of this new standard will not materially impact the combined financial position or the results of operations of the Group.
(14) OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCING ACTIVITIES
The financial statements of Chevron Corporation and Texaco Inc. contain required supplementary information on oil and gas producing activities, including disclosures on equity affiliates. Accordingly, such disclosures are not presented herein.
C-19
CALTEX GROUP OF COMPANIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (MILLIONS OF DOLLARS)
OTHER BALANCE AT ADDI- RETIRE- CHANGES BALANCE BEGINNING TIONS MENTS ADD AT END CLASSIFICATION OF PERIOD AT COST OR SALES (DEDUCT) OF PERIOD - ------------------------------------------------------------------------------- Year ended December 31, 1993 Producing $2,783 $247 $ 3 $ - $3,027 Refining 1,259 237 6 (7) (1) 1,483 Marketing 2,107 262 108 (9) (2) 2,252 Marine 35 - - - 35 Capitalized leases 113 8 2 - 119 ------ ---- ---- ---- ------ Total $6,297 $754 $119 $(16) $6,916 ====== ==== ==== ==== ======
Year ended December 31, 1992 Producing $2,462 $322 $ 1 $ - $2,783 Refining 1,111 166 18 - 1,259 Marketing 1,915 253 46 (15) (3) 2,107 Marine 55 - 20 - 35 Capitalized leases 113 - - - 113 ------ ---- ---- ---- ------ Total $5,656 $741 $ 85 $(15) $6,297 ====== ==== ==== ==== ======
Year ended December 31, 1991 Producing $2,179 $284 $ 1 $ - $2,462 Refining 1,008 105 2 - 1,111 Marketing 1,689 243 39 22 (1) 1,915 Marine 54 1 - - 55 Capitalized leases 111 3 1 - 113 ------ ---- ---- ---- ------ Total $5,041 $636 $ 43 $ 22 $5,656 ====== ==== ==== ==== ======
(1) Reclassification (2) Currency translation adjustment $(4) and reclassification $(5) (3) Currency translation adjustment
C-20
CALTEX GROUP OF COMPANIES SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (MILLIONS OF DOLLARS)
ADDITIONS OTHER BALANCE AT CHARGED TO RETIRE- CHANGES BALANCE BEGINNING COSTS AND MENTS ADD AT END CLASSIFICATION OF PERIOD EXPENSES OR SALES (DEDUCT) OF PERIOD - ------------------------------------------------------------------------------- Year ended December 31, 1993 Producing $1,158 $128 $ 1 $ - $1,285 Refining 646 51 6 (2) (1) 689 Marketing 736 104 32 (2) (2) 806 Marine 7 2 - - 9 Capitalized leases 81 10 2 - 89 ------ ---- --- ---- ------ Total $2,628 $295 $41 $(4) $2,878 ====== ==== === ==== ======
Year ended December 31, 1992 Producing $1,051 $106 $(1) $ - $1,158 Refining 614 47 15 - 646 Marketing 672 98 25 (9) (3) 736 Marine 23 2 18 - 7 Capitalized leases 73 10 2 - 81 ------ ---- --- ---- ------ Total $2,433 $263 $59 $(9) $2,628 ====== ==== === ==== ======
Year ended December 31, 1991 Producing $ 940 $111 $ - $ - $1,051 Refining 567 49 2 - 614 Marketing 609 85 22 - 672 Marine 21 2 - - 23 Capitalized leases 64 10 1 - 73 ------ ---- --- ---- ------ Total $2,201 $257 $25 $ - $2,433 ====== ==== === ==== ======
(1) Reclassification (2) Currency translation adjustment $(1) and reclassification $(1) (3) Currency translation adjustment
C-21