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 ("upstream") operations in the United States are carried out through Chevron U.S.A. Production Company. U.S. refining and marketing ("downstream") activities are performed by Chevron U.S.A. Products Company. Warren Petroleum Company engages in all phases of the domestic natural gas liquids business. A list of the company's major subsidiaries is presented on page EX-2 of this Annual Report on Form 10-K. As of December 31, 1994, Chevron had 45,758 employees, 77 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 and natural gas is largely driven by the health of local, national and worldwide economies, although weather patterns and taxation relative to other energy sources also play a significant part. Natural gas is generally produced and consumed on a country or regional basis. Its largest use is for electrical generation, where it competes with other energy fuels.
CURRENT OPERATING ENVIRONMENT ----------------------------- After starting the year at a five-year low, crude oil prices rebounded in the second quarter of 1994 on news of OPEC's decision at their March 1994 meeting to hold production at their current level of 24.5 million barrels per day for the balance of the year (subsequently extended through 1995) and concern of supply disruptions due to local disturbances in Nigeria. Crude oil prices began to fall in August and continued to trend downward through the end of the year due to ample crude supplies, settlement of the Nigerian oil
------------------ (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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worker's strike in early September and an abnormally mild winter in most parts of the United States. The company's U.S. realizations declined 72 cents per barrel from the previous year, representing the fourth consecutive year average realizations have fallen.
U.S. natural gas prices also trended downward throughout 1994 after having posted increases in the prior three years. Factors contributing to the decrease in natural gas prices included poor utility demand driven by the relatively mild summer and winter weather in many parts of the U.S., increased Canadian gas exports to the U.S., high gas storage levels and improved performance of nuclear power plants that experienced downtime in the previous year. In the United States, the Henry Hub, Louisiana spot price for natural gas, a common benchmark for natural gas prices, averaged $1.86 per thousand cubic feet (MCF) in 1994, a decrease of $.25 per MCF from 1993.
The company's average realization from U.S. crude oil production declined from $14.58 per barrel in 1993 to $13.86 per barrel in 1994 while average liquids realizations from international liftings, including equity affiliates, declined by $1.23 per barrel to $14.86 per barrel. Average U.S. natural gas realizations from production decreased to $1.77 per MCF in 1994 from $1.99 per MCF in 1993.
The following table compares the high, low and average Chevron posted prices for West Texas Intermediate (WTI), an industry benchmark light crude oil, for each of the quarters during 1994 and for the full years of 1994, 1993, and 1992:
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WEST TEXAS INTERMEDIATE CRUDE OIL CHEVRON POSTED PRICES (Dollars per Barrel)
------------------------------------- 1ST Q 2ND Q 3RD Q 4TH Q YEAR 1993 1992 ----- ----- ----- ----- ----- ----- ----- High 15.00 19.75 19.50 18.00 19.75 20.25 21.75 Low 13.00 13.75 15.75 15.75 13.00 13.00 16.50 Average 13.80 16.71 17.48 16.68 16.18 17.68 19.71 ----------------------------------------------------------------------
For the first two months of 1995, average natural gas realizations for the company's U.S. operations were $1.43 per MCF. During this period, the company's posted price for WTI ranged from $16.50 per barrel to $18.00, with an average of $17.28. On March 20, 1995 the company's posted price for WTI was $17.50 per barrel.
Chevron's refining and marketing operations in the United States were adversely affected by scheduled and unscheduled refinery downtime and other refinery operating problems in the first half of 1994. These refinery problems increased the company's operating costs and caused the company to purchase more costly third-party products to supply the company's marketing system. This put additional pressure on the company's sales margins on refined products which were already depressed most of the year due to ample supplies in the marketplace. The company's average sales price per barrel of refined product declined for the fourth year in a row, falling to $24.37 per barrel in 1994 from $25.35 per barrel in 1993.
The company's chemical operations improved significantly in 1994 as improving worldwide economies, including the U.S., reduced industry overcapacity, resulting in higher sales volumes and stronger prices for the company's commodity chemicals. Sales and other operating revenues from the company's chemical operations, including sales to other Chevron companies, increased $431 million from the $3,296 million recorded in 1993.
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CHEVRON STRATEGIC DIRECTION --------------------------- To improve financial performance and to compete more effectively, Chevron developed and implemented seven "strategic intents" in 1992 and added an eighth "strategic intent" in 1993. The company periodically reviews and modifies these "strategic intents" to reflect Chevron's current operating environment. The eight "strategic intents" for 1995 are:
- BUILD A COMMITTED TEAM TO ACCOMPLISH THE CORPORATE MISSION. The company continues to believe the success of the other seven strategic intents is dependent on the commitment and dedication that Chevron employees bring to their jobs. For the past three years, Chevron has measured employees' attitudes about the company and diagnosed areas of employee concerns by the use of the Worldwide Employee Survey. Due in large part to employee responses to the surveys, the company has recently developed or revamped programs in the areas of skills development, job selection, and upward feedback, a process in which employees are given the opportunity to evaluate their immediate supervisor. In 1994, the company sought to articulate this "strategic intent" by issuing a vision statement that outlined the attributes of a committed team. Underlying the vision statement was the need to promote trust, respect, support and teamwork among and between its employees and supervisors. The company is encouraging informed risk taking and encouraging employees to take an active role in planning and decision making while also increasing their accountability. Due in part to this "strategic intent," a greater number of cross-functional teams are being formed in the company to make decisions and manage projects, demonstrating a greater amount of teamwork and cooperation among its employees. In January 1995, the company announced a new program that will provide employees with a cash bonus if the company achieves certain financial goals. In 1995 the program, called "Chevron Success Sharing," will be based on Chevron's adjusted Return on Capital Employed (ROCE). If the company achieves an ROCE of 10 percent or greater and its ROCE is among the top four of its major U.S. competitors, a cash bonus, varying from two to eight percent of an employee's annual salary depending on the company's relative ROCE ranking, will be paid to employees eligible to participate in the program.
- FOCUS ON REDUCING COSTS ACROSS ALL ACTIVITIES. Operating expenses, adjusted for special items, declined $150 million in 1994 when compared to 1993, sustaining the prior year's cost reductions as well as offsetting inflation and mitigating expenses associated with refinery problems in the first half of 1994. When compared to 1991, the base measurement year established when Chevron undertook an extensive cost-cutting and work force reduction program in early 1992, operating expenses in 1994 have declined by over $1 billion. Although a portion of the cost reduction is related to discontinued operations, the company believes the majority is the result of a permanent reduction in the company's ongoing cost structure.
The company remains committed to further reductions in operating expense in 1995. Four "breakthrough" initiatives are currently in various stages of study or implementation that could result in large, permanent cost savings. These four "breakthrough" initiatives involve ways to reduce corporate energy costs; ways to reduce the cost of goods and services by working more efficiently with fewer suppliers; improvements to the project management process which is used to evaluate and administer large capital projects; and improvements in inventory management in order to avoid tying up working capital in excessive inventories.
- CONTINUE UPSTREAM GROWTH IN INTERNATIONAL AREAS. The company continues to believe opportunities to discover and develop major new reserves in the United States are limited due to regulatory barriers and drilling prohibitions on many of the most promising areas of development. In 1994, international exploration and production (E&P) capital spending rose 3 percent to approximately 71 percent of total E&P capital spending, including affiliates. This same ratio of international versus total E&P spending is expected to continue in 1995. As recently as 1990, U.S. exploration and production capital spending was approximately 50 percent of the total. Since 1991, international oil and gas production has increased nearly 25 percent and oil and gas reserves have increased 80 percent.
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- GENERATE GREATER THAN $800 MILLION IN CASH PER YEAR FROM U.S. UPSTREAM. Chevron is emphasizing a steady cash flow from a core group of approximately 400 oil and gas fields concentrated in California, Texas, the Rocky Mountains and the Gulf of Mexico. Net cash flow after capital and exploratory expenditures for U.S. exploration and production operations fell to $750 million in 1994 from $1.2 billion in 1993 due to weak crude oil and natural gas prices throughout most of the year.
The company modified this "strategic intent" in 1995 by lowering the annual cash generation amount from $1 billion to $800 million. This modification reflects the significant change in the outlook for both crude and U.S. natural gas prices since the original "strategic intent" was set in 1991 combined with the progress achieved in cost reduction.
The company continues to evaluate its current properties as well as evaluate and acquire new properties that the company believes will help it meet and sustain its cash generation goal. In 1994, the company acquired certain gas properties in West Texas by purchasing 100 percent of the stock of Pakenham, Inc., a subsidiary of Wes-Tex Drilling Company. The company believes these properties hold considerable development potential. Over the next five years, Chevron plans to drill about 150 wells on these properties at a cost of approximately $100 million and expects production to triple to 90 million cubic feet per day by 1999.
- ACHIEVE TOP FINANCIAL PERFORMANCE IN U.S. DOWNSTREAM. Chevron is seeking to strengthen its competitive position by investing in core refineries, reducing the size of its refining system and concentrating on specific marketing regions. The company sold its Philadelphia, Pennsylvania, refinery to Sun Company, Inc. in August 1994 and its Port Arthur, Texas, refinery to Clark Refining and Marketing, Inc. in February 1995. These refineries no longer fit Chevron's plan to have a more focused U.S. refining operation and their sales eliminated large capital expenditures that would otherwise have been required to make the refineries more competitive and to meet the Clean Air Act Amendments of 1990.
- GROW CALTEX IN ATTRACTIVE MARKETS WHILE ACHIEVING SUPERIOR COMPETITIVE FINANCIAL PERFORMANCE. Management believes that the demand for petroleum products will continue to grow in the Asia Pacific region. Chevron's 50 percent owned Caltex affiliate, a leading competitor in these areas, has and is continuing to make significant capital investments to expand and upgrade its refining capacity and its retail marketing systems. Refinery upgrade projects are continuing in Singapore and Korea, as well as the construction of a new refinery in Thailand. In 1994, Caltex opened representative offices in Ho Chi Minh City and Hanoi to develop and evaluate business opportunities in Vietnam. In China, Caltex is exploring technical and commercial aspects of developing a business relationship with Sinopec's Nanjing Refinery operated by Jinling Petrochemical Corporation. Caltex is also studying the feasibility of a joint venture with Shantou Ocean Enterprises to build a liquefied petroleum gas (LPG) terminal in Shantou, China.
- IMPROVE COMPETITIVE FINANCIAL PERFORMANCE IN CHEMICALS WHILE DEVELOPING ATTRACTIVE OPPORTUNITIES FOR GROWTH. Financial results for the company's chemical operations improved significantly in 1994 as the chemical industry in general rebounded from a period of depressed earnings due to sluggish world economies and production overcapacity. Improving world economies resulted in increased demand for the company's commodity chemicals, which are used to package or manufacture numerous consumer goods. In addition, the company believes the restructuring and cost reduction plans that have been implemented in recent years positioned the company to take advantage of the improved industry conditions. In 1995, the company plans to continue its restructuring with the closing of its nitric acid and fertilizer plants in Richmond, California, while also investing in areas demonstrating growth potential. Chevron plans to invest about $200 million in its chemical operations in 1995, including plans to expand production capacity by 65 percent at its linear low density polyethylene (LLDPE) plant at Cedar Bayou, Texas. This expansion is expected to be completed in 1996.
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- BE SELECTIVE IN NON-CORE BUSINESSES. Chevron operates four units that are outside the corporation's core focus. These four units are Chevron Canada Limited (CCL) and Gulf Oil Great Britain (GOGB) whose primary operations are the refining and marketing of petroleum products in Canada and the U.K., respectively, The Pittsburg & Midway Coal Mining Co. (P&M), operator of the company's mineral interests, and Chevron Land and Development Co. (CL&D), manager of the company's surplus fee production properties and other real estate operations in California. Chevron manages these four units for cash flow and profitability, and for growth when attractive opportunities exist. In 1994, GOGB expanded its service station network by approximately 7 percent to total about 500 service stations at year-end. P&M completed its planned sale of Chevron's non- coal interests in 1994 with the sale of its 50 percent interest in the Stillwater platinum and palladium mine in Montana and its 52.5 percent interest in some zinc-lead prospects in Ireland. CL&D generated over $140 million in sales of developed and undeveloped real estate properties in 1994.
In 1994, Chevron continued to dispose of other marginally performing or non-strategic assets, including the aforementioned refinery sales and the company's headquarters building located in San Francisco, California. Due to recent downsizing and restructuring of its operations, it was determined that employees currently located in the headquarters building could be accommodated in the company's other two San Francisco office buildings. Relocation of employees is expected to occur over the next 5 years.
The company is currently seeking prospective purchasers for its real estate development assets in California and is currently reviewing its oil and gas operations in western Canada.
(b) INDUSTRY SEGMENT AND GEOGRAPHIC AREA INFORMATION
The company's primary business is its integrated petroleum operations. Secondary operations include chemicals and minerals. The petroleum activities of the company are widely distributed geographically, with major operations in the United States, Australia, United Kingdom, Canada, Nigeria, Angola, Congo, Papua New Guinea, China, Indonesia and Zaire. The company's Caltex affiliate, through its subsidiaries and affiliates, conducts exploration and production operations in Indonesia and refining and marketing activities in the Eastern Hemisphere, with major operations in Japan, Korea, Australia, the Philippines, Thailand and South Africa. Tengizchevroil (TCO), a 50/50 joint venture with a subsidiary of the national oil company of the Republic of Kazakhstan conducts production activities in Kazakhstan, a former Soviet republic.
The company's and its affiliates' chemicals operations are concentrated in the United States, but include operating facilities in France, Japan and Brazil. The company's and its affiliates' principal minerals activities consist of coal 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.
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In the United States, environmental regulations and federal, state and local actions and policies concerning economic development, energy and taxation may have a significant effect on the company's operations.
Internationally, the company continues to closely monitor the civil unrest 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.
The company utilizes various derivative instruments to manage its exposure to price risk stemming from its integrated petroleum activities. Some of the instruments may be settled by delivery of the underlying commodity, whereas others can only be settled by cash. All these instruments are commonly used in the global trade of petroleum products and are relatively straightforward, involve little complexity and are substantially of a short-term duration.
The company enters into forward exchange contracts as a hedge against some of its foreign currency exposures. Interest rate swaps are entered into as part of the company's overall strategy to manage the interest rate risk on its debt. The impact of the forward exchange contracts and interest rate swaps on the company's results of operations is not material.
CAPITAL AND EXPLORATORY EXPENDITURES
Chevron's capital and exploratory expenditures during 1994 and 1993 are summarized in the following table:
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CAPITAL AND EXPLORATORY EXPENDITURES (Millions of Dollars) 1994 1993 ------ ------ Exploration and Production $2,586 $2,217 Refining, Marketing and Transportation 1,105 1,166 Chemicals 135 224 Coal and Other Minerals 44 42 All Others 103 90 ------ ------ Total Consolidated Companies 3,973 3,739 Equity in Affiliates 846 701 ------ ------ Total Including Affiliates $4,819 $4,440 ====== ====== -------------------------------------------------------
Total consolidated expenditures in 1994 increased 6 percent when compared to 1993, largely due to a $369 million increase in exploration and production (E&P) expenditures that was partially offset by decreases in chemical expenditures of $89 million and decreases in refining, marketing and transportation expenditures amounting to $61 million.
Consolidated E&P expenditures amounted to 65 percent of the company's total consolidated expenditures in 1994, compared with 59 percent in 1993. The percentage increase was due solely to increased expenditures in international E&P as U.S. E&P expenditures, as a percentage of total consolidated expenditures, remained relatively unchanged from 1993. U.S. E&P expenditures in 1994 included the company's acquisition of certain natural gas operations in West Texas. Major international E&P expenditures in 1994 included the acquisition of exploration and development interests in the Republic of Congo and exploration and development activities associated with the Alba Field in the U.K. North Sea, the North West Shelf Project in Australia, the Hibernia Project offshore Newfoundland, the Duri Steamflood Project
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in Indonesia, Areas B and C in Angola, the Niger Delta region in Nigeria and the Tengiz Project in Kazakhstan. Refining, marketing and transportation outlays in 1994 included expenditures for upgrading U.S. refineries to produce reformulated gasoline in order to comply with federal, state and local air quality regulations as well as other projects intended to upgrade and increase efficiencies at the refineries.
The company's share of capital and exploratory expenditures by its affiliates was $846 million in 1994, an increase of 21 percent from $701 million in 1993. This increase was primarily due to expenditures by the company's Caltex affiliate in the high growth Pacific Rim areas on refinery expansion/upgrade projects in Korea and Singapore and the construction of a new refinery in Thailand.
In 1995, the company expects to spend approximately $5.1 billion, including its share of equity affiliates' expenditures, an increase of approximately 5 percent over 1994 levels. Consolidated expenditures in 1995 are expected to remain relatively flat at $3.9 billion while affiliate expenditures are expected to increase 37 percent to $1.2 billion. Worldwide E&P expenditures are expected to total $2.7 billion, of which approximately 70 percent will be for international projects such as the continued development of the Hibernia Field, expansion of the North West Shelf Project, enhanced recovery projects in Indonesia, development of the Tengiz Field in Kazakhstan, development of the Alba and Britannia fields in the North Sea, development of the N'Kossa and Kitina fields in Congo, and other development projects in West Africa. Worldwide refining, marketing and transportation expenditures are estimated at $1.9 billion, with U.S. expenditures of about $900 million. These U.S. expenditures are largely due to major capital programs to manufacture clean fuels at the Richmond and El Segundo, California, refineries as mandated by the California Air Resources Board regulations. Major international refining and marketing expenditures in 1995 include the continuation of refinery construction and expansion/upgrade projects by the company's Caltex affiliate to meet growing product demand in the Pacific Rim areas. Chemical expenditures are also expected to rise in 1995 due to planned expansion of the linear low- density polyethylene manufacturing plant at the Cedar Bayou, Texas, chemical facility.
The actual expenditures for 1995 will depend on various conditions affecting the company's operations, including crude oil prices, and may differ significantly from the company's forecast.
PETROLEUM - EXPLORATION
The following table summarizes the company's net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 1994. "Exploratory wells" include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir beyond the proved area. "Wells drilling" include wells temporarily suspended.
----------------------------------------------------------------------------- EXPLORATORY WELL ACTIVITY
NET WELLS COMPLETED (1) WELLS DRILLING --------------------------------------- AT 12/31/94 1994 1993 1992 ------------------- ----------- ---------- ----------- GROSS (2) NET (2) PROD. DRY PROD. DRY PROD. DRY --------- ------- ---- ---- ---- ---- ---- ---- United States 43 32 53 17 32 14 42 16 --------- ------- ---- ---- ---- ---- ---- ----
Africa 11 4 5 2 3 4 3 3 Other International 42 18 55 42 27 35 15 4 --------- ------- ---- ---- ---- ---- ---- ---- Total International 53 22 60 44 30 39 18 7 --------- ------- ---- ---- ---- ---- ---- ---- Total Consolidated Companies 96 54 113 61 62 53 60 23
Equity in Affiliates 8 4 - 1 1 1 1 - --------- ------- ---- ---- ---- ---- ---- ---- Total Including Affiliates 104 58 113 62 63 54 61 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. ----------------------------------------------------------------------------- - 7 -
At December 31, 1994, the company owned or had under lease or similar agreements undeveloped and developed oil and gas properties located throughout the world. Undeveloped acreage includes undeveloped proved acreage. The geographical distribution of the company's acreage is shown in the next table.
----------------------------------------------------------------------------- ACREAGE* AT DECEMBER 31, 1994 (Thousands of Acres) DEVELOPED UNDEVELOPED DEVELOPED AND UNDEVELOPED ---------------- -------------- ---------------- GROSS NET GROSS NET GROSS NET ------- ------ ----- ----- ------- ------ United States 4,301 2,854 6,059 2,558 10,360 5,412 ------- ------ ----- ----- ------- ------ Canada 18,325 10,514 615 395 18,940 10,909 Africa 26,589 18,143 139 55 26,728 18,198 Asia 42,809 19,296 45 16 42,854 19,312 Europe 3,060 1,362 62 14 3,122 1,376 Other International 10,191 3,671 54 15 10,245 3,686 ------- ------ ----- ----- ------- ------ Total International 100,974 52,986 915 495 101,889 53,481 ------- ------ ----- ----- ------- ------ Total Consolidated Companies 105,275 55,840 6,974 3,053 112,249 58,893 Equity in Affiliates 3,202 1,601 233 116 3,435 1,717 ------- ------ ----- ----- ------- ------ Total Including Affiliates 108,477 57,441 7,207 3,169 115,684 60,610 ======= ====== ===== ===== ======= ======
* Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage is the sum of the company's fractional interests in gross acreage. -----------------------------------------------------------------------------
The company had $257 million of suspended exploratory wells included in properties, plant and equipment at year-end 1994. The wells are suspended pending drilling of additional wells to determine if commercially producible quantities of oil or gas reserves are present. The ultimate disposition of these well costs is dependent on the results of this future activity.
During 1994, the company explored for oil and gas in the United States and about 21 other countries. The company's 1994 exploratory expenditures, including affiliated companies' expenditures but excluding unproved property acquisitions, were $526 million compared with $533 million in 1993. Domestic expenditures represented approximately 40 percent of the consolidated companies' worldwide exploration expenditures, a 5 percent increase from the prior year. Significant activities in Chevron's exploration program during 1994 include the following (number of wells are on a "gross" basis):
UNITED STATES: Domestic exploratory expenditures, excluding unproved property acquisitions, were $209 million in 1994, compared to $183 million spent in 1993. In addition, the company incurred costs of $28 million for unproved property acquisitions in 1994. The company continued to focus its exploratory efforts in 1994 in the Gulf of Mexico, Texas, California, the Rocky Mountains and in other areas where it has existing production. Twelve wildcat exploratory wells were initiated in 1994 of which eleven were in new areas and one was in an existing core area. Including three wells commenced in late 1993, thirteen wells were completed in 1994, resulting in two discoveries in the Gulf of Mexico. The company's exploratory well in the Destin Dome Block 97, located 30 miles south of Pensacola, Florida in the Gulf of Mexico, resulted in a dry hole. Exploration efforts in high-potential areas, including Alaska's Arctic National Wildlife Refuge (ANWR) and parts of offshore Florida, California and North Carolina have been blocked by legal restrictions and drilling moratoria. Chevron and other oil companies have sued the Department of Interior to recover bonus payments, lease rentals and certain geophysical costs for federal offshore leases that remain undrilled due to state, federal, and private objections to drilling. The company is seeking to recover approximately $126 million, plus interest, spent on leases off Florida, North Carolina and Alaska. Currently all parties have filed Motions for Summary Judgment in this matter. Oral arguments were held on January 31, 1995 and a ruling is expected in 1995.
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AFRICA: In Africa, the company spent $81 million during 1994 on exploratory efforts, excluding the acquisition of unproved properties, compared with $104 million in 1993. The company also acquired $19 million of unproved properties in 1994.
In Nigeria, the company's operations are managed by three subsidiaries. Chevron Nigeria Limited (CNL) operates and holds a 40 percent interest in concessions totaling 2.3 million acres in the onshore and offshore regions of the Niger Delta. Chevron Oil Company (Nigeria) Limited (COCNL) holds a 20 percent interest in six concessions covering 600,000 acres with six oil fields operated by a partner. Chevron Petroleum Nigeria Limited (CPNL) has a 30 percent interest in two deepwater Niger Delta blocks and three inland Benue Basin blocks and an additional sole interest, through a production sharing contract signed in October 1994 with the Nigerian National Petroleum Company (NNPC), in six other Benue Basin blocks. CNL drilled seven exploratory and appraisal wells in 1994 which resulted in three new field discoveries, two successful appraisal wells and two dry holes. CNL also acquired 3-D seismic data covering Nigerian acreage of 200 square miles. COCNL, through its operating partner, drilled one exploratory well in 1994 which discovered gas and gas condensate. CPNL will begin seismic studies in 1995 as part of a work program expected to span the next six years to explore for oil in six Benue Basin blocks, totaling approximately 5,600 square miles. The company will finance the exploration phase and offset its cost from any future crude oil production. This production sharing agreement is a departure from the joint venture agreements of the past in which cost and revenue were shared according to each party's interest in the venture.
In Angola, the company is the operator of a 2,700 square mile concession off the coast of Angola's Cabinda exclave. The concession is divided into Areas A, B, and C, with Area A generating the majority of 1994 production. Area B production commenced in November 1994 with the commissioning of installations in the Kokongo Field. Chevron has a 39 percent interest in the concession. Six exploratory wells were drilled in 1994, with three wells in Area A resulting in oil discoveries. Two of these wells will be developed by drilling from existing facilities while the third well will be appraised in 1995 for the appropriate installation facilities required for development. The other three exploratory wells were drilled in Areas B and C and resulted in the discoveries of the N'Sangui and Minzu fields. The current exploration license for Areas B and C expired in 1994. Negotiations are currently underway to renew this agreement for five additional years. In 1994, Chevron (operator with 31 percent interest) and its partners completed negotiations of a Production Sharing Agreement for Deepwater Block 14, located due west of Areas B and C. The Angolan government approved the agreement in December 1994 and signing occurred in February 1995. A seismic program is scheduled to begin in April 1995 followed by the first of four exploration obligation wells in early 1996.
Offshore Congo, Chevron currently participates in two production licenses and two exploration licenses. The company has a 29 percent interest in the Kitina production license and the Marine VII exploration license operated by AGIP. Between October 1994 and March 1995 Chevron acquired a 30 percent interest in the N'Kossa production license and the Haute Mer exploration license operated by ELF Congo. The company and its partners plan to drill two wildcat wells in 1995, one in each of the two exploration areas. The company opened an office in Congo in January 1995 to facilitate its participation in the two joint ventures.
In Zaire, the company has a 50 percent interest in, and is the operator of, a 390 square mile concession off the coast of Zaire. Exploration activity in 1994 resulted in an oil discovery in the Tshiala East exploration well. An existing production well was also deepened in 1994 and a new reservoir underlying Mibale Field was discovered. An exploration well in the Mibale Field and the Tshiala West #1 well commenced in December 1994.
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Exploration expenditures, excluding unproved property acquisitions, were $236 million in 1994, a decrease of $10 million from the 1993 amount of $246 million. In addition, unproved properties of $21 million were acquired in 1994.
In Europe, Chevron's exploration efforts were concentrated in the U.K. sector of the North Sea and off the coast of Wales where the company has conducted research and a joint environmental appraisal of the coast in order to allay local concern about the environmental impacts of exploration off the Pembrokeshire coast.
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In Ireland, the company converted three blocks in the Celtic Sea from seismic options to full exploration licenses in February 1995. In addition, the company filed an application for blocks in the deep water area west of Ireland during the Porcupine Basin Licensing Round.
In Canada, exploration efforts in 1994 continued to be concentrated in the western part of the country near existing infrastructures that would allow any reserves to be brought on production quickly. A total of 26 exploratory wells were drilled in 1994, resulting in 2 oil and 6 gas discoveries.
In Australia, Chevron and its partners in West Australia Petroleum Pty., Ltd. (WAPET) participated in two successful exploration wells resulting in an oil discovery in the Crest 1 well and a gas discovery in the Chrysaor 1 well. Both discoveries are located off the western coast of Australia. The company completed its 3D seismic surveys over the northern part of the Barrow Island oil field and over the onshore Dongara gas/oil field in 1994. Permit WA-253-P, covering a 519,000 acre block north of Gorgon, was issued to WAPET on behalf of Chevron (50 percent) and a partner during 1994. In December 1994, Chevron signed an agreement to farm-in to WA-215-P in the area between Barrow and Thevenard Island. A farm-in well will be drilled late in the first half of 1995. In addition, the company and its partners in the North West Shelf Project continued their interpretative work on the East Dampier 3D seismic survey. As a result of this work, two exploration wells will be drilled in 1995. In March 1995, the company announced that one of these wells, Perseus-1, had discovered a natural gas and condensate deposit in the waters off northwest Australia, between the North Rankin and Goodwyn fields. The company withdrew from a permit it held with Shell in the Timor Sea in 1994.
In Papua New Guinea, Chevron and its partners' 1994 efforts were focused on the delineation of the Gobe Main oil field. In addition, two new exploratory wells commenced in 1994: the SE Mananda 2X well extended a previous oil discovery that may eventually be tied in with the Kutubu field's production and the TA-1X well was drilling at year-end on another prospect between the Gobe and Kutubu fields. In 1995, the company and its partners anticipate an active exploration program to follow up the prospect development work that was carried out in 1994. Exploratory efforts in 1995 are expected to focus on untested trends in the PPL-161 and PDL-2 licenses, where prospects with Kutubu-sized potential still remained to be tested. In the past, exploration efforts have largely concentrated on a single trend which included the Kutubu fields, the Gobe fields, and the SE Mananda discovery.
In China, Chevron completed seismic studies on Block 33/08 in the East China Sea in 1994. The company was awarded sole interest in this block in late 1993. Two exploratory wells are planned for 1995, the first of which commenced in February. This wildcat well, designated Wenzhou 15-1-1, reached its targeted depth and was plugged and abandoned. The second well is scheduled to commence in late March 1995. A production sharing agreement, granting sole interest in Block 62/23 in the South China Sea, was signed by the company and the Chinese National Offshore Oil Company in late February 1995. A natural gas exploratory well is planned for this block in 1996. Exploration obligations for the current phase of Contract area 16/08 were fulfilled in 1994. Studies are planned in 1995 to determine the optimum program for the three marginal discoveries in this Contract area.
In Bolivia, Chevron at year-end was negotiating the final terms of a farm out of the Caipipendi Exploration Block which, if successful, will lead to a partner funded seismic program over prospects in the southern half of the block.
In Trinidad and Tobago, the first of four exploratory wells, Rocky Palace #1, was drilled and tested in 1994. Iguana River #1, the second exploratory well, was drilled in 1994 but encountered mechanical problems and was unable to reach the reservoir objectives. Ste. Croix #1, the third well in the program, has been approved for drilling in mid-1995.
In Colombia, two prospects were identified in the Rio Blanco Block using seismic data acquired in 1994. The company plans to drill an exploratory well on one of these prospects in mid-1995. Drill site permitting and road construction is currently underway.
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PETROLEUM - OIL AND NATURAL GAS PRODUCTION
The following table summarizes the company's and its affiliates' 1994 net production of crude oil, natural gas liquids and natural gas.
----------------------------------------------------------------------------- 1994 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 127,770 137,110 -Gulf of Mexico 118,370 1,109,390 -Texas 69,270 431,530 -Louisiana 4,470 38,010 -Wyoming 9,690 151,480 -Colorado 14,290 - -New Mexico 8,560 104,540 -Other States 16,220 112,610 ------- --------- Total United States 368,640 2,084,670 ------- ---------
Africa 237,600 - Canada 51,510 246,820 United Kingdom (North Sea) 70,720 30,400 Indonesia 20,310 560 Australia 20,570 199,140 Papua New Guinea 29,770 - China 8,250 - Other International 9,570 4,840 ------- --------- Total International 448,300 481,760 ------- --------- Total Consolidated Companies 816,940 2,566,430 ------- --------- Equity in Affiliates 175,570 64,140 ------- --------- Total Including Affiliates 992,510 2,630,570 ======= =========
* Net production excludes royalties owned by others. -----------------------------------------------------------------------------
PRODUCTION LEVELS: In 1994, net crude oil and natural gas liquids production, including affiliates, increased for the second year in a row, rising four percent to 992,510 barrels per day from 950,150 barrels per day in 1993. Production increases were noted in a number of countries. In the U.K., production from Alba Field, which went on stream in January 1994, and additional production from Ninian Field, as a result of the company's acquisition of an additional 6 percent equity interest in December 1993, caused U.K. production to increase 43 percent to 70,720 barrels of oil per day. Oil production in Africa increased 9 percent to 237,600 barrels per day primarily due to increased Nigerian production as a result of full year production from three fields placed on stream in late 1993, four new fields placed on stream in 1994 and higher production quotas in 1994, and Angolan production, which increased in 1994 due to new wells in the Takula, Numbi and N'Sano fields. Indonesian production, including the company's share of its affiliate's production, rose 6 percent to
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173,250 barrels per day in 1994 as a result of the application of enhanced recovery methods in certain fields. In Kazakhstan, Chevron's net oil production doubled to 22,630 barrels per day in 1994 due to full year production and increased export quotas in the latter half of the year. These production increases were partially offset by production declines in the United States due to divestments of producing properties in late 1993, primarily Milne Point, and normal field declines.
Net production of natural gas, including affiliates, increased 4 percent to 2,630,570 thousand cubic feet per day. Increases were noted in Australia due to initial production from the Roller, Skate and Crest fields, in Canada as a result of reduced re-injection requirements and the shallow gas program, which is designed to rapidly develop and produce gas from low-depth reserves, in the U.S. due primarily to new wells in the Laredo area of Texas and one month's production from the Pakenham, Inc. acquisition, and in Kazakhstan due to full year production.
The natural gas industry is undergoing rapid and significant changes that have squeezed margins and caused markets to become more competitive. In the United States, natural gas producers have traditionally sold their production to pipeline companies, who in turn distribute the product to their customers. As a result of FERC Order 636, producers now can sell directly to customers and provide many of the services previously provided by the pipeline companies. Chevron has concentrated its natural gas marketing efforts on the longer term contract market. These customers, which include local distribution companies and industrials, require premium bearing services and marketing arrangements that Chevron can fulfill. The company's sales to these customers have risen significantly, while sales to pipeline companies have correspondingly declined. Chevron has recently completed a detailed evaluation of its existing natural gas marketing efforts and, as a result, will be dedicating additional resources to the effort of marketing gas to targeted end-users. The company has developed and implemented a process that it believes will significantly reduce the cycle time associated with identifying, piloting, and capitalizing on new natural gas marketing opportunities. This new process should allow the company to more readily move natural gas out of mature, lower margin markets into emerging, high-growth premium markets.
Data on the company's average sales price per unit of oil and gas produced, as well as the average production cost per unit for 1994, 1993, and 1992 are reported in Table III on pages FS-32 and 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 1994.
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PRODUCTIVE OIL AND GAS WELLS AT DECEMBER 31, 1994
PRODUCTIVE (1) PRODUCTIVE (1) OIL WELLS GAS WELLS ------------------ ------------------- GROSS (2) NET(2) GROSS (2) NET (2) --------- ------ --------- ------- United States 27,898 14,180 3,992 1,715 --------- ------ --------- ------- Canada 1,818 963 301 168 Africa 861 335 5 2 United Kingdom (North Sea) 207 35 - - Other International 937 349 37 15 --------- ------ --------- ------- Total International 3,823 1,682 343 185 --------- ------ --------- ------- Total Consolidated Companies 31,721 15,862 4,335 1,900
Equity in Affiliates 4,524 2,262 33 16 --------- ------ --------- ------- Total Including Affiliates 36,245 18,124 4,368 1,916 ========= ====== ========= ======= Multiple completion wells included above: 432 218 21 11
(1) Includes wells producing or capable of producing and injection wells temporarily functioning as producing wells. Wells that produce both oil and gas are classified as oil wells. (2) Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company's fractional interests in gross wells.
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DEVELOPMENT ACTIVITIES: The company's development expenditures, including affiliated companies but excluding proved property acquisitions, were $1,508 million in 1994 and $1,451 million in 1993.
The table below summarizes the company's net interest in productive and dry development wells completed in each of the past three years and the status of the company's development wells drilling at December 31, 1994. (A "development well" is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. "Wells drilling" include wells temporarily suspended.)
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DEVELOPMENT WELL ACTIVITY
NET WELLS COMPLETED (1) WELLS DRILLING -------------------------------------- AT 12/31/94 1994 1993 1992 ------------------- ----------- ---------- ----------- GROSS (2) NET (2) PROD. DRY PROD. DRY PROD. DRY --------- ------- ---- ---- ---- ---- ---- ---- United States 62 59 194 5 293 11 217 5 --------- ------- ---- ---- ---- ---- ---- ---- Africa 12 4 9 - 10 - 10 1 Other International 32 9 48 4 57 12 55 4 --------- ------- ---- ---- ---- ---- ---- ---- Total International 44 13 57 4 67 12 65 5 --------- ------- ---- ---- ---- ---- ---- ---- Total Consolidated Companies 106 72 251 9 360 23 282 10
Equity in Affiliates 41 20 98 - 93 - 159 5 --------- ------- ---- ---- ---- ---- ---- ---- Total Including Affiliates 147 92 349 9 453 23 441 15 ========= ======= ==== ==== ==== ==== ==== ====
(1) Indicates the number of wells completed during the year regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of oil or gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. (2) Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company's fractional interests in gross wells. -----------------------------------------------------------------------------
Significant 1994 development activities include the following:
UNITED STATES: Chevron's U.S. development expenditures were $416 million in 1994, a decrease of $59 million from the 1993 figure of $475 million. Expenditures for proved reserve acquisitions amounted to $95 million in 1994, primarily due to the company's acquisition of certain gas properties in West Texas from Wes-Tex Drilling Company, compared to $12 million in 1993. Additions to proved reserves during 1994 from extensions, discoveries and improved recovery, before revisions, were 57 million barrels of crude oil and natural gas liquids and 538 billion cubic feet of natural gas. Additions to proved reserves from acquisitions were approximately 1 million barrels of crude oil and natural gas liquids and 55 billion cubic feet of natural gas.
Chevron's development of its wholly owned San Joaquin Valley diatomite reserves in the Lost Hills Field in California continued with the drilling and completion of 37 new wells and the reworking of 42 older wells using reservoir fracturing techniques. A four year water injection project, initiated in 1992, to sustain reservoir pressure and further boost production continued into its third year with the drilling of 39 injection wells and the conversion of 7 producing wells to injection. When completed, the 520-acre project will have over 200 injectors with a total injection rate of 40,000 barrels of water per day. The combination of reservoir fracturing and water injection is expected to significantly increase both the production rate and the amount of oil ultimately recoverable from this resource.
Chevron owns approximately 25 percent of the Point Arguello project, offshore California, and operates two offshore platforms (Hermosa and Hidalgo), the onshore Gaviota oil and gas plant and the interconnecting pipelines. Chevron and its partners ceased double-hull tankering of oil from the project to the Los Angeles area on February 1, 1994 in compliance with the terms of the tankering permit granted by the California Coastal Commission. These terms required suspension of tankering if Chevron and its partners were unable to sign, by February 1, an agreement with a pipeline developer, who possessed the necessary discretionary permits needed for a new pipeline, that the developer could use for pipeline financing.
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Production from the project averaged 78,000 barrels of oil per day in 1994, somewhat below its full production capacity but at about the same level as under tankering. About a third of current production is delivered via pipeline to Los Angeles area refineries. However, due to a shortage of adequate transportation facilities to Los Angeles, the balance of production is shipped via pipeline to markets in the Midwest, resulting in increased transportation costs. In March 1994, the company announced that an agreement had been reached with a pipeline developer to build a 130-mile pipeline in Southern California that would carry Point Arguello oil production to Los Angeles. Chevron and certain other project partners will have a minority interest in the pipeline. The pipeline project is currently in the environmental review stage and is scheduled to be certified in October 1995. However, a property owner in the pipeline right of way is pushing for an alternate route, which may cause further delays. If the environmental review is certified in October 1995, the issuance of permits and the start of construction are expected in the first quarter of 1996. A workover and drilling program, designed to add proved reserves and abate the decline in production rate continued in 1994 with the drilling and completion of two new wells and one redrill during the year.
In 1994, Chevron completed an economic evaluation of the viability of developing the Green Canyon 205 Field located 2,600 feet below the ocean's surface in the Gulf of Mexico. Preliminary field development plans have been finalized; however, alternative development concepts will be considered through the first half of 1995, at which time a final selection will be made. Preliminary engineering work is expected to begin in early 1995. Initial production is planned for 1999 and is expected to exceed 50,000 barrels per day. Chevron has a 67 percent interest in this field.
The drilling phase at the company's Garden Banks 191 "A" platform in the Gulf of Mexico was completed in late 1994. Natural gas production from this block started in late 1993 and is currently producing at a daily rate of 200 million cubic feet of gas, exceeding original production estimates of 150 million cubic feet per day. Chevron is the operator and holds a 50 percent interest in this block.
In the Gulf of Mexico's Norphlet gas trend, which stretches some 80 miles from the Destin Dome area (offshore Florida) to the Mobile Block 861 area (offshore Mississippi), production from the Mobile Block 861 #8 well commenced in February 1994. Production from three additional wells drilled in 1994 is expected to start in 1996 with the completion of a processing facility currently being fabricated for the Mobile 861 Area. Production from three wells in the Mobile Block 916 Area offshore Alabama is expected to come on stream in April 1995 with a combined daily net rate of 50 million cubic feet of gas. Chevron's interest in various blocks in the Norphlet gas trend vary from 33 percent to 100 percent.
Nine of thirty-six prospects identified using the 3-D seismic survey of the Eugene Island 238 Field in the Gulf of Mexico have been drilled by the end of 1994. Seven wells were successful, resulting in four gas and three oil discoveries. A new production platform, added in 1994 to accommodate the oil discoveries, will increase production by 9,000 barrels per day. Three additional wells will be drilled and an additional satellite platform will be installed in 1995. By the end of 1995, daily total production for the field is forecasted to exceed 200 million cubic feet of gas and 15,000 barrels of oil. Chevron has a 100 percent interest in this field except for Block 229, where Chevron's interest is 70 percent.
Chevron continued to aggressively develop "tight gas" (gas which is produced from a tight, low-permeability formation) in the Laredo, Texas area. In 1994, twenty-five wells were drilled, adding proved reserves of 176 billion cubic feet of gas. Current net production averaged 165 million cubic feet of gas per day. The company acquired more than 12,000 new acres in 1994 for future development. Chevron's interest in the leases is 100 percent except for one lease in which the company's interest is 59 percent.
In 1994, the company purchased the stock of Pakenham, Inc., a subsidiary of Wes-Tex Drilling Company. Assets acquired in the purchase included 47 natural gas producing wells in West Texas, 52 billion cubic feet of net proved natural gas reserves and a gathering system that is currently used to transport natural gas to a pipeline owned by Valero Transmission Company. Warren Petroleum Company, Chevron's gas processing unit, is expanding its operations to include the Pakenham gas gathering and processing business. The company believes the field holds the potential to further increase the company's gas reserves and expects to add wells that will more than triple the current production of 25 million cubic feet per day to 90 million cubic feet per day by 1999.
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AFRICA: Developmental expenditures in Africa were $276 million in 1994, compared to $239 million in 1993. Expenditures for proved reserve acquisitions amounted to $145 million in 1994. Additions to proved reserves from extensions, discoveries and improved recovery, before revisions, were 103 million barrels of crude oil and natural gas liquids. Additions to proved reserves from acquisitions were approximately 76 million barrels of crude oil and natural gas liquids. Acquisition expenditures and proved reserves from acquisitions in 1994 were both primarily related to the company's activities in the Congo.
In Angola, where Chevron's equity interest is 39 percent, 15 development wells were added in Area A fields in 1994. Production from the greater Takula Area fields increased in 1994 due to ongoing development of the N'Sano and Numbi Southeast fields and from infill programs in existing reservoirs. A new production platform and associated pipelines were installed in N'Sano Field during 1994 and development drilling commenced at mid-year. A decline in production from the greater Malongo Area fields was reversed in 1994 through a combination of production from new exploration discoveries and continued infill activity. One offshore processing platform in the Malongo South Field was revamped and modernized in 1994. The company expects to maintain production from Area A in future years through the combination of infill drilling, workovers, facility modernization, waterflood and gas injection.
Areas B and C continued to be the major focus of 1994 development programs in Angola with the installation of two integrated drilling and production platforms in the Kokongo Field in Area B. The East Kokongo platform is designed as the hub for future phases of development for Areas B and C and includes a thirty-eight mile pipeline linking the platforms to onshore terminal facilities in Malongo. Drilling rigs were installed in the fourth quarter of 1994 which resulted in initial production being established in late November. By year-end, two wells had been completed and additional drilling is expected to continue into 1996. The Nemba Field in Area B is expected to operate as a satellite of East Kokongo. Contracts were awarded in 1994 for an early production system consisting of three subsea wells, a tanker for floating production service and related flowlines and pipelines. Production start-up is scheduled for the second half of 1995. Tenders were issued in 1994 for the construction of additional Area B facilities, consisting of two integrated platforms and associated pipelines, related to the development of Lomba Field and the southern portion of Nemba Field. Start-up is forecasted for 1997 at which time the early production system at Nemba will be de- commissioned and the three subsea wells tied-back to Nemba South for continued production. The Lomba installation will operate as a satellite of Nemba South. Contracts for the development of the Sanha and N'Dola fields in Area C were released in the fourth quarter of 1994 following resolution of partner financing issues. The development will consist of two integrated platforms and related pipelines and facilities which are currently being fabricated in South Africa. These fields will act as satellites of East Kokongo with start-up forecasted for early 1997.
In Nigeria, total production from the 26 CNL-operated fields averaged 369,200 barrels of oil per day, an increase of over 41,000 barrels of oil per day from 1993. This increase was the result of new field development programs, development drilling in existing fields, workover programs and increased commercial allowables. Four new fields, Abigborodo, Jokka, Kito and Benin River, were placed on production in 1994. Benin River production commenced in December 1994 from one well. Detailed engineering for the full development of Benin River will continue in 1995 with full production start-up planned for 1996. The platform upgrade program marked its second year in 1994. This program, intended to upgrade all existing platforms in order to extend the useful life and enhance the safety and environmental performance of these facilities, continued at Delta, Meren 1 and Okan fields. Engineering was completed for Utonana and is underway for Abiteye, Makaraba, Isan/West Isan, Malu and two satellite platforms at Okan. Work on the Escravos Gas Project, Phase I, continued in 1994 with the completion of sand-filling at the onshore site for the Liquefied Petroleum Gas (LPG) extraction/fractionation plant. In addition, 93 percent of the detailed design engineering work for Phase I of the project was completed in 1994. This first phase will utilize gas that is currently being flared in the Okan and Mefa fields. The project will include offshore gas compression facilities, an onshore 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 15,000 barrels per day of hydrocarbon liquids for export. Start- up of the project is now expected in mid-1997.
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In the Congo, Chevron and its partners have begun developing the Kitina Field. Development consists of a drilling jacket with some topside facilities, tied via a pipeline to other onshore processing and export facilities at Djeno Terminal. Production is forecasted to begin in mid-1997 with peak production of 50,000 barrels per day by 1999. In late 1994 the company and its partners successfully drilled an appraisal well in the 1992 Kitina South discovery. The development of the N'Kossa Field started in 1993. Two producing platforms connected to a floating barge containing processing facilities will allow crude oil and LPG to be loaded onto tankers for direct export. Production is forecasted to commence in mid-1996 at a rate of 80,000 barrels per day, reaching peak production of about 120,000 barrels per day in 1998.
In Zaire, one development well, one re-drill, and five workovers were completed in 1994. Early production from the Tshiala East exploration discovery was developed by installation of a satellite production platform and tie-back to existing processing facilities. Additional development planning studies are underway to evaluate further development of this field.
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Development expenditures in 1994 were $816 million compared to $737 million in 1993. Additions to proved reserves from extensions, discoveries and improved recoveries were 91 million barrels of crude oil and natural gas liquids and 708 billion cubic feet of natural gas.
In the United Kingdom the company has interests in over 50 blocks on the U.K. Continental Shelf which total approximately 1.7 million gross acres, including six producing fields in the North Sea where interests vary from 4.9 to 33.3 percent. At the Ninian Field in the North Sea, Chevron (24 percent interest) and its partners are paid a tariff for processing third-party oil and gas production using available processing capacity at the Ninian facilities. In 1994 third-party oil flowing through the Ninian Field's facilities increased with production from Columba and Dunbar Fields coming on stream. This follows production from Staffa Field which was brought on stream in 1992, Lyell Field (Chevron owns a 33.3 percent interest) in early 1993 and Strathspey Field at year-end 1993. Production from the first phase of a two-phase development plan for the North Sea's Alba Field, in which Chevron has a 33 percent interest, commenced in January 1994. Average daily gross oil production was 42,400 barrels, with a fourth quarter average of 62,900 barrels of oil per day. Plans for the second phase of Alba, which will develop the southern area of the reservoir, continued in 1994 with conceptual engineering studies to select a preferred development option. A decision is expected by late 1995 which should result in first production from the southern part of the field in 1996. The Britannia gas field development in the North Sea was approved by the United Kingdom Department of Trade and Industry at the end of 1994. Development will initially consist of a steel drilling, production and accommodation platform and a subsea well center, along with a gas offtake pipeline and onshore gas processing facilities. Condensate from the field will be transported ashore via the Forties pipeline system. Gas and gas liquids will be transported to and processed at the St. Fergus terminal in northeast Scotland. Peak production is expected to be approximately 740 million cubic feet of gas and 70,000 barrels of condensate per day. Initial production is expected to commence in late 1998. Agreements have been reached to sell gas to four purchasers. Chevron's share of production is just over 30 percent.
In Canada, the company continues to concentrate its development efforts in six core producing areas in Alberta and one in Manitoba where operating efficiencies and lower operating costs can be realized using existing infrastructure. In 1994, the company drilled 49 wells that were targeted at new reserves around existing fields along with 58 development wells. The company also continued its development of the late-1993 Simonette oil discovery with further delineation drilling and site construction activities in 1994.
Chevron has a 27 percent interest in the Hibernia Field, located approximately 200 miles offshore Newfoundland. In 1994, the Gravity Based Structure (GBS) was floated to a deep water construction site where final construction, including installation of the topside structures will be completed before mid- 1997, the date for its scheduled towing to the drilling site. Engineering cost and construction delays caused by the
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complexity of the GBS have resulted in higher than projected pre-production costs for the project. The company is working very closely with the Hibernia Management Development Company and with partners to keep the project on schedule and to control construction costs. Initial production has been delayed and is now forecasted for 1998. Hibernia investment is projected to be slightly over $210 million in 1995, an increase of $17 million over 1994 levels. The company's capitalized investment in this project was $570 million at year-end 1994.
In Indonesia, Chevron's interests in 13 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 and steaming began early in 1995. Area 8 is due to be on stream early in 1997. More than three billion additional barrels of oil are expected to be recovered from the Duri Field as a result of steamflooding. Total production at Duri averaged 300,000 barrels per day in 1994. A waterflood project involving 21 fields in Central Sumatra, including the Minas field, continued in 1994. Over the next 20 years, waterflood operations will be introduced or expanded at these fields.
First steam from the Darajat geothermal field, located 115 miles southeast of Jakarta, was delivered to Prusahaan Listrik Negara (PLN), Indonesia's state electricity agency, in late 1994. The Darajat I plant was commissioned in late 1994 with initial production targeted for PLN's nearby 55-megawatt power plant. Negotiations with the Indonesian government on developing Darajat II is expected to commence in 1995. This future expansion will allow production to increase to 130 megawatts by 1999.
In Kazakhstan, the company formed a 50/50 joint venture with Tengizmunaigaz, a subsidiary of Kazakhstanmunaigaz - the national oil company of the Republic of Kazakhstan - to develop the Tengiz and Korolev oil fields on the northeast coast of the Caspian Sea. This joint venture affiliate, Tengizchevroil (TCO), began operations in April 1993. TCO's total production capacity was 65,000 barrels per day for most of 1994. However, production in the early part of 1994 was limited to 35,000 barrels per day due to the amount of mercaptans, foul-smelling sulfur compounds, in the oil. The mercaptan problem was resolved at mid-year through the use of chemical scavengers and exports reached 65,000 barrels per day in the fourth quarter. Production capacity was increased to 95,000 barrels per day at year-end with the completion of a second processing plant. By the end of 1995, production capacity is scheduled to increase to 130,000 barrels per day and could reach 260,000 barrels per day by the late 1990's. However, the pace of further development beyond the 130,000 barrels per day is dependent on the availability of additional export capacity. Current production is restricted by the limited transportation facilities 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. Production levels have been and are continuing to be restricted by the monthly export quotas (currently 65,000 barrels per day) set by Russia under this agreement. The company has been in prolonged negotiations with the Caspian Pipeline Consortium, composed of the Republics of Russia and Kazakhstan and the Sultanate of Oman, to agree on terms for an export pipeline system that would enable the project to increase its production and sell its output directly to world markets. It is currently impossible to predict the eventual outcome of these negotiations or its impact on the joint venture.
In Australia, drilling commenced in October 1994 in the Goodwyn Field which is being developed as part of the North West Shelf Project in which Chevron holds a one-sixth interest. Production started in February 1995 with total initial production expected at around 10,000 barrels of condensate per day, rising to 80,000 barrels of condensate and 900 million cubic feet of natural gas per day at its peak in 1996. First production from the Wanaea and Cossack oil field development is expected late in 1995. Combined peak production from the two oilfields is forecasted at 115,000 barrels of oil per day and should occur in mid-1996. The liquids-rich gas from Wanaea will be combined with gas from the North Rankin and Goodwyn fields and processed at the onshore gas plant at Karratha, which is being modified to allow the export sale of LPG. In 1994, Chevron and its partners in West Australian Petroleum Pty., Ltd. (WAPET) continued to evaluate options for the commercialization of the Gorgon gas field. The North Gorgon 2 appraisal well was
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successful with combined tests from four sands of 175 million cubic feet of gas per day. Initial production from the Roller/Skate oilfield development commenced in May 1994, averaging 40,000 barrels per day. Associated gas from the Roller/Skate and Saladin fields is being piped to shore and either sold in the Perth market or stored in the Dongara field for future sales. The Crest discovery well was put on extended production tests in 1994 and was producing over 6,000 barrels of oil per day in December. Full field development will consist of drilling two more wells onshore Thevenard Island and tying them into existing facilities in mid-1995. Chevron's interest in WAPET projects varies from 26 to 50 percent.
In Papua New Guinea, Chevron (19 percent interest) and its partners are currently undertaking front-end engineering work on the Gobe fields in the southeastern portion of the PPL-161 license. This work is expected to lead to the submission of a Petroleum Development License application to the Papua New Guinea government in 1995. The Gobe fields consist of SE Gobe (discovered in 1991) and Gobe Main (discovered in 1993). A delineation program on Gobe Main was conducted in 1994 that defined the scope of the oil discovery and allowed planning for a joint development of the two fields to progress. If the government approves the development application in early 1996, initial oil production from the Gobe fields will commence in 1997. Chevron and its partners, as well as other competitor groups, have made significant gas discoveries in the Papuan Basin. Evaluations for the development of gas discoveries in the PPL-101 license (P'nyang and Juha gas fields) and the PDL-2 license (Hedinia field gas cap) are continuing. An active development drilling program designed to accelerate production and develop new reserves is scheduled for the Kutubu fields in early 1995. This program, which will contain both vertical and horizontal wells, is expected to allow production from the Kutubu fields to remain at a rate in excess of 100,000 barrels of oil per day throughout 1995.
In China, work continued in 1994 on projects to develop the HZ/32-2 and HZ/32-3 fields in the South China Sea. The plan includes two platforms, 12 additional wells and a tie-in to the existing production facility at the HZ/21-1 Field. Initial production, expected to peak at 45,000 barrels per day, is scheduled for mid-1995. Chevron holds a 16 percent interest in the venture.
In Kuwait, the company signed a three-and-a-half year agreement with the Kuwait Oil Company in August 1994 to provide technical services to help develop the Burgan Field, the world's second largest oil field.
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 1994 totaled 281,000 barrels per day (includes sales of 72,000 barrels per day to Chevron subsidiaries). Warren's business encompasses:
EXTRACTION - Warren operates 18 gas processing plants in Oklahoma, Texas, Louisiana and New Mexico with a total processing capacity of 3.5 billion cubic feet of gas per day and holds equity interests in an additional 25 plants. Natural gas from Chevron's and other producers' wells is piped to these plants, where the various liquids are extracted. Warren's share of gas liquids production from these plants was 66,000 barrels per day in 1994.
FRACTIONATION - Raw natural gas liquids are collected from Warren's processing plants, third-party purchases and Warren's gas liquids import facility on the Houston Ship Channel and transported via pipelines to Warren's fractionation plant at Mont Belvieu, Texas. The 220,000 barrel per day capacity facility fractionates raw NGL's into ethane, propane, normal butane, iso-butane and natural gasoline products. The Mont Belvieu complex includes a 45 million barrel capacity underground gas liquids storage facility.
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DISTRIBUTION - Gas liquids are distributed to refineries, petrochemical manufacturers and independent distributors via terminals supplied by pipelines, barges, tank cars and trucks. NGL imports and exports are handled at Warren's marine terminal, the Warrengas Terminal, located on the Houston Ship Channel and linked to the Mont Belvieu complex by dedicated pipelines. Petrochemical manufacturers are the main purchasers of ethane while propane is sold to petrochemical manufacturers as well as residential and commercial users. Refineries are the major customers for the remaining types of NGL's.
Warren's activities in international LPG business development included marketing LPG for other Chevron companies in Canada, West Africa, the U.K., and Australia. In 1994, the company also lent support to a Caltex study of LPG opportunities in China.
In 1994, Warren began construction of field gathering and compression facilities to support Chevron U.S.A. Production Company's Pakenham Field acquisition in West Texas. The company also converted an underutilized ethylene pipeline owned by Chevron Chemical Company to an isobutane pipeline in 1994, allowing Warren to utilize the excess fractionation capacity it had at its Mt. Belvieu, Texas plant to produce isobutane for transportation and sale in the Texas City, Texas market.
The company's total third-party natural gas liquids sales volumes over the last three years are reported in the following table.
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NATURAL GAS LIQUIDS SALES VOLUMES (Thousands of barrels per day)
1994 1993 1992 ---- ---- ---- United States - Warren 209 208 191 United States - Other 6 3 3 ---- ---- ---- Total United States 215 211 194 Canada 27 30 26 Other International 7 7 7 ---- ---- ---- Total Consolidated Companies 249 248 227 ==== ==== ====
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PETROLEUM - RESERVES AND CONTRACT OBLIGATIONS
Table IV on pages FS-33 and FS-34 of this Annual Report on Form 10-K sets forth the company's net proved oil and gas reserves, by geographic area, as of December 31, 1994, 1993, and 1992. During 1994, the company filed estimates of oil and gas reserves with the Department of Energy, Energy Information Agency. Those estimates were consistent with the reserve data reported on page FS-34 of this Annual Report on Form 10-K.
The company sells gas from its producing operations under a variety of contractual arrangements. Most contracts generally commit the company to sell quantities based on production from specified properties but certain gas sales contracts specify delivery of fixed and determinable quantities. In the United States, the quantities of natural gas the company is obligated to deliver in the future under existing contracts is not significant in relation to the quantities available from the production of the company's proved developed U.S. reserves in these areas. Outside the United States, the company replaced its single Western Australian domestic gas contract with six agreements, involving sales to five direct-end users. Those agreements commit the company to deliver approximately 258 billion cubic feet of natural gas through 2005. The company believes it can satisfy these contracts from quantities available from production of the company's proved developed Australian natural gas reserves.
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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, 1994 ------------------ REFINERY INPUTS OPERABLE -------------------- LOCATIONS NUMBER CAPACITY 1994 1993 1992 ---------------------------- ------ -------- ---- ---- ---- Pascagoula, Mississippi 1 295 324 283 294 Port Arthur, Texas (1) 1 185 158 177 189 Richmond, California 1 230 220 228 228 El Segundo, California 1 230 227 233 235 Philadelphia, Pennsylvania (1) - - 94 184 164 Other (2) 6 261 190 202 201 -- ----- ----- ----- ----- Total United States 10 1,201 1,213 1,307 1,311 -- ----- ----- ----- -----
Burnaby, B.C., Canada 1 50 47 43 41 Milford Haven, Wales United Kingdom 1 115 116 120 103 -- ----- ----- ----- ----- Total International 2 165 163 163 144 -- ----- ----- ----- ----- Total Consolidated Companies 12 1,366 1,376 1,470 1,455
Equity in Various Affiliate Locations 14 492 460 435 399 -- ----- ----- ----- ----- Total Including Affiliate 26 1,858 1,836 1,905 1,854 == ===== ===== ===== =====
(1) The company sold the Philadelphia, Pennsylvania refinery in August 1994 and the Port Arthur, Texas refinery in February 1995.
(2) Refineries in El Paso, Texas; Barber's Point, Hawaii; Salt Lake City, Utah; Perth Amboy, New Jersey; Willbridge, Oregon; and Richmond Beach, Washington. Capacity and input amounts for El Paso represent Chevron's share.
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At the end of 1994, Chevron had the largest U.S. refining capacity and ranked among the top ten in worldwide refining capacity including its share of affiliate's refining capacity. The company wholly owned and operated 10 refineries in the United States and one each in Canada and the United Kingdom. The company's Caltex Petroleum Corporation affiliate owns or has interests in 14 operating refineries in Japan (4), Korea, the Philippines, Australia, New Zealand, Bahrain, Singapore, Pakistan, Thailand, Kenya and South Africa.
Distillation operating capacity utilization in 1994 averaged 93 percent in the United States and 94 percent worldwide (including affiliate), compared with 94 percent in the United States and 95 percent worldwide in 1993. Chevron's capacity utilization of its domestic cracking and coking facilities, which are the primary facilities used to convert heavier products to gasoline and other light products, averaged 90 percent in 1994, up 2 percent from 1993.
In 1994, the company continued work on various expansion/upgrade projects, which are expected to cost over $1 billion when completed, at its Richmond and El Segundo, California, refineries. These projects are aimed at meeting regional clean air requirements and producing cleaner burning motor gasoline and diesel fuel as required by the California Air Resources Board and the Federal Clean Air Act Amendments of 1990. Projects to produce federal reformulated gasoline were completed at both refineries in 1994. In addition, a $300 million investment to upgrade key processing units to improve yields of high value light products is continuing at the Richmond refinery.
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For the last few years, the U.S. downstream industry has been going through massive recapitalization in order to meet the stringent new environmental requirements under the 1990 amendments to the Clean Air Act. As a result, in 1993, the company announced a major restructuring of the company's downstream operations which included the divestment of refineries in Philadelphia, Pennsylvania and Port Arthur, Texas. These refineries no longer fit in Chevron's long term plans to have a more strategically focused U.S. refining operation and the divestitures would reduce the capital expenditures that would have been required to meet the Clean Air Act amendments. The company sold its Philadelphia, Pennsylvania, refinery to Sun Company, Inc. in August 1994 and its Port Arthur, Texas, refinery to Clark Refining and Marketing, Inc. in February 1995.
Federal regulations required that reformulated gasoline (RFG) be sold in nine mandated areas in the United States beginning January 1, 1995. In addition, certain states and other areas voluntarily opted for the RFG requirement. Some of these areas have subsequently withdrawn, or are considering withdrawing, from the voluntary requirement. Also, in some areas complaints have surfaced that an RFG ingredient, MTBE, is causing illness among users. The company is unable to predict the outcome of these developments on its operations and the industry. Chevron is selling RFG in a total of nine mandated and voluntary areas.
In 1994, Caltex and its partners continued construction of a grassroots, 130,000 barrels per day refinery in Thailand. Mechanical completion of the refinery is expected by the first quarter of 1996, with full production commencing by mid-1996. The anticipated fall 1995 completion of the Residuum Fluid Catalytic Cracking (RFCC) unit at the Singapore export refinery will mark the completion of that refinery's expansion/upgrade project. The upgrade will increase refining capacity by 60,000 barrels per day, increase yield of light products by 33,000 barrels per day, and enable the refinery to produce oxygenated unleaded gasoline and low sulfur diesel fuel. At the Yocheon refinery in South Korea, construction of an RFCC unit is currently underway to position Caltex's Honam affiliate for Korea's shift to a higher-margin, lighter product mix.
PETROLEUM - REFINED PRODUCTS MARKETING
PRODUCT SALES: The company and its Caltex Petroleum Corporation affiliate markets petroleum products throughout much of the world. The principal trademarks for identifying these products are "Chevron," "Gulf" (principally in the United Kingdom) and "Caltex." U.S. sales volumes of refined products by the company during 1994 amounted to 1,314 thousand barrels per day, equivalent to approximately eight percent of total U.S. consumption. Worldwide sales volumes, including the company's share of affiliate's sales, averaged 2,248 thousand barrels per day in 1994, a decrease of about four percent over 1993. This decrease was largely due to the sale of the company's Philadelphia, Pennsylvania, refinery in August 1994, and refinery downtime in the first half of 1994.
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The following table shows the company's and its affiliate's 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)
1994 1993 1992 ----- ----- ----- UNITED STATES Gasolines 615 652 646 Gas Oils and Kerosene 277 325 347 Jet Fuel 260 247 252 Residual Fuel Oil 65 94 110 Other Petroleum Products* 97 105 115 ----- ----- ----- Total United States 1,314 1,423 1,470 ----- ----- -----
INTERNATIONAL United Kingdom 118 111 108 Canada 56 50 39 Other International 140 168 147 ----- ----- ----- Total International 314 329 294 ----- ----- ----- Total Consolidated Companies 1,628 1,752 1,764
Equity in Affiliate 620 594 565 ----- ----- ----- Total Including Affiliate 2,248 2,346 2,329 ===== ===== =====
* 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 1994 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 affiliate's sales in 1994 consists of the company's interest in Caltex Petroleum Corporation, which operates in 61 countries including Australia, the Philippines, New Zealand, South Africa and, through Caltex affiliates, in Japan and Korea.
RETAIL OUTLETS: In the United States, the company supplies, directly or through jobbers, approximately 8,600 motor vehicle, aircraft and marine retail outlets, including more than 2,000 company-owned or -leased motor vehicle service stations. The company's gasoline market area is concentrated in the Southern, Southwestern and Western states. Chevron estimates it is the fourth largest seller of gasoline in the United States and is among the top three marketers in 15 states.
Chevron is continuing its efforts to increase non-fuel related revenues through its existing customer and asset base. In 1994, the company revised its credit terms for Chevron credit card holders and introduced a "Gold" tier to its Travel Club. The company is also gauging consumer interest in having McDonald's restaurants on the premises of company-owned service stations, with a number of test sites in Texas and Louisiana now in operation. Revenues from Direct Mail Marketing, introduced in 1993, continued to grow in 1994.
The company continued to expand its "FastPay" system by approximately 700 stations in 1994, increasing the total service stations with the system to over 2,000 nationwide. This automated system allows credit card customers to pay at the pump with credit approvals processed in about five seconds using satellite data transmission.
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Internationally, the company's branded products are sold in 200 owned or leased stations in British Columbia, Canada and in 498 (233 owned or leased) stations in the United Kingdom.
PETROLEUM - TRANSPORTATION
TANKERS: Chevron's controlled seagoing fleet at December 31, 1994 is summarized in the following table. All controlled tankers were utilized in 1994.
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CONTROLLED TANKERS AT DECEMBER 31, 1994
U.S. FLAG FOREIGN FLAG ----------------------------- ------------------------------ CARGO CAPACITY CARGO CAPACITY NUMBER (millions of barrels) NUMBER (millions of barrels) ------ --------------------- ------ --------------------- Owned 1 - 23 22 Bareboat Charter 6 2 7 12 Time-Charter - - 8 4 ---- ---- ---- ---- Total 7 2 38 38 ==== ==== ==== ====
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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 1994, the company's U.S. flag fleet was engaged primarily in transporting crude oil from Alaska and California terminals to refineries on the West Coast and Hawaii, refined products between the Gulf Coast and East Coast, and refined products from California refineries to terminals on the West Coast, Alaska and Hawaii.
At year-end 1994, two of the company's controlled international flag vessels were being used for floating storage. The remaining international flag vessels were engaged primarily in transporting crude oil from the Middle East, Indonesia, Mexico, West Africa and the North Sea to ports in the United States, Europe, the United Kingdom, and Asia. Refined products also were transported worldwide.
In addition to the tanker fleet summarized in the table above, the company owns a one-sixth undivided interest in each of six liquefied natural gas (LNG) ships that are bareboat chartered to the Australian North West Shelf Project. One of the ships, the Northwest Stormpetrel, was delivered in late December 1994. These ships, along with two time-chartered LNG vessels, transport LNG from Australia primarily to various Japanese gas and electric utilities.
Chevron continued to upgrade and "right-size" its fleet of vessels in 1994 by taking delivery of two 1.1 million barrel capacity, double hull tankers and selling two 2.0 million, one 1.2 million and one .9 million barrel capacity tankers. The company also reduced its time-chartered fleet by a net one tanker and 1.0 million barrels of capacity during 1994.
Page 28 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.
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PIPELINES: Chevron owns and operates an extensive system of domestic crude oil, refined products and natural gas pipelines. The company also has direct or indirect interests in other domestic and international pipelines. The company's ownership interests in pipelines are summarized in the following table:
----------------------------------------------------------- PIPELINE MILEAGE AT DECEMBER 31, 1994
WHOLLY PARTIALLY OWNED OWNED (1) TOTAL ----- ----- ------ UNITED STATES: Crude oil (2) 5,150 620 5,770 Natural gas 413 32 445 Petroleum products 4,041 1,472 5,513 ----- ----- ------ Total United States 9,604 2,124 11,728 ----- ----- ------
INTERNATIONAL: Crude oil (2) - 785 785 Natural gas - 205 205 Petroleum products 12 109 121 ----- ----- ------ Total International 12 1,099 1,111 ----- ----- ------ Worldwide 9,616 3,223 12,839 ===== ===== ======
(1) Reflects equity interest in lines. (2) Includes gathering lines related to the transportation function. Excludes gathering lines related to the domestic production function.
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The company has signed an agreement with Pemex, the national oil company of Mexico, to build a $8.5 million, 19-mile pipeline from Chevron's El Paso, Texas, refinery to a Pemex storage terminal just south of Ciudad Juarez, Mexico. The pipeline will transport gasoline, diesel, and possibly kerosene and is expected to be in service in 1996, pending approval by various regulatory agencies.
CHEMICALS
The company's chemical operation manufactures and markets commodity chemical products for industrial use and chemical additives for fuels and lubricants. After a period of ample supplies caused by industry production overcapacity, the petrochemical industry rebounded dramatically in 1994. The excess industry capacity of the last four years was rapidly eliminated as improved industrialized economies, particularly in the United States, raised demand for consumer goods, many of which are made from or packaged with plastics derived from commodity chemicals marketed by the company. The elimination of the industry's excess capacity tightened supplies, which led to higher margins for the company's products. The profitability of chemical operations in 1994 was further enhanced by the restructuring and cost reduction programs the company had undertaken in recent years which positioned the company to benefit from improved industry conditions.
At year-end 1994, Chevron Chemical Company owned and operated 20 U.S. manufacturing facilities in 10 states, owned manufacturing facilities in Brazil and France, and owned a majority interest in a manufacturing facility in Japan. The principal domestic plants are located at Cedar Bayou, Orange and Port Arthur, Texas; St. James and Belle Chasse, Louisiana; Marietta, Ohio; Pascagoula, Mississippi; St. Helens, Oregon; and Richmond, California. The company's three major operating divisions are "Aromatics and Derivatives," which are marketed in 32 countries, "Olefins and Derivatives," which are marketed in 45 countries and "Oronite Additives," which are marketed in over 80 countries. The following table shows, by chemical division, 1994 revenues and the number of owned or majority owned chemical manufacturing facilities and combined operating capacities as of December 31, 1994.
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----------------------------------------------------------------------------- CHEMICAL OPERATIONS
MANUFACTURING FACILITIES 1994 ------------------- ANNUAL REVENUE (1) DIVISION U.S. INTERNATIONAL CAPACITY ($ Millions) --------------------- ---- ------------- ------------------- ------------ Olefins and Derivatives 11 - 7,050 million lbs. $1,186 Aromatics and Derivatives 5 - 5,210 million lbs. 944 Oronite Additives 2 3 160 million gal. 832 Other (including excise tax) 2 - (2) 119 -- - ------ Totals 20 3 $3,081 == = ======
(1) Excludes intercompany sales. (2) No meaningful common measurement. -----------------------------------------------------------------------------
The company plans to expand its linear low density polyethylene (LLDPE) manufacturing facility at Cedar Bayou, Texas in 1995 with project completion expected in the first quarter of 1996. The expansion will increase the plant's production capacity of LLDPE by 340 million pounds per year. The plant is also capable of manufacturing high density polyethylene. These materials are used to produce a variety of products for the packaging industry.
The company is continuing with its previously announced plans to withdraw from its agricultural and consumer product businesses. Plans to shut down the company's nitric acid and fertilizer plants in Richmond, California by the end of July 1995 were announced by the company in late January 1995. Chevron sold the majority of its nitrogen fertilizer business to Unocal in 1991 and has operated the facilities since that time under contract with Unocal. The company's remaining fertilizer plant in St. Helens, Oregon is currently for sale.
COAL AND OTHER MINERALS
COAL: The company's wholly-owned coal mining and marketing subsidiary, The Pittsburg and Midway Coal Mining Co. (P&M), owned and operated four surface and three underground mines at year-end 1994. Three of the mines are located in New Mexico and one each in Alabama, Wyoming, Kentucky and Colorado. All of the mines produce steam coal used primarily for electric power generation. P&M's strategy is to focus on regional markets in the United States, capitalizing on major utility growth markets in the southwest and southeast.
In 1994, the company restructured its interest in the Black Beauty Coal Company by adding a new partner who contributed both cash and additional coal properties to the partnership. This restructuring reduced the company's interest in the partnership from 50 percent to 33 percent. The Black Beauty Coal Company's principal operations are in the Indiana/Illinois coal market.
Sales of coal from P&M's wholly-owned mines and from its interest in the Black Beauty Coal Company were 20.4 million tons in 1994, a decrease of approximately 2 percent from 1993 sales of 20.8 million tons. However, 1994 production was at 94 percent of estimated capacity, a 2 percent increase over 1993. About 59 percent of 1994 sales came from two mines, the McKinley Mine in New Mexico and the Kemmerer Mine in Wyoming. The average selling price for coal from mines owned and operated by P&M was $24.39 per ton in 1994 compared to $24.62 per ton in 1993, contributing $414 million and $426 million to Chevron's consolidated sales and other operating revenues in 1994 and 1993, respectively. At year-end 1994, P&M controlled approximately 538 million tons of developed and undeveloped coal reserves.
Demand growth for coal in the United States remains largely dependent on the demand for electric power, which in turn depends on regional and national economic conditions and on competition from other fuel sources. In 1994, the electric utility industry consumed over 80 percent of all coal produced in the United States.
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Approximately 87 percent of P&M's coal sales are made to electric utilities. Of those sales, about 50 percent are under contracts longer than 10 years and 20 percent are under three to ten year contracts. As a result, P&M is not particularly exposed to short-term fluctuations in market prices. Generally, these contracts contain negotiated cost pass through and inflation adjustment provisions.
P&M controls a significant inventory of low-sulfur coal reserves, and the company expects demand for this type of coal to grow as utilities implement their strategies to comply with the air quality emission standards of Phase I of the Clean Air Act Amendments of 1990, which began on January 1, 1995. In addition, P&M anticipates that the Energy Policy Act of 1992 will increase competition in the electric power market and will provide new market opportunities for low-cost coal producers.
OTHER MINERALS: In 1994, the company completed its previously announced plan to exit the non-coal minerals business by selling its two remaining non-coal assets: the company's 50 percent interest in the Stillwater Mining Company, a Montana platinum-palladium mining operation, and the company's 52.5 percent holding in some zinc-lead prospects in Ireland.
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). Chevron Land's activities are predominantly handled by the company's offices in Newport Beach and San Francisco, California.
Real estate operations have concentrated on converting Chevron's surplus fee production properties in California into residential and commercial real estate. After making major infrastructure improvements, the properties are sold to third parties or jointly developed. At the end of 1994, Chevron Land managed approximately 35,000 acres of real estate in California. 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.
Chevron Land participates in residential developments through partnerships with home builders. During 1994, the company sold over 340 homes in California, more than doubling the 160 homes sold in 1993. The California economy is now beginning to show signs of renewed economic growth and the company is positioning itself to take advantage of the recovery by developing properties at a pace that meets market demand while preserving current real estate development entitlements.
In addition to its sales of residential real estate, the company also generated over $140 million in revenues from about 25 sales involving commercial, recreational or undeveloped real estate. The largest of these sales involved the sale of two undeveloped properties to Kaufman and Broad and the sale of two golf courses and related facilities to Club Corporation of America. These sales were made through the company's 80 percent interest in the Coto de Caza Partnership.
The company announced in March 1995 that it has established a marketing team for the possible sale of its real estate development assets. If a satisfactory price and other terms can be obtained, the company hopes to conclude the sale in 1995.
RESEARCH AND ENVIRONMENTAL PROTECTION
RESEARCH: The company's principal research laboratories are at Richmond and La Habra, California. The Richmond facility engages in research on new and improved refinery processes, develops petroleum and chemical products, and provides technical services for the company and its customers. The La Habra facility conducts research and provides technical support in geology, geophysics and other exploration science, as well as oil production methods such as hydraulics, assisted recovery programs and drilling, including offshore drilling. Employees in subsidiaries engaged primarily in research activities at year-end 1994 numbered approximately 2,000.
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Chevron's research and development expenses were $179 million, $206 million and $229 million for the years 1994, 1993 and 1992, respectively.
In 1994, the company developed a synthetic-based drilling mud for offshore use. Drilling mud is a liquid mixture that transports drill cuttings or small rock fragments out of the well. Conventional oil-based muds produce toxic oil- coated cuttings that are illegal to dispose of offshore. The new synthetic drilling mud meets all environmental requirements for discharge directly into the ocean, thereby eliminating the additional expense needed to transport and dispose of the cutting onshore.
The company signed an agreement in 1994 with Excel Paralubes, a joint venture of Conoco Inc. and Pennzoil Products Co., which licensed the company's Isodewaxing technology for a new lube oil manufacturing facility to be built at Conoco's Lake Charles refinery in Westlake, Louisiana. The Isodewaxing technology was also selected by Petro-Canada for a major expansion of their lube oil facilities in Mississauga, Ontario. Isodewaxing is a catalytic process that changes the characteristics of waxy molecules in crude feedstocks, resulting in a greater yield of high-quality base oils at a lower operating cost than conventional solvent based processing. The Petro-Canada facility is expected to come on stream in the fourth quarter 1996, followed by the Excel Paralube facility in 1997. The company also licensed, in 1994, its residuum desulfurization technology to Tohoku Oil Co. of Japan for its 100,000 barrel per day Sendai refinery and to Formosa Petrochemical Corporation for its 450,000 barrel per day refinery in Taiwan.
Licenses under the company's patents are generally made available to others in the petroleum and chemical industries. However, the company's business is not dependent upon licensing patents.
ENVIRONMENTAL PROTECTION: One of Chevron's 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 102 management practices was approved by senior management to strengthen the implementation of the policy. The program is called "Protecting People and the Environment" and is modeled after the Chemical Manufacturers Associations' program called "Responsible Care." It is also similar to the American Petroleum Institute's program called "Strategies for Today's Environmental Partnership." In 1994, the company published an environmental, health and safety performance report named "Measuring Progress - A Report on Chevron's Environmental Performance." This report describes the company's environmental performance since its last environmental report issued in 1990 and summarizes the company's policy and approach to environmental protection.
The company's oil and gas exploration activities, along with those of many other petroleum companies, have been hampered by drilling moratoria, imposed because of environmental concerns, in areas where the company has leasehold interests, particularly Alaska, offshore Florida and offshore California. Difficulties and delays in obtaining necessary permits, such as those experienced by Chevron and its partners in the Point Arguello Field offshore California, can delay or restrict oil and gas development projects. While events such as these can impact current and future earnings, either directly or through lost opportunities, the company does not believe they will have a material effect on the company's consolidated financial 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.
Since 1991, the company has spent about $1.2 billion in capital expenditures on air quality projects at its refining facilities, primarily in order to comply with federal and state clean air regulations and to provide consumers with fuels that reduce air pollution and air toxicity. The Clean Air Act Amendments of 1990 require that only reformulated gasoline (RFG) may be sold in the nine worst ozone areas in the United States beginning on January 1, 1995 while other areas may voluntarily opt into the RFG requirement. Chevron began selling RFG in nine areas in 1995. The California Air Resources Board requires a more stringent reformulated gasoline be sold statewide beginning in March 1996 and work is continuing at the company's Richmond and El Segundo, California, refineries to meet these requirements.
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The Federal Oil Pollution Act of 1990 (OPA) expanded federal authority to direct responses to oil spills to improve preparedness and response capabilities and to impose penalties on spillers for restoration costs and loss of use of the resources during restoration. Under OPA, the U.S. Coast Guard imposed new regulations on owners of vessels operating in U.S. waters after December 28, 1994 which required owners to meet strict guidelines for financial responsibility in the case of an oil spill. The company complied with the requirements by self-insurance and was issued a Certificate of Financial Responsibility for each of its vessels operating in U.S. waters prior to the December 28 deadline. OPA also requires the scheduled phase-out of single hull tankers for trading to U.S. ports, which has resulted in the utilization of more costly double hull tankers. Many of the coastal states have enacted or are preparing legislation in these same areas. In 1994, the company took delivery of two double hull tankers, the last of seven such vessels ordered in 1990. The company has been actively involved in the Marine Preservation Association, a non-profit organization that funds the Marine Spill Response Corporation (MSRC). MSRC owns the largest stockpile of oil spill response equipment in the nation and operates five strategically located U.S. coastal regional centers.
The company expects the enactment of additional federal and state regulations addressing the issue of waste management and disposal and effluent emission limitations for offshore oil and gas operations. While the costs of operating in an environmentally responsible manner and complying with existing and anticipated environmental legislation and regulations, including loss contingencies for prior operations, are expected to be significant, the company anticipates that these costs will not have a material impact on its consolidated financial position, its liquidity, or its competitive position in the industry.
In 1994, the company's U.S. capitalized environmental expenditures were $645 million, representing approximately 33 percent of the company's total consolidated U.S. capital and exploratory expenditures. The company's U.S. capitalized environmental expenditures were $620 million and $430 million in 1993 and 1992, respectively. These environmental expenditures include capital outlays to retrofit existing facilities, as well as those associated with new facilities. The expenditures are predominantly in the petroleum segment and relate mostly to air and water quality projects and activities at the company's refineries, oil and gas producing facilities and marketing facilities. For 1995, the company estimates that capital expenditures for environmental control facilities will be approximately $558 million. The actual expenditures for 1995 will depend on various conditions affecting the company's operations and may differ significantly from the company's forecast. The company is committed to protecting the environment wherever it operates, including strict compliance with all governmental regulations. The future annual capital costs of fulfilling this commitment are uncertain, but are expected to decrease after expenditures required to produce fuels that reduce air pollution and air toxicity reached their peak in 1994.
Under provisions of the Superfund law, Chevron has been designated as a potentially responsible party (PRP) for remediation of a portion of 238 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 1994, the company's environmental remediation reserve related to Superfund sites amounted to $61 million. Forecasted expenditures for the largest of these sites, located in California, amounts to approximately 20 percent of the reserve.
The company's 1994 environmental expenditures, remediation provisions and year-end environmental reserves are discussed on pages FS-2 through FS-4 of this Annual Report on Form 10-K. These pages also contain additional discussion of the company's liabilities and exposure under the Superfund law and additional discussion of the effects of the Clean Air Act Amendments of 1990.
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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-25 of this Annual Report on Form 10-K presents information on the company's gross and net properties, plant and equipment, and related additions and depreciation expenses, by geographic area and industry segment for 1994, 1993 and 1992.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
A. CITIES SERVICE TENDER OFFER CASES. The complaint by Cities Service Co. ("Cities Service") and two individual plaintiffs was originally filed in August 1982 in Oklahoma state court in Tulsa. Prior proceedings have effectively eliminated the two individual plaintiffs as parties. The defendants were initially Gulf Oil Corporation and GOC Acquisition Corporation. Subsequent filings have identified Chevron U.S.A. Inc. as the successor in interest to Gulf Oil Corporation. In the original complaint Cities Service pleaded for damages of not less than $2.7 billion together with legal interest for breach of contract and misrepresentation. The great bulk of the damages were related to claims on behalf of shareholders of Cities Service. All of the claims by Cities Service shareholders have been dismissed.
Plaintiff Cities Service filed its Second Amended Petition on April 25, 1994, adding Oxy U.S.A. as the successor to plaintiff Cities Service, adding Chevron U.S.A. Inc. as successor to Gulf Oil Corporation and adding Chevron Corporation as a new defendant. In addition to the existing claims for breach of contract and fraud, the amendments added the following causes of action: willful and malicious breach of contract, negligent misrepresentation, interference with prospective economic advantage in connection with the 1989 proposed Oxy-Cities Department of Energy ("DOE") settlement, and the claimed DOE liability as additional contract damages and as additional fraud damages. The amendment also added a claim for punitive damages based upon the alleged fraud, negligent misrepresentation, willful breach and interference claims and requested not less than $100 million on each of the several claims, together with pre-judgment interest and punitive damages. It also requested $12 million plus prejudgment interest for Cities' costs in defending against DOE proceedings since 1989, and an order entitling Cities Service to recover such "restitutionary obligation" amounts ultimately paid by Oxy U.S.A. to the DOE in excess of its proposed 1989 DOE settlement, and punitive damages.
Defendants answered, in part, the plaintiff's Second Amended Petition and moved to dismiss the claims for negligent misrepresentation, malicious breach of contract and interference with prospective economic advantage. In addition, defendant Chevron Corporation moved to dismiss the petition for lack of subject matter jurisdiction.
The motion to dismiss the new tort claim and certain other claims was denied and an answer to these claims was timely filed. Chevron Corporation's motion to dismiss for lack of personal jurisdiction was granted on September 7, 1994. Plaintiff's motion to dismiss defendants' counterclaim was also granted.
The Oklahoma Supreme Court has denied defendants' petition for certiorari on the trial court's certified interlocutory order concerning the defenses based upon certain conditions in the contract and alleged misstatements by plaintiff concerning its potential DOE liability.
Plaintiff's motion to bifurcate this case for two trials was granted by the trial court on January 23, 1995. The first trial will concern plaintiff's claims for alleged breach of contract, willful and malicious breach of contract, and negligent misrepresentation. The second trial will cover plaintiff's claims for alleged interference with prospective economic advantage in connection with the proposed 1989 DOE settlement, and the claimed DOE liability as additional damages under another claim of breach of contract.
Various discovery motions are pending. There is no discovery cut-off and no trial date has yet been set.
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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 contended that a partial termination of the Gulf Pension Plan had occurred and they were entitled to immediate vesting and distribution of plan benefits and to distribution of alleged excess plan assets, which allegedly had been unlawfully seized by Gulf or Chevron. All aspects of this case have now been resolved except for plaintiffs' claim to entitlement to $620 million in surplus funds in the Gulf Pension Plan. This issue was decided adversely to plaintiffs by the District Court on April 10, 1991.
On October 21, 1994, the Fifth Circuit Court of Appeals affirmed the District Court's determination that the plaintiffs were not entitled to surplus assets of the Gulf Pension Plan. On November 18, 1994, plaintiffs filed a petition for rehearing and a suggestion for rehearing en banc with the Fifth Circuit. Both of these were denied on December 1, 1994.
On March 1, 1995, the plaintiffs filed a Petition for a Writ of Certiorari with the United States Supreme Court.
C. PERTH AMBOY NEW SOURCE PERFORMANCE STANDARD PENALTY. The United States Environmental Protection Agency (EPA) claims that Chevron's Perth Amboy refinery violated various provisions of the Clean Air Act New Source Performance Standards ("NSPS") as a result of refinery modifications conducted in 1973 and 1983. The EPA issued a compliance order in November 1993 and in 1994 issued a formal determination that the NSPS applied to the refinery. This NSPS applicability determination has been appealed to the United States Circuit Court of Appeals for the Third Circuit. The EPA's penalty demand is $15.2 million. Chevron has made a counteroffer of $150,000.
D. PREMANUFACTURE NOTIFICATION FOR DETERGENT ADDITIVES. On September 30,1993, the EPA instituted an administrative proceeding, assessing civil penalties of about $17 million for alleged violations of the Toxic Substances Control Act (TSCA). The EPA contends that the company was required to file Premanufacture Notifications (PMNs) with regard to six chemical substances manufactured or imported since 1990. The company believes that no PMNs were required because the chemicals were within the scope of existing TSCA inventory listings. Nevertheless, the company reported the situation to the EPA when it was advised by a third party that the EPA may, without public notice, have revised its interpretation of TSCA regulations to require PMNs to be filed in such circumstances. Thereafter, under protest, the company suspended the production and importation of the chemicals and filed PMNs for them, continuing the suspension for the 90-day period contemplated by TSCA. The detergents in question are very similar to common detergents and intermediates used in their production, and the EPA does not appear to claim that failure to file a PMN resulted in any health or safety risk. The EPA permitted the company to dispose of its current stocks of the chemicals during the period that the company suspended their production and importation. The company has challenged the penalty assessment through an administrative appeal.
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 was federally mandated by January 1, 1995 under other provisions of the CAAA. All company activities had been conducted in accordance with authorization by the South Coast Air Quality Management District (SCAQMD), the primary enforcing agency of the rule that the EPA contends the company violated. EPA efforts to cause the company to cease all construction activities were stayed by the Ninth Circuit Court of Appeals, and SCAQMD has since issued the company a formal permit to construct. The EPA also sought civil penalties from the company for activities conducted prior to the issuance of the permit. The company has declined to accept the EPA's penalty demand of $1.635 million and is in the process of formulating a counteroffer. The matter has been referred to the Department of Justice for enforcement.
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F. PORT ARTHUR REFINERY ASSESSMENT. On August 3, 1994, the Environmental Protection Agency (EPA) issued a Notice of Violation and Civil Penalty Assessment against the Port Arthur Refinery, alleging exceedances of the refinery's water discharge permit on 24 occasions between 1989 and 1994. The EPA further alleged various violations of record- keeping and reporting requirements regarding monitoring of the wastewater effluent discharge pursuant to the permit. The EPA sought civil penalties in excess of $100,000. The refinery denied all allegations, many of which were subject to the "upset" defense available to dischargers during extraordinary weather events and temporary maintenance of wastewater treatment equipment. Without admitting liability, Chevron agreed to pay a fine of $124,000 and to implement various changes in recordkeeping procedures.
G. CHEVRON PIPELINE COMPANY PENALTY ASSESSMENT. By letter dated December 13, 1994, the EPA alleged that Chevron has violated the New Source Performance Standards applicable to petroleum liquid storage vessels ("Subpart Ka") and thereby has violated section 111(e) of the Clean Air Act. More particularly, the EPA contends that one petroleum liquid storage vessel at Chevron's pipeline facility in La Mirada, California, has continuously operated in violation of one provision of Subpart Ka since 1979. The EPA has proposed a civil penalty of $306,000 for Chevron's alleged violation of the Act. Chevron has contacted EPA and will commence settlement negotiations with the EPA in the near future.
Other previously reported legal proceedings have been settled or the issues resolved so as not to merit further reporting.
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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 1994 to a vote of security holders through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT AT MARCH 1, 1995
MAJOR AREA OF NAME AND AGE EXECUTIVE OFFICE HELD RESPONSIBILITY ------------------- -------------------------------- ---------------------- K.T. Derr 58 Chairman of the Board since 1989 Chief Executive Director since 1981 Officer Executive Committee Member since 1986
J.D. Bonney 64 Vice-Chairman of the Board Worldwide Exploration since 1987 and Production Director and Executive Activities, Coal, Committee Member since 1986 Administrative Services, Aircraft Services
J.N. Sullivan 57 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
R.E. Galvin 63 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.J. O'Reilly 48 Vice-President since 1991 U.S. Refining, President of Chevron U.S.A. Marketing and Products Company since 1994 Supply Executive Committee Member since 1994
M.R. Klitten 50 Vice-President and Chief Finance Financial Officer since 1989 Executive Committee Member since 1989
R.H. Matzke 58 Vice-President since 1990 Overseas Exploration President of Chevron Overseas and Production Petroleum Inc. since 1989 Executive Committee Member since 1993
J.E. Peppercorn 57 Vice-President since 1990 Chemicals President of Chevron Chemical Company since 1989 Executive Committee Member since 1993
H.D. Hinman 54 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, O'Reilly, Matzke and Peppercorn are rotating members of the Executive Committee, with two serving at any one time.
H.D. Hinman - Partner, Law Firm of Pillsbury Madison & Sutro - 1973 - Vice-President and General Counsel, Chevron Corporation - 1993
M.R. Klitten - President, Chevron Information Technology Company - 1987 - Vice-President and Chief Financial Officer, Chevron Corporation - 1989
R.H. Matzke - President, Chevron Canada Resources Limited - 1986 - President, Chevron Overseas Petroleum Inc. - 1989 - Vice-President, Chevron Corporation and President, Chevron Overseas Petroleum Inc. - 1990
D.J. O'Reilly - General Manager of El Segundo Refinery, Chevron U.S.A. Inc. - 1986 - Senior Vice President, Chevron Chemical Company - 1989 - Vice President for Strategic Planning and Quality, Chevron Corporation - 1991 - Vice President, Chevron Corporation and President, Chevron U.S.A. Products Company - 1994
J.E. Peppercorn - Senior Vice-President, Chevron Chemical Company - 1986 - President, Chevron Chemical Company - 1989 - Vice-President, Chevron Corporation and President, Chevron Chemical Company - 1990
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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 1990 through 1994 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 39 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 39 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 pages 2 through 4 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 24, 1995, is incorporated herein by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 32 and 33 of this Annual Report on Form 10-K for information about executive officers of the company.
Item 405 of Regulation S-K calls for disclosure of any known late filing or failure by an insider to file a report required by Section 16 of the Exchange Act. This disclosure is contained on page 21 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 24, 1995 and is incorporated herein by reference in this Annual report on Form 10-K.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
The information on pages 11 through 13 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 24, 1995, is incorporated herein by reference in this Annual Report on Form 10-K.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information on page 5 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 24, 1995, 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, 1994 FS-14
Consolidated Balance Sheet at December 31, 1994 and 1993 FS-15
Consolidated Statement of Cash Flows for the three years ended December 31, 1994 FS-16
Consolidated Statement of Stockholders' Equity for the three years ended December 31, 1994 FS-17
Notes to Consolidated Financial Statements FS-18 to FS-29
(2) FINANCIAL STATEMENT SCHEDULES:
Caltex Group of Companies Combined Financial Statements and Schedules C-1 to C-20
The Combined Financial Statements and Schedules of the Caltex Group of Companies are filed as part of this report. All other schedules are omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.
(3) EXHIBITS:
The Exhibit Index on pages 37 and 38 of this Annual Report on Form 10-K lists the exhibits that are filed as part of this report.
(b) REPORTS ON FORM 8-K:
A Current Report on Form 8-K, dated January 24, 1995, was filed by the company on January 24, 1995. This report announced unaudited preliminary earnings for the quarter and the twelve months ended December 31, 1994.
A Current Report on Form 8-K, dated February 27, 1995, was filed by the company on February 28, 1995. This report announced the sale of the Port Arthur, Texas, fuels refinery to Clark Refining and Marketing, Inc. and a $98 million increase to 1994 preliminary earnings as a result of the reversal of a previously established provision for the closure of the refinery.
A Current Report on Form 8-K, dated March 10, 1995, was filed by the company on March 10, 1995. This report contained the Company's 1994 Financial Statements (audited) and Management's Discussion and Analysis of Financial Condition and Results of Operations.
A Current Report on Form 8-K, dated March 10, 1995, was filed by the company on March 10, 1995. This report contained Summarized Financial Data for the three years ended December 31, 1994 for the company's Chevron Transport Corporation subsidiary.
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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 29th day of March 1995.
Chevron Corporation
By KENNETH T. DERR* ------------------------------------ Kenneth T. Derr, Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 29th day of March 1995.
PRINCIPAL EXECUTIVE OFFICERS DIRECTORS (AND DIRECTORS)
KENNETH T. DERR* SAMUEL H. ARMACOST* ------------------------------------- -------------------------------------- Kenneth T. Derr, Samuel H. Armacost Chairman of the Board
J. DENNIS BONNEY* SAM GINN* ------------------------------------- -------------------------------------- J. Dennis Bonney, Sam Ginn Vice-Chairman of the Board
JAMES N. SULLIVAN* CARLA A. HILLS* ------------------------------------- -------------------------------------- James N. Sullivan, Carla A. Hills Vice-Chairman of the Board
CHARLES M. PIGOTT* -------------------------------------- PRINCIPAL FINANCIAL OFFICER Charles M. Pigott
MARTIN R. KLITTEN* CONDOLEEZZA RICE* ------------------------------------- -------------------------------------- Martin R. Klitten, Condoleezza Rice Vice-President and Chief Financial Officer
S. BRUCE SMART, JR.* -------------------------------------- S. Bruce Smart, Jr. PRINCIPAL ACCOUNTING OFFICER
DONALD G. HENDERSON* JOHN A. YOUNG* ------------------------------------- -------------------------------------- Donald G. Henderson, John A. Young Vice-President and Comptroller
*By: /s/ MALCOLM J. McAULEY GEORGE H. WEYERHAEUSER* -------------------------------- -------------------------------------- Malcolm J. McAuley, George H. Weyerhaeuser Attorney-in-Fact
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EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION ------- -------------------------------------------------------------------- 3.1 Restated Certificate of Incorporation of Chevron Corporation, dated August 2, 1994, filed as Exhibit 3.1 to Chevron Corporation's Quarterly Report on Form 10-Q for the quarter and six month period ended June 30, 1994, and incorporated herein by reference.
3.2 By-Laws of Chevron Corporation, as amended July 27, 1994, including provisions giving attorneys-in-fact authority to sign on behalf of officers of the corporation, filed as Exhibit 3.2 to Chevron Corporation's Quarterly Report on Form 10-Q for the quarter and six month period ended June 30, 1994, and incorporated herein by reference.
4.1 Rights Agreement dated as of November 22, 1988 between Chevron Corporation and Manufacturers Hanover Trust Company of California, as Rights Agent, filed as Exhibit 4.0 to Chevron Corporation's Current Report on Form 8-K dated November 22, 1988, and incorporated herein by reference.
4.2 Amendment No. 1 dated as of December 7, 1989 to Rights Agreement dated as of November 22, 1988 between Chevron Corporation and Manufacturers Hanover Trust Company of California, as Rights Agent, filed as Exhibit 4.0 to Chevron Corporation's Current Report on Form 8-K dated December 7, 1989, and incorporated herein by reference.
Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the corporation and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.
10.1 Management Incentive Plan of Chevron Corporation, as amended and restated effective January 1, 1990, filed as Exhibit 10.1 to Chevron Corporation's Annual Report on Form 10-K for 1990, and incorporated herein by reference.
10.2 Management Contingent Incentive Plan of Chevron Corporation, as amended May 2, 1989, filed as Exhibit 10.2 to Chevron Corporation's Annual Report on Form 10-K for 1989, and incorporated herein by reference.
10.3 Chevron Corporation Excess Benefit Plan, amended and restated as of July 1, 1990, filed as Exhibit 10.3 to Chevron Corporation's Annual Report on Form 10-K for 1990, and incorporated herein by reference.
10.4 Supplemental Pension Plan of Gulf Oil Corporation, amended as of June 30, 1986, filed as Exhibit 10.4 to Chevron Corporation's Annual Report on Form 10-K for 1986 and incorporated herein by reference.
10.5 Chevron Restricted Stock Plan for Non-Employee Directors, as amended and restated effective January 29, 1992, filed as Appendix A to Chevron Corporation's Notice of Annual Meeting of Stockholders and Proxy Statement dated March 16, 1992, and incorporated herein by reference.
10.6 Chevron Corporation Long-Term Incentive Plan, filed as Appendix A to Chevron Corporation's Notice of Annual Meeting of Stockholders and Proxy Statement dated March 19, 1990, and incorporated herein by reference.
12.1 Computation of Ratio of Earnings to Fixed Charges (page EX-1).
21.1 Subsidiaries of Chevron Corporation (page EX-2).
23.1 Consent of Price Waterhouse LLP (page EX-3).
23.2 Consent of KPMG Peat Marwick LLP (page EX-4).
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EXHIBIT INDEX (continued)
EXHIBIT NO. DESCRIPTION ------- -------------------------------------------------------------------- 24.1 Powers of Attorney for directors and certain officers of Chevron to Corporation, authorizing the signing of the Annual Report on 24.13 Form 10-K on their behalf.
99.1 Definitions of Selected Financial Terms (page EX-5).
Copies of above exhibits not contained herein are available, at a fee of $2 per document, to any security holder upon written request to the Secretary's Department, Chevron Corporation, 225 Bush Street, San Francisco, California 94104.
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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 1994 1993 1992 ------------------------------------------------------------------------------- Sales and Other Operating Revenues $35,130 $36,191 $38,212 Income Before Cumulative Effect of Changes in Accounting Principles $ 1,693 $ 1,265 $ 2,210 Cumulative Effect of Changes in Accounting Principles - - $ (641) Net Income $ 1,693 $ 1,265 $ 1,569 Special Credits (Charges) Included in Income* $ 22 $ (883) $ 651 Per Share: Income Before Cumulative Effect of Changes in Accounting Principles $ 2.60 $ 1.94 $ 3.26 Net Income $ 2.60 $ 1.94 $ 2.31 Dividends $ 1.85 $ 1.75 $ 1.65 Return On: Average Capital Employed 8.7% 6.8% 8.5% Average Stockholders' Equity 11.8% 9.1% 11.0% =============================================================================== * BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES.
Chevron's net income for 1994 was $1.693 billion, up 34 percent and 8 percent from 1993 and 1992, respectively. However, special items in all years, and the cumulative effect of adopting two new accounting standards in 1992, affected the comparability of the company's reported results. Special items, after related tax effects, increased earnings in 1994 by $22 million, decreased earnings in 1993 by $883 million and increased earnings in 1992 by $651 million. Also, the cumulative effect of adopting two new accounting standards reduced 1992 earnings $641 million. Excluding the effects of special items in all years and the 1992 accounting changes, 1994 earnings of $1.671 billion declined 22 percent from very strong operating earnings of $2.148 billion in 1993 and increased 7 percent from $1.559 billion in 1992.
OPERATING ENVIRONMENT AND OUTLOOK. Worldwide petroleum industry conditions were weak throughout 1994. Crude oil prices were at a five-year low at the beginning of the year. Although prices recovered somewhat during the year, supplies remained plentiful. The company's U.S. realizations were, on average, 72 cents per barrel less than in the prior year, and its international realizations declined $1.23 per barrel. Average crude oil prices have declined for four consecutive years.
U.S. natural gas prices, after increasing the past two years, began falling in 1994 and averaged 22 cents per thousand cubic feet less than in 1993, as ample supplies and mild weather held down prices. The company's international natural gas prices fell by about the same amount.
Sales margins on refined products were depressed much of the year. For example, in the United States, product prices averaged about $1 per barrel less than in the previous year as highly competitive markets, particularly in the East, held down prices. These market conditions tended to lengthen the time lag for product prices to reflect the gradually increasing crude oil costs during the year.
On the other hand, the chemicals industry experienced a dramatic turnaround from the excess capacity and weak demand of the past four years. Strengthening industrialized economies, particularly in the United States, resulted in strong demand and higher prices - and Chevron's chemicals earnings rebounded substantially.
All these industry conditions have continued into 1995. The company's posted price for West Texas Intermediate (WTI), a benchmark crude oil, was $16.75 per barrel at year-end 1994 and $17.50 at February 28, 1995. The Henry Hub natural gas spot price, an industry marker, was $1.61 per thousand cubic feet at year-end 1994 and $1.55 at February 28, 1995. U.S. refined products prices in January 1995 were about flat with December. Planned major maintenance shutdowns at two of the company's core refineries resulted in lower refinery utilization rates, lower sales volumes and increased product purchases in the early part of 1995. Chemicals operations remained strong.
Chevron began selling federally mandated reformulated gasoline January 1, 1995 in nine areas in the United States, accounting for about 20 percent of its January gasoline sales volumes. The increased cost of manufacturing reformulated gasoline has not yet been fully reflected in sales prices.
The company embarked on an aggressive program several years ago to increase its competitiveness and achieve superior returns for its stockholders. Businesses were restructured, marginal and non-core assets were divested and the company's cost structure was significantly reduced. At
FS-1
the same time, the company has selectively pursued growth opportunities in its areas of strength.
The company continues to review and analyze its operations and may incur future charges related to the restructuring of its businesses and disposition of marginal or non-strategic assets. In particular, the company is currently reviewing its oil and gas operations in western Canada and options to maximize the value of certain real estate operations located in California.
UNITED STATES REFINING AND MARKETING DEVELOPMENTS. In connection with the previously announced restructuring of its U.S. downstream operations, Chevron sold its Philadelphia refinery in August 1994 and its Port Arthur, Texas, refinery in February 1995. The two refineries had a combined capacity of about 350,000 barrels per day or about 25 percent of the company's total U.S. refining capacity prior to the sales. The Philadelphia refinery had been operated as a merchant refinery, with its 175,000 barrels per day output sold to independent petroleum marketers. Products for the company's marketing system that were previously supplied by the Port Arthur refinery will be obtained from other sources.
The restructuring reflected the company's strategy to focus its resources in the West, Southwest and those parts of the South where the company's marketing business is strongest. The smaller refinery organization is expected to be more efficient, with improved cash flow and return on capital employed. The disposition of the two refineries has also eliminated large capital investments that would have otherwise been required.
In connection with the Port Arthur refinery sale, the company retained certain environmental cleanup obligations. The company has accrued for presently anticipated costs of $282 million, most of which will be expended over approximately the next ten years. It is possible additional provisions may be necessary in the future. The expenditures will be funded by future cash flows from operations, with no material effect anticipated on the company's liquidity.
INTERNATIONAL EXPLORATION AND PRODUCTION DEVELOPMENTS. Liquids production from 50 percent owned Tengizchevroil (TCO), a joint venture with the Republic of Kazakhstan, averaged about 46,000 barrels per day in 1994, up from 30,000 barrels per day in 1993. At year-end 1994 TCO was producing about 65,000 barrels per day. With the completion of a second processing plant in December 1994, production capacity increased to 95,000 barrels per day and is scheduled to increase to 130,000 barrels per day by the end of 1995. Beyond this, the pace of further field development is dependent on the availability of additional export capability. Production levels are dependent on monthly export quotas set by Russia, under a transportation/exchange agreement, and are currently set at 65,000 barrels per day. Chevron has been in prolonged negotiations with the Caspian Pipeline Consortium, composed of the Republics of Russia and Kazakhstan and the Sultanate of Oman, to agree on terms for an export pipeline system that would enable the project to sell its output directly to world markets.
Although the company's operations in Nigeria and the Angolan exclave of Cabinda have been generally unaffected by the political uncertainty and civil unrest that continues to exist in those countries, the company continues to closely monitor developments. Chevron has significant oil producing properties in both countries and has major development projects underway. In 1994, the company's net share of production in Nigeria averaged about 130,000 barrels per day, and in Angola about 100,000 barrels per day.
Chevron's partner in Nigeria, the government-owned Nigerian National Petroleum Corporation (NNPC) has fallen behind in paying its cash calls to Chevron, as well as to other oil companies operating in Nigeria. However, NNPC continues to make payments and the company believes all amounts owed it will ultimately be paid.
The Nigerian government effectively devalued its currency, the naira, in January 1995 by changing from a fixed exchange rate to a floating, free market rate. This devaluation did not have a significant effect on the financial position of the company's Nigerian subsidiary and is not expected to have a significant effect on its ongoing operations.
ENVIRONMENTAL MATTERS. Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity, and govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with myriad laws and regulations pertaining to its operations and products are embedded in the normal costs of conducting its business.
FS-2
Using definitions and guidelines established by the American Petroleum Institute, Chevron estimates its worldwide environmental spending in 1994 was about $1.5 billion for its consolidated companies. Included in these expenditures were $683 million of environmental capital expenditures, and $638 million of costs associated with the control and abatement of hazardous substances and pollutants from ongoing operations. The total amount also includes spending charged against reserves established for future environmental cleanup programs (but not non-cash provisions recorded during the year).
In addition to the costs for environmental protection associated with its ongoing operations and products, the company (as well as other companies engaged in the petroleum or chemicals industries) incurs 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 the company's own policies in this area. Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition, an obligation may arise when operations are closed or sold. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable under standards existing at the time, but now require investigatory and/or remedial work to meet current standards.
During 1994, the company recorded $505 million of before-tax provisions to provide for environmental remediation efforts, including Superfund sites. Actual expenditures charged against these provisions and other previously established reserves amounted to $182 million in 1994. At year-end 1994, the company's environmental remediation reserve was $1.219 billion, including $61 million related to Superfund sites.
Under provisions of the Superfund law, the Environmental Protection Agency (EPA) has designated Chevron a potentially responsible party (PRP), or has otherwise involved it, in the remediation of 238 hazardous waste sites. At year-end 1994, the company's cumulative share of costs and settlements for approximately 168 of these sites, for which payments or provisions have been made in 1994 and prior years, was about $96 million, including a provision of $16 million made during 1994. No single site is expected to result in a material liability for the company at this time. For the remaining sites, investigations are not yet at a stage where the company is able to quantify a probable liability or determine a range of reasonably possible exposure. The Superfund law provides for joint and several liability. Any future actions by the EPA and other regulatory agencies to require Chevron to assume other responsible parties' costs at designated hazardous waste sites are not expected to have a material effect on the company's consolidated financial position or liquidity.
Generally, provisions are recorded for work at identified sites where an assessment or cleanup plan has been developed and for which costs can reasonably be estimated. In 1994, the company recorded environmental remediation provisions aggregating $223 million for its U.S. marketing sites where no specific contamination had yet been identified, using estimates based on its history of required remediation at other similar sites.
It is likely the company will continue to incur additional charges for environmental remediation relating to past operations. These future costs are indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties and the extent to which such costs are recoverable from third parties. While the amounts of future costs may be material to the company's results of operations in the period in which they are recognized, the company does not expect these costs to have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had or will have any significant impact on the company's competitive position relative to other domestic or international petroleum or chemicals concerns. Although environmental compliance costs are substantial, the company has no reason to believe they vary significantly from similar costs incurred by other companies engaged in similar businesses in similar areas. The company believes that such costs ultimately are reflected in the petroleum and chemicals industries' prices for products and services.
The petroleum industry is incurring major capital expenditures to meet clean-air regulations, such as the 1990 amendments to the Clean Air Act in the United States. For companies operating in California, where Chevron has a significant presence, the California Air Resources Board has imposed even stricter requirements. The company's worldwide capital expenditures related to air quality are believed to have peaked at $495 million in 1994. For 1995, total worldwide environ-
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mental capital expenditures are estimated at $622 million, of which $438 million are expected to be spent on air quality related measures. This is in addition to the ongoing costs of complying with other environmental regulations and the costs to remediate previously contaminated sites.
In addition to the reserves for environmental remediation discussed above, the company maintains reserves for dismantlement, abandonment and restoration of its worldwide oil and gas and coal properties at the end of their productive lives. Most such costs are environmentally related. Provisions are recognized on a unit-of-production basis as the properties are produced. The amount of these reserves at year-end 1994 was $1.520 billion and is included in accumulated depreciation, depletion and amortization in the company's consolidated balance sheet.
For the company's other ongoing operating assets, such as refineries, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise abandon the facility has been made.
OTHER CONTINGENCIES. At year-end 1994 the company had $257 million of suspended exploratory wells included in properties, plant and equipment. The wells are suspended pending the drilling of additional wells to determine if commercially producible quantities of oil and gas are present. These well costs will be capitalized or expensed depending on the results of this future drilling activity.
The company is the subject of various lawsuits and claims and other contingent liabilities. These are discussed in the notes to the accompanying consolidated financial statements. The company believes that the resolution of these matters will not materially affect its financial position or liquidity.
The company utilizes various derivative instruments to manage its exposure to price risk stemming from its integrated petroleum activities. Some of the instruments may be settled by delivery of the underlying commodity, whereas others can only be settled by cash. All these instruments are commonly used in the global trade of petroleum products and are relatively straightforward, involve little complexity and are substantially of a short-term duration. Most of the activity in these instruments is intended to hedge a physical transaction, hence gains and losses arising from these instruments offset, and are recognized concurrently with, gains and losses from the underlying commodities.
NEW ACCOUNTING STANDARDS. In the 1994 first quarter, the company adopted two new accounting standards, Statement of Financial Accounting Standards (SFAS) No. 112, "Employers Accounting for Postemployment Benefits" and SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." The adoption of these standards did not have a material effect on the company's consolidated financial statements and had no effect on its liquidity. The 1994 consolidated financial statements also include the disclosures required by SFAS 119, "Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments," dealing with instruments that can only be settled in cash.
SPECIAL ITEMS. Net income is affected by transactions that are unrelated to, or are not representative of, the company's ongoing operations for the periods presented. These transactions, defined by management and designated "special items," can obscure the underlying results of operations for a year as well as affect comparability between years. The table below summarizes the gains (losses), on an after-tax basis, from special items included in the company's reported net income.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Prior-Year Tax Adjustments $ 344 $(130) $ 72 Asset Dispositions 48 122 757 Asset Write-Offs and Revaluations - (71) (133) Environmental Remediation Provisions (304) (90) (44) Restructurings and Reorganizations (45) (554) (40) LIFO Inventory Losses (10) (46) (26) Other (11) (114) 65 ------------------------------------------------------------------------------ Total Special Items $ 22 $(883) $651 ==============================================================================
PRIOR-YEAR TAX ADJUSTMENTS are generally the result of the settlement of audit issues with taxing authorities or the re-evaluation by the company of its tax liabilities as a result of new developments. Also, adjustments are required for the effect on deferred income taxes of changes in statutory tax rates. In 1994, prior-year tax adjustments increased earnings $344 million, including the
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net reversal of $301 million of tax and related interest reserves resulting from the company's global settlement with the Internal Revenue Service for issues relating to the years 1979 through 1987. Tax adjustments decreased earnings $130 million in 1993, which included the effect of a one percent increase in the U.S. corporate income tax rate, but increased earnings by $72 million in 1992.
ASSET DISPOSITIONS in 1994 consisted of the sale of the company's lead and zinc prospect in Ireland, generating an after-tax profit of $48 million. This sale completed the company's withdrawal from non-coal minerals activities. The Ortho lawn and garden products business was the major asset sold in 1993, generating a $130 million gain. In addition, oil and gas properties in the United States and Indonesia, undeveloped coal properties in the United States and marketing assets in Central America were sold in 1993 resulting in a net loss of $8 million. In 1992, assets sold included oil and gas properties in the United States, United Kingdom, Canada and Sudan; a fertilizer business in the United States; and a copper interest in Chile. In addition, the stock of a U.S. oil and gas subsidiary was exchanged for 31,500,000 shares of Chevron stock, a transaction valued at $1.1 billion. The combination of these and other smaller sales resulted in after-tax gains of $757 million in 1992.
ASSET WRITE-OFFS AND REVALUATIONS in 1993 were comprised of certain U.S. refinery assets, U.S. and Canadian production assets, and miscellaneous corporate assets. Asset write-offs in 1992 consisted of a $110 million write-down of the company's Beaufort Sea oil properties and a net $23 million charge related to certain U.S. refining, marketing and chemical fertilizer assets.
ENVIRONMENTAL REMEDIATION PROVISIONS pertain to estimated future costs for environmental cleanup programs at certain of the company's U.S. service stations, marketing terminals, refineries, chemical locations and oil and gas properties; divested operations in which Chevron has liability for future cleanup costs; and sites, commonly referred to as Superfund sites, for which the company has been designated a PRP by the EPA. In addition to environmental remediation and cleanup costs included in the 1994 and 1993 restructuring charges discussed below, provisions for environmental remediation amounted to $304 million in 1994, $90 million in 1993, and $44 million in 1992.
RESTRUCTURINGS AND REORGANIZATIONS charges in 1994 were a net $45 million addition to the $543 million charge provided in 1993 to restructure the company's U.S. refining and marketing business. The 1994 adjustment included $6 million applicable to the effect of the restructuring on the company's chemicals operations. The adjustment also included the result of environmental remediation actions agreed to with regulatory agencies, and retained by the company, in connection with the terms of the sale of the Port Arthur refinery.
The 1993 charge was composed primarily of a write-down of the company's Philadelphia and Port Arthur refinery facilities and related inventories to their realizable values. In estimating the refineries' realizable values, the company took into account certain environmental cleanup obligations. The charges also included provisions for environmental site assessments and employee severance.
The Philadelphia refinery was sold in August 1994 and the Port Arthur refinery was sold in February 1995. At year-end 1994, the reserve balance of $715 million, before tax, was comprised of $491 million applicable to the loss on the Port Arthur facilities and inventories and $224 million for retained future Port Arthur environmental cleanup obligations. Additional Port Arthur environmental reserves had been established prior to the decision to sell the refinery.
In 1992, Chevron recorded a net charge of $40 million associated with restructuring and work-force reductions in connection with the company's enhanced early retirement program.
LIFO INVENTORY LIQUIDATION LOSSES result from the reduction of inventories in certain inventory pools valued under the Last-In, First-Out (LIFO) accounting method. LIFO losses decreased net income in 1994, 1993 and 1992 by $10 million, $46 million and $26 million, respectively, as inventories were liquidated at higher than then-current costs. These amounts include the company's equity share of Caltex LIFO inventory effects. Chevron's consolidated petroleum inventories were 99 million barrels at year-end 1994 and 1993 and 105 million barrels at year-end 1992.
OTHER SPECIAL ITEMS in 1994 included charges for litigation and regulatory settlements of $31 million, which were partially offset by a casualty insurance recovery of $20 million. In 1993, net additions of $70 million to reserves for various litigation and regulatory issues and a one-time cash bonus award to employees totaling $60 million, were partially offset by a favorable inventory adjustment of $16 million. In 1992, insurance recoveries and chemical products licensing agreements of $76 million were partially offset by $11 million of net additions to reserves for various litigation and regulatory issues.
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RESULTS OF OPERATIONS. Results for 1994 were depressed by lower average crude oil and natural gas prices and lower sales margins on refined products. Crude oil prices were especially low in the first quarter and U.S. refined products margins were very weak in the second quarter. In addition to these industry conditions, the company experienced unscheduled refinery downtime and other refinery operating problems in its U.S. operations, particularly in the first half of the year, that further reduced earnings. Chemicals operations, however, were very strong, benefiting from improved industry fundamentals and the restructuring and cost reduction programs undertaken in recent years.
In 1993, compared with 1992, strong worldwide refined product sales margins and high U.S. natural gas prices mitigated the effects of lower crude oil prices. Another contributing factor to the company's improved operating performance in 1993 was the large reduction in its operating and administrative costs. Also, lower interest and exploration expenses helped earnings. Chemicals operations were at depressed levels in both years, reflecting continued industry overcapacity and weak worldwide economies.
SALES AND OTHER OPERATING REVENUES were $35.1 billion, down from $36.2 billion in 1993 and $38.2 billion in 1992. Revenues declined from 1993 and 1992 levels primarily due to lower prices for crude oil, natural gas and refined products together with lower refined product sales volumes. These factors also accounted for corresponding declines in PURCHASED CRUDE OIL AND PRODUCTS. The decline in total revenues was partially mitigated by higher chemicals revenues and gasoline excise tax collections.
OTHER INCOME in all years included net gains resulting from the disposition of non-core assets, which caused other income to fluctuate from year to year.
OPERATING, SELLING AND ADMINISTRATIVE EXPENSES, adjusted for special items, declined $150 million in 1994. Annual operating costs in 1994 were over $1 billion less than in 1991, the base measurement year set when the company launched its cost reduction program in early 1992. Operating expenses in 1994 included unanticipated costs associated with unscheduled refinery shutdowns and maintenance, as well as other refinery operating problems. Although a portion of the cost reduction is a result of operations disposed of over the years, the bulk of the decrease is due to a significant reduction to the company's ongoing cost structure. Reported selling, general and administrative expenses in 1994 included the reversal of $319 million of accrued interest reserves on federal income taxes payable resulting from the company's settlement with the IRS of nine open tax years, 1979 through 1987.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Reported Operating Expenses* $6,314 $6,267 $6,145 Reported Selling, General and Administrative Expenses 963 1,530 1,761 ------------------------------------------------------------------------------ Total Operational Costs 7,277 7,797 7,906 Eliminate Special Charges Before Tax (161) (531) (282) ------------------------------------------------------------------------------ Adjusted Ongoing Operational Costs $7,116 $7,266 $7,624 ============================================================================== * OPERATIONS ARE CHARGED AT MARKET RATES FOR CONSUMPTION OF THE COMPANY'S OWN FUEL. THESE "COSTS" ARE ELIMINATED IN THE CONSOLIDATED FINANCIAL STATEMENTS. FOR COST PERFORMANCE MEASUREMENT, SUCH COSTS ARE INCLUDED AND AMOUNTED TO $1,027, $1,017 AND $1,251 IN 1994, 1993 AND 1992, RESPECTIVELY.
TAXES on income were $1.1 billion in 1994, $1.2 billion in 1993, and $1.3 billion in 1992, equating to effective income tax rates of 39.6 percent, 47.9 percent, and 36.2 percent for each of the three years, respectively. The lower effective tax rate for 1994 is attributable to the effect of favorable prior-year tax adjustments resulting from a global settlement with the Internal Revenue Service for the years 1979 through 1987, which included the reversal of excess interest reserves with little associated tax effect. The increase in the 1993 tax rate from 1992 levels is due primarily to unfavorable prior-year tax adjustments, including an increase in deferred income taxes resulting from the one percent increase in the U.S. corporate income tax rate. The 1992 rate included the effect of a tax-free exchange, which resulted in a large book gain with no associated tax cost.
CURRENCY TRANSACTIONS decreased net income $64 million in 1994 compared with increases of $46 million in 1993 and $90 million in 1992. These amounts include the company's share of affiliates' currency transactions. The loss on currency transactions in 1994 resulted primarily from fluctuations in the value of the Australian and Philippine currencies relative to the U.S. dollar. In 1993, gains resulted from fluctuations in the currency of Nigeria. In 1992, gains resulted from fluctuations in the currencies of the United Kingdom, Canada, Australia and Nigeria.
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RESULTS BY MAJOR OPERATING AREAS MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Exploration and Production United States $ 518 $ 566 $1,043 International 539 580 594 ------------------------------------------------------------------------------ Total Exploration and Production 1,057 1,146 1,637 ------------------------------------------------------------------------------ Refining, Marketing and Transportation United States 40 (170) 297 International 239 252 111 ------------------------------------------------------------------------------ Total Refining, Marketing and Transportation 279 82 408 ------------------------------------------------------------------------------ Total Petroleum 1,336 1,228 2,045 Chemicals 206 143 89 Coal and Other Minerals 111 44 198 Corporate and Other 40 (150) (122) ------------------------------------------------------------------------------ Income Before Cumulative Effect of Changes in Accounting Principles $1,693 $1,265 $2,210 Cumulative Effect of Changes in Accounting Principles - - (641) ------------------------------------------------------------------------------ Net Income $1,693 $1,265 $1,569 ==============================================================================
SPECIAL ITEMS BY MAJOR OPERATING AREAS MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Exploration and Production United States $ (66) $(136) $413 International 20 (61) 14 ------------------------------------------------------------------------------ Total Exploration and Production (46) (197) 427 ------------------------------------------------------------------------------ Refining, Marketing and Transportation United States (285) (725) (53) International (10) 1 (3) ------------------------------------------------------------------------------ Total Refining, Marketing and Transportation (295) (724) (56) ------------------------------------------------------------------------------ Total Petroleum (341) (921) 371 Chemicals (9) 112 53 Coal and Other Minerals 48 - 159 Corporate and Other 324 (74) 68 ------------------------------------------------------------------------------ Total Special Items Included in Net Income $ 22 $(883) $ 651 ==============================================================================
U.S. EXPLORATION AND PRODUCTION earnings in 1994, excluding special items, were down 17 percent from 1993 levels and down 7 percent from 1992 results.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Earnings Excluding Special Items $584 $702 $ 630 ------------------------------------------------------------------------------ Prior-Year Tax Adjustments - (40) 5 Asset Dispositions - (54) 419 Asset Write-Offs and Revaluations - (13) - Environmental Remediation Provisions (51) (13) (2) Restructurings and Reorganizations - (2) (35) LIFO Inventory (Losses) Gains (4) 1 5 Other (11) (15) 21 ------------------------------------------------------------------------------ Total Special Items (66) (136) 413 ------------------------------------------------------------------------------ Reported Earnings $518 $566 $1,043 ==============================================================================
Operationally, lower average crude oil and natural gas prices and lower crude oil production levels in 1994 contributed to the earnings decline from 1993. Crude prices were sharply lower in the last half of 1993, but recovered to the point that in December 1994, the company's average realizations were $3.12 per barrel higher than in December 1993. Overall, however, the company's average crude oil realization for 1994 decreased $.72 per barrel to $13.86. Natural gas prices fell throughout 1994, averaging $1.77 per thousand cubic feet for the year, down $.22 from the 1993 average price. Natural gas accounts for almost half of the company's U.S. oil and gas production volumes.
Cost cutting efforts and higher natural gas prices were the major factors in 1993's earnings improvement from 1992, offsetting lower crude oil prices and lower production levels.
Net liquids production for 1994 averaged 369,000 barrels per day, down 6 percent from 394,000 in 1993 and down 15 percent from 432,000 barrels per day in 1992. Net natural gas pro-
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duction in 1994 averaged about 2.1 billion cubic feet per day, about the same level as 1993 but down from 2.3 billion cubic feet per day in 1992. The production declines resulted from producing property sales, in connection with the company's decision to concentrate its efforts on a core portfolio of about 400 producing properties, and from normal field declines.
INTERNATIONAL EXPLORATION AND PRODUCTION earnings in 1994, excluding special items, were down 19 percent from 1993 levels and down 11 percent from 1992 results, due primarily to foreign currency effects. In 1994, foreign exchange losses were $28 million, whereas in 1993 and 1992, foreign exchange gains amounted to $57 million and $80 million, respectively.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Earnings Excluding Special Items $519 $641 $580 ------------------------------------------------------------------------------ Prior-Year Tax Adjustments 20 (63) (27) Asset Dispositions - 29 166 Asset Write-Offs and Revaluations - (19) (110) Restructurings and Reorganizations - (2) (9) LIFO Inventory Losses - (1) (1) Other - (5) (5) ------------------------------------------------------------------------------ Total Special Items 20 (61) 14 ------------------------------------------------------------------------------ Reported Earnings $539 $580 $594 ==============================================================================
Operationally, higher production volumes did not fully offset the effect of lower average crude oil and natural gas prices in 1994. The company's average international liquids prices, including equity in affiliates, declined to $14.86 per barrel from $16.09 in 1993 and $17.93 in 1992. Average natural gas prices were $1.84 per thousand cubic feet in 1994 compared with $2.08 and $2.07 in 1993 and 1992, respectively. In 1994, net liquids production, including production from equity affiliates, increased 12 percent over 1993 to 624,000 barrels per day, and was up 22 percent from 1992 production levels. Net natural gas production volumes also increased in 1994, up 16 percent from 1993 to 546 million cubic feet per day and up 18 percent from 1992 levels. Production of crude oil and natural gas has been increasing steadily since the late 1980s, reflecting the company's strategy of growing its international operations.
SELECTED OPERATING DATA 1994 1993 1992 ------------------------------------------------------------------------------- U.S. EXPLORATION AND PRODUCTION Net Crude Oil and Natural Gas Liquids Production (MBPD) 369 394 432 Net Natural Gas Production (MMCFPD) 2,085 2,056 2,313 Natural Gas Liquids Sales (MBPD) 215 211 194 Revenues from Net Production Crude Oil ($/bbl.) $13.86 $14.58 $16.50 Natural Gas ($/MCF) $ 1.77 $ 1.99 $ 1.70
INTERNATIONAL EXPLORATION AND PRODUCTION (1) Net Crude Oil and Natural Gas Liquids Production (MBPD) 624 556 512 Net Natural Gas Production (MMCFPD) 546 469 463 Natural Gas Liquids Sales (MBPD) 34 37 33 Revenues from Liftings Liquids ($/bbl.) $14.86 $16.09 $17.93 Natural Gas ($/MCF) $ 1.84 $ 2.08 $ 2.07
U.S. REFINING AND MARKETING Gasoline Sales (MBPD) 615 652 646 Other Refined Product Sales (MBPD) 699 771 824 Refinery Input (MBPD) 1,213 1,307 1,311 Average Refined Product Sales Price ($/bbl.) $24.37 $25.35 $25.96
INTERNATIONAL REFINING AND MARKETING (1) Refined Product Sales (MBPD) 934 923 859 Refinery Input (MBPD) 623 598 543
CHEMICALS SALES AND OTHER OPERATING REVENUES (2) United States $3,079 $2,694 $2,929 International 648 602 566 ------------------------------ Worldwide $3,727 $3,296 $3,495 =============================================================================== (1) INCLUDES EQUITY IN AFFILIATES. REFINERY INPUT IN 1992 DOES NOT INCLUDE SOUTH AFRICA WHERE LOCAL GOVERNMENT RESTRICTIONS PROHIBITED DISCLOSURE OF REFINERY INPUT IN 1992 AND PRIOR YEARS. (2) MILLIONS OF DOLLARS. INCLUDES SALES TO OTHER CHEVRON COMPANIES.
MBPD=thousand barrels per day; MMCFPD=million cubic feet per day; bbl.=barrel; MCF=thousand cubic feet
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U.S. REFINING AND MARKETING earnings, excluding special items, declined 41 percent from 1993's strong results and were down 7 percent from 1992 levels. Sales volumes in 1994 declined 8 percent from 1993 levels, largely due to the sale of the company's Philadelphia refinery in August.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Earnings Excluding Special Items $ 325 $ 555 $350 ------------------------------------------------------------------------------ Prior-Year Tax Adjustments - (38) 7 Asset Dispositions - (1) - Asset Write-Offs and Revaluations - (25) (31) Environmental Remediation Provisions (249) (77) (42) Restructurings and Reorganizations (39) (543) (1) LIFO Inventory Gains (Losses) 3 (44) (22) Other - 3 36 ------------------------------------------------------------------------------ Total Special Items (285) (725) (53) ------------------------------------------------------------------------------ Reported Earnings $ 40 $(170) $297 ==============================================================================
Sales margins were lower in 1994 compared with 1993. Refined products prices were weak as ample supplies created a highly competitive market. The company also experienced unscheduled refinery downtime and other refinery operating problems early in 1994 that increased operating expenses and required more expensive third-party product purchases to supply the company's marketing system.
Compared with the previous year, the strong earnings in 1993 reflected lower crude oil prices and lower operating costs, resulting in higher average sales margins than in 1992. Total product sales volumes declined 3 percent from 1992 levels, although sales of higher-valued motor fuels increased about 1 percent.
INTERNATIONAL REFINING AND MARKETING earnings include international marine operations and equity earnings of the company's Caltex Petroleum Corporation affiliate. Excluding special items, 1994 earnings were about level with 1993, but more than doubled from 1992.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Earnings Excluding Special Items $249 $251 $114 ------------------------------------------------------------------------------ Prior-Year Tax Adjustments - (4) 7 Asset Dispositions - 13 - Asset Write-Offs and Revaluations - (1) - Restructurings and Reorganizations - (1) (1) LIFO Inventory Losses (10) (3) (9) Other - (3) - ------------------------------------------------------------------------------ Total Special Items (10) 1 (3) ------------------------------------------------------------------------------ Reported Earnings $239 $252 $111 ==============================================================================
Earnings in 1994 reflected lower results from the company's United Kingdom operations and several of the Caltex major areas of operations, particularly refining operations in Bahrain. United Kingdom operations were impacted by weak sales margins and the effects of an explosion and fire at the cracking facility that manufactures its gasoline. Shipping and trading earnings also declined. On the other hand, Canadian results improved on higher sales volumes and stronger markets. Results in 1992 reflected weak global economic conditions that held down product prices, shrinking sales margins in all the company's areas of operations.
Sales volumes for 1994 increased slightly over 1993 levels as a 5 percent increase in marketing sales was mostly offset by a decline in the company's trading sales volumes; however, 1994 volumes were up nearly 9 percent from 1992 due to continued demand growth in the Caltex areas of operations. Caltex volumes, excluding transactions with Chevron, increased 4 percent from 1993 and 6 percent from 1992 to 1993, continuing its growth of the past several years.
Equity earnings of Caltex were $210 million, $227 million and $180 million for 1994, 1993, and 1992, respectively. Between 1994 and 1993, there was a favorable swing of $69 million resulting from inventory adjustments and an unfavorable impact of $43 million caused by foreign currency transactions. In 1994, Chevron's share of annual Caltex earnings benefited $17 million from upward adjustments to the carrying value of its petroleum inventories to reflect market values after a 1993 write-down of $52 million. Caltex foreign currency transactions were losses of $27 million in 1994 but were gains of $16 million and $21 million in 1993 and 1992, respectively.
Total international refining and marketing foreign currency transaction losses were $19 million in 1994, compared with gains of $2 million in 1993 and $13 million in 1992.
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CHEMICALS earnings, excluding special items, were up dramatically from 1993 and 1992 levels. The improving U.S. economy reduced industry overcapacity, resulting in higher sales volumes at stronger prices, and reversing 5 years of successively lower operating earnings caused by industry over-expansion just prior to a downturn in the U.S. economy. Restructurings and cost reduction programs undertaken in recent years positioned the company's chemicals businesses to benefit from the improved industry conditions. Operating results were strong in all the company's divisions - additives, aromatics and, especially, olefins. Olefins results would have been even higher had a major plant not been shut down for over a month because of damage caused by flooding in southeast Texas in mid-October. The shutdown resulted in lost earnings and higher operating and repair expenses.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Earnings Excluding Special Items $215 $ 31 $36 ------------------------------------------------------------------------------ Prior-Year Tax Adjustments - (5) (2) Asset Dispositions - 130 13 Asset Write-Offs and Revaluations - - 8 Environmental Remediation Provisions (4) - - Restructurings and Reorganizations (6) (5) (1) LIFO Inventory Gains 1 1 1 Other - (9) 34 ------------------------------------------------------------------------------ Total Special Items (9) 112 53 ------------------------------------------------------------------------------ Reported Earnings $206 $143 $89 ==============================================================================
COAL AND OTHER MINERALS earnings, excluding special items, increased 43 percent from 1993 and 62 percent from 1992 results. Operationally, earnings improved as coal sales margins were slightly higher. Sales tonnage, at 20.4 million tons, was down slightly from the prior year, but up from 16.5 million tons in 1992. Also, earnings benefited from the absence of 1993 and 1992 losses from non-coal minerals activities.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Earnings Excluding Special Items $ 63 $44 $ 39 ------------------------------------------------------------------------------ Prior-Year Tax Adjustments - (2) - Asset Dispositions 48 5 159 Other - (3) - ------------------------------------------------------------------------------ Total Special Items 48 - 159 ------------------------------------------------------------------------------ Reported Earnings $111 $44 $198 ==============================================================================
CORPORATE AND OTHER activities include interest expense, interest income on cash and marketable securities, real estate and insurance operations, and corporate center costs.
Excluding the effects of special items, corporate and other charges in 1994 were $284 million, compared with net charges of $76 million in 1993 and $190 million in 1992.
MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ Earnings Excluding Special Items $(284) $ (76) $(190) ------------------------------------------------------------------------------ Prior-Year Tax Adjustments 324 22 82 Asset Write-offs and Revaluations - (13) - Restructurings and Reorganizations - (1) 7 Other - (82) (21) ------------------------------------------------------------------------------ Total Special Items 324 (74) 68 ------------------------------------------------------------------------------ Reported Earnings $ 40 $(150) $(122) ==============================================================================
In 1994, the company changed its method of distributing certain corporate expenses to its business segments. As a result, corporate and other charges for 1994 included $190 million that, under the previous method, would have been allocated to the business segments. This change had no net income effect. Amounts that would have been allocated in 1994 to the company's major operating areas under the prior method are as follows: U.S. Exploration and Production - $34 million; U.S. Refining and Marketing - $32 million; International Exploration and Production - $63 million; International Refining and Marketing - $48 million; Chemicals - $10 million; and Coal and Other Minerals - $3 million.
Higher interest costs in 1994 resulted from the combined effect of higher debt levels and higher interest rates than in 1993. The decline in 1993 costs relative to 1992 reflects an $84 million after-tax reduction in interest expense, due to lower interest rates and lower debt levels.
LIQUIDITY AND CAPITAL RESOURCES. Cash, cash equivalents and marketable securities decreased $710 million to $1.3 billion at year-end 1994. Cash provided by operating activities decreased $1.3 billion in 1994 to $2.9 billion, compared with $4.2 billion in 1993 and $3.9 billion in 1992. The 1994 decrease reflects lower operational earnings, adjusted for non-cash charges, and increased working capital requirements, including the payment of $675 million to the Internal Revenue Service for the settlement of substantially all open tax issues for the nine
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years 1979 through 1987. Cash from operations, proceeds from asset sales, an increase in overall debt levels and the draw-down of cash balances were used to fund the company's capital expenditures and dividend payments to stockholders.
AT YEAR-END 1994, THE COMPANY CLASSIFIED $1.8 BILLION OF SHORT-TERM OBLIGATIONS AS LONG-TERM DEBT. Settlement of these obligations, consisting of commercial paper, is not expected to require the use of working capital in 1995 because the company has the intent and the ability, as evidenced by revolving credit arrangements, to refinance them on a long-term basis. The company's practice has been to continually refinance its commercial paper, maintaining levels it believes to be appropriate.
ON DECEMBER 31, 1994, CHEVRON HAD $4.4 BILLION IN COMMITTED CREDIT FACILITIES WITH VARIOUS MAJOR BANKS. These facilities support commercial paper borrowing and can also be used for general credit requirements. No borrowings were outstanding under these facilities during the year or at year-end 1994. In addition, Chevron and one of its subsidiaries each have existing "shelf" registrations on file with the Securities and Exchange Commission that together would permit registered offerings of up to approximately $700 million of debt securities.
THE COMPANY'S DEBT AND CAPITAL LEASE OBLIGATIONS TOTALED $8.142 BILLION AT DECEMBER 31, 1994, up $604 million from $7.538 billion at year-end 1993. The increase is primarily from $466 million of additional net short-term borrowings, largely the issuance of commercial paper, the issuance of $350 million of 7.45 percent notes due in the year 2004 and $65 million in capital lease obligations associated with the delivery of a new vessel. These increases were partially offset by the first quarter repayment of $200 million of 7.875 percent public debt originally due March 1, 1997. The company also retired $40 million of debt related to the Employee Stock Ownership Plan in January 1994.
THE COMPANY'S FUTURE DEBT LEVEL IS PRIMARILY DEPENDENT ON ITS CAPITAL SPENDING PROGRAM AND ITS BUSINESS OUTLOOK. While the company does not currently expect its debt level to increase significantly during 1995, it believes it has substantial borrowing capacity to meet unanticipated cash requirements.
FINANCIAL RATIOS 1994 1993 1992 ------------------------------------------------------------------ Current Ratio 0.8 0.8 0.9 Interest Coverage Ratio 7.6 7.4 8.2 Total Debt/Total Debt Plus Equity 35.8% 35.0% 36.4% ==================================================================
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 1994 were lower than current costs by $684 million. Also the company's practice of continually refinancing its commercial paper, $3.2 billion classified as short-term at year-end 1994, results in a large portion of its short-term debt being outstanding indefinitely. Chevron's interest coverage ratio increased in 1994 due to higher income before tax. The INTEREST COVERAGE RATIO is defined as income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. The company's DEBT RATIO (total debt to total debt plus equity) increased slightly, as total debt increased more than equity did year-to-year.
The company's senior debt is rated AA by Standard & Poor's Corporation and Aa2 by Moody's Investors Service. Chevron's U.S. commercial paper is rated A-1$PL by Standard & Poor's and Prime-1 by Moody's, and Chevron's Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All these ratings denote high-quality, investment-grade securities.
CAPITAL AND EXPLORATORY EXPENDITURES
WORLDWIDE CAPITAL AND EXPLORATORY EXPENDITURES FOR 1994, INCLUDING THE COMPANY'S EQUITY SHARE OF AFFILIATES' EXPENDITURES, TOTALED $4.8 BILLION. Expenditures for exploration and production accounted for 57 percent of total outlays in 1994, 53 percent in 1993 and 51 percent in 1992. International exploration and production spending increased to 71 percent of worldwide exploration and production expenditures in 1994, up from 68 percent in 1993 and 65 percent in 1992, reflecting the company's increased focus on international exploration and production activities.
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THE COMPANY PROJECTS 1995 CAPITAL AND EXPLORATORY EXPENDITURES AT APPROXIMATELY $5.1 BILLION, including Chevron's share of spending by affiliates. Excluding affiliates, spending will be essentially flat at $3.9 billion. The 1995 program provides $2.7 billion in exploration and production investments, of which about 70 percent are for international projects.
The company is participating in several significant oil and gas development projects. These include the development of the Hibernia field off the coast of Newfoundland; the Tengiz project in Kazakhstan; steam- and water-flood projects in Indonesia; expansion of the North West Shelf liquefied natural gas project in Australia; continued development of the Britannia natural gas field in the North Sea; expanded production projects in Angola; field development and expanded exploration in Congo; new field development in Papua New Guinea; and the Norphlet Trend natural gas development project in the Gulf of Mexico.
Refining, marketing and transportation expenditures are estimated at about $1.9 billion, with about $900 million of that planned for the U.S., including upgrading U.S. refineries to produce reformulated gasolines needed to comply with the Clean Air Act and California Air Resources Board regulations. Most of the balance will be focused on high growth Asia Pacific Rim countries where the company's Caltex affiliate has several major refinery projects under way to meet rising demand, including continuing the construction of a new refinery in Thailand and capacity expansion projects in Japan and Korea.
Projected spending also includes funds for the expansion of the linear low-density polyethylene manufacturing plant at the Cedar Bayou, Texas, chemicals facility.
CAPITAL AND EXPLORATORY EXPENDITURES
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 LLP, independent accountants, selected by the Audit Committee and approved by the stockholders. Management has made available to Price Waterhouse LLP all the company's financial records and related data, as well as the minutes of stockholders' and directors' meetings.
Management of the company has established and maintains a system of internal accounting controls that is designed to provide reasonable assurance that assets are safeguarded, transactions are properly recorded and executed in accordance with management's authorization, and the books and records accurately reflect the disposition of assets. The system of internal controls includes appropriate division of responsibility. The company maintains an internal audit department that conducts an extensive program of internal audits and independently assesses the effectiveness of the internal controls.
The Audit Committee is composed of directors who are not officers or employees of the company. It meets regularly with members of management, the internal auditors and the independent accountants to discuss the adequacy of the company's internal controls, financial statements and the nature, extent and results of the audit effort. Both the internal auditors and the independent accountants have free and direct access to the Audit Committee without the presence of management.
/s/ K.T. Derr /s/ M.R. Klitten /s/ D.G. Henderson
Kenneth T. Derr Martin R. Klitten Donald G. Henderson Chairman of the Board Vice President, Finance Vice President and Chief Executive Officer and Chief Financial Officer and Comptroller
February 28, 1995
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders' equity and cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 1992, the company changed its methods of accounting for postretirement benefits other than pensions and for income taxes.
/s/ Price Waterhouse LLP
San Francisco, California February 28, 1995
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CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31 MILLIONS OF DOLLARS, ---------------------------------- EXCEPT PER-SHARE AMOUNTS 1994 1993 1992 ------------------------------------------------------------------------------ REVENUES Sales and other operating revenues (1) $35,130 $36,191 $38,212 Equity in net income of affiliated companies 440 440 406 Other income 284 451 1,059 ------------------------------------------------------------------------------ TOTAL REVENUES 35,854 37,082 39,677 ------------------------------------------------------------------------------ COSTS AND OTHER DEDUCTIONS Purchased crude oil and products 16,990 18,007 19,872 Operating expenses 6,314 6,267 6,145 Provision for U.S. refining and marketing restructuring 69 837 - Exploration expenses 379 360 507 Selling, general and administrative expenses 963 1,530 1,761 Depreciation, depletion and amortization 2,431 2,452 2,594 Taxes other than on income (1) 5,559 4,886 4,899 Interest and debt expense 346 317 436 ------------------------------------------------------------------------------ TOTAL COSTS AND OTHER DEDUCTIONS 33,051 34,656 36,214 ------------------------------------------------------------------------------ INCOME BEFORE INCOME TAX EXPENSE AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 2,803 2,426 3,463 INCOME TAX EXPENSE 1,110 1,161 1,253 ============================================================================== INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES $ 1,693 $ 1,265 $ 2,210 CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES - - (641) ============================================================================== NET INCOME $ 1,693 $ 1,265 $ 1,569 ============================================================================== PER SHARE OF COMMON STOCK: (2) INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES $2.60 $1.94 $3.26 CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES - - (.95) ---------------------------------- NET INCOME PER SHARE OF COMMON STOCK $2.60 $1.94 $2.31
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING 651,672,238 650,957,752 677,954,828 ============================================================================== (1) INCLUDES CONSUMER EXCISE TAXES. $4,790 $4,068 $3,964 (2) SHARES AND PER-SHARE AMOUNTS REFLECT A TWO-FOR-ONE STOCK SPLIT IN MAY 1994.
See accompanying notes to consolidated financial statements.
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CONSOLIDATED BALANCE SHEET
AT DECEMBER 31 -------------------------- MILLIONS OF DOLLARS 1994 1993 ------------------------------------------------------------------------------ ASSETS Cash and cash equivalents $ 413 $ 1,644 Marketable securities 893 372 Accounts and notes receivable (less allowance: 1994 - $62; 1993 - $66) 3,923 3,808 Inventories: Crude oil and petroleum products 1,036 1,108 Chemicals 391 423 Materials and supplies 263 252 Other merchandise 20 18 -------------------------- 1,710 1,801 Prepaid expenses and other current assets 652 1,057 ------------------------------------------------------------------------------ TOTAL CURRENT ASSETS 7,591 8,682 Long-term receivables 138 94 Investments and advances 3,991 3,623
Properties, plant and equipment, at cost 46,810 44,807 Less: accumulated depreciation, depletion and amortization 24,637 22,942 -------------------------- 22,173 21,865 Deferred charges and other assets 514 472 ------------------------------------------------------------------------------ TOTAL ASSETS $34,407 $34,736 ==============================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY Short-term debt $ 4,014 $ 3,456 Accounts payable 2,990 3,325 Accrued liabilities 1,274 2,538 Federal and other taxes on income 624 782 Other taxes payable 490 505 ------------------------------------------------------------------------------ TOTAL CURRENT LIABILITIES 9,392 10,606 Long-term debt and capital lease obligations 4,128 4,082 Deferred credits and other non-current obligations 2,043 1,677 Non-current deferred income taxes 2,674 2,916 Reserves for employee benefit plans 1,574 1,458 ------------------------------------------------------------------------------ TOTAL LIABILITIES 19,811 20,739 ------------------------------------------------------------------------------ Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued) - - Common stock (authorized 1,000,000,000 shares, $1.50 par value, 712,487,068 shares issued) * 1,069 1,069 Capital in excess of par value 1,858 1,855 Deferred compensation - Employee Stock Ownership Plan (ESOP) (900) (920) Currency translation adjustment and other 175 108 Retained earnings 14,457 13,955 Treasury stock, at cost (1994 - 60,736,435 shares; 1993 - 61,008,858 shares) * (2,063) (2,070) ------------------------------------------------------------------------------ TOTAL STOCKHOLDERS' EQUITY 14,596 13,997 ------------------------------------------------------------------------------ TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $34,407 $34,736 ==============================================================================
* SHARES AND PAR VALUE AMOUNTS REFLECT A TWO-FOR-ONE STOCK SPLIT IN MAY 1994.
See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31 ------------------------------ MILLIONS OF DOLLARS 1994 1993 1992 ------------------------------------------------------------------------------ OPERATING ACTIVITIES Net income $ 1,693 $ 1,265 $ 1,569 Adjustments Depreciation, depletion and amortization 2,431 2,452 2,594 Dry hole expense related to prior years' expenditures 53 29 57 Distributions less than equity in affiliates' income (55) (173) (144) Net before-tax (gains) losses on asset retirements and sales (83) 373 (568) Net currency translation losses (gains) 40 (27) (66) Deferred income tax provision 110 (160) (176) Cumulative effect of changes in accounting principles - - 641 Net (increase) decrease in operating working capital (1) (1,773) 463 82 Other (2) 480 (1) (75) ------------------------------------------------------------------------------ NET CASH PROVIDED BY OPERATING ACTIVITIES (3) 2,896 4,221 3,914 ------------------------------------------------------------------------------ INVESTING ACTIVITIES Capital expenditures (3,405) (3,323) (3,352) Proceeds from asset sales 731 908 1,043 Net (purchases) sales of marketable securities (4) (545) 30 45 ------------------------------------------------------------------------------ NET CASH USED FOR INVESTING ACTIVITIES (3,219) (2,385) (2,264) ------------------------------------------------------------------------------ FINANCING ACTIVITIES Net borrowings of short-term obligations 466 293 1,333 Proceeds from issuance of long-term debt 436 199 23 Repayments of long-term debt and other financing obligations (588) (854) (1,260) Cash dividends paid (1,206) (1,139) (1,115) Purchases of treasury shares (5) (4) (382) ------------------------------------------------------------------------------ NET CASH USED FOR FINANCING ACTIVITIES (897) (1,505) (1,401) ------------------------------------------------------------------------------ EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS (11) 21 3 ------------------------------------------------------------------------------ NET CHANGE IN CASH AND CASH EQUIVALENTS (1,231) 352 252 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,644 1,292 1,040 ------------------------------------------------------------------------------ CASH AND CASH EQUIVALENTS AT YEAR-END $ 413 $ 1,644 $ 1,292 ============================================================================== (1) THE "NET (INCREASE) DECREASE IN OPERATING WORKING CAPITAL" IS COMPOSED OF THE FOLLOWING: (INCREASE) DECREASE IN ACCOUNTS AND NOTES RECEIVABLE $ (44) $ 187 $ 97 (INCREASE) DECREASE IN INVENTORIES (57) 288 292 DECREASE (INCREASE) IN PREPAID EXPENSES AND OTHER CURRENT ASSETS 4 (52) 85 (DECREASE) INCREASE IN ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (1,510) 214 (567) (DECREASE) INCREASE IN INCOME AND OTHER TAXES PAYABLE (166) (174) 175 ------------------------------------------------------------------------------ NET (INCREASE) DECREASE IN OPERATING WORKING CAPITAL $(1,773) $ 463 $ 82 ============================================================================== (2) IN 1994, "OTHER" OPERATING ACTIVITIES WERE COMPRISED PRIMARILY OF INCREASES IN NON-CURRENT OBLIGATIONS WHICH INCLUDED, IN PART, NON-CASH PROVISIONS FOR ENVIRONMENTAL REMEDIATION. (3) "NET CASH PROVIDED BY OPERATING ACTIVITIES" INCLUDES THE FOLLOWING CASH PAYMENTS FOR INTEREST AND INCOME TAXES: INTEREST PAID ON DEBT (NET OF CAPITALIZED INTEREST) $ 310 $ 309 $ 392 INCOME TAXES PAID $ 1,147 $ 1,505 $ 1,236 ============================================================================== (4) "NET (PURCHASES) SALES OF MARKETABLE SECURITIES" CONSISTS OF THE FOLLOWING GROSS AMOUNTS: MARKETABLE SECURITIES PURCHASED $(1,943) $(1,855) $(2,633) MARKETABLE SECURITIES SOLD 1,398 1,885 2,678 ------------------------------------------------------------------------------ NET (PURCHASES) SALES OF MARKETABLE SECURITIES $ (545) $ 30 $ 45 ==============================================================================
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.
DERIVATIVES. Gains and losses on hedges of existing assets or liabilities are included in the carrying amounts of those assets or liabilities and are ultimately recognized in income as part of those carrying amounts. Gains and losses related to qualifying hedges of firm commitments or anticipated transactions also are deferred and are recognized in income or as adjustments of carrying amounts when the hedged transaction occurs. Gains and losses on derivatives contracts that do not qualify as hedges are recognized currently in "Other income."
SHORT-TERM INVESTMENTS. All short-term investments are classified as available-for-sale, and are in highly liquid debt securities. Those investments that are part of the company's cash management portfolio with original maturities of three months or less are reported as cash equivalents. The balance of the short-term investments is reported as marketable securities.
INVENTORIES. Crude oil, petroleum products, 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 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 recognized using the unit-of-production method by individual fields as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed.
Depreciation and depletion expenses for coal are determined using the unit-of-production method as the proved reserves are produced. The capitalized costs of all other plant and equipment are depreciated or amortized over estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method generally is used to depreciate international plant and equipment and to amortize all capitalized leased assets.
Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements or sales are included in income.
Expenditures for maintenance, repairs and minor renewals to maintain facilities in operating condition are expensed. Major replacements and renewals are capitalized.
ENVIRONMENTAL EXPENDITURES. Environmental expenditures that relate to current ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when environmental assessments and/or cleanups are probable, and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals is generally based on the company's commitment to a formal plan of action, such as an approved remediation plan or the sale or disposal of an asset. For the company's domestic marketing facilities, the accrual is based on the probability that a future remediation commitment will be required. For oil and gas and coal producing properties, a provision is made through depreciation expense for anticipated abandonment and restoration costs at the end of the property's useful life.
For Superfund sites, the company records a liability for its share of costs when it has been named as a Potentially Responsible Party (PRP) and when an assessment or cleanup plan has been developed. This liability includes the company's own portion of the costs and also the company's portion of amounts for
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NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued
other PRPs when it is probable that they will not be able to pay their share of the cleanup obligation.
The company records the gross amount of its liability based on its best estimate of future costs in current dollars and using currently available technology and applying current regulations as well as the company's own internal environmental policies. Future amounts are not discounted. Probable recoveries or reimbursements are recorded as an asset.
CURRENCY TRANSLATION. The U.S. dollar is the functional currency for the company's consolidated operations as well as for substantially all operations of its equity method companies. For those operations, all gains or losses from currency transactions are included in income currently. The cumulative translation effects for the few equity affiliates using functional currencies other than the U.S. dollar are included in the currency translation adjustment in stockholders' equity.
TAXES. Income taxes are accrued for retained earnings of international subsidiaries and corporate joint ventures intended to be remitted. Income taxes are not accrued for unremitted earnings of international operations that have been, or are intended to be, reinvested indefinitely.
NOTE 2. 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 $.95 per share, attributable to the cumulative effect of adoption, including the company's share of equity affiliates. This net charge was composed of $833, after related tax benefits of $423, for the recognition of liabilities for retiree benefits (primarily health and life insurance), partially offset by a credit of $192 for deferred income tax benefits and other changes stipulated by the new income tax accounting rules.
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 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ Asset dispositions, net Lead and zinc property in Ireland $ 48 $ - $ - Ortho lawn and garden products - 130 - Oil and gas properties - (25) 209 Stock exchange with Pennzoil Company - - 376 Copper interest in Chile - - 159 Other - 17 13 ------------------------------ 48 122 757 ------------------------------------------------------------------------------ Asset write-offs and revaluations Oil and gas properties - (31) (110) Refining and marketing assets - (24) (31) Other - (16) 8 ------------------------------ - (71) (133) ------------------------------------------------------------------------------ Prior-year tax adjustments 344 (130) 72 ------------------------------------------------------------------------------ Environmental remediation provisions (304) (90) (44) ------------------------------------------------------------------------------ Restructurings and reorganizations Work-force reductions, net - (11) (40) U.S. refining and marketing (39) (543) - Chemicals (6) - - ------------------------------ (45) (554) (40) ------------------------------------------------------------------------------ LIFO inventory losses (10) (46) (26) ------------------------------------------------------------------------------ Other, net Litigation and regulatory issues (31) (70) (11) One-time employee bonus - (60) - Chemicals products license agreements - - 32 Insurance gains and other adjustments 20 16 44 ------------------------------ (11) (114) 65 ------------------------------------------------------------------------------ Total special items, after tax $ 22 $(883) $651 ==============================================================================
The 1994 U.S. refining and marketing restructuring charge of $39 and the chemicals charge of $6 were net adjustments made to the 1993 charge of $543. The restructuring reserve was primarily composed of writedowns of two refineries and their related inventories to estimated realizable values. The estimated realizable value of the refineries took into account certain environmental cleanup obligations. Also included in the reserve were amounts for environmental site assessments and employee severance. The refineries are located in Philadelphia, Pennsylvania, and Port Arthur, Texas.
The Philadelphia refinery was sold in August 1994 and the Port Arthur refinery was sold in February 1995. The reserve was reduced by the amount of proceeds received from the sale of the Philadelphia refinery and adjustments were made to reflect the terms of the sales. These included adjustments to the realizable values of the assets, primarily inventories, and the recognition of certain environmental remediation obligations retained by the company. These adjustments resulted in a $45 net increase to the reserve. At year-end 1994, the reserve balance, before related tax effects, was composed of $491 for loss on the sale of the Port Arthur refinery and related inventories and $224 for Port Arthur environmental cleanup obligations.
The company does not expect the environmental cleanup expenditures, most of which will be made over an approximate
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NOTE 3. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION - Continued
ten-year period, to have any material effect on its liquidity. The costs will be funded through cash from future operations.
Other financial information is as follows:
YEAR ENDED DECEMBER 31 ------------------------------- 1994 1993 1992 ------------------------------------------------------------------------------ Total financing interest and debt costs $419 $371 $478 Less: capitalized interest 73 54 42 ------------------------------------------------------------------------------ Interest and debt expense 346 317 436 Research and development expenses 179 206 229 Currency transaction (losses) gains * $(64) $ 46 $ 90 ============================================================================== * INCLUDES $(24), $18 AND $24 IN 1994, 1993 AND 1992, RESPECTIVELY, FOR THE COMPANY'S SHARE OF AFFILIATES' CURRENCY TRANSACTION EFFECTS.
The excess of current cost (based on average acquisition costs for the year) over the carrying value of inventories for which the LIFO method is used was $684, $671 and $803 at December 31, 1994, 1993 and 1992, respectively.
NOTE 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS The Consolidated Statement of Cash Flows excludes the following non-cash transactions:
In 1994, the company took delivery of a new tanker under a capital lease arrangement. This asset was recorded as a $65 million addition to properties, plant and equipment and to capital lease obligations.
The company's Employee Stock Ownership Plan (ESOP) repaid $40 and $30 of matured debt guaranteed by Chevron Corporation in 1994 and 1993, respectively. The company reflected this payment as reductions in debt outstanding and in Deferred Compensation - ESOP.
In 1993, the company acquired a 50 percent interest in the Tengizchevroil joint venture (TCO) in the Republic of Kazakhstan through a series of cash and non-cash transactions. The company's interest in TCO is accounted for using the equity method of accounting and is recorded in "Investments and advances" in the consolidated balance sheet. The cash expended in connection with the formation of TCO and subsequent advances to TCO have been included in the consolidated statement of cash flows in "Capital expenditures." The deferred payment portion of the TCO investment totaled $709 at December 31, 1993, and $466 at year-end 1994 and is recorded in "Accrued liabilities" and "Deferred credits and other non-current obligations" in the consolidated balance sheet. Payments in 1993 and 1994 related to the deferred portion of the TCO investment were classified as "Repayments of long-term debt and other financing obligations" in the consolidated statement of cash flows.
The company refinanced an aggregate amount of $334 and $57 in tax exempt long-term debt and capital lease obligations in 1993 and 1992, respectively. These refinancings are not reflected in the consolidated statement of cash flows.
In 1992, the company received 31,500,000 shares of its common stock held by a stockholder in exchange for the stock of a subsidiary owning certain U.S. oil and gas producing properties and related facilities, cash and other current assets and current liabilities. The value attributed to the treasury shares received was $1,100. The property exchanged consisted of properties, plant and equipment with a carrying value of $790 and, excluding cash, net current liabilities of $1. Cash of $57 was included as a reduction of proceeds from asset sales.
In 1992, the company acquired an additional ownership interest in an affiliate, accounted for under the equity method, in a non-cash transaction. This increase in ownership required the consolidation of the affiliate into the company's financial statements. The principal result of this consolidation was to increase non-current assets and liabilities by approximately $64.
There have been other non-cash transactions that have occurred during the years presented. These include the reissuance of treasury shares for management compensation plans; 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 ------------------------------- 1994 1993 1992 ------------------------------------------------------------------------------ Additions to properties, plant and equipment * $3,112 $3,214 $3,342 Additions to investments 284 179 47 Payments for other assets and (liabilities), net 9 (70) (37) ------------------------------------------------------------------------------ Capital expenditures 3,405 3,323 3,352 Expensed exploration expenditures 326 330 450 Payments of long-term debt and other financing obligations 242 86 - ------------------------------------------------------------------------------ Capital and exploratory expenditures, excluding equity companies $3,973 $3,739 $3,802 ============================================================================== * 1994 EXCLUDES NON-CASH CAPITAL LEASE ADDITION OF $65.
NOTE 5. STOCKHOLDERS' EQUITY Retained earnings at December 31, 1994 and 1993, include $2,265 and $2,087, respectively, for the company's share of undistributed earnings of equity affiliates.
At the company's annual meeting on May 3, 1994, stockholders approved an increase in the authorized shares of common stock from 500 million to 1 billion and approved a two-for-one split of the company's issued common stock, effective May 11, 1994. All share and per-share amounts prior to that date have been restated to reflect the stock split.
In 1988, the company declared a dividend distribution of one Right for each outstanding share of common stock. The Rights will be exercisable, unless redeemed earlier by the company, if a person or group acquires, or obtains the right to acquire, 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer that would result in acquiring 10 percent or more of the outstanding shares of common stock, either event occurring without the prior consent of the company. Each Right entitles its holder to purchase stock having a value equal to two times the exercise price of the
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NOTE 5. STOCKHOLDERS' EQUITY - Continued
Right. The person or group who had acquired 10 percent or more of the outstanding shares of common stock without the prior consent of the company would not be entitled to this purchase opportunity.
The Rights will expire in November 1998, or they may be redeemed by the company at 5 cents per share prior to that date. The Rights do not have voting or dividend rights and, until they become exercisable, have no dilutive effect on the earnings of the company. Twenty million shares of the company's preferred stock have been designated Series A participating preferred stock and reserved for issuance upon exercise of the Rights.
No event during 1994 made the Rights exercisable.
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, primarily anticipated purchase transactions forecasted to occur within 90 days. At December 31, 1994 and 1993, the notional amounts were $60 and $114, respectively.
The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements, based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts, are made either semi-annually or annually, and are recorded monthly as "Interest and debt expense." At December 31, 1994, the notional principal amounts of the swaps held by the company totaled $850, and the contracts have remaining terms of between two to five years.
The impact of the swaps and forward exchange contracts on the company's results of operations is not material.
The company utilizes certain derivative financial instruments as hedges to manage a small portion of its exposure to price volatility stemming from its integrated petroleum activities. Relatively straightforward and involving little complexity, these instruments consist mainly of crude oil futures contracts traded on the International Petroleum Exchange and natural gas swap contracts, entered into principally with major financial institutions. The futures contracts hedge anticipated crude oil purchases and sales, generally forecasted to occur within a ninety-day period. Natural gas swaps are primarily used to hedge firmly committed sales, and the terms of the swap contracts held have an average maturity of twelve months, mirroring the terms of the committed sales. Gains and losses on the instruments offset, and are recognized concurrently with gains and losses associated with the underlying commodities.
CONCENTRATIONS OF CREDIT RISK. The company's financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables.
The company's short-term investments are placed with various foreign governments and a wide array of financial institutions with high credit ratings. This diversified investment policy limits the company's exposure both to credit risk and to concentration of credit risk. Similar standards of diversity and creditworthiness are applied to the company's counterparties in derivative financial instruments.
The trade receivable balances, reflecting the company's diversified sources of revenue, are dispersed among the company's broad customer base worldwide. As a consequence, concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. Letters of credit are the principal security obtained to support lines of credit or negotiated contracts when the financial strength of a customer is not considered sufficient.
FAIR VALUE. At December 31, 1994, the company's long-term debt of $2,155 had an estimated fair value of $2,127. The fair value is based on quoted market prices at December 31, 1994, or the present value of expected cash flows when a quoted market price was not available.
At December 31, 1994, the company held crude oil futures contracts and natural gas swap contracts with approximate negative fair values totaling $(38).
The company holds cash equivalents and U.S. dollar marketable securities in domestic and offshore portfolios. Eurodollar bonds and floating rate notes are the primary instruments held. At December 31, 1994, cash equivalents and marketable securities had a fair value of $1,178. Of this balance, $285 classified as cash equivalents had average maturities under 90 days, while the remainder, classified as marketable securities, had an average maturity of 4 years.
NOTE 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC. At December 31, 1994, Chevron U.S.A. Inc. was Chevron Corporation's principal operating company, consisting primarily of the company's U.S. integrated petroleum operations (excluding most of the domestic pipeline operations). These operations are conducted by three divisions: Chevron U.S.A. Production Company, Chevron U.S.A. Products Company and Warren Petroleum Company. Summarized financial information for Chevron U.S.A. Inc. and its consolidated subsidiaries is presented below:
YEAR ENDED DECEMBER 31 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ Sales and other operating revenues $25,833 $28,092 $29,454 Total costs and other deductions 25,367 27,588 28,410 Income before cumulative effect of changes in accounting principles 501 325 811 Cumulative effect of changes in accounting principles - - (573) Net income 501 325 238 ==============================================================================
AT DECEMBER 31 ------------------ 1994 1993 ------------------------------------------------------------------------------ Current assets $ 3,341 $ 3,661 Other assets 14,136 14,099 Current liabilities 6,347 5,936 Other liabilities 5,599 5,738 Net equity 5,531 6,086 ==============================================================================
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NOTE 8. LITIGATION The company is a defendant in numerous lawsuits. Plaintiffs may seek to recover large and sometimes unspecified amounts, and some matters may remain unresolved for several years.
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.) OXY also asserts that the company improperly interfered with a proposed settlement of claims brought against OXY by the Department of Energy.
Management is of the opinion that resolution of the lawsuits will not result in any significant liability to the company in relation to its consolidated financial position or liquidity.
NOTE 9. GEOGRAPHIC AND SEGMENT DATA The geographic and segment distributions of the company's identifiable assets, operating income and sales and other operating revenues are summarized in the following tables.
AT DECEMBER 31 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ IDENTIFIABLE ASSETS United States Petroleum $15,540 $16,443 $18,508 Chemicals 1,992 2,045 2,165 Coal and Other Minerals 592 744 762 ------------------------------------------------------------------------------ Total United States 18,124 19,232 21,435 ------------------------------------------------------------------------------ International Petroleum 12,493 12,202 9,671 Chemicals 411 412 390 Coal and Other Minerals 45 13 10 ------------------------------------------------------------------------------ Total International 12,949 12,627 10,071 ------------------------------------------------------------------------------ TOTAL IDENTIFIABLE ASSETS 31,073 31,859 31,506 Corporate and Other 3,334 2,877 2,464 ------------------------------------------------------------------------------ TOTAL ASSETS $34,407 $34,736 $33,970 ==============================================================================
YEAR ENDED DECEMBER 31 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ OPERATING INCOME United States Petroleum $ 831 $ 692 $ 1,693 Chemicals 241 162 46 Coal and Other Minerals 60 59 68 ------------------------------------------------------------------------------ Total United States 1,132 913 1,807 ------------------------------------------------------------------------------ International Petroleum 1,672 1,772 1,731 Chemicals 81 63 70 Coal and Other Minerals 79 (3) 177 ------------------------------------------------------------------------------ Total International 1,832 1,832 1,978 ------------------------------------------------------------------------------ TOTAL OPERATING INCOME 2,964 2,745 3,785 Corporate and Other (161) (319) (322) Income Tax Expense (1,110) (1,161) (1,253) ------------------------------------------------------------------------------ Income before cumulative effect of changes in accounting principles $ 1,693 $ 1,265 $ 2,210 Cumulative effect of changes in accounting principles - - (641) ------------------------------------------------------------------------------ NET INCOME $ 1,693 $ 1,265 $ 1,569 ==============================================================================
YEAR ENDED DECEMBER 31 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ SALES AND OTHER OPERATING REVENUES United States Petroleum-Refined products $11,690 $13,169 $13,964 -Crude oil 3,466 4,086 5,138 -Natural gas 1,755 1,776 1,631 -Natural gas liquids 1,072 1,098 1,075 -Other petroleum revenues 637 682 700 -Excise taxes 2,977 2,554 2,458 -Intersegment 977 924 1,052 ------------------------------ Total Petroleum 22,574 24,289 26,018 ------------------------------ Chemicals-Products 2,528 2,211 2,409 -Intersegment 273 248 266 ------------------------------ Total Chemicals 2,801 2,459 2,675 ------------------------------ Coal and Other Minerals-Products 415 447 395 ------------------------------ Total United States 25,790 27,195 29,088 ------------------------------------------------------------------------------ International Petroleum-Refined products 2,638 2,920 2,857 -Crude oil 4,783 4,415 4,893 -Natural gas 383 380 364 -Natural gas liquids 108 137 115 -Other petroleum revenues 307 285 227 -Excise taxes 1,797 1,499 1,490 -Intersegment (2) 1 10 ------------------------------ Total Petroleum 10,014 9,637 9,956 ------------------------------ Chemicals-Products 537 497 463 -Excise taxes 16 15 16 -Intersegment 8 6 5 ------------------------------ Total Chemicals 561 518 484 ------------------------------ Coal and Other Minerals-Products 1 - 2 ------------------------------ Total International 10,576 10,155 10,442 ------------------------------------------------------------------------------ Intersegment sales elimination (1,256) (1,179) (1,333) ------------------------------------------------------------------------------ Corporate and Other 20 20 15 ------------------------------------------------------------------------------ TOTAL SALES AND OTHER OPERATING REVENUES $35,130 $36,191 $38,212 ============================================================================== Memo: Intergeographic Sales United States $ 512 $ 266 $ 309 International 1,803 4,418 3,823 ==============================================================================
The company's primary business is its integrated petroleum operations. Secondary operations include chemicals and coal. The company's real estate and insurance operations and worldwide cash management and financing activities are in "Corporate and Other."
Beginning January 1, 1994, the company no longer distributes certain corporate expenses to its business segments. Prior to 1994, these expenses were allocated on the basis of each segment's identifiable assets (including an allocation to "Corporate and Other"). Starting in 1994, segments are billed for direct corporate services; unbilled corporate expenses are included in "Corporate and Other." The company believes this better reflects the current organizational and management structure of its business units and corporate departments.
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NOTE 9. GEOGRAPHIC AND SEGMENT DATA - Continued
As a result of the change, "Corporate and Other" in 1994 included $232 of before-tax expenses that, under the previous method, would have reduced segment operating income. There was no change in the net income of the company.
Also in connection with the change, the company no longer allocates certain corporate identifiable assets to the business segments. At December 31, 1994, "Corporate and Other" included $1,259 of identifiable assets that in previous years would have been included in the identifiable assets of the business segments.
These changes resulted in an increase to 1994 U.S. and International Petroleum operating income of $101 and $111, respectively. Identifiable assets at December 31, 1994 for U.S. and International Petroleum were reduced $630 and $506, respectively. The effect of these changes on 1994 operating income and year-end 1994 identifiable assets of the company's other segments and geographic areas was not material.
Identifiable assets for the business segments include all assets associated with operations in the indicated geographic areas, including investments in affiliates.
Sales and other operating revenues for the petroleum segment are derived from the production and sale of crude oil, natural gas and natural gas liquids, and from the refining and marketing of petroleum products. The company also obtains revenues from the transportation and trading of crude oil and refined products. Chemicals revenues result primarily from the sale of petrochemicals, plastic resins, and lube oil and fuel additives. Coal and other minerals revenues relate primarily to coal sales. During 1994, the company completed its withdrawal from non-coal minerals activities.
Sales and other operating revenues in the above table include both sales to unaffiliated customers and sales from the transfer of products between segments. Sales from the transfer of products between segments and geographic areas are generally at estimated market prices. Transfers between geographic areas are presented as memo items below the table.
Equity in earnings of affiliated companies has been associated with the segments in which the affiliates operate. Sales to the Caltex Group are included in the "International Petroleum" segment. Information on the Caltex and Tengizchevroil affiliates is presented in Note 11. Other affiliates are either not material or not vertically integrated with a segment's operations.
NOTE 10. LEASE COMMITMENTS Certain non-cancelable leases are classified as capital leases, and the leased assets are included as part of "Properties, 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 ------------------ 1994 1993 ------------------------------------------------------------------------------ Petroleum Exploration and Production $ 45 $ 50 Refining, Marketing and Transportation 618 554 ----------------------------------------------------------------------------- 663 604 Less: accumulated amortization 398 409 ----------------------------------------------------------------------------- Net capitalized leased assets $265 $195 =============================================================================
At December 31, 1994, the future minimum lease payments under operating and capital leases are as follows:
AT DECEMBER 31 ------------------- OPERATING CAPITAL YEAR LEASES LEASES ----------------------------------------------------------------------------- 1995 $158 $ 64 1996 144 60 1997 131 56 1998 114 52 1999 107 44 Thereafter 218 659 ----------------------------------------------------------------------------- Total $872 935 ------------------------------------------------------------------- Less: amounts representing interest and executory costs (456) ----------------------------------------------------------------------------- Net present value 479 Less: capital lease obligations included in short-term debt (306) ----------------------------------------------------------------------------- Long-term capital lease obligations $173 ============================================================================= Future sublease rental income $ 43 $ - =============================================================================
Rental expenses incurred for operating leases during 1994, 1993 and 1992 were as follows:
YEAR ENDED DECEMBER 31 ---------------------------- 1994 1993 1992 ----------------------------------------------------------------------------- Minimum rentals $410 $452 $408 Contingent rentals 7 9 10 ----------------------------------------------------------------------------- Total 417 461 418 Less: sublease rental income 14 15 14 ----------------------------------------------------------------------------- Net rental expense $403 $446 $404 =============================================================================
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.
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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 ------------------ 1994 1993 ------------------------------------------------------------------------------ Equity method affiliates Caltex Group $2,362 $2,147 Tengizchevroil 1,153 927 Other affiliates 346 426 ------------------------------------------------------------------------------ 3,861 3,500 Other, at or below cost 130 123 ------------------------------------------------------------------------------ Total investments and advances $3,991 $3,623 ==============================================================================
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.
Tengizchevroil (TCO) is a 50 percent owned joint venture formed in 1993 with the Republic of Kazakhstan to develop the Tengiz and Korolev oil fields over a 40-year period. The investment in TCO at December 31, 1994 and 1993 included a deferred payment portion of $466 and $709 respectively, $420 of which is payable to the Republic of Kazakhstan upon the attainment of a dedicated export system with the capability of the greater of 260,000 barrels of oil per day or TCO's production capacity. This portion of the investment was recorded upon formation of the venture as the company believed at the time, and continues to believe, that its payment is beyond a reasonable doubt given the original intent and continuing commitment of both parties to realizing the full potential of the venture over its 40-year life.
Equity in earnings of companies accounted for by the equity method, together with dividends and similar distributions received from equity method companies for the years 1994, 1993 and 1992, are as follows:
YEAR ENDED DECEMBER 31 ----------------------------------------------------- EQUITY IN EARNINGS DIVIDENDS ------------------------- ------------------------- 1994 1993 1992 1994 1993 1992 ------------------------------------------------------------------------------ Caltex Group $350 $361 $334* $239 $172 $183 Tengizchevroil (10) (1) - - - - Other affiliates 100 80 72 146 95 79 ------------------------------------------------------------------------------ Total $440 $440 $406 $385 $267 $262 ============================================================================== * BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES.
The company's transactions with affiliated companies, primarily for the purchase of Indonesian crude oil from P.T. Caltex Pacific Indonesia and the sale of crude oil and products to Caltex Petroleum Corporation's refining and marketing companies, are summarized in the adjacent table.
Accounts and notes receivable in the consolidated balance sheet include $135 and $156 at December 31, 1994 and 1993, respectively, of amounts due from affiliated companies. Accounts payable include $46 and $35 at December 31, 1994 and 1993, respectively, of amounts due to affiliated companies.
YEAR ENDED DECEMBER 31 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ Sales to Caltex Group $1,166 $1,739 $1,784 Sales to other affiliates 7 5 5 ------------------------------------------------------------------------------ Total sales to affiliates $1,173 $1,744 $1,789 ============================================================================== Purchases from Caltex Group $ 800 $ 842 $ 797 Purchases from other affiliates 52 101 56 ------------------------------------------------------------------------------ Total purchases from affiliates $ 852 $ 943 $ 853 ==============================================================================
The following tables summarize the combined financial information for the Caltex Group and substantially all of the other equity method companies together with Chevron's share. Amounts shown for the affiliates are 100 percent.
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NOTE 12. PROPERTIES, PLANT AND EQUIPMENT
Expenses for maintenance and repairs were $928, $875 and $1,045 in 1994, 1993 and 1992, respectively.
NOTE 13. TAXES
YEAR ENDED DECEMBER 31 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ Taxes Other Than on Income United States Taxes on production $ 102 $ 135 $ 140 Import duties 21 21 18 Excise taxes on products and merchandise 2,978 2,554 2,458 Property and other miscellaneous taxes 374 380 416 Payroll taxes 112 122 141 ------------------------------------------------------------------------------ Total United States 3,587 3,212 3,173 ------------------------------------------------------------------------------ International Taxes on production 14 7 30 Import duties 11 22 55 Excise taxes on products and merchandise 1,812 1,514 1,506 Property and other miscellaneous taxes 116 112 114 Payroll taxes 19 19 21 ------------------------------------------------------------------------------ Total International 1,972 1,674 1,726 ------------------------------------------------------------------------------ Total taxes other than on income $5,559 $4,886 $4,899 ------------------------------------------------------------------------------
U.S. federal income tax expense was reduced by $60, $57 and $49 in 1994, 1993 and 1992, respectively, for low-income housing and other business tax credits.
In 1994, before-tax income for U.S. operations was $1,194 compared with $687 in 1993 and $1,592 in 1992. Before-tax income for international operations was $1,609, $1,739 and $1,871 in 1994, 1993 and 1992, respectively.
YEAR ENDED DECEMBER 31 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ Taxes on Income U.S. federal Current $ 175 $ 394 $ 329 Deferred 43 (241) (129) Deferred - Adjustment for enacted changes in tax laws/rates - 54 - State and local 10 63 54 ------------------------------------------------------------------------------ Total United States 228 270 254 ------------------------------------------------------------------------------ International Current 815 864 1,046 Deferred 67 48 (47) Deferred - Adjustment for enacted changes in tax laws/rates - (21) - ------------------------------------------------------------------------------ Total International 882 891 999 ------------------------------------------------------------------------------ Total taxes on income $1,110 $1,161 $1,253 ==============================================================================
The deferred income tax provisions included (costs) benefits of $(222), $98 and $163 related to properties, plant and equipment in 1994, 1993 and 1992, respectively. U.S. benefits were recorded in 1993 related to the U.S. refining and marketing restructuring provision.
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.
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NOTE 13. TAXES - Continued
The company's effective income tax rate varied from the U.S. statutory federal income tax rate because of the following:
YEAR ENDED DECEMBER 31 ------------------------------ 1994 1993 1992 ------------------------------------------------------------------------------ Statutory U.S. federal income tax rate 35.0% 35.0% 34.0% Effects of income taxes on international operations in excess of taxes at the U.S. statutory rate 18.5 15.6 15.2 Effects of asset dispositions - (0.6) (8.0) State and local taxes on income, net of U.S. federal income tax benefit 0.2 2.2 1.1 Prior-year tax adjustments (4.4) 3.0 (0.6) Effects of enacted changes in tax laws/rates on deferred tax liabilities - 1.3 - Tax credits (2.1) (2.4) (1.4) All others (3.2) (0.9) (0.9) ------------------------------------------------------------------------------ Consolidated companies 44.0 53.2 39.4 Effect of recording equity in income of certain affiliated companies on an after-tax basis (4.4) (5.3) (3.2) ------------------------------------------------------------------------------ Effective tax rate 39.6% 47.9% 36.2% ==============================================================================
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, 1994 and 1993, deferred taxes were classified in the consolidated balance sheet, as follows:
AT DECEMBER 31 ------------------ 1994 1993 ------------------------------------------------------------------------------ Prepaid expenses and other current assets $ (112) $ (495) Deferred charges and other assets (148) (146) Federal and other taxes on income 18 27 Non-current deferred income taxes 2,674 2,916 ------------------------------------------------------------------------------ Total deferred taxes, net $2,432 $2,302 ==============================================================================
The reported deferred tax balances are composed of the following deferred tax liabilities (assets):
AT DECEMBER 31 ------------------ 1994 1993* ------------------------------------------------------------------------------ Properties, plant and equipment $4,451 $4,201 Inventory 240 293 Miscellaneous 254 237 ------------------------------------------------------------------------------ Deferred tax liabilities 4,945 4,731 ------------------------------------------------------------------------------ Abandonment/environmental reserves (1,066) (910) Employee benefits (564) (535) AMT/other tax credits (711) (486) Other accrued liabilities (299) (472) Miscellaneous (523) (523) ------------------------------------------------------------------------------ Deferred tax assets (3,163) (2,926) ------------------------------------------------------------------------------ Deferred tax assets valuation allowance 650 497 ------------------------------------------------------------------------------ Total deferred taxes, net $2,432 $2,302 ============================================================================== * CERTAIN 1993 AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE 1994 PRESENTATION.
It is the company's policy for subsidiaries included in the U.S. consolidated tax return to record income tax expense as though they filed separately, with the parent recording the adjustment to income tax expense for the effects of consolidation.
Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $3,815 at December 31, 1994. Substantially all of this amount represents earnings reinvested as part of the company's ongoing business. It is not practical to estimate the amount of taxes that might be payable on the eventual remittance of such earnings. On remittance, certain countries impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any. The company estimates withholding taxes of approximately $258 would be payable upon remittance of these earnings.
NOTE 14. SHORT-TERM DEBT
AT DECEMBER 31 ----------------- 1994 1993 ------------------------------------------------------------------------------ Commercial paper (1) $5,036 $4,391 Current maturities of long-term debt 134 167 Current maturities of long-term capital leases 33 23 Redeemable long-term obligations Long-term debt 315 297 Capital leases 273 255 Notes payable 23 203 ------------------------------------------------------------------------------ Subtotal (2) 5,814 5,336 Reclassified to long-term debt (1,800) (1,880) ------------------------------------------------------------------------------ Total short-term debt $4,014 $3,456 ============================================================================== (1) WEIGHTED AVERAGE INTEREST RATES AT DECEMBER 31, 1994 AND 1993 WERE 6.0% AND 3.3%, RESPECTIVELY. (2) WEIGHTED AVERAGE INTEREST RATES AT DECEMBER 31, 1994 AND 1993 WERE 5.8% AND 3.4%, RESPECTIVELY.
Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.
NOTE 15. LONG-TERM DEBT
AT DECEMBER 31 ----------------- 1994 1993 ------------------------------------------------------------------------------ 8.11% amortizing notes due 2004 (1) $ 750 $ 750 7.45% notes due 2004 348 - 9.375% sinking-fund debentures due 2016 278 278 5.6% notes due 1998 190 190 9.75% sinking-fund debentures due 2017 180 179 4.625% 200 million Swiss franc issue due 1997 152 136 6.90% serial notes due 1994-1997 (1),(2) 150 190 7.875% notes due 1997 (3) - 200 Other long-term obligations (7.02%) (2) (less than $50 individually) 183 223 Other foreign currency obligations (5.45%) (2) 58 78 ------------------------------------------------------------------------------ Total including debt due within one year 2,289 2,224 Debt due within one year (134) (167) Reclassified from short-term debt (6.0%) (2) 1,800 1,880 ------------------------------------------------------------------------------ Total long-term debt $3,955 $3,937 ============================================================================== (1) GUARANTEE OF ESOP DEBT. (2) WEIGHTED AVERAGE INTEREST RATE AT DECEMBER 31, 1994. (3) DEBT RETIRED BEFORE MATURITY DATE.
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NOTE 15. LONG-TERM DEBT - Continued
Chevron and one of its wholly owned subsidiaries each have "shelf" registrations on file with the Securities and Exchange Commission (SEC) that together would permit the issuance of $700 of debt securities pursuant to Rule 415 of the Securities Act of 1933.
At year-end 1994, the company had $4,425 of committed credit facilities with banks worldwide, $1,800 of which had termination dates beyond one year. The facilities support the company's commercial paper borrowings. Interest on any borrowings under the agreements is based on either the London Interbank Offered Rate or the Reserve Adjusted Domestic Certificate of Deposit Rate. No amounts were outstanding under these credit agreements during the year nor at year-end.
At December 31, 1994 and 1993, the company classified $1,800 and $1,880, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 1995, as the company has both the intent and ability to refinance this debt on a long-term basis.
Consolidated long-term debt maturing in each of the five years after December 31, 1994, is as follows: 1995-$134, 1996-$98, 1997-$246, 1998-$276 and 1999-$94.
NOTE 16. EMPLOYEE BENEFIT PLANS
PENSION PLANS. The company has defined benefit pension plans for most employees. The principal plans provide for automatic membership on a non-contributory basis. The retirement benefits provided by these plans are based primarily on years of service and on average career earnings or the highest consecutive three years' average earnings. The company's policy is to fund at least the minimum necessary to satisfy requirements of the Employee Retirement Income Security Act.
The net pension expense (credit) for all of the company's pension plans for the years 1994, 1993 and 1992 consisted of:
1994 1993 1992 ------------------------------------------------------------------------------ Cost of benefits earned during the year $ 97 $103 $106 Interest cost on projected benefit obligations 263 276 302 Actual return on plan assets (62) (472) (309) Net amortization and deferral (294) 101 (134) ------------------------------------------------------------------------------ Net pension expense (credits) $ 4 $ 8 $(35) ==============================================================================
Settlement gains in 1994, related to lump-sum payments, totaled $17. In addition to the net pension expense in 1993, the company recognized a net settlement loss of $63 and a curtailment loss of $4 reflecting the termination of a former Gulf pension plan and lump-sum payments from other company pension plans. In 1992, the company recorded charges of $65 and a curtailment loss of $7, offset by net lump-sum settlement gains of $101 related to an early retirement program offered to employees of its U.S. and certain Canadian subsidiaries.
At December 31, 1994 and 1993, the weighted average discount rates and long-term rates for compensation increases used for estimating the benefit obligations and the expected rates of return on plan assets were as follows:
1994 1993 ------------------------------------------------------------------------------ Assumed discount rates 8.8% 7.4% Assumed rates for compensation increases 5.1% 5.1% Expected return on plan assets 10.1% 9.1% ==============================================================================
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, 1994 and 1993, was as follows:
PLANS WITH PLANS WITH ASSETS ACCUMULATED IN EXCESS OF BENEFITS ACCUMULATED IN EXCESS OF BENEFITS PLAN ASSETS ----------------- ----------------- AT DECEMBER 31 1994 1993 1994 1993 ------------------------------------------------------------------------------ Actuarial present value of: Vested benefit obligations $(2,596) $(2,854) $ (186) $ (183) ============================================================================== Accumulated benefit obligations $(2,680) $(2,949) $ (194) $ (194) ============================================================================== Projected benefit obligations $(3,053) $(3,456) $ (222) $ (229) Plan assets at fair values 3,626 3,831 - 1 ------------------------------------------------------------------------------ Plan assets greater (less) than projected benefit obligations 573 375 (222) (228) Unrecognized net transition (assets) liabilities (294) (349) 18 20 Unrecognized net (gains) losses (178) 41 54 74 Unrecognized prior service costs 113 84 6 7 Minimum liability adjustment - - (80) (52) ------------------------------------------------------------------------------ Net pension cost prepaid (accrued) $ 214 $ 151 $ (224) $ (179) ==============================================================================
The net transition assets and liabilities generally are being amortized by the straight-line method over 15 years.
PROFIT SHARING/SAVINGS PLAN AND SAVINGS PLUS PLAN. Eligible employees of the company and certain of its subsidiaries who have completed one year of service may participate in the Profit Sharing/Savings Plan and the Savings Plus Plan. Charges to expense for the profit sharing part of the Profit Sharing/Savings Plan and the Savings Plus Plan were $75, $95 and $84 in 1994, 1993 and 1992, respectively.
EMPLOYEE STOCK OWNERSHIP PLAN (ESOP). In December 1989, the company established an ESOP as part of the Profit Sharing/Savings Plan. The ESOP Trust Fund borrowed $1,000 and purchased 28.2 million previously unissued shares of the company's common stock. The ESOP provides a partial pre-funding of the company's future commitments to the profit sharing part of the Plan, which will result in annual income tax savings for the company. The ESOP is expected to satisfy most of the company's obligations to the profit sharing part of the Plan during the next 10 years.
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NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
As allowed by AICPA Statement of Position (SOP) 93-6, the company has elected to continue its current practices which are based on SOP 76-3 and subsequent consensuses of the Emerging Issues Task Force of the Financial Accounting Standards Board. Accordingly, the debt of the ESOP is recorded as debt and shares pledged as collateral are reported as deferred compensation in the consolidated balance sheet and statement of stockholders' equity. The company reports compensation expense equal to the ESOP debt principal repayments less dividends received by the ESOP. Interest incurred on the ESOP debt is recorded as interest expense. Dividends paid on ESOP shares are reflected as a reduction of retained earnings. All ESOP shares are considered outstanding for earnings-per-share computations.
The company recorded expense for the ESOP of $42, $60 and $50 in 1994, 1993 and 1992, respectively, including $71, $74 and $75 of interest expense related to the ESOP debt. All dividends paid on the shares held by the ESOP are used to service the ESOP debt. The dividends used were $50, $47 and $35 in 1994, 1993 and 1992, respectively.
The company made contributions to the ESOP of $63, $57 and $18 in 1994, 1993 and 1992, respectively, to satisfy ESOP debt service in excess of dividends received by the ESOP. The ESOP shares were pledged as collateral for its debt. Shares are released from a suspense account and allocated to profit sharing accounts of plan participants, based on the debt service deemed to be paid in the year in proportion to the total of current year and remaining debt service. Compensation expense was $(10), $(17) and $(35) in 1994, 1993 and 1992, respectively. The ESOP shares as of December 31 were as follows:
THOUSANDS 1994 1993 ------------------------------------------------------------------------------ Allocated shares 5,969 5,010 Unallocated shares 21,208 22,452 ------------------------------------------------------------------------------ Total ESOP shares 27,177 27,462 ==============================================================================
MANAGEMENT INCENTIVE PLANS. The company has two incentive plans, the Management Incentive Plan (MIP) and the Long-Term Incentive Plan (LTIP) for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. The MIP makes outright distributions of cash for services rendered or deferred awards in the form of stock units. Awards under LTIP may take the form of, but are not limited to, stock options, restricted stock, stock units and non-stock grants. Stock options become exercisable not earlier than one year and not later than 10 years from the date of grant.
The maximum number of shares of common stock that may be granted each year is 1 percent of the total outstanding shares of common stock as of January 1 of such year. As of December 31, 1994, 5,845,260 shares were under option at exercise prices ranging from $31.9375 to $43.875 per share. Stock option transactions for 1994 and 1993 are as follows:
AT DECEMBER 31 ------------------ THOUSANDS OF SHARES 1994 1993 ------------------------------------------------------------------------------ Outstanding January 1 4,303 3,934 Granted 1,770 1,413 Exercised (140) (1,019) Forfeited (88) (25) ------------------------------------------------------------------------------ Outstanding December 31 5,845 4,303 ------------------------------------------------------------------------------ Exercisable December 31 4,152 2,912 ==============================================================================
Charges to expense for the combined management incentive plans were $31, $36 and $20 in 1994, 1993 and 1992, respectively.
OTHER BENEFIT PLANS. In addition to providing pension benefits, the company makes contributions toward certain health care and life insurance plans for active and qualifying retired employees. Substantially all employees in the United States and in certain international locations may become eligible for coverage under these benefit plans. The company's annual contributions for medical and dental benefits are limited to the lesser of actual medical and dental claims or a defined fixed per capita amount. Life insurance benefits are paid by the company and annual contributions are based on actual plan experience.
Non-pension postretirement benefits are funded by the company when incurred. A reconciliation of the funded status of these benefit plans is as follows:
AT DECEMBER 31, 1994 AT DECEMBER 31, 1993 -------------------------- -------------------------- HEALTH LIFE TOTAL HEALTH LIFE TOTAL ------------------------------------------------------------------------------ Accumulated postretirement benefit obligation (APBO) Retirees $(480) $(262) $ (742) $(593) $(320) $ (913) Fully eligible active participants (120) (57) (177) (139) (64) (203) Other active participants (190) (37) (227) (271) (56) (327) ------------------------------------------------------------------------------ Total APBO (790) (356) (1,146) (1,003) (440) (1,443) Fair value of plan assets - - - - - - ------------------------------------------------------------------------------ APBO (greater) than plan assets (790) (356) (1,146) (1,003) (440) (1,443) Unrecognized net (gain) loss (195) (66) (261) 63 25 88 ------------------------------------------------------------------------------ Accrued postretirement benefit costs $(985) $(422) $(1,407) $(940) $(415) $(1,355) ==============================================================================
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NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
The company's net postretirement benefits expense was as follows:
1994 1993 1992 ----------------- ----------------- ----------------- HEALTH LIFE TOTAL HEALTH LIFE TOTAL HEALTH LIFE TOTAL ------------------------------------------------------------------------------ Cost of benefits earned during the year $23 $ 4 $ 27 $23 $ 3 $ 26 $23 $ 4 $ 27 Interest cost on benefit obligation 71 31 102 76 30 106 70 30 100 ------------------------------------------------------------------------------ Net post-retirement benefits expense $94 $35 $129 $99 $33 $132 $93 $34 $127 ==============================================================================
For measurement purposes, separate health care cost-trend rates were utilized for pre-age 65 and post-age 65 retirees. The 1995 annual rates of increase were assumed to be 4.0 percent and 4.3 percent, respectively, increasing to 8.5 percent and 7.7 percent in 1996 and gradually decreasing thereafter to the average ultimate rates of 6.0 percent in 2000 for pre-age 65 and 5.0 percent in 2000 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 1994 by $13 and would increase the December 31, 1994 accumulated postretirement benefit obligation (APBO) by $105.
At December 31, 1994, the weighted average discount rate was 8.75 percent and the assumed rate of compensation increase related to the measurement of the life insurance benefit was 5.0 percent.
NOTE 17. OTHER CONTINGENT LIABILITIES AND COMMITMENTS The U.S. federal income tax and California franchise tax liabilities of the company have been settled through 1976 and 1987, respectively. For federal income tax purposes, all issues other than the allocation of state income taxes and the creditability of taxes paid to the Government of Indonesia have been resolved through 1987. The Indonesia issue applies only to years after 1982. Settlement of open tax matters is not expected to have a material effect on the consolidated net assets or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years either under examination or subject to future examination.
At December 31, 1994, the company and its subsidiaries, as direct or indirect guarantors, had contingent liabilities of $249 for notes of affiliated companies and $55 for notes of others.
The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, throughput agreements and take-or-pay agreements, some of which relate to suppliers' financing arrangements. The aggregate amount of required payments under these various commitments are: 1995-$141; 1996-$137; 1997-$102; 1998-$89; 1999-$86; 2000 and after-$497. Total payments under the agreements were $154 in 1994, $142 in 1993 and $128 in 1992.
In March 1992, an agency within the Department of Energy (DOE) issued a Proposed Remedial Order (PRO) claiming Chevron failed to comply with DOE regulations in the course of its participation in the Tertiary Incentive Program. Although the DOE regulations involved were rescinded in March 1981, following decontrol of crude oil prices in January 1981, and the statute authorizing the regulations expired in September 1981, the PRO purports to be for the period April 1980 through April 1990. The PRO claimed the company overrecouped under the regulations by $125 during the period in question. Including interest through December 1994, the total claim amounted to $295. The DOE is seeking to increase the claim by an additional $42, plus interest, of alleged over-recovery. The company asserts that in fact it incurred a loss through participation in the DOE program. Discovery has been completed and evidentiary hearings are in progress before the Office of Hearings and Appeals.
The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior disposal or release of chemical or petroleum substances by the company or other parties. Such contingencies may exist for various sites including, but not limited to: Superfund sites and refineries, oil fields, service stations, terminals and land development areas, whether operating, closed or sold. The amount of such future cost is indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties and the extent to which such costs are recoverable from third parties. While the company provides for known environmental obligations that are probable and reasonably estimable, the amount of future costs may be material to results of operations in the period in which they are recognized.
The company's operations, particularly oil and gas exploration and production, can be affected by changing economic, regulatory and political environments in the various countries, including the United States, in which it operates. In certain locations, host governments have imposed restrictions, controls and taxes, and, in others, political conditions have existed that may threaten the safety of employees and the company's continued presence in those countries. Internal unrest or strained relations between a host government and the company or other governments may affect the company's operations. Those developments have, at times, significantly affected the company's related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries.
Areas in which the company has significant operations include the United States, Australia, United Kingdom, Canada, Nigeria, Angola, Congo, Papua New Guinea, China, Indonesia and Zaire. The company's Caltex affiliates have significant operations in Indonesia, Japan, Korea, Australia, the Philippines, Thailand and South Africa. The company's Tengizchevroil affiliate operates in Kazakhstan. FS-29
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES Unaudited
In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities" (SFAS 69), this section provides supplemental information on oil and gas exploration and producing activities of the company in six separate tables. The first three tables provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the company's estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The Africa geographic area includes activities in Nigeria, Angola, Zaire, Congo and other countries. The "Other" geographic category includes activities in Australia, the United Kingdom North Sea, Canada, Papua New Guinea 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)
FS-30
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued Unaudited
TABLE II - CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
FS-31
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued Unaudited
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1)
The company's results of operations from oil and gas producing activities for the years 1994, 1993 and 1992 are shown below.
Net income from exploration and production activities as reported on page FS-7 reflects income taxes computed on an effective rate basis. In accordance with SFAS 69, income taxes below are based on statutory tax rates, reflecting allowable deductions and tax credits. Results reported below exclude any allocation of corporate overhead; net income for 1993 and 1992 reported on page FS-7 includes allocated corporate overhead, but 1994 does not. Interest expense is excluded from the results reported below and from the net income amounts on page FS-7.
FS-32
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued Unaudited
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1) - Continued
TABLE IV - RESERVE QUANTITIES INFORMATION
The company's estimated net proved underground oil and gas reserves and changes thereto for the years 1994, 1993 and 1992 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.
Proved reserves for Tengizchevroil (TCO), the company's 50 percent owned affiliate in Kazakhstan, do not include reserves that will be produced when a dedicated export system is in place.
FS-33
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued Unaudited
TABLE IV - RESERVE QUANTITIES INFORMATION - Continued
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
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - Continued 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
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with "Revisions of previous quantity estimates." The increase for 1994 reflected higher crude oil prices and natural gas reserve quantity increases, partially offset by lower natural gas prices. The decline from 1992 to 1993 was due primarily to lower crude oil prices.
FS-35
FIVE-YEAR FINANCIAL SUMMARY (1)
FS-36
CALTEX GROUP OF COMPANIES COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1994
C-1
CALTEX GROUP OF COMPANIES COMBINED FINANCIAL STATEMENTS DECEMBER 31, 1994
INDEX
PAGE -------------
General Information C-3 to C-4
Independent Auditors' Report C-5
Combined Balance Sheet C-6 to C-7
Combined Statement of Income C-8
Combined Statement of Retained Earnings C-9
Combined Statement of Cash Flows C-9
Notes to Combined Financial Statements C-10 to C-20
Note: Financial statement schedules are omitted as permitted by Rule 4.03 and Rule 5.04 of Regulation S-X.
C-2
CALTEX GROUP OF COMPANIES GENERAL INFORMATION
The Caltex Group of Companies (Group) is jointly owned 50% each by Chevron Corporation and Texaco Inc. The private joint venture was created in Bahrain in 1936 by its two owners to produce, transport, refine and market crude oil and refined products. The Group is comprised of the following companies:
- Caltex Petroleum Corporation, a company incorporated in Delaware, that through its many subsidiaries and affiliates, conducts refining, marketing and transporting activities in the Eastern Hemisphere;
- P. T. Caltex Pacific Indonesia, an exploration and production company incorporated and operating in Indonesia;
- American Overseas Petroleum Limited, a company incorporated in the Bahamas, that, through its subsidiaries, manages certain exploration and production operations in Indonesia in which Chevron and Texaco have interests, but not necessarily jointly or in the same properties.
A brief description of each company's operations and the Group's environmental activities follows:
Caltex Petroleum Corporation (Caltex) -------------------------------------
Through its subsidiaries and affiliates, Caltex operates in 61 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 920,000 barrels per day in 1994. 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 1994, Caltex had over 8,000 employees, of which about 3% were located in the United States.
With a strong presence in its principal operating areas, Caltex has an average market share of 17.4% with refined product sales of approximately 1.3 million barrels per day in 1994. Caltex built 119 new branded retail outlets during 1994 and refurbished 177 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, Dallas, Capetown, 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 through 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 1994 was 718,000 barrels per day. CPI entitlements are sold to its shareholders, who use it in their systems or sell it to third parties. At year end 1994, 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. Oil production is currently established in two contract areas, while exploration was being pursued in seven others. Before year end 1994, two of those seven exploration areas had been relinquished. The remaining area is in Darajat, West Java, which contains geothermal reserves sufficient to supply a 55- megawatt power generating plant for over 30 years. Production of the geothermal reserves began in 1994 and amounted to 62,185,795 KWH. AOPL's 1994 share of crude oil production amounted to 18,600 barrels per day. At year end, AOPL had 254 employees, of which about 13% 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, 1994, 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, 1994, the Group, including its equity share of nonsubsidiary companies, incurred capital costs of $233 million and nonremediation related operating expenses of $132 million. The major component of the Group's expenditures is for the prevention of air pollution. In addition, as of December 31, 1994, reserves relative to the future cost of restoring and abandoning existing oil and gas properties were $27 million. Based upon existing statutory and regulatory requirements, investment and operating plans and known exposures, the Group believes environmental expenditures will not materially affect its liquidity, financial position or results of operations.
C-4
INDEPENDENT AUDITORS' REPORT ----------------------------
TO THE STOCKHOLDERS THE CALTEX GROUP OF COMPANIES:
We have audited the accompanying combined balance sheets of the Caltex Group of Companies as of December 31, 1994 and 1993, 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, 1994. These combined financial statements
are the responsibility of the Group's management. Our responsibility is to express an opinion on these combined financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Caltex Group of Companies as of December 31, 1994 and 1993 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note 2 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 (SFAS) No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" and No. 109, "Accounting for Income Taxes." As discussed in Note 2, effective January 1, 1994, the Group adopted the provisions of the Financial Accounting Standards Board's SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities."
/s/ KPMG Peat Marwick LLP
Dallas, Texas February 14, 1995
C-5
CALTEX GROUP OF COMPANIES COMBINED BALANCE SHEET - DECEMBER 31, 1994 AND 1993 (MILLIONS OF DOLLARS)
ASSETS
1994 1993 ------- ------- CURRENT ASSETS:
Cash and cash equivalents (including time deposits of $136 in 1994 and $64 in 1993) $ 251 $ 166
Notes and accounts receivable, less allowance for doubtful accounts of $14 in 1994 and 1993: Trade 1,107 950 Other 187 155 Nonsubsidiary companies 88 112 ------- ------- 1,382 1,217 Inventories: Crude oil 132 148 Refined products 573 532 Materials and supplies 73 56 ------- ------- 778 736
Deferred income taxes 10 4 ------- ------- Total current assets 2,421 2,123
INVESTMENTS AND ADVANCES:
Nonsubsidiary companies at equity 2,370 1,796 Miscellaneous investments and long-term receivables, less allowance of $8 in 1994 and $7 in 1993 198 195 ------- ------- 2,568 1,991
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Producing 3,284 3,027 Refining 1,787 1,483 Marketing 2,552 2,252 Marine 35 35 Capitalized leases 119 119 ------- ------- 7,777 6,916
Less: Accumulated depreciation, depletion and amortization 3,165 2,878 ------- ------- 4,612 4,038 PREPAID AND DEFERRED CHARGES 209 237 ------- ------- Total assets $9,810 $8,389 ======= =======
See accompanying Notes to Combined Financial Statements.
C-6
CALTEX GROUP OF COMPANIES COMBINED BALANCE SHEET - DECEMBER 31, 1994 AND 1993 (MILLIONS OF DOLLARS)
LIABILITIES AND STOCKHOLDERS' EQUITY
1994 1993 ------- ------- CURRENT LIABILITIES:
Notes payable to banks and other financial institutions $1,229 $ 966
Long-term debt due within one year 157 51
Accounts payable: Trade and other 1,240 967 Stockholder companies 77 87 Nonsubsidiary companies 123 149 ------- ------- 1,440 1,203
Accrued liabilities 113 86
Estimated income taxes 133 105 ------- ------- Total current liabilities 3,072 2,411
LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS 715 530
ACCRUED LIABILITY FOR EMPLOYEE BENEFITS 113 98
DEFERRED CREDITS AND OTHER NON-CURRENT LIABILITIES 789 646
DEFERRED INCOME TAXES 236 263
MINORITY INTEREST IN SUBSIDIARY COMPANIES 152 146
STOCKHOLDERS' EQUITY:
Common stock 355 355 Additional paid-in capital 2 2 Retained earnings 3,898 3,688 Currency translation adjustment 399 250 Unrealized holding gain on investments 79 - ------- ------- Total stockholders' equity 4,733 4,295
COMMITMENTS AND CONTINGENT LIABILITIES ------- -------
Total liabilities and stockholders' equity $9,810 $8,389 ======= =======
See accompanying Notes to Combined Financial Statements.
C-7
CALTEX GROUP OF COMPANIES COMBINED STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 (MILLIONS OF DOLLARS)
1994 1993 1992 ------- ------- -------
SALES AND OTHER OPERATING REVENUES (1) $14,751 $15,409 $17,281
OPERATING CHARGES: Cost of sales and operating expenses (2) 12,801 13,431 15,348 Selling, general and administrative expenses 568 496 479 Depreciation, depletion and amortization 331 295 263 Maintenance and repairs 160 170 165 ------- ------- ------- 13,860 14,392 16,255
Operating income 891 1,017 1,026
OTHER INCOME (DEDUCTIONS): Equity in net income of nonsubsidiary companies 263 140 163 Dividends, interest and other income 134 99 83 Foreign exchange, net (73) 23 21 Interest expense (101) (93) (102) Minority interest in subsidiary companies (3) (8) (13) ------- ------- ------- 220 161 152 ------- ------- -------
Income before provision for income taxes and cumulative effects of changes in accounting principles 1,111 1,178 1,178 ------- ------- -------
PROVISION FOR INCOME TAXES: Current 467 433 456 Deferred (45) 25 53 ------- ------- ------- Total provision for income taxes 422 458 509 ------- ------- -------
Income before cumulative effects of changes in accounting principles 689 720 669 Cumulative effects of changes in accounting principles - - 51 ------- ------- ------- Net income $ 689 $ 720 $ 720 ======= ======= ======= (1) Includes sales to: Stockholder companies $ 1,192 $ 907 $ 835 Nonsubsidiary companies $ 1,044 $ 944 $ 924
(2) Includes purchases from: Stockholder companies $ 1,800 $ 3,333 $ 3,917 Nonsubsidiary companies $ 1,612 $ 1,385 $ 641
See accompanying Notes to Combined Financial Statements.
C-8
CALTEX GROUP OF COMPANIES COMBINED STATEMENT OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 (MILLIONS OF DOLLARS)
1994 1993 1992 ------- ------- ------- Balance at beginning of year $3,688 $3,310 $2,955 Net income 689 720 720 Cash dividends (479) (342) (365) ------- ------- ------- Balance at end of year $3,898 $3,688 $3,310 ======= ======= =======
COMBINED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 (MILLIONS OF DOLLARS)
1994 1993 1992
------- ------- ------- OPERATING ACTIVITIES: Net income $689 $720 $720 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effects of changes in accounting principles - - (51) Depreciation, depletion and amortization 331 295 263 Dividends from nonsubsidiary companies, less than equity in net income (220) (103) (133) Net gains on asset sales (17) (4) (4) Deferred income taxes (45) 25 53 Prepaid charges and deferred credits 115 (41) 25 Changes in operating working capital 58 31 (58) Other 77 10 (46) ------- ------- ------- Net cash provided by operating activities 988 933 769 ------- ------- -------
INVESTING ACTIVITIES: Capital expenditures (837) (763) (711) Investments in and advances to nonsubsidiary companies (131) (149) (17) Net purchases/sales of investment instruments 14 (21) (11) Proceeds from asset sales 37 73 144 ------- ------- ------- Net cash used in investing activities (917) (860) (595)
FINANCING ACTIVITIES: Proceeds from borrowings having original terms in excess of three months 1,257 745 831 Repayments of borrowings having original terms in excess of three months (880) (704) (857) Net increase in other borrowings 135 140 94 Dividends paid, including minority interest (482) (342) (365) ------- ------- ------- Net cash provided by (used in) financing activities 30 (161) (297) ------- ------- ------- Effect of exchange rate changes on cash and cash equivalents (16) 15 (8) ------- ------- ------- NET CHANGE IN CASH AND CASH EQUIVALENTS 85 (73) (131) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 166 239 370 ------- ------- ------- CASH AND CASH EQUIVALENTS AT END OF YEAR $251 $166 $239 ======= ======= =======
See accompanying Notes to Combined Financial Statements.
C-9
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF COMBINATION
The combined financial statements of the Caltex Group of Companies (Group) include the accounts of Caltex Petroleum Corporation and subsidiaries, American Overseas Petroleum Limited and subsidiary and P.T. Caltex Pacific Indonesia after the elimination of intercompany balances and transactions. 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.
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
ENVIRONMENTAL MATTERS
Compliance with environmental regulations is determined in consideration of the existing laws in each of the countries in which the Group operates and the Group's own internal standards. The Group capitalizes expenditures that create future benefits or contribute to future revenue generation. Remediation costs are accrued based on estimates of known environmental exposure even if uncertainties exist about the ultimate cost of the remediation. Such accruals are based on the best available nondiscounted estimated costs using data developed by third party experts. Costs of environmental compliance for past and ongoing operations, including maintenance and monitoring, are expensed as incurred. Recoveries from third parties are recorded as assets when realization is determined to be probable.
(2) CHANGES IN ACCOUNTING PRINCIPLES
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. The adoption of SFAS No. 106 resulted in a cumulative after-tax charge of $26 million.
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. The adoption of SFAS No. 109 resulted in a cumulative benefit of $77 million.
Effective January 1, 1994, the Group adopted SFAS No. 112 "Employers' Accounting for Postemployment Benefits." SFAS No. 112 requires companies to accrue for the cost for benefits provided to former or inactive employees after employment but prior to retirement. Adoption of this standard did not materially impact the combined financial statements of the Group.
The Group adopted SFAS No. 115 "Accounting for Certain Investments in Debt and Equity Securities" effective January 1, 1994. SFAS No. 115 requires that investments in equity securities that have readily determinable fair values and all investments in debt securities be classified into three categories based on management's intent. Such investments are to be reported at fair value except for debt securities intended to be held to maturity which are to be reported at amortized cost. Previously, all such investments were accounted for at amortized cost. The cumulative effect of this change at January 1, 1994 was an increase in stockholders' equity of $70 million, after related taxes, representing unrealized net gains applicable to securities categorized as available-for-sale under the new standard. Such securities are primarily held by nonsubsidiary companies accounted for by the equity method.
C-11
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(3) INVENTORIES
The excess of current cost over the stated value of inventory maintained on the LIFO basis was approximately $56 million and $40 million at December 31, 1994 and 1993, respectively.
During 1994, 1993 and 1992, inventory quantities maintained on the LIFO basis were reduced at certain locations. The inventory reductions resulted in a decrease in the earnings of consolidated subsidiaries and nonsubsidiary companies at equity of approximately $12 million and $2 million in 1994 and 1992, respectively, and an increase in earnings of $1 million in 1993.
Charges of $104 million reduced income in 1993 to reflect a market value of certain inventories lower than their LIFO carrying value. Earnings of $34 million and $14 million were recorded in 1994 and 1992, respectively, to reflect a partial recovery of prior year charges.
(4) NONSUBSIDIARY COMPANIES AT EQUITY
Investments in and advances to nonsubsidiary companies at equity at December 31 include the following (in millions):
Equity Share 1994 1993 ------------ ------- -------
Nippon Petroleum Refining Company, Ltd. 50% $ 997 $ 829 Koa Oil Company, Ltd. 50% 448 310 Honam Oil Refinery Company, Ltd. 50% 557 423 All other Various 368 234 ------- ------- $2,370 $1,796 ======= =======
Shown below is summarized combined financial information for these nonsubsidiary companies (in millions):
100% Equity Share ------------------ ------------------ 1994 1993 1994 1993
------- ------- ------- ------- Current assets $5,352 $4,680 $2,651 $2,316 Other assets 7,821 6,147 3,858 2,975
Current liabilities 4,940 4,900 2,363 2,349 Other liabilities 3,504 2,306 1,776 1,146 Net worth 4,729 3,621 2,370 1,796
100% Equity Share ------------------------- ------------------------- 1994 1993 1992 1994 1993 1992 ------------------------- ------------------------- Operating revenues $10,886 $10,679 $10,502 $5,418 $5,304 $5,216 Operating income 770 494 645 381 242 319 Net income 526 281 326 263 140 163
C-12
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(4) NONSUBSIDIARY COMPANIES AT EQUITY - CONTINUED
Retained earnings at December 31, 1994, includes $1.4 billion representing the Group's share of undistributed earnings of nonsubsidiary companies at equity.
Cash dividends received from these nonsubsidiary companies were $43 million, $37 million, and $30 million in 1994, 1993, and 1992, 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 $2 billion, $1.9 billion, and $2 billion in 1994, 1993, and 1992, respectively.
(5) NOTES PAYABLE
Short-term financing consists primarily of demand loans, promissory notes, acceptance credits and overdrafts. The weighted average interest rates on short-term financing at December 31, 1994, and 1993 were 6.8% and 4.7%, respectively.
Unutilized lines of credit available for short-term financing totaled $678 million at December 31, 1994.
(6) LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
Long-term debt and capital lease obligations, with related interest rates at December 31, 1994, consist of the following (in millions):
1994 1993 ------- -------
U.S. dollars: Variable interest rate term loans $233 $173 Fixed interest rate term loans with 7.6% average rate 206 220 Australian dollars: Debentures with interest rates at 12.5% due 1996 4 8 Promissory notes payable with 7.2% average rate 81 76 Fixed interest rate loan with 11.2% rate due 2001 132 - Commercial paper with 7.0% average rate 23 - Capital lease obligations 11 33 New Zealand dollars: Term loans with interest rates 6-6.35% due 1996-1997 16 14 Other 9 6 ------- ------- $715 $530 ======= =======
C-13
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(6) LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS - CONTINUED
At December 31, 1994 and 1993, $124 million and $101 million, respectively, of short-term borrowings were classified as long-term debt. Settlement of these obligations is not expected to require the use of working capital in 1995, as the Group has both the intent and ability to refinance this debt on a long-term basis. At December 31, 1994 and 1993, $170 million and $101 million, respectively, of long-term committed credit facilities were available with major banks to support notes payable classified as long-term debt.
Contractual maturities subsequent to December 31, 1994 follow (in millions): 1995 - $157 (included on the combined balance sheet as a current liability and excluding short-term borrowings classified as long-term debt); 1996 - $101; 1997 - $61; 1998 - $94; 1999 - $137; 2000 and thereafter - $322.
(7) EMPLOYEE BENEFITS
The Group has retirement plans covering substantially all eligible employees. Generally, these plans provide defined benefits based on final or final average pay, as defined. The benefit levels, vesting terms and funding practices vary among plans.
The funded status of retirement plans, primarily foreign and inclusive of nonsubsidiary companies at equity, at December 31 follows (in millions):
Assets Exceed Accumulated Accumulated Benefits Funding Status Benefits Exceed Assets -------------- ------------- -------------
1994 1993 1994 1993 ------ ------ ------ ------
Actuarial present value of: Vested benefit obligation $282 $280 $137 $117 Accumulated benefit obligation 317 309 161 137 Projected benefit obligation 493 484 225 195
Amount of assets available for benefits: Funded assets at fair value $435 $450 $ 58 $ 39 Net pension (asset) liability recorded (8) (11) 136 128 ------ ------ ------ ------ Total assets $427 $439 $194 $167 ====== ====== ====== ======
Assets less than projected benefit obligation $(66) $(45) $(31) $(28)
Consisting of: Unrecognized transition net assets (liabilities) 16 31 (3) (2) Unrecognized net losses (55) (44) (25) (23) Unrecognized prior service costs (27) (32) (3) (3)
Weighted average rate assumptions: Discount rate 9.7% 9.5% 6.6% 6.5% Rate of increase in compensation 7.2% 7.4% 4.6% 4.7% Expected return on plan assets 10.2% 10.3% 5.5% 5.5%
C-14
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(7) EMPLOYEE BENEFITS - CONTINUED
Expenses (Funded & Unfunded Combined) 1994 1993 1992 -------- ------ ------- ------- Cost of benefits earned during the year $27 $27 $26 Interest cost on projected benefit obligation 55 58 54 Actual return on plan assets (23) (59) (9) Net amortization and deferral (16) 16 (38) ------ ------- ------- $43 $42 $33 ====== ======= =======
(8) OPERATING LEASES
The Group has various operating leases involving service stations, equipment and other facilities for which net rental expense was $121 million, $110 million, and $95 million in 1994, 1993 and 1992, respectively.
Future net minimum rental commitments under operating leases having noncancelable terms in excess of one year are as follows (in millions): 1995 - $55; 1996 - $67; 1997 - $52; 1998 - $47; 1999 - $44; 2000 and thereafter - $106.
(9) COMMITMENTS AND CONTINGENCIES
On January 25, 1990, Caltex Petroleum Corporation and certain of its subsidiaries were named as defendants, along with privately held Philippine ferry and shipping companies and the shipping company's insurer, in a lawsuit filed in Houston, Texas State Court. After removal to Federal District Court in Houston, the litigation's disposition turned on questions of federal court jurisdiction and whether the case should be dismissed for forum non conveniens. The plaintiffs' petition purported to be a class action on behalf of at least 3,350 parties, who were either survivors of, or next of kin of persons deceased in a collision in Philippine waters on December 20, 1987. One vessel involved in the collision was carrying Group products in connection with a freight contract. Although the Group had no direct or indirect ownership in or operational responsibility for either vessel, various theories of liability were alleged against the Group. No specific monetary recovery was sought although the petition contained a variety of demands for various categories of compensatory as well as punitive damages. These issues were resolved in the Group's favor by the Federal District Court in March 1992, through a forum non conveniens dismissal, and that decision is now final. Subsequent to that dismissal, but consistent with its terms, cases were filed against the Group entities in the Philippine courts (over and above those previously filed there subsequent to the collision, all of which are in various stages of litigation and are being vigorously resisted). However, and notwithstanding the Houston Federal District Court dismissal, the plaintiffs filed another lawsuit, alleging the same causes of action as in the Texas litigation, in Louisiana State Court in New Orleans. The Group removed that case to Federal District Court in New Orleans from which it was remanded back to Louisiana State Court. The Group then sought injunctive and other relief from the Federal District Court in Houston in order to ensure that that Court's previous dismissal would be given proper effect. On having its request for relief denied, the Group then filed an expedited appeal to the U. S. Fifth Circuit Court of Appeals. That Court's ruling is expected shortly. 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.
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CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(9) COMMITMENTS AND CONTINGENCIES - 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.
Unconditional purchase obligations in 1992 and 1993 were not considered material. However, in April 1994, a Group subsidiary entered into a contractual commitment, effective October 1996, for a period of eleven years, to purchase refined products in conjunction with the financing of a refinery that is presently under construction by a nonsubsidiary company. Total future estimated commitments (in billions) for the Group under this and other similar contracts, based on current pricing and projected growth rates, are: 1995 - $.6, 1996 - $.9, 1997 - $1.1, 1998 - $1.3, 1999 - $1.5, and 2000 to expiration of contracts - $9.6. Purchases (in billions) under similar contracts were $.5, $.6, and $.4 in 1994, 1993, and 1992, respectively.
The Group is in the process of finalizing sales of certain property required by a local government. The Group will be compensated for the value of the property transferred and the cost of replacing operating assets affected by the transfer. While the compensation is to be fully utilized in the reconstruction program over a five year period, the excess of the compensation over the net book value of the property and the dismantled operating assets will be recognized in earnings in early 1995. The impact to the Group's earnings is currently estimated to be a net after-tax gain of approximately $155 million.
(10) FINANCIAL INSTRUMENTS
Certain Group companies are parties to financial instruments with off-balance sheet credit and market risk, principally interest rate risk. As of December 31, the Group had commitments outstanding for interest rate swaps and foreign currency transactions for which the notional or contractual amounts are as follows (in millions):
1994 1993 ------- ------- Interest rate swaps - Pay Fixed, Receive Floating $363 $294 Interest rate swaps - Pay Floating, Receive Fixed $182 $ 50 Commitments to purchase foreign currencies $252 $244 Commitments to sell foreign currencies $274 $183
The Group enters into interest rate swaps in managing its interest rate risk, and their effects are recognized in the statement of income at the same time as the interest expense on the debt to which they relate. The swap contracts have remaining maturities up to eight years. The fair values of these swaps are not material.
The Group enters into forward exchange contracts to hedge against some of its foreign currency exposure stemming from existing liabilities and firm commitments. Forward exchange contracts hedging existing liabilities have maturities of up to seven years, and those contracts hedging firm commitments have maturities of under a year. Gains and losses on the forward exchange contracts are recognized in income concurrent with the income recognition of the underlying hedged transaction. The fair values of these forward exchange contracts are not material.
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CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(10) FINANCIAL INSTRUMENTS - CONTINUED
The Group's activity in commodity-based derivative contracts, that must be settled in cash, is not material.
The Group's long-term debt, excluding capital lease obligations, of $704 million and $497 million at December 31, 1994 and 1993, respectively, had fair values of $696 million and $511 million at December 31, 1994 and 1993, 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.
At December 31, 1994, the Group had investments in debt securities available- for-sale and debt securities held to maturity at amortized costs of $63 million (maturity less than ten years) and $77 million (maturity less than one year), respectively. The fair value of these securities approximates amortized costs. The investment in marketable equity securities is not material. At December 31, 1994, the Group's carrying amount for investments in nonsubsidiary companies accounted for at equity included $83 million for net-of-tax unrealized net gains on investments held by these nonsubsidiaries.
Certain Group companies were contingently liable as guarantors for $2 million and $7 million at December 31, 1994 and 1993, respectively. The Group also had commitments of $99 million and $36 million at December 31, 1994 and 1993, respectively, in the form of letters of credit which have been issued on behalf of Group companies to facilitate either the Group's or other parties' ability to trade in the normal course of business. In addition, the Group is contingently liable at December 31, 1994, for a maximum of $192 million, to a nonsubsidiary for precompletion sponsor support of its project finance obligations.
The Group is exposed to credit risks in the event of non-performance by counterparties to financial instruments. For financial instruments with institutions, the Group does not expect any counterparty to fail to meet their obligations given their high credit ratings. Other financial instruments exposed to credit risk consist primarily of trade receivables. These receivables are dispersed among the countries in which the Group operates, thus limiting concentrations of such risk.
The Group performs ongoing credit evaluations of its customers and generally does not require collateral. Letters of credit are the principal security obtained to support lines of credit when the financial strength of a customer or country is not considered sufficient. Credit losses have been historically within management's expectations.
(11) TAXES
Taxes charged to income consist of the following (in millions):
1994 1993 1992 ------- ------- ------- Taxes other than income taxes: Duties, import and excise taxes $2,384 $1,978 $1,891 Other 32 29 29 ------- ------- ------- Total taxes other than income taxes 2,416 2,007 1,920 Provision for income taxes 422 458 509 ------- ------- ------- $2,838 $2,465 $2,429 ======= ======= =======
C-17
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(11) TAXES - CONTINUED
The provision for income taxes, substantially all foreign, has been computed on an individual company basis at rates in effect in the various countries of operation. The actual tax expense differs from the "expected" tax expense (computed by applying the U.S. Federal corporate tax rate to income before provision for income taxes) as follows:
1994 1993 1992 ------- ------- ------- Computed "expected" tax expense 35.0% 35.0% 34.0%
Effect of recording equity in net income of nonsubsidiary companies on an after tax basis (8.3) (4.2) (4.9)
Effect of dividends received from subsidiary and nonsubsidiary companies 4.4 4.2 3.8
Foreign income subject to foreign taxes in excess of U.S. statutory tax rate 6.9 7.4 11.6
Increase/(Decrease) in deferred tax asset valuation allowance .3 (3.1) (.4)
Other (.3) (.4) (.9) ------- ------- ------- 38.0% 38.9% 43.2% ======= ======= =======
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, 1994 and 1993 are as follows (in millions):
Deferred Deferred Tax Assets Tax Liabilities ---------------- --------------- 1994 1993 1994 1993 ------ ------ ------ ------ Inventory $ 17 $ 10 $ 12 $ 18 Depreciation - - 310 298 Retirement plans 34 33 2 3 Tax loss carryforwards 27 29 - - Investment allowances 40 8 - - Other 30 20 41 34 ------ ------ ------ ------ 148 100 365 353 Valuation allowance (9) (6) - - Total deferred taxes $139 $ 94 $365 $353 ====== ====== ====== ======
C-18
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(11) TAXES - CONTINUED
The valuation allowance has been established to record deferred tax assets at amounts where recoverability is more likely than not. Net income was decreased in 1994 by $3 million and increased by $36 million and $5 million in 1993 and 1992, respectively, for changes in the deferred tax asset valuation allowance.
Undistributed earnings for which no deferred income tax provision has been made approximated $3.8 billion at December 31, 1994. Such earnings have been or are intended to be indefinitely reinvested. These earnings would become taxable in the U.S. only upon remittance as dividends. It is not practical to estimate the amount of tax that might be payable on the eventual remittance of such earnings. Upon remittance, certain foreign countries impose withholding taxes which, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.
(12) CASH FLOWS
For purposes of the statement of cash flows, all highly liquid debt instruments with original maturities of three months or less are considered cash equivalents.
The "Changes in Operating Working Capital" consists of the following (in millions):
1994 1993 1992 ------- ------- -------
Notes and accounts receivable $(97) $ 82 $ (45) Inventories (37) 66 (114) Accounts payable 152 (147) 212 Accrued liabilities 16 16 (27) Estimated income taxes 24 14 (84) ------- ------- ------- Total $ 58 $ 31 $ (58) ======= ======= =======
"Net Cash Provided by Operating Activities" includes the following cash payments for interest and income taxes (in millions):
1994 1993 1992 ------- ------- ------- Interest paid (net of capitalized interest) $ 94 $ 92 $106
Income taxes paid $444 $391 $528
No significant non-cash investing or financing transactions occurred in 1994, 1993 or 1992.
(13) OTHER
On December 14, 1994, Caltex Australia Limited (CAL), a subsidiary of the Group, entered into a conditional agreement to form a petroleum refining and marketing joint venture with Ampol Limited, a competitor, effective January 1, 1995. The agreement was subject to completion of certain conditions which included, among others, confirmation by the Australian Trade Practices Commission (TPC) that the merger would not contravene local laws. On February 2, 1995, CAL received notification of the TPC's opinion that the merger would lessen competition and, therefore, would contravene Australian regulations. CAL and Ampol Limited are currently evaluating alternative options to address the TPC ruling and have not yet formed a joint venture.
C-19
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(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-20