Item 1. Business
(a) General Development of Business
Summary Description of Chevron - ------------------------------ Chevron Corporation (1) , a Delaware corporation, provides administrative, financial and management support for, and manages its investments in, U.S. and foreign subsidiaries and affiliates which engage in fully integrated petroleum operations, chemicals operations and coal mining. The company operates in the United States and approximately 90 other countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipelines, marine vessels, motor equipment and rail car. Chemicals operations include the manufacture and marketing of a wide range of chemicals for industrial uses.
In this report, exploration and production of crude oil, natural gas liquids and natural gas may be referred to as "E&P" or "upstream" activities. Refining, marketing and transportation may be referred to as "RM&T" or "downstream" activities.
A list of the company's major subsidiaries is presented on page E-2 of this Annual Report on Form 10-K. As of December 31, 1997, Chevron had 39,362 employees, 74 percent of whom were employed in U.S. operations.
CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION FOR THE PURPOSE OF "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This annual report on Form 10-K contains forward-looking statements relating to Chevron's operations that are based on management's current expectations, estimates and projections about the petroleum and chemicals industries. Words such as "expects," "intends," "plans," "projects," "believes," "estimates" and similar expressions are used to identify such forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecast in such forward-looking statements.
Among the factors that could cause actual results to differ materially are crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for the company's aromatics, olefins and additives products; potential failure to achieve expected production from existing and future oil and gas development projects; potential disruption or interruption of the company's production or manufacturing facilities due to accidents or political events; potential liability for remedial actions under existing or future environmental regulations; and potential liability resulting from pending or future litigation. In addition, such statements could be affected by general domestic and international economic and political conditions. - ---------------------------------------------------
(1) Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984. 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 i.e. those companies accounted for by the equity method (generally 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.
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 usually 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.
Current Operating Environment - ----------------------------- The spot price for West Texas Intermediate (WTI), an industry benchmark light crude oil, averaged $25.17 per barrel in January 1997, as a result of strong heating fuel demand due to cold winter weather and low inventories. In February 1997, crude oil prices began to trend downwards as the winter weather turned mild and inventories began to build. Prices ranged from $19-$21 per barrel during most of the year until December 1997, when a number of factors began to exert downward pressure. Lower expected economic growth in Asia as a result of the region's financial crises, coupled with warm winters in the United States, Europe and Japan, reduced forecast demand. At the same time, crude oil supplies had increased both from OPEC and non-OPEC sources, resulting in an oversupplied world market. This has continued into the early months of 1998, causing crude oil prices to remain at relatively depressed levels. The spot WTI price reached a year-to-date low of $13.23 per barrel on March 17, 1998. Inventories remain at high levels.
In January 1997, cold winter weather together with concerns about tight supplies supported high U.S. prices for natural gas, with the benchmark Henry Hub Louisiana spot price averaging $3.47 per thousand cubic feet (MCF). Demand and prices for natural gas declined by over 25 percent during February 1997 as the winter weather turned mild in late January and concerns about availability dissipated. Prices fell by more than another 25 percent to an average of $1.88 per MCF in March. Until late summer, natural gas prices ranged from $2.00 - $2.20 per MCF. Prices then began to trend upwards until December 1997, as a result of a combination of factors, including concerns that the industry had not been able to sufficiently increase productive capacity to satisfy demand, lost production due to normal field declines, and the seasonal trend towards the end of the year in anticipation of colder weather. Prices have since trended downwards into 1998, mainly as a result of the mild winter weather in the United States. Spot natural gas prices averaged $2.57 per MCF in 1997 compared with $2.76 per MCF in 1996.
The company's average realization from U.S. crude oil production decreased to $17.68 per barrel in 1997 from $18.80 in 1996, while average liquids realizations from international liftings, including equity affiliates, decreased $1.51 per barrel to $17.97. Although industry average spot prices declined in 1997 from 1996, the company's average U.S. natural gas realizations from production increased by $0.14 per MCF in 1997 to $2.42 per MCF due to the timing of sales during the year.
For the first two months of 1998, average natural gas realizations for the company's U.S. operations were $2.06 per MCF compared with $3.34 for the same period in 1997. During this period, the company's posted price for WTI ranged from $17.00 per barrel to $14.50, with an average of $15.72 representing a 32 percent decline from the 1996 period. On March 20, 1998, the company's posted price for WTI was $13.50 per barrel.
The following table compares the high, low and average Chevron posted prices for WTI for each of the quarters during 1997 and for the full years of 1997, 1996, and 1995:
- ----------------------------------------------------------------------- West Texas Intermediate Crude Oil Chevron Posted Prices (Dollars per Barrel)
-------------------------------------------- 1st Q 2nd Q 3rd Q 4th Q Year 1996 1995 ----- ----- ----- ----- ---- ---- ---- High 25.75 21.25 20.50 22.00 25.75 25.50 19.50 Low 19.25 17.75 18.25 16.75 16.75 16.50 16.00 Average 22.02 19.17 19.00 19.24 19.85 21.00 17.40 - -----------------------------------------------------------------------
In 1997, Chevron's refining and marketing operations in the United States experienced increased demand for refined products and improved sales margins over 1996. Chevron's refined product sales volumes in the United States increased by about 6 percent to 1.2 million barrels per day. Although the company's average sales price per barrel of refined product in the United States was $28.93 per barrel in 1997, a decrease of $1.01 per barrel from 1996, margins improved significantly due to lower crude oil feedstock costs and operating expenses. Margins began narrowing in early 1998, despite continuing low crude oil prices, as competitive pressures forced refined products prices down and planned shutdowns at two refineries led to increased maintenance costs.
The chemicals industry entered a cyclical downturn in the latter half of 1995, which persisted throughout 1996 and 1997. Earnings from the company's chemicals operations in 1997, excluding special items, were nearly flat with those of 1996. Earnings for 1997 benefited from strong sales volumes and reduced depreciation expense, as a result of a reassessment and extension of the useful lives of certain assets. These benefits were offset by lower industry prices, higher feedstock and fuel costs, and expenses related to maintenance and expansion activities during the year. Sales volumes were strong for most of 1997. While margins improved for benzene and ethylene, industry overcapacity led to depressed margins for styrene, paraxylene and polystyrene. Sales and other operating revenues from the company's chemicals operations, including sales to other Chevron companies, totaled $3.633 billion, an increase of $92 million from the $3.541 billion in 1996.
Chevron Strategic Direction - --------------------------- The company is following certain strategies to improve its financial performance and to support its mission to create superior value for its stockholders, customers and employees. The company periodically reviews and modifies these "strategic intents" to reflect Chevron's current operating environment. In 1998, the company added a new strategic intent to accelerate growth in earnings from the Caspian Sea region, which is discussed below. The nine "strategic intents" for 1998 are:
Build a committed team to accomplish the corporate mission. - ----------------------------------------------------------- The company believes that the success of the other eight strategic intents is strongly linked to the level of commitment and dedication that Chevron employees bring to their jobs. Employees are guided by "The Chevron Way," a statement of the company's Mission and Vision and other key principles - Committed Team Values, Total Quality Management, Protecting People and the Environment and Vision Metrics - that establish a standard of excellence for each employee. The company has also made efforts to measure employees' attitudes about the company and diagnose areas of employee concerns over the past five years by the use of the Worldwide Employee Survey. As a result, many processes, including leadership training, diversity training, upward feedback and job selection, have been developed or revamped to address those concerns. A new employee survey is underway in 1998 to measure the company's progress in this area.
The company is also fostering employee commitment by sharing its financial success. In January 1995, the company announced a program called "Chevron Success Sharing" that provides eligible employees with a percentage of their annual salary as a cash bonus if the company achieves certain financial goals. The maximum payout under the program is currently eight percent of the employee's salary. For 1997, payouts ranged from
three to seven percent. As an extra enticement to achieve 1994 through 1998 financial targets, the company awarded 150 special performance stock options to each eligible employee on the payroll as of January 31, 1996. The grant price was set at $51-7/8 and the options were to become exercisable, after a six-month holding period, on the business day after the stock price closed at $75 or higher for three consecutive days or, if Chevron ranked number one in total shareholder return versus its five major U.S. competitors for the period 1994 through 1998. The options became exercisable in June 1997 after Chevron's stock closed above $75 per share for three consecutive days. In February 1998, the company awarded options that varied from 100 to 300 shares of stock, dependent on salary or job grade, to most U.S. dollar payroll employees. The options have a 10 year life and vest in February 2000, or in February 1999 if the company is number one in shareholder return among its competitor group for the years 1994 through 1998. Similar programs are also being provided for Chevron employees in other countries.
Accelerate exploration and production growth in international areas. - -------------------------------------------------------------------- The company continues to believe that its most promising area of financial and operational growth is in its international E&P activities. Between 1990 and 1997, total capital and exploratory (C&E) expenditures for E&P activities grew by 57 percent. During this time period, international expenditures grew by 74 percent while U.S. expenditures grew by 40 percent, with all of the U.S. growth occurring in 1997. The 1998 C&E program provides $4.0 billion for E&P investments with about 63 percent targeted for international projects. As a measure of its success in growing its international upstream business, the company's year-end 1997 international net proved reserves of crude oil, natural gas liquids and natural gas have more than doubled since 1990, even though international production has increased more than 50 percent during this same time period.
Accelerate the growth of our Caspian area earnings by cooperatively applying the skills and talents of all Chevron organizations to develop infrastructure, new markets and regional business opportunities. - ---------------------------------------------------------------------------- Chevron is expanding its operations and pursuing a wide range of other opportunities in the Caspian Sea region, as the company believes that this area holds tremendous potential for long-term growth. In January 1998, the company formed a senior-level cross-organizational team to identify the most promising opportunities to complement current exploration and production operations in this region. The team will be focusing on exploration and production, refining, marketing, supply, transportation, and community development. Also, in February 1998, Chevron announced that it had entered into a cooperative agreement in the Caspian region with The Royal Dutch Shell Group. The agreement establishes a framework for Chevron and Shell to jointly identify, develop, and share equally in new projects in the areas of exploration, production, transportation and sale of crude oil, gas liquids and natural gas. Chevron has established itself as one of the pre-eminent international oil companies operating in the Caspian region by its early involvement in the Tengiz project in Kazakhstan through the Tengizchevroil (TCO) joint venture, established in 1993 with the Republic of Kazakhstan. In May 1997, Chevron acquired a 15 percent ownership interest in the restructured Caspian Pipeline Consortium, formed to build a crude oil pipeline from the Tengiz oil field to the Russian Black Sea coast. In Kazakhstan, Chevron is building an office complex in Atyrau, has opened a service station in Almaty, and has plans for additional stations. Elsewhere in the Caspian region, the company has established regional offices in Baku, Azerbaijan, and Tiblisi, Georgia.
Generate cash from North American exploration and production operations, while maintaining value through sustained production levels. - ------------------------------------------------------------------------ The company has several projects under way, mainly major deepwater developments in the Gulf of Mexico, that are intended to slow the decline in the company's North American oil and gas production. In the next ten years, the company seeks to add more than 2 billion barrels of reserves from Gulf of Mexico deepwater projects. The company also continues to invest in mature producing areas for modest growth, steady production, and cash flow. C&E expenditures for U.S. upstream projects in 1997 increased 42 percent from 1996, as a result of lease acquisitions in the Gulf of Mexico and Alaska, accelerated drilling activity in the Gulf of Mexico, and continued drilling activity in the mid- continent area of the United States. As a measure of its success in sustaining U.S. exploration and production operations, U.S. oil and gas reserve net additions, excluding property sales and acquisitions, replaced net production for the first time since 1984. Also, 1997 liquids production levels increased slightly from 1996. The company believes that attractive growth opportunities exist within its current portfolio of assets, and, if other attractive opportunities arise, acquisitions and exchanges may be considered. In 1997, the company generated cash proceeds of
Approximately $450 million from the sale of non-core U.S. assets and may sell additional properties over the next three years, mainly in the Gulf of Mexico and Texas.
Achieve top financial performance in U.S. refining and marketing. - ----------------------------------------------------------------- Over the past few years, the company has focused its attention on efficiently utilizing its refining portfolio after selling refineries in Port Arthur, Texas and Philadelphia, Pennsylvania, and spending over $1 billion on its two California refineries in order to produce state-mandated cleaner-burning fuels and to increase their efficiency and reliability. In 1997, the company continued the improving trend in earnings and reliable operations established in 1996. Operating earnings in 1997 more than doubled when compared with 1996, based on increased refined products sales volumes, improved refining reliability, and a decline in crude oil feedstock costs and operating expenses. With the West Coast refinery upgrades complete, the company has shifted the majority of its investment spending to marketing projects aimed at meeting customers' needs and improving the company's competitive market position. The company is expanding its service station network to capture gasoline volume growth. In addition to fuels volume growth, the company is stressing growth in convenience store goods and other services. Chevron plans to increase the number of company-operated convenience stores by 20 percent, while increasing the average store size by 30 percent during the 1998 - 2000 period. The Chevron-McDonald's alliance in 12 western and southwestern states continues to grow. Additional sites that combine Chevron service stations with McDonald's restaurants are planned through 1999 to complement the approximately 75 sites currently operating under the alliance.
Caltex should achieve superior competitive financial performance, while selectively growing in attractive markets. - ----------------------------------------------------------------------- Chevron's 50 percent-owned international downstream affiliate, Caltex Petroleum Corporation, operates in about 60 countries in the Middle East, Africa, and the Asia-Pacific region. The past year was one of economic turmoil and currency devaluations in the Asia-Pacific region. Demand growth for crude oil and petroleum products in the Caltex operating area is expected to slow as a result. Caltex has responded by increasing its focus on managing costs and investments. The company continues to believe that economic growth in the Pacific Rim will nonetheless surpass that of most other regions. Caltex, as a leading competitor in these areas, has made significant capital investments to expand and upgrade its refining capacity and will continue to implement a program, which began in 1996, to enhance the Caltex brand with a service station re-imaging program.
In 1997, Caltex sold its 40 percent interest in a refinery in Bahrain, after ceding its throughput rights in April 1996. In a separate agreement, Caltex agreed to integrate the operations of its 64 percent-owned Star Petroleum Refinery Company Ltd. facility in Thailand with a nearby Shell refinery. To increase its market share in Thailand, Caltex acquired 47 service station sites from British Petroleum. In Australia, a Caltex affiliate acquired Pioneer International's 50 percent ownership share of Australian Petroleum Pty Ltd., thereby becoming the leading refiner and marketer in the country.
Improve competitive financial performance in chemicals while developing and implementing attractive opportunities for growth. - --------------------------------------------------------------------------- Financial results for the company's chemicals operations continue to reflect the cyclical downturn in the chemicals industry. However, the company has undertaken several major projects to lower its unit cost structure and position its operations to benefit from the next industry upturn. The company has expanded facilities at several U.S. plants, and has plans for further expansions over the next three years which will increase overall U.S. product capacity by 25 percent. The company is also expanding its international operations to take advantage of the expected growth in global demand for petrochemicals. Construction has begun on a fuel and lube oil additives plant in Singapore, and a benzene and cyclohexane facility in Saudi Arabia. The company has planned, and continues to evaluate, international projects in Venezuela, China and Thailand.
Be selective in other businesses. - --------------------------------- During 1997, Chevron operated three units that are outside the corporation's core focus and are managed for cash flow, profitability, and growth when attractive opportunities exist. These units were Chevron Canada Limited (CCL), The Pittsburg & Midway Coal Mining Co. (P&M), and Gulf Oil Great Britain (GOGB). CCL's primary operations are the refining and marketing of petroleum products in British Columbia, Canada, while P&M is the operator of the company's coal interests.
In December 1997, following the termination of earlier merger discussions with Elf Oil UK Ltd. and Murco Petroleum Ltd., the company completed the sale of GOGB's marketing assets to Shell UK Ltd., divested its equity interest in the Pembroke Cracking Company, and discontinued processing at its refinery in Milford Haven, Wales. The company will close the refinery and sell its remaining U.K. downstream assets. In 1997, the company recorded an additional after-tax provision of $72 million, including amounts for severance, environmental and shutdown costs, the majority of which are expected to be incurred during 1998. The company had previously recorded a $200 million after-tax impairment provision in 1996. These transactions substantially complete the company's withdrawal from the refining and marketing business in the United Kingdom.
Focus on reducing costs across all activities. - ---------------------------------------------- Operating expenses, adjusted for special items, decreased about $400 million in 1997 from 1996. A portion of this decrease was due to the merger in August 1996 of the company's natural gas liquids gathering, processing, and marketing operations with NGC. The remaining decrease between years is attributable to lower fuel, transportation and marketing costs, which were partially offset by costs of the start-up and expansion of chemicals facilities. Lower costs combined with higher liquids production and product sales volumes to push per-barrel operating expenses down to $5.68 in 1997 from $6.10 in 1996. Since 1991, the company has realized a significant reduction in its operating costs. Although a portion of the cost reduction is related to divested and restructured operations, the company believes it has achieved a significant permanent reduction in the company's ongoing cost structure.
The company expects to realize savings in operating expenses through the 1997 and planned 1998 reorganizations of its North American exploration and production, research, shipping, information technology, corporate human resources and finance activities. A corporate wide "breakthrough" initiative aimed at reducing corporate energy costs has resulted in substantial savings since 1991. The company is currently undertaking a project, to be completed in 1998, to standardize its worldwide computing infrastructure, which is expected to reduce information technology costs. Additional savings have been realized in operating expenses and the cost of capital projects since 1994 from an initiative focusing on reducing the costs for goods and services by working more efficiently with fewer suppliers. Other initiatives that have resulted in significant savings include a uniform project management process that is used to evaluate and administer large capital projects, and the improved management of inventory to enhance cash flow.
In addition to following the above strategic intents, Chevron and its affiliates continue to review and analyze their operations and may close, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits to improve competitiveness and profitability.
(b) Industry Segment and Geographic Area Information
The company's largest business is its integrated petroleum operations. Other operations include chemicals and coal mining. The petroleum activities of the company are widely distributed geographically, with major operations in the United States, Canada, Nigeria, Angola, Australia, the United Kingdom, Republic of Congo, and Indonesia. The company's Caltex affiliate, through its subsidiaries and affiliates, conducts exploration and production and geothermal operations in Indonesia and refining and marketing activities in Asia, Africa, the Middle East, Australia and New Zealand, with major operations in Korea, Japan, Australia, Thailand, the Philippines, Singapore and South Africa. The company's TCO affiliate conducts production activities in Kazakhstan. The company expects to expand its operations in the Caspian Sea area of Central Asia by developing infrastructure, new crude oil and natural gas markets, and other business opportunities.
The company's chemicals operations are concentrated in the United States, but also include manufacturing facilities in France, Japan and Brazil. Chemicals manufacturing facilities are under construction in Singapore and Saudi Arabia, with potential opportunities for construction of facilities in Thailand and China. The company's coal operations are concentrated in the United States but also include interests in mining operations located in Venezuela.
Tabulations setting forth 1995 to 1997 identifiable assets, operating income and sales and other operating revenues for the company's three industry segments, by United States and International geographic areas, may be found in Note 10 to the Consolidated Financial Statements beginning on page FS-22 of this Annual Report on Form 10-K. In addition, similar comparative data for the company's property, plant and equipment is contained in Note 13 on page FS-25.
(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. To succeed in its competitive environment, the company must identify and manage significant risks in its various activities.
The company's worldwide operations can be affected significantly by changing economic, regulatory and political environments in the various countries, including the United States, in which it operates. Environmental regulations and government policies concerning economic development, energy and taxation may have a significant effect on the company's operations. The company evaluates the economic and political risk of initiating, maintaining or expanding operations in any geographical area. The company closely monitors political events worldwide and the possible threat these may pose to its activities, particularly the company's oil and gas exploration and production operations, and the safety of the company's employees.
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 international integrated petroleum activities. All these instruments are commonly used in oil and gas trading activities and, except for certain long-term natural gas swaps, are 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. All commodity and financial derivative instruments used by the company are relatively straightforward and involve little complexity. Their impact on the company's results of operations has not been material.
Capital and Exploratory Expenditures
Chevron's capital and exploratory expenditures during 1997 and 1996 are summarized in the following table:
- ------------------------------------------------------------------ Capital and Exploratory Expenditures (Millions of Dollars) 1997 1996 ------ ------ Exploration and Production $2,968 $2,778 Refining, Marketing and Transportation 572 486 Chemicals 662 495 Coal and Other Minerals 90 28 All Other 75 70 ------ ------ Total Consolidated Companies 4,367 3,857 Equity in Affiliates 1,174 983 ------ ------ Total Including Affiliates $5,541 $4,840 ====== ====== - ------------------------------------------------------------------
Total consolidated companies' C&E expenditures in 1997 were $4.367 billion compared with $3.857 billion in 1996. Higher U.S. exploration and production expenditures were incurred as a result of lease acquisitions and
accelerated drilling activity in the Gulf of Mexico and continued drilling activity in the mid-continent area of the United States, reflecting the company's efforts to slow U.S. production declines. This increase was slightly offset by a decrease in international exploration and production expenditures between years. Lower expenditures in 1997 for the Hibernia Project offshore Newfoundland more than offset increases between years in other international areas including Venezuela and Angola. Refining, marketing and transportation expenditures increased between years driven by the increased focus on the U.S. marketing network. Chemicals incurred higher expenditures in 1997 primarily for the expansion of certain U.S. chemicals facilities, the commencement of construction of a new additives manufacturing facility in Singapore and initial costs for the construction of a benzene and cyclohexane manufacturing facility in Saudi Arabia. Coal and other minerals expenditures increased between years as the company's Pittsburg and Midway Coal Mining Co. made two business acquisitions during 1997.
Consolidated companies' exploration and production C&E expenditures were 68 percent and 72 percent of the company's total consolidated companies' expenditures in 1997 and 1996, respectively. Major international exploration and production expenditures in 1997 included exploration and development drilling offshore Angola and Congo; development activities associated with the Britannia Field in the U.K. North Sea, the Hibernia Project offshore Newfoundland, and the Escravos Gas Project in Nigeria; and the acquisition of proved reserves in Venezuela. Major U.S. exploration and production expenditures included lease acquisitions and deepwater exploration and development activities, such as the Genesis and Norphlet trend projects in the Gulf of Mexico, and other projects in Texas, California, and Wyoming. Consolidated companies' refining, marketing and transportation outlays focused on the expansion of Chevron's service station network, including the expansion and enhancement of the company's service station convenience stores and the continued implementation of the company's alliance with McDonald's at selected service stations in the western and southwestern United States.
The company's share of C&E expenditures by its affiliates was $1.174 billion in 1997, an increase of 19 percent from $983 million in 1996. The company's Caltex affiliate accounted for nearly 60 percent of affiliates' expenditures, although at lower levels than in 1996 when Caltex completed several major projects. In 1997, Caltex also curtailed C&E expenditures as a result of the Asian financial crisis. The decrease in Caltex expenditures in 1997 was more than offset by increases from continued development activities at the Tengiz field in Kazakhstan, and from the company's NGC affiliate's acquisition of Destec Energy Inc. and continued expansion of the Venice, Louisiana, gas gathering facilities.
The company's 1998 C&E expenditures, including its share of equity affiliates' expenditures, are expected to increase 14 percent over 1997 amounts to a record $6.3 billion. Consolidated companies' expenditures are planned to increase by 14 percent to $5.0 billion and the company's share of equity affiliates' expenditures is expected to increase by 11 percent to $1.3 billion.
Worldwide exploration and production C&E expenditures in 1998, including the company's share of equity affiliates' expenditures, are expected to total $4.0 billion, of which approximately 63 percent, or about $2.5 billion will be for international projects. Major planned international projects include construction of the Caspian Pipeline, the continued development of the Tengiz Field, development projects for Area A and Block 14 in Angola, development of the Moho Field offshore Congo and the third phase of the Hibernia Field development offshore Newfoundland. In the United States, major exploration and production expenditures include various development projects in the Gulf of Mexico, including the deepwater Genesis and Gemini developments, the Norphlet trend, and exploration and evaluation of other Gulf of Mexico prospects.
Worldwide refining, marketing and transportation C&E expenditures in 1998, including the company's share of equity affiliates' expenditures, are estimated at $1.1 billion, of which $600 million is planned for projects in the United States. The company will concentrate the majority of its U.S. expenditures on retail marketing projects aimed at meeting consumers' needs and improving the company's market position. The company plans to continue its programs to upgrade convenience stores, install fast-pay card readers and install multi- product dispensers (to dispense cash, event tickets etc.) at service stations. International refining, marketing and transportation expenditures in 1998 include the continuation of a major program by the company's Caltex affiliate to improve its retail marketing image and operations in the Asia-Pacific region.
Worldwide chemicals C&E expenditures in 1998, including the company's share of equity affiliates' expenditures, are estimated at about $830 million, of which approximately 56 percent will be for international projects. Major international projects include the construction of a petrochemicals complex in Saudi Arabia by Chevron and its partner, and the completion of the Singapore additives facility. In the United States, 1998 projects include paraxylene and ethylene plant expansions at Pascagoula, Mississippi, and a polyethylene debottlenecking project at the company's Orange, Texas, facility.
The actual C&E expenditures for 1998 will depend on various conditions affecting the company's operations, including crude oil and natural gas prices and changing economic conditions in the various countries in which it operates, and may differ significantly from the company's forecast. The company has the ability to modify its C&E expenditures in the event the lower crude oil price environment becomes more severe or prolonged.
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, 1997. "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
Wells Drilling Net Wells Completed (1) --------------------------------------- At 12/31/97 1997 1996 1995 -------------- ----------- ----------- ----------- Gross (2) Net (2) Prod. Dry Prod. Dry Prod. Dry ----- ----- ----- --- ----- --- ----- --- United States 83 68 56 31 120 25 101 24 ----- ----- ----- --- ----- --- ----- ---
Africa 12 4 5 1 3 2 3 4 Other International 29 8 12 6 32 22 22 27 ----- ----- ----- --- ----- --- ----- --- Total International 41 12 17 7 35 24 25 31 ----- ----- ----- --- ----- --- ----- --- Total Consolidated Companies 124 80 73 38 155 49 126 55 Equity in Affiliates 8 3 3 - - 1 1 - ----- ----- ----- --- ----- --- ----- --- Total Including Affiliates 132 83 76 38 155 50 127 55 ===== ===== ===== === ===== === ===== ===
(1) Indicates the number of wells completed during the year regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of oil or gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. (2) Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company's fractional interests in gross wells. - ------------------------------------------------------------------------------
At December 31, 1997, 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 (1) At December 31, 1997 (Thousands of Acres)
Developed Undeveloped Developed and Undeveloped -------------- ------------- --------------- Gross Net Gross Net Gross Net ------ ------ ----- ----- ------ ------ United States 6,024 4,028 5,684 2,493 11,708 6,521 ------ ------ ----- ----- ------ ------
Canada 18,481 9,732 1,420 632 19,901 10,364 Africa 22,692 16,856 163 62 22,855 16,918 Asia 31,610 17,454 54 19 31,664 17,473 Europe 1,887 793 81 21 1,968 814 Other International 15,957 5,275 76 20 16,033 5,295 ------ ------ ----- ----- ------ ------ Total International 90,627 50,110 1,794 754 92,421 50,864 ------ ------ ----- ----- ------ ------ Total Consolidated Companies 96,651 54,138 7,478 3,247 104,129 57,385 Equity in Affiliates 3,181 1,543 254 125 3,435 1,668 ------ ------ ----- ----- ------ ------ Total Including Affiliates 99,832 55,681 7,732 3,372 107,564 59,053 ====== ====== ===== ===== ======= ======
(1)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 $224 million of suspended exploratory wells included in properties, plant and equipment at year-end 1997. The wells are suspended pending a final determination of the commercial potential of the related oil and gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions.
During 1997, the company incurred expenditures for oil and gas exploration in the United States and about 30 other countries. The company's 1997 exploratory expenditures, including affiliated companies' expenditures but excluding unproved property acquisitions, were $798 million compared with $806 million in 1996. U.S. expenditures represented approximately 45 percent of the consolidated companies' worldwide exploration expenditures, compared with 53 percent in 1996. Significant activities in Chevron's exploration program during 1997 include the following: (numbers of wells are on a "gross" basis)
United States: Exploratory expenditures, excluding unproved property acquisitions, were $360 million in 1997, compared with $425 million spent in 1996. In addition, the company incurred costs of $101 million for unproved property acquisitions in 1997, compared with $62 million in 1996. Exploration efforts were concentrated in the Gulf of Mexico and several onshore basins in Texas and Alaska, where the potential for large discoveries has been demonstrated. Chevron participated in 17 exploratory wildcat wells, which resulted in four discoveries in the Gulf of Mexico. Continuing Chevron's focus in the eastern North Slope of Alaska, Chevron and BP Exploration, Alaska, announced an agreement in February 1998, aligning their respective leasehold interests in the Point Thomson area east of Prudhoe Bay. The alignment area encompasses the Point Thomson Unit, the Flaxman and Point Thomson discoveries, and the Sourdough discovery, which was announced in 1997. Additional technical work is planned to determine the extent and economic viability of the Sourdough discovery. Chevron holds a 44 percent interest in the two companies' joint lease holdings in the area, and BP holds the remaining 56 percent. In the March and August 1997 Gulf of Mexico Lease Sales, Chevron successfully bid, alone and with partners, for the rights to 139 leases, 134 of which were in deep water, boosting Chevron's deepwater lease inventory to 362 leases. The company also acquired interests in 18 new tracts, covering 17 thousand net acres on Alaska's eastern North Slope, in the November 1997 State of Alaska Lease Sale 86.
Africa: In Africa, the company spent $147 million during 1997 on exploratory efforts, excluding the acquisition of unproved properties, compared with $122 million in 1996. The increase between years was driven by higher 1997 well expenditures in Angola, where total exploration expenditures were $72 million in 1997 compared with $34 million in 1996.
In Angola, the company is the operator of two concessions off the coast of Angola's Cabinda exclave. Block 0 is a 2,100 square mile concession adjacent to the Cabinda coastline and is divided into three areas: Area A, which began production in late 1960, includes 19 major fields (15 currently producing) in two major areas, Malongo and Takula; Area B, which began production in late 1994 with six major fields, includes the Kokongo, Nemba and Lomba fields; and Area C, which began first production in 1997, includes the Ndola and Sanha fields. Chevron has a 39.2 percent interest in the Block 0 concession. The 1997 exploration and appraisal well program in Area A consisted of seven wells targeting open water prospects and delineation of existing fields. Five appraisal wells were drilled in the Lifua and Banzala fields. The Lifua appraisal well extended this discovery approximately one mile to the north. The four Banzala wells yielded results that are currently being evaluated. In Area B, one exploration well was drilled and resulted in a discovery of light oil. In Area C, two appraisal wells were drilled. The first well discovered oil but its development is deemed not economic at this time, while the second well produced encouraging results. The second Angolan concession, Block 14, was acquired in 1995 and Chevron's interest is 31 percent. Block 14 is a 1,560 square mile concession located in waters due west of Areas B and C. Three exploration wells were drilled in Block 14 during 1997 resulting in three discoveries, including two major commercial finds. The Kuito Field is characterized as a giant field with recoverable reserves greater than 500 million barrels of crude oil. Three appraisal wells drilled on the Kuito Field in 1997 helped refine the geologic model and the calculation of reserves. The second commercial discovery occurred in November 1997 and is also a significant find. The Block 14 program planned for 1998 includes drilling three exploratory wells, which will increase the evaluation of the block, two appraisal wells to follow up on the discoveries, and the acquisition of new 3-D seismic data over the Kuito Field.
In Nigeria, the company's operations are managed by three subsidiaries. Chevron Nigeria Limited (CNL) operates and holds a 40 percent interest in concessions totaling approximately 2.2 million acres in the onshore swamp and near offshore regions of the Niger Delta. Chevron Oil Company Nigeria Limited (COCNL) holds a 20 percent interest in six concessions covering about 600 thousand acres, with six offshore oil fields operated by a partner. Chevron Petroleum Nigeria Limited (CPNL) oversees and manages new venture projects in Nigeria. CPNL has a 30 percent interest in two deepwater Niger Delta blocks and three inland Benue Basin blocks, and an additional sole interest in six other Benue Basin blocks. CNL drilled only one exploration well in 1997 as funding from its partner, the Nigerian National Petroleum Company, was restricted during the year. CPNL exploration activities included the initiation of geological studies and a 2-D seismic program in the six Chevron operated Benue Trough blocks. In the partner-operated deep offshore blocks, CPNL participated in the drilling of two exploration wells. One well was suspended after encountering oil and gas zones; the other well was plugged and abandoned.
Offshore Republic of Congo, the company has a 29.25 percent interest in the partner-operated Marine VII license, which includes the Kitina and Sounda developments, and a 30 percent interest in the Haute Mer license, which is operated by a partner and includes the Nkossa Field. In 1997, a second appraisal well began on the Moho Field in the Haute Mer license and resulted in the new Moho Marine No. 3 discovery when it struck oil in a new oil-bearing section. Facilities design work is ongoing on Moho, with an intent to accelerate early production from the field. A 3-D seismic survey was shot over the outer part of the Haute Mer license in 1997 and is expected to identify several more exploration prospects. The second of two test wells drilled in 1997 led to a potentially commercial crude oil discovery in the Haute Mer deepwater area, which tested at 8,520 barrels of oil per day, and has been named Bilondo Marine No. 1. At least three exploration wells are currently planned for 1998. Processing of seismic data acquired in 1996 from the Marine IV license, located offshore northern Congo and operated by Chevron with an 85 percent interest, was completed in 1997, and interpretation is ongoing. One exploration well is planned for 1998.
In Democratic Republic of Congo (formerly Zaire), the company has a 50 percent interest in, and is the operator of, a 390 square mile offshore concession. A 3-D seismic program was started in late 1997 and continued into 1998,
after which approximately 95 percent of the concession will be covered with 3-D seismic data. No exploration wells were drilled in 1997, but one exploration well is planned for 1998.
Other International including affiliated companies: Exploration expenditures, excluding unproved property acquisitions, outside the United States and Africa, were $291 million in 1997, an increase of $32 million from the 1996 amount of $259 million. In addition, unproved properties of $23 million were acquired in 1997 compared with $43 million in 1996.
In Europe, Chevron has interests in about 40 blocks in the United Kingdom and Ireland. Blocks are located in the U.K. North Sea, west of Shetland Islands, offshore Wales, and in Liverpool Bay. In Ireland, the company has acreage in the Porcupine Basin. In 1997, Chevron continued with its strategy of establishing an enhanced Britannia area equity position. The company increased its interests in its core Alba/Britannia area by acquiring a 35 percent interest in the Alder discovery in Block 15/29a, following a swap with Texaco for Chevron's interests in the West Guillemot discovery. Chevron also purchased a 17.25 percent interest in Block 15/24a, increasing the company's interest in the block to 26.84 percent. The company drilled two exploration wells in the West of Shetland Islands blocks, both of which were dry, and completed 3-D seismic data acquisition over two blocks in the central North Sea. In Ireland, the company carried out extensive exploration work on two licenses in the Porcupine Basin. One license was retained for further exploration work that will require the drilling of at least one well by the end of 2001, while the other license was dropped. In 1998, a major 3-D seismic survey will be undertaken over the Chevron-operated Porcupine License 5/95.
In Canada, exploration efforts in 1997 were concentrated in the western part of the country in two core areas that the company is optimistic will provide good opportunities for long term growth and value. These areas include the Liard Basin in northeast British Columbia, and an area west of Kaybob in north central Alberta. Drilling commenced in the Liard area in December 1997. The company also sought additional growth opportunities in the offshore areas of eastern Canada, including entering into a strategic alliance with Mobil Oil Canada to explore and develop within a 29-million-acre area in the Grand Banks area, offshore Newfoundland.
In Azerbaijan, Chevron signed an agreement in August 1997 to explore the 160 square mile Absheron Block in the Caspian Sea, about 60 miles off the Azerbaijan coast, in water depths of about 1,600 feet. Chevron's equity share is 30 percent. In the initial three-year work program, operated by Chevron, a 3-D seismic survey will be conducted in 1998, and two exploration wells are expected to begin drilling in late 1999. Chevron is currently working with the Azerbaijan State Oil Company and other operators in the region to develop options to secure semi-submersible rigs necessary for completion of the work program.
In Indonesia, Chevron's interests are managed by its 50 percent owned P.T. Caltex Pacific Indonesia (CPI) and Amoseas Indonesia (AI) affiliates. CPI holds interests in nine oil and gas production sharing contracts, while AI is now focused solely on geothermal power generation and has an interest in one geothermal production sharing contract. Within the central Sumatra contract areas, an aggressive multi-year 3-D seismic acquisition effort continued to evaluate oil and gas potential in the under-explored areas between current producing fields. CPI is currently negotiating with Pertamina, the national oil company, for a 20-year extension of the Coastal Plains block in Central Sumatra, currently set to expire in 2001, while AI is pursuing several new geothermal areas in Sumatra.
In Australia, Chevron's primary interests are in two non-operated joint ventures. The company has a 16.7 percent interest in the North West Shelf (NWS) Project and 25 to 50 percent interests in permits operated by West Australian Petroleum Pty. Ltd. (WAPET), including a 25 percent interest in one Carnarvon Basin block acquired in 1997, adjacent to the Gorgon/Chrysaor/Dionysus gas fields. The NWS Project is currently engaged in an exploration drilling program assessing prospects identified from the East Dampier 3-D seismic survey. Separate from NWS and outside the WAPET-operated area, Chevron holds a 25 percent interest in four blocks in the Browse Basin area and a 17.25 percent interest in an additional Carnarvon Basin block. Two of the Browse Basin blocks were acquired in 1997, and are adjacent to a discovery made in 1997 in the Cornea Block. A 770-square-mile 3-D seismic program over the Cornea discovery was completed in 1997, with an appraisal drilling program proceeding into 1998.
In Papua New Guinea, Chevron is operator for the Kutubu, Moran, and Gobe projects. Chevron holds a 19.38 percent interest in the Kutubu and Moran development and surrounding Petroleum Development License (PDL)-2, and a 15 percent interest in the Gobe development. Chevron, as operator, also holds a 35.5 percent interest in the Petroleum Prospecting License (PPL)-101. During 1997, Chevron and its partners continued evaluating the 1996 Moran Central crude oil discovery in the PDL-2 area, with the drilling of a second well from the same location as the discovery well. Construction of a flowline from Moran to existing infrastructure in the producing Kutubu area fields began in late 1997 to transfer production from extended well tests on two Moran wells. Production start-up occurred in January 1998, at a rate of 10,000 barrels per day, with full production anticipated in 2000. Seismic data acquired in the Moran area during 1997 continues to be evaluated. At year-end 1997, an exploration well was drilling on the Nomad prospect in PPL-101. Seismic data acquired over the Gobe area in 1997 continues to be evaluated with additional seismic acquisitions planned for 1998.
In China, Chevron signed a production-sharing contract with China National Petroleum Corporation (CNPC), effective August 1, 1997, to explore for crude oil in the 700 square-mile Zhanhuadong block in the Shengli Field Complex in China's Shandong Province. The Shengli field is China's second-largest oil field. Chevron will explore the deeper pre-Tertiary geologic zones which lie beneath the existing production. This contract represents Chevron's first onshore exploration contract in China and requires that two wells be drilled before the end of July 2000. Exploration well HZ/32-5-1 in the Block 16/08 contract, which discovered crude oil in 1996, was successfully appraised during 1997. The production will be tied back to producing field HZ/26-1. A 3-D seismic survey recorded in early 1996 was interpreted in early 1997 and identified exploration targets in Block 16/08 and adjacent Block 16/19. The first prospect drilled resulted in the discovery of the new field HZ/26-2, with three geologic zones testing at a combined rate of 7,566 barrels of crude oil per day. During 1997, 3-D seismic acquisition was completed in Block 02/31, as was a 2-D seismic survey in Block 06/17. Drilling in Blocks 06/17 and 02/31 is currently scheduled for 1998. A 3-D seismic survey completed in Block 63/15 during 1997 will lead to one well planned for early 1998 in this natural-gas prone area.
In Bahrain, the company signed an agreement in February 1998 to explore for oil in three offshore areas designated as Blocks 1, 2 and 3. Under the agreement, Chevron is operator with a 100 percent interest and is expected to begin 2-D and 3-D seismic surveys in 1998 with exploratory drilling planned to begin in 2000.
Exploration activities occurred in other areas during 1997. In Qatar, where in April 1996 the company obtained a 60 percent interest in and was appointed operator for Block 1NW, evaluation of a 3-D seismic survey of 360 square miles in the Block began in 1997. A seismic acquisition program is in progress to evaluate potential in the Galeron Block of Colombia, which is in the Llanos foothills south of the area where the recent trend of discoveries at Florena, Pauto Sur and Volcanera fields are located. At year-end 1997, Chevron and the Colombian state oil company Ecopetrol were finalizing an exploration contract for the Rio Guape Block, located to the south and on trend with the Chichimene Field. The company continued evaluating the results of 320 miles of seismic data acquired in 1996 in Exploration Block 52 in Peru, where it has a 100 percent interest, and which is adjacent to the Camisea gas-condensate field.
Petroleum - Oil and Natural Gas Production
The following table summarizes the company's and its affiliates' 1997 net production of crude oil, natural gas liquids and natural gas.
- ----------------------------------------------------------------------- 1997 Net Production (1) 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 115,500 135,900 -Gulf of Mexico 115,900 901,700 -Texas 62,300 371,300 -Colorado 11,400 900 -Wyoming 9,000 165,500 -New Mexico 11,500 60,700 -Louisiana 4,500 66,100 -Other States 13,200 146,700 ---------- --------- Total United States 343,300 1,848,800 ---------- ---------
Africa 311,300 6,900 United Kingdom (North Sea) 54,700 22,000 Canada 46,600 215,600 Australia 37,500 214,900 Indonesia 17,400 - Papua New Guinea 14,500 - China 12,900 - Colombia 12,900 - Netherlands - 2,400 ---------- --------- Total International 507,800 461,800 ---------- --------- Total Consolidated Companies 851,100 2,310,600 Equity in Affiliates 223,300 114,700 ---------- --------- Total Including Affiliates 1,074,400 2,425,300 ========== =========
(1) Net production excludes royalty interests owned by others. - -----------------------------------------------------------------------
Production Levels:
In 1997, worldwide net crude oil and natural gas liquids production, including that of affiliates, increased for the fifth year in a row. Production rose in 1997 by three percent to a record 1,074,400 barrels per day, compared with 1,043,500 barrels per day in 1996. International net liquids production, including affiliates, increased by about four percent to 731,100 barrels per day in 1997, the eighth consecutive year of production increases. This increase was due primarily to higher production in Congo and Nigeria, where development drilling continued in new and existing fields, and in Kazakhstan, where the company's share of production at the Tengiz Field increased as the plant expansion project progressed and new markets were added. These production increases were partially offset by production declines in the United Kingdom and Papua New Guinea due primarily to normal field declines and dispositions of producing properties. The decline in the United Kingdom included the absence of production from four mature producing oil fields in the United Kingdom sector of the North Sea that were sold in October 1996. In Papua New Guinea production continues to be constrained because of gas re- injection capacity.
Net production of natural gas, including affiliates, decreased one percent to 2.4 billion cubic feet per day in 1997 from about 2.5 billion cubic feet per day in 1996. The decrease was primarily due to lower production in the United States, which decreased approximately 26 million cubic feet per day, reflecting normal field declines and property
sales, and smaller production decreases in Canada, the United Kingdom and Indonesia. These decreases were partially offset by new production in Nigeria, as the Escravos Natural Gas Project began operation in 1997, and by a small production increase in Australia. The company expects development of the Norphlet trend in the U.S. Gulf of Mexico, the expansion of the Escravos Gas Project in Nigeria, and the continued expansion and development of its Australian projects, to mitigate further natural gas production declines in its portfolio.
Data about the company's average sales price per unit of oil and gas produced, as well as the average production cost per unit for 1997, 1996 and 1995 are reported in Table III on pages FS-34 and FS-35 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 1997.
- ---------------------------------------------------------------------------- Productive Oil And Gas Wells At December 31, 1997
Productive(1) Productive(1) Oil Wells Gas Wells ------------------- ----------------- Gross(2) Net(2) Gross(2) Net(2) ------- ------ ------ ------- United States 24,165 13,085 4,032 1,991 ------- ------ ------ -------
Canada 1,403 1,039 392 221 Africa 1,081 407 9 3 United Kingdom (North Sea) 103 9 - - Other International 1,192 420 46 11 ------- ------ ------ ------ Total International 3,779 1,875 447 235 ------- ------ ------ ------ Total Consolidated Companies 27,944 14,960 4,479 2,226
Equity in Affiliates 5,434 2,715 50 25 ------- ------ ------ ------ Total Including Affiliates 33,378 17,675 4,529 2,251 ======= ====== ====== ====== Multiple completion wells included above: 688 398 281 189
(1) Includes wells producing or capable of producing and injection wells temporarily functioning as producing wells. Wells that produce both oil and gas are classified as oil wells. (2) Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company's fractional interests in gross wells. - ----------------------------------------------------------------------------
Development Activities:
The company's development expenditures, including those of affiliated companies but excluding proved property acquisitions, were $2,219 million in 1997 and $1,835 million in 1996. The increase between years resulted from higher 1997 expenditures in the United States and by TCO. In addition, $84 million was spent in 1997 on proved property acquisitions, compared with $15 million in 1996. The increase occurred primarily in Venezuela.
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, 1997. (A "development well" is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. "Wells drilling" include wells temporarily suspended.)
- ------------------------------------------------------------------------------- Development Well Activity
Wells Drilling Net Wells Completed (1) ---------------------------------------- At 12/31/97 1997 1996 1995 ------------ ---- --- ----- --- ---- ---- Gross(2) Net(2) Prod. Dry Prod. Dry Prod. Dry ----- ---- ---- --- ---- --- ---- --- United States 305 228 617 6 485 8 281 6 ----- ---- ---- --- ---- --- ---- ---
Africa 22 7 22 1 21 1 20 1 Other International 27 8 67 - 49 4 28 2 ----- ---- ---- --- ---- --- ---- --- Total International 49 15 89 1 70 5 48 3 ----- ---- ---- --- ---- --- ---- --- Total Consolidated Companies 354 243 706 7 555 13 329 9
Equity in Affiliates 21 10 150 - 262 - 135 - ----- ---- ---- --- ---- --- ---- --- Total Including Affiliates 375 253 856 7 817 13 464 9 ===== ==== ==== === ==== === ==== ===
(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 1997 development activities include the following: (Production volumes are gross unless otherwise stated.)
United States: Chevron's U.S. development expenditures were $918 million in 1997, an increase of $315 million from $603 million in 1996. Expenditures for proved reserve acquisitions amounted to $3 million in 1997 compared with $5 million in 1996. Additions to proved reserves during 1997 from extensions, discoveries and improved recovery, before revisions, were 196 million barrels of crude oil and natural gas liquids and 581 billion cubic feet of natural gas. U.S. operations replaced 120 percent of net liquids and gas production in 1997, excluding property sales and purchases, the highest U.S. replacement rate since 1984. The U.S. reserve additions resulted primarily from discoveries and extensions in the Gulf of Mexico, and improved recovery and extension projects in California.
In the Gulf of Mexico, significant development activities in 1997 included the continued work on the hull fabrication and the construction of the topsides and decks for the Genesis project, Chevron's first deepwater operation in the Gulf of Mexico, located in 2,600 feet of water. Chevron is the unit operator with a 57 percent working interest. The two spar hull sections to be used in the offshore construction had arrived in Corpus Christi, Texas from Finland, by March 1998. The project execution plan anticipates initial production in late 1998, with total peak production expected to reach 55,000 barrels of oil per day and 72 million cubic feet of gas per day by 2000.
Chevron has a 40 percent interest in the Gemini deepwater development in the Gulf of Mexico, where water depth ranges from 3,000 to 4,300 feet. The discovery well, located on Mississippi Canyon block 292, was spudded in 1995. The company and its partner will drill two development wells, complete one existing exploratory well and build processing facilities on an existing host platform and pipelines. Initial production from the project is expected in 1999, with peak production rates anticipated to reach 150 - 200 million cubic feet of gas per day and 2,000 - 3,000 barrels of condensate per day.
Phase I of the development of the Norphlet trend, which stretches some 80 miles from the Destin Dome area (offshore Florida) to the Mobile Block 861 area (offshore Mississippi), was completed in 1996. Chevron's net
production in the Mobile area during 1997 averaged 95 million cubic feet of gas per day from seven wells, double the average net production in 1996. Phase II of the company's development plans in the Norphlet trend includes participation in three development wells (two as operator) and one operated exploration well in 1998. Continued development work over the next two years is expected to increase net production to around 180 million cubic feet of gas per day by 2000. In August 1997, the Minerals Management Service (MMS), U.S. Department of the Interior, deemed Chevron's filing of a Development and Production Plan (DPP) for Destin Dome to be complete. The MMS, in conjunction with other federal and state agencies, is in the process of preparing an Environmental Impact Statement, which is expected to be completed by late 1999, and is required prior to approving the DPP. Assuming that all regulatory approvals are obtained by late 1999, the company expects initial production from Destin Dome by late 2001.
In the Vermilion 214 Field, where Chevron has a 100 percent interest, the installation of a production platform and a facilities upgrade were completed. In addition, five previously drilled delineation wells were tied back and completed as of October 1997. Current production is six thousand barrels of crude oil and 40 million cubic feet of gas per day. Additional development drilling of seven wells is planned for the 1998 - 1999 period. Three of the seven wells should be on production by mid-1998. The company is currently evaluating further development in the field beyond 1999.
The use of 3-D seismic technology has led to successful development programs at certain mature fields in the Gulf of Mexico. At Eugene Island 238, 22 of 25 prospects drilled to date have been successful and at the end of 1997 accounted for the majority of the field's total daily production. Thirteen wells found gas and nine wells found oil. At South Marsh Island 66, ten of eleven wells drilled since 1995 have been successful, and have produced 41 billion cubic feet of gas and 218 thousand barrels of condensate through year-end 1997.
Offshore California, the company has established a strategy to exit its operations, either through selling its interests, or implementing abandonment as soon as operations reach their economic limit and an abandonment infrastructure is in place.
Onshore California, Chevron continued to expand its employment of enhanced recovery methods using thermal operations to increase both the production rate and the amount of oil ultimately recoverable from fields in California's San Joaquin Valley, with efforts focused on the Cymric and Coalinga fields. This multi-year project began in 1995, and net production from thermal operations currently accounts for over 19 percent of Chevron's daily U.S. liquids production.
Other development activities took place in the United States during 1997. The drilling of 25 new wells in the Laredo area of Texas increased proved gas reserves by a combined 66 billion cubic feet. The interstate pipeline debottlenecking at the Waltman field in Wyoming, which commenced in November 1997, is expected to eliminate the curtailment of high pressure wells and allow production start-up of low pressure wells that have been shut-in for more than two years.
Africa: Development expenditures in Africa were $461 million in 1997, compared with $465 million in 1996. Higher 1997 expenditures in Nigeria were more than offset by decreases between years in Angola, Congo, and the Democratic Republic of Congo. Expenditures for proved reserve acquisitions amounted to $6 million in 1997 compared with $1 million in 1996. Additions to proved reserves from extensions, discoveries and improved recovery, before revisions, were 228 million barrels of crude oil and natural gas liquids, of which 164 million barrels were in Angola. The additions to proved reserves arose primarily from new discoveries and improved recovery projects in Angola and Nigeria.
In Nigeria, total gross production from 30 CNL-operated fields, where Chevron has a 40 percent equity interest, averaged 423,000 barrels of oil per day, an increase of about 22,000 barrels per day from 1996. This increase was primarily due to a substantial workover program and the addition of the Ewan Field, which began production in early 1997 and reached production levels of more than 13,000 barrels of oil per day. Production from non-operated fields, where Chevron has a 20 percent equity interest, averaged approximately 72,000 barrels of oil per day in 1997, an increase of 2,000 barrels per day from 1996. Engineering and construction work continued on the
development of the CNL-operated Dibi, Ewan, Gbokoda and Opolo fields. The Opolo Field began production in March 1998 at a rate of 20,000 barrels per day. The Dibi and Gbokoda fields are scheduled to begin production in 1998 with combined production from the four fields expected to exceed 200,000 barrels of oil per day by 2001. These development projects are part of CNL's plans to achieve a gross production level of more than 600,000 barrels of oil per day by 2001. Phase One of the Escravos Gas Project was completed and commissioned during 1997. This project provides a commercial outlet for LPG derived from natural gas produced with the company's crude oil operations. The facility processes 175 million cubic feet per day of gas previously flared at the Okan and Mefa fields, yielding about 8,000 barrels a day of natural gas liquids and 2,000 barrels a day of condensate for export, and 100 million cubic feet per day of dry gas, which is sold to the Nigerian Gas Corporation. Engineering and construction is currently underway for Phase Two of the Escravos Gas Project, which is scheduled to begin operation in late 1999 and will process an additional 100 to 120 million cubic feet of gas per day.
In Angola, several waterflood projects, aimed at increasing production in the Area A fields, are in the early stages of development. Additionally, 14 development wells were drilled in Area A in 1997. Areas B and C continue to be the primary focus of major development activities in the Block 0 concession. In Area B, pre-drilling of 11 development wells in the southern part of the Nemba Field was completed during 1997. Construction of platforms and facilities for further development of the Lomba Field and the southern portion of the Nemba Field is currently in progress. Platform installation and start of production from both of these projects is scheduled for 1998. Production from the 11 southern Nemba wells will be combined with the currently producing three Nemba wells on the new Nemba platform. Drilling on the Lomba field will start in early 1998. Additional development in the northern area of the Nemba Field is underway, with platform and facilities design and construction to begin in 1998. First oil production from the North Nemba Project is planned for early 2000. In Area C, installation of the first two platforms for the Ndola and Sanha fields was completed in 1997, with combined production from both fields currently at 30,000 barrels per day representing the company's first production from Area C. The Kuito Field in Block 14, discovered and appraised during 1997, will be developed using a phased approach, with drilling of the wells for the first phase commencing in 1998. First phase oil production is expected in early 1999 and is anticipated to be 50,000 barrels per day. Chevron's interest in the Kuito Field is 31 percent.
Offshore Republic of Congo, construction, installation, and hookup of the Kitina platform and onshore facilities were completed, and first oil production was achieved in December 1997. Peak production of 45,000 barrels per day is expected by the end of 1998. Plans are to use the Kitina facilities to handle additional production from the Kitina South and Sounda satellite fields starting in late 1998.
In Democratic Republic of Congo, three well workovers were performed at Tshiala and Motoba fields to optimize production, and one water injection well was spudded at Motoba Field to provide pressure support to a producing reservoir.
Other International including affiliated companies: Development expenditures in 1997, outside the United States and Africa, were $840 million compared with $767 million in 1996. The increase was largely due to higher expenditures by the company's affiliates TCO in Kazakhstan and CPI in Indonesia, which were $102 million and $36 million higher in 1997 and 1996, respectively. Expenditures for proved reserve acquisitions amounted to $75 million in 1997, compared with $9 million in 1996 with an increase of $75 million between years in Venezuela for the LL-652 Field slightly offset by a decrease in Canada. Additions to proved reserves from extensions, discoveries and improved recoveries were 52 million barrels of crude oil and natural gas liquids and 20 billion cubic feet of natural gas.
In Europe, production from the Chevron-operated North Sea Alba Field, located 130 miles northeast of Aberdeen, averaged 91,000 barrels of oil per day. In February 1998, Chevron's equity interest in Alba was reduced from 33.17 percent to 21.17 percent following an asset exchange with Statoil in Norway. Chevron acquired a 7.56 percent interest in Statoil's Draugen Field in the Norwegian North Sea and an interest in five exploration blocks offshore Norway as part of the exchange. The concept work and detailed design and procurement was completed on the gross fluids upgrade component of the Alba Phase II development. A subsea water injection well was commenced and a four mile pipeline connecting the platform to the water injection well was installed. Also in 1997, new water treatment facilities,
necessary to handle the increased volume of water associated with higher crude oil production levels, were installed. Completion of the gross fluids upgrade is expected during early 1998. The development of the North Sea Britannia gas field, which lies underneath the Alba Field, and in which Chevron has a 30.2 percent equity interest, continued with the installation and beginning of hook-up and commissioning of the jacket and platform topsides. The project remains on target for gas production in August 1998. Peak production is expected to be approximately 740 million cubic feet of gas and 60,000 barrels of liquids per day. Seventy-five percent of the estimated deliverable gas is currently under long-term contracts. The owners of the Alba and Britannia fields also reached an agreement to share gas resources. A pipeline will be laid between Alba and the adjacent Britannia platform to allow Alba to sell excess gas to Britannia, and conversely purchase gas from Britannia when insufficient gas is produced to run the Alba platform facilities. This arrangement is expected to reduce the amount of gas flared from the Alba platform. In addition to ongoing geologic and reservoir studies, two additional appraisal wells were drilled in 1997 in the Clair Field, located 40 miles west of the Shetland Islands, in which Chevron has a 19.42 percent equity interest. The current work program is focused on achieving first oil production during 2001 from the first phase of development and targets 250 million barrels of recoverable oil in a core part of the field.
In Canada, the company aggressively pursued development of the 650 million barrel Hibernia project offshore Newfoundland and continues to concentrate its other development efforts in western Canada, where operating efficiencies and lower operating costs can be realized using existing infrastructure. The Hibernia development, in which Chevron has a 26.9 percent interest, began producing oil in November 1997. The sale and lifting of the first 850,000 barrel tanker cargo occurred in December. At year-end 1997, two wells were producing approximately 60,000 barrels per day with a third well being drilled. Production is anticipated to reach design capacity of 150,000 barrels per day in 1999. The company's capitalized investment (including capitalized interest) in this project was $1.3 billion at year-end 1997. In western Canada, completion of the Chinchaga gas plant expansion in northwestern Alberta doubled processing capacity to 120 million cubic feet per day, enabling the company to handle increased production from the area and to capture additional revenue through the processing of third party volumes. Successful horizontal drilling in mature fields such as Virden, Princess, and Mitsue, along with development drilling programs in central Alberta, helped maintain the company's net production volumes of crude oil and natural gas in the region.
In Indonesia, the Duri Steamflood Project, begun in 1985 to assist the difficult production process for the relatively heavy, waxy Duri crude, is being completed in 13 stages (Areas 1-13) with eight areas currently on production. Total Duri production averaged over 284,000 barrels per day in 1997. A waterflood project involving 21 fields in Central Sumatra continued in 1997, as the installation of the fourth area in the Minas pattern waterflood project started and the approval of a fifth area for pattern waterflood development was received. Construction of the Light Oil Steamflood pilot at Minas began in 1997, with first steam injection targeted for early 1999. Chevron's Amoseas Indonesia (AI) affiliate in Indonesia is now focused on geothermal power generation and operates the Darajat geothermal contract in central Java. Steam from the Darajat geothermal field, located 115 miles southeast of Jakarta, was produced and sold to the national power company, PLN, for electricity generation in the PLN-owned Darajat I power plant, for the third full year. Construction of the first expansion phase Darajat II 70 megawatts power plant, to be owned and operated by AI and its Indonesian partner, is on schedule for completion in late 1998. Reserves for a third power plant were proved with the successful 1997 drilling program. AI continues drilling for additional reserves.
In Kazakhstan, TCO's average liquids production was 155,000 barrels per day for the year, an increase of 43,000 barrels per day over the average for 1996. In 1997, TCO began an extensive plant expansion program to increase production capacity at the Tengiz Field to approximately 185,000 barrels per day in 1998 by modifying existing facilities, and 240,000 barrels per day by 2000 by the construction of new facilities. In April 1997, Chevron completed the sale of 10 percent of its 50 percent interest in TCO to LUKARCO, an affiliate of LUKoil, a Russian oil company, and Arco, thereby reducing Chevron's ownership to 45 percent. In May 1997, Chevron acquired a 15 percent ownership interest in the restructured Caspian Pipeline Consortium, formed to build a crude oil pipeline from the Tengiz oil field to the Russian Black Sea coast. In March 1998, Chevron and Caspian TransCo entered into an agreement with the Republic of Georgia to build a new section of pipeline and to reconstruct an existing section, which together will link Ali Bairamly in Azerbaijan with Georgia's Black Sea port of Batumi. The new link will allow TCO to significantly increase the amount of crude oil it can transport by pipeline through Azerbaijan
and Georgia. TCO continues to move oil by pipeline, barge, and rail car to destinations in the former Soviet Union and Europe, and in 1997 signed an agreement with Sinochem, a Chinese state oil trader, to make a test shipment of crude oil from the Tengiz Field to China.
In Australia, debottlenecking plans are in the evaluation stage to improve the onshore fractionation capacity of NWS condensate to increase liquefied petroleum gas production to 10 million barrels per year, and to increase Wanaea/Cossack crude oil production to over 100,000 barrels per day. The NWS participants are currently negotiating a Letter of Intent (LOI) with Japanese buyers to double the volume of LNG deliveries from the NWS project starting in 2003. The expansion is expected to cost approximately $5 billion (total project) with start-up by 2003 based on the expected signing of the LOI in 1998. WAPET development activities included the completion of a 23 well infill drilling program on Barrow Island, which stabilized oil production and added oil reserves. Evaluations by the partners continued regarding options for the commercial development of the Gorgon and Chrysaor gas fields as liquefied natural gas and domestic gas projects.
In Papua New Guinea (PNG), Chevron (with an average 15 percent interest) and its partners commenced construction of production facilities for the Gobe Area fields in 1997. First oil production from Gobe occurred in March 1998 with peak production of 50,000 barrels per day expected in mid-1998. An active infill development drilling program designed to accelerate production and develop new oil reserves for the Kutubu Area fields, where Chevron has a 19.38 percent interest, continued in 1997. Three horizontal sidetracks of existing wells and one new well resulted in an increase in proved reserves of 6 million barrels. This essentially completes the development drilling of Kutubu. During 1997, Chevron continued to pursue the PNG to Queensland, Australia, Gas Pipeline Project. This project plans to allow commercialization of PNG natural gas reserves and the recovery of substantial quantities of LPG's. In March 1998, Chevron filed an environmental impact assessment study for the proposed pipeline for public review. A decision on the viability of this project is expected in 1998.
In Venezuela, Chevron and Maraven S.A. formed an alliance in late 1995 to further develop the Boscan oil field. In July 1996, Chevron became responsible for the operations, production and development of this field under an operating services agreement, whereby Chevron receives operating expense reimbursement and capital recovery, plus interest and an incentive fee. At year-end 1997, Boscan production was about 90,000 barrels per day with plans to increase production to 115,000 barrels per day by the end of 1998. In addition, the alliance calls for the supply of Venezuelan crude oil to Chevron refineries in the United States through several independent supply arrangements. Because of specific contract provisions in the Boscan Field Operating Services Agreement, production and reserves for this field are not included in the company's reported production and reserve quantities. In 1997, a consortium consisting of Chevron, Statoil, Arco, and Phillips, with Chevron as operator, successfully bid to operate the LL-652 field located in the northeast section of Lake Maracaibo. The LL-652 oil field, one of the largest offered by Petroleos de Venezuela, S.A. (PDVSA) in the Third Bid Round, is estimated to contain recoverable reserves exceeding 500 million barrels. The 20-year agreement between the consortium and PDVSA calls for takeover of the field no later than May 1998, upon approval of the development plan. Through an extensive drilling program, installation of offshore platforms for gas handling, and a large-scale waterflood to repressure the reservoir, it is expected to increase total production from a baseline of 10,000 barrels per day to 115,000 barrels per day by 2006. Chevron's 30 percent interest is likely to be reduced to 27 percent once EPIC, a Venezuelan state-sponsored mutual fund, exercises its option to participate as a 10 percent partner in LL-652. In 1997, Chevron recorded 49 million barrels of proved reserves for LL-652.
In Colombia, the Castilla and Chichemene fields, where Chevron holds 50 percent interests, were producing 34,000 barrels of oil per day at year-end 1997. Both fields are located in the Llanos Basin. During 1997, one development well at each field was drilled and brought to production.
Petroleum - Natural Gas Liquids and NGC Corporation
The company sells natural gas liquids from its producing operations under a variety of contractual arrangements. In the United States, the majority of sales are to the company's NGC affiliate. On September 1, 1996, Chevron merged its natural gas liquids gathering, processing and marketing operations, conducted by its Warren Petroleum Company division, and its U.S. natural gas marketing activities, conducted by Chevron U.S.A. Production
Company, with NGC, and assumed a 28 percent equity interest in NGC. Outside the United States, significant sales take place in the company's Canadian upstream operations and lower levels of sales in upstream operations in Africa, Australia and Europe. In 1997, U.S. sales volumes, including the company's share of NGC sales, comprised about 75 percent of the company's total worldwide natural gas liquids sales volume.
NGC is one of the leading processors and marketers of natural gas liquids in North America with production of 140,000 barrels per day and sales of more than 400,000 barrels per day. Also NGC is the second largest marketer of natural gas in North America with sales of 8 billion cubic feet per day, and is the second largest electric power marketer in the United States. NGC and Chevron have entered into long-term strategic alliances whereby NGC purchases substantially all natural gas and natural gas liquids produced by Chevron in the United Sates, excluding Alaska, and supplies natural gas and natural gas liquids feedstocks to Chevron's U.S. refineries and chemicals plants. Through its "Energy Store" concept, NGC offers multi-commodity energy products and services that provide natural gas, NGL's, electricity and crude oil. NGC maintains an asset base that includes interests in approximately 15,000 miles of natural gas gathering and transmission pipelines, 19 power generation facilities, approximately 50 gas processing plants currently operating, three NGL fractionation facilities, 60 million barrels of NGL storage capacity, three NGL import/export marine terminals, ten other NGL terminals and approximately 2,100 miles of NGL pipelines.
Chevron's total third-party natural gas liquids sales volumes over the last three years are reported in the following table:
- ---------------------------------------------------------------
Natural Gas Liquids Sales Volumes (Thousands of barrels per day)
1997 1996 1995 ---- ---- ---- United States - Warren - 139 203 United States - Other 64 25 10 ---- ---- ---- Total United States 64 164 213 Canada 30 27 40 Other International 13 9 7 ---- ---- ---- Total Consolidated Companies 107 200 260 ---- ---- ----
Equity in NGC Affiliate 68 23 - ---- ---- ---- Total including Affiliate 175 223 260 ==== ==== ====
- ---------------------------------------------------------------
In 1997, Venice Energy Services Company (VESCO), a partnership between Chevron and Warren Petroleum, a subsidiary of NGC, was further expanded by the addition of Koch Energy Services Company and an affiliate of Shell Midstream Enterprises, as partners. VESCO owns and operates the Venice, Louisiana natural gas facilities, located approximately 75 miles southeast of New Orleans, which include an offshore gas-gathering system, a gas-processing plant, a gas-liquids fractionation facility, an underground gas-liquids storage facility and a multi-barge, gas-liquids terminal. Koch contributed a cryogenic gas processing plant in exchange for an ownership interest in the partnership. Shell dedicated natural gas production from three Gulf of Mexico fields and certain future developments in the offshore Mississippi Canyon area for processing at the Venice facilities in exchange for an ownership interest in the partnership. The partnership has doubled the gas gathering capacity of the Venice complex to 800 million cubic feet per day. The cryogenic plant contributed by Koch increased gas processing capacity at Venice from 1.0 billion to 1.3 billion cubic feet per day. Under terms of the partnership, Chevron operates the offshore facilities and remains one of the major producer- suppliers to the Venice complex. Warren operates the onshore facilities and has commercial responsibility for the partnership. The Venice facilities are well positioned to take advantage of anticipated growth opportunities resulting from increased production of liquids- rich gas from deepwater projects in the Gulf of Mexico. There are plans for further plant expansion by year-end 1999 to accommodate the expected future needs of Shell and other producers in the region.
Petroleum - Reserves and Contract Obligations
Table IV on pages FS-35 and FS-36 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, 1997, 1996, and 1995. During 1997, 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-36 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 company is obligated to sell substantially all of the natural gas produced and owned or controlled by the company in the lower 48 states to NGC. Chevron has retained a few long-term natural gas supply contracts, but the volumes associated with these agreements are not material. Outside the United States, the company is contractually committed to deliver approximately 550 billion cubic feet of natural gas through 2020 in Australia, 46 billion cubic feet of natural gas through 2000 in the United Kingdom, and approximately 3 billion cubic feet of natural gas through 1999 in Canada. The company believes it can satisfy these contracts from quantities available from production of the company's proved developed Australian, U.K. and Canadian natural gas reserves.
Petroleum - Refining
The daily refinery inputs over the last three years for the company's and its Caltex affiliate's refineries are shown in the following table:
Petroleum Refineries: Locations, Capacities And Inputs (Inputs and Capacities are in Thousands of Barrels Per Day)
December 31, 1997 ----------------- Operable Refinery Inputs -------------------- Locations Number Capacity 1997 1996 1995 - --------------------------- ------ -------- ----- ---- -----
Pascagoula, Mississippi 1 295 312 313 282 El Segundo, California 1 260 203 223 221 Richmond, California 1 225 220 220 202 El Paso,(1) Texas 1 65 60 60 58 Honolulu, Hawaii 1 54 53 54 55 Salt Lake City, Utah 1 45 41 40 41 Other(2) 3 102 44 41 66 ----- -------- ----- ---- ----- Total United States 9 1,046 933 951 925 ----- -------- ----- ---- -----
Burnaby, B.C., Canada 1 50 48 48 47 Milford Haven, Wales,(3) United Kingdom - - 101 117 100 ----- -------- ----- ----- ----- Total International 1 50 149 165 147 ----- -------- ----- ----- ----- Total Consolidated Companies 10 1,096 1,082 1,116 1,072
Equity in Caltex Affiliate Various Locations 13 452 416 372 451 ----- -------- ----- ----- ----- Total Including Affiliate 23 1,548 1,498 1,488 1,523 ===== ======== ===== ===== =====
(1) Capacity and input amounts for El Paso represent Chevron's share. (2) Refineries in Perth Amboy, New Jersey; Portland, Oregon; and Richmond Beach, Washington, which are primarily asphalt plants. Inputs include Port Arthur, Texas (sold in 1995). (3) Ceased processing operations December, 1997.
Based on refinery statistics published in the December 22, 1997, issue of The Oil and Gas Journal, Chevron had the third largest U.S. refining capacity and ranked among the top ten in worldwide refining capacity including its share of affiliate's refining capacity. At year-end 1997, the company owned and operated nine refineries in the United States and one in Canada. In December 1997, the company ceased processing operations at, and will shut down, its 115,000 barrel-per-day refinery located near Milford Haven, Wales. The company also divested its 50 percent equity interest in the Pembroke Cracking Co., which operates a 90,000 barrel-per-day catalytic cracking facility at Texaco's refinery in Pembroke, Wales. At year-end 1997, the company's 50 percent owned Caltex Petroleum Corporation affiliate owned or had interests in 13 operating refineries: Japan (2), Australia (2), Thailand (2), Korea, the Philippines, New Zealand, Singapore, Pakistan, Kenya and South Africa. In April 1997, Caltex sold its 40 percent interest in a refinery in Bahrain, having ceded its throughput rights to 107,000 barrels per day of capacity at the refinery in April 1996. Also in April 1996, Caltex sold its 50 percent interest in Nippon Petroleum Refining Company, Limited, which included two refineries in Japan, to its partner, Nippon Oil Company, Limited. Caltex's share of refining capacity for these two refineries totaled 255,000 barrels per day at year-end 1995.
Distillation operating capacity utilization, adjusted for sales and closures, in 1997 averaged 89 percent in the United States (including asphalt plants) and 91 percent worldwide (including affiliate), compared with 91 percent in the United States and 90 percent worldwide in 1996. Chevron's capacity utilization at its U.S. fuels refineries averaged 94 percent in 1997 and 97 percent in 1996. Chevron's capacity utilization of its U.S. cracking and coking facilities, which are the primary facilities used to convert heavier products to gasoline and other light products, averaged 80 percent in 1997, down from 82 percent in 1996. The company processed imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 53 percent of Chevron's U.S. refinery inputs in 1997.
Petroleum - Refined Products Marketing
Product Sales: The company and its Caltex Petroleum Corporation affiliate market petroleum products throughout much of the world. The principal trademarks for identifying these products are "Chevron," "Gulf" (principally in the United Kingdom prior to the December 1997 disposition of that business) and "Caltex." Worldwide refined products sales volumes, including the company's share of affiliate's sales, increased to 2,079,000 barrels per day in 1997, slightly higher than the 2,066,000 barrels per day in 1996. The company's U.S. sales volumes of refined products during 1997 increased about six percent from 1996 to 1,193,000 barrels per day, equivalent to approximately seven percent of total U.S. consumption. The company's share of affiliate's sales during 1997 decreased about three percent from 1996 to 577,000 barrels per day and were about 12 percent lower than 1995 sales volumes. These decreases were primarily due to lower Caltex sales volumes after Caltex's sale of its 50 percent interest in Nippon Petroleum Refining Company, Limited in April 1996. The following table shows the company's and its affiliate's refined product sales volumes, excluding intercompany sales, over the past three years.
- ------------------------------------------------------------------- Refined Products Sales Volumes (Thousands of Barrels Per Day)
1997 1996 1995 ----- ----- ----- United States Gasolines 591 556 552 Jet Fuel 249 255 241 Gas Oils and Kerosene 204 186 196 Residual Fuel Oil 60 39 38 Other Petroleum Products (1) 89 86 90 ----- ----- ----- Total United States 1,193 1,122 1,117
International United Kingdom 103 110 97 Canada 61 60 58 Other International 145 180 157 ----- ----- ----- Total International 309 350 312 ----- ----- ----- Total Consolidated Companies 1,502 1,472 1,429
Equity in Affiliate 577 594 657 ----- ----- ----- Total Including Affiliate 2,079 2,066 2,086 ===== ===== =====
(1)Principally naphtha, lubes, asphalt and coke. - -------------------------------------------------------------------
The company's Canadian sales volumes consist of refined product sales in British Columbia and Alberta by the company's Chevron Canada Limited subsidiary. In the United Kingdom, the reported sales volumes represented a full range of products by the company's Gulf Oil (Great Britain) Ltd. subsidiary until the sale of its retail marketing assets to Shell in December 1997. The 1997 volumes reported for "Other International" relate to international sales of aviation and marine fuels, lubricants, gas oils and other refined products, primarily in Latin America, Asia and Europe. The equity in affiliate's sales in 1997 consists of the company's interest in Caltex Petroleum Corporation, which maintains an interest in about 7,900 service stations (of which 4,600 are branded Caltex) operating in approximately 60 countries including the Philippines, Thailand, New Zealand, South Africa and, through Caltex affiliates, in Australia, Japan and Korea.
Retail Outlets: In the United States, the company supplies, directly or through jobbers, more than 7,700 motor vehicle retail outlets, of which more than 1,700 are company-owned or -leased motor vehicle service stations, and more than 500 aircraft and marine retail outlets. The company's gasoline market area is concentrated in the southern, southwestern and western states. According to the Lundberg Share of Market Report, Chevron ranks among the top three gasoline marketers in 14 states, and is the top marketer of aviation fuel in the western United States.
In 1997, Chevron continued to implement an alliance with McDonald's to develop a network of retail sites that combine Chevron service stations and convenience stores with McDonald's restaurants in 12 western and southwestern states. As of year-end 1997, the two companies operated 75 sites together in these states.
Convenience store sales continue to be an area of growth and opportunity for the company. Key programs were added in 1997 to accelerate profit growth including the installation of automated teller machines, which in time, will dispense a variety of products such as event tickets, in addition to cash, at approximately 430 service stations.
The company expanded its "FastPay" system, increasing the total number of service stations with the system to about 4,100 nationwide. This automated system allows credit card customers to pay at the pump with credit approvals processed in about five seconds using satellite data transmission.
During 1997, the company continued to expand and institute programs intended to build positive brand recognition and reputation for quality products and service in the United States. Training programs, emphasizing a customer focus at company service stations, were expanded. A new station performance review program, designed to improve service and image throughout the retail network, was introduced.
Internationally, the company's branded products are sold in 187 stations (all owned or leased) in British Columbia, Canada, and were sold in approximately 450 stations (about 190 owned or leased) in the United Kingdom prior to the company's exit from that business in December 1997. The company also has an interest in one service station in Kazakhstan and another is currently under construction.
Petroleum - Transportation
Tankers: Chevron's controlled seagoing fleet at December 31, 1997, is summarized in the following table. All controlled tankers were utilized in 1997. In addition, at any given time, the company has 25 to 35 vessels under charter on a term or voyage basis.
- ----------------------------------------------------------------------------- Controlled Tankers At December 31, 1997
U.S. Flag Foreign Flag ---------------------------- ---------------------------- Cargo Capacity Cargo Capacity Number (Millions of Barrels) Number (Millions of Barrels) ------ ------------------- ----- ------------------- Owned 3 1.0 20 19.5 Bareboat Charter 2 0.5 9 12.5 Time-Charter - - 5 2.3 -- --- -- ---- Total 5 1.5 34 34.3 == === == ==== - -----------------------------------------------------------------------------
Federal law requires that cargo transported between U.S. ports be carried in ships built and registered in the United States, owned and operated by U.S. entities and manned by U.S. crews. At year-end 1997, 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 1997, two of the company's controlled international flag vessels was being used for floating storage. The remaining international flag vessels were engaged primarily in transporting crude oil from the Middle East, Indonesia, Mexico and West Africa to ports in the United States, Europe, the United Kingdom, and Asia. Refined products also were transported by tanker worldwide.
In addition to the tanker fleet summarized in the table above, the company owns a one-sixth undivided interest in each of six LNG ships that are bareboat chartered to the Australian North West Shelf Project. These ships, along with two time-chartered LNG vessels, primarily transport LNG from Australia to various Japanese gas and electric utilities. The company also has a 40.4 percent interest in one tanker with a capacity of 850,000 barrels used to transport crude oil from the Hibernia Field offshore Newfoundland.
During 1997, the company acquired four domestic tankers with about two million barrels of capacity that were previously leased by the company under bareboat charters. Agreements were reached in 1997 to sell two of these vessels. One sale was completed in 1997, and the second sale will be completed in mid-1998.
In December 1996 and June 1997, the company reached agreements to lease, under bareboat charters, and operate four new 308,500 deadweight ton, double-hull tankers. The tankers will be built in Korea with deliveries of three tankers scheduled for 1999 and one scheduled for 2000. These additions will bring to 16 the number of double-hull tankers controlled by Chevron. In July 1997, the company began operation of a liquid petroleum gas floating storage tanker offshore Nigeria. The tanker stores, prior to its export, up to 30,000 metric tons of LPG per month produced from the Escravos Gas Project.
Page 29 of this Annual Report on Form 10-K contains a discussion of the effects of the Federal Oil Pollution Act on the company's shipping operations.
Pipelines: Chevron owns and operates an extensive system of crude oil, refined products, chemicals, natural gas liquids and natural gas pipelines in the United States. The company also has direct or indirect interests in other U.S. and international pipelines. The company's ownership interests in pipelines are summarized in the following table:
- ----------------------------------------------------------------------- Pipeline Mileage At December 31, 1997
Wholly Partially Owned Owned(1) Total ------ -------- ------ United States: Crude oil(2) 3,773 366 4,139 Natural gas 477 138 615 Petroleum products 2,074 2,624 4,698 ------ -------- ------ Total United States 6,324 3,128 9,452 ------ -------- ------ International: Crude oil - 1,009 1,009 Natural gas - 265 265 Petroleum products - 104 104 ------ -------- ------ Total International - 1,378 1,378 ------ -------- ------ Worldwide 6,324 4,506 10,830 ====== ======== ======
(1)Reflects equity interest in lines. (2)Includes gathering lines related to the transportation function. Excludes gathering lines related to the U.S. production function. - -----------------------------------------------------------------------
Chemicals
The company's chemicals operations manufacture and market commodity chemical products for industrial use and chemical additives for fuels and lubricants. At year-end 1997, Chevron Chemical Company owned and operated 15 U.S. manufacturing facilities in nine states, owned manufacturing facilities in Brazil and France, and owned a majority interest in a manufacturing facility in Japan. The principal U.S. plants are located at Cedar Bayou, Orange and Port Arthur, Texas; St. James and Belle Chasse, Louisiana; Marietta, Ohio; Pascagoula, Mississippi; and Richmond, California.
The following table shows, by chemicals division, 1997 revenues and the number of owned or majority owned chemicals manufacturing facilities and combined operating capacities as of December 31, 1997.
- ------------------------------------------------------------------------------- Chemicals Operations
Manufacturing 1997 Facilities Annual Revenue(1) -------------------- Division U.S. International Capacity ($Millions) - ------------------ ---- ------------- ------------------ --------- U.S. Chemicals 13 - 14,691 million lbs. $2,636 Oronite Additives 2 3 197 million gals. 766 Other - - N/A 118 -- -- ------ Total 15 3 $3,520 == == ====== (1)Excludes intercompany sales. - -------------------------------------------------------------------------------
During 1997, the company completed major expansion and de-bottleneck projects to increase ethylene and polystyrene production capacities at the Port Arthur, Texas and the Marietta, Ohio plants. Planned expansions, expected to be completed in 1998 and 1999, will increase paraxylene and polyethylene production capacities at the company's Pascagoula, Mississippi, and Orange, Texas facilities, respectively.
In 1997, Chevron continued with plans to construct manufacturing facilities and expand its chemicals business outside the United States. In Saudi Arabia, the company and its joint venture partner, the Saudi Industrial Venture Capital Group, broke ground on a petrochemicals complex expected to produce annually approximately 480,000 tons of benzene, using the company's proprietary Aromax technology, and 220,000 tons of cyclohexane. Construction of this facility is scheduled to be completed in 1999. Construction also began on a fuel and lube oil additives manufacturing facility in Singapore, which will have an annual capacity of approximately 100,000 metric tons of additives. Additionally, Chevron signed a memorandum of understanding with a subsidiary of Petroleos de Venezuela, S.A. to study the feasibility of an integrated aromatics project in Venezuela. The company also has plans to construct a polystyrene plant in China which will represent the company's entry into the chemicals business in that country. Engineering work is complete and groundbreaking is expected in 1998. In November 1997, Chevron completed the sale of its 10.65 percent interest in the Octel Group, a U.K.-based manufacturer and marketer of leaded fuel additives.
Coal and Other Minerals
Coal: The company's wholly-owned coal mining and marketing subsidiary, The Pittsburg and Midway Coal Mining Co. (P&M), owned and operated three surface and two underground mines at year-end 1997. Two of the mines are located in New Mexico and one each in Wyoming, Alabama and Kentucky. All of the mines produce steam coal used primarily for electric power generation. P&M's strategy is to focus on regional markets in the United States, capitalizing on major utility growth markets in the southwest and southeast. P&M also has a 33 percent interest in the Black Beauty Coal Company, whose principal operations are in Indiana and Illinois. In 1997, P&M acquired the Skull Point Mine in Wyoming, adjacent to its Kemmerer, Wyoming, facility, which it combined with its existing operations. P&M also acquired a 29.8 percent interest in Inter- American Coal Holding N.V., which has interests in mining operations in Venezuela. The company also formed two partnerships in Montana in the North Powder River Basin, which is the largest remaining undeveloped compliance coal area in the United States.
Sales of coal from P&M's wholly-owned mines and from its interest in the Black Beauty Coal Company were 19.6 million tons in 1997, an increase of 22 percent from 1996 sales of 16.0 million tons. About 56 percent of 1997 sales came from two mines, the McKinley Mine in New Mexico and the Kemmerer Mine in Wyoming. The increase in
sales volumes between years arose primarily at the Black Beauty Coal Company stemming from new sales contracts and mine developments, at the McKinley Mine as electricity markets improved in the southwest United States, and at the Kemmerer Mine, stemming from supply agreements included with the 1997 acquisition of the Skull Point Mine. The average selling price for coal from mines owned and operated by P&M was $23.43 per ton in 1997 compared with $24.48 per ton in 1996. Sales and other operating revenues were $359 million and $329 million in 1997 and 1996, respectively. The decrease in average selling price between years was primarily due to incentive pricing offered on the higher sales volumes in 1997. In 1996, the company also recovered liquidated damages from customers who did not purchase their minimum contract tonnage obligations. At year-end 1997, P&M controlled approximately 509 million tons of developed and undeveloped coal reserves, including significant reserves of environmentally desirable low-sulfur coal.
Demand growth for coal in the United States remains largely dependent on the demand for electric power, which in turn depends on regional and national economic conditions and on competition from other fuel sources. In 1997, the electric utility industry consumed over 80 percent of all coal produced in the United States. Approximately 85 percent of P&M's coal sales are made to electric utilities, of which, about 50 percent are under long-term contracts. Generally, these contracts contain index-adjusted pricing provisions and minimum-take requirements that have helped mitigate the effects on P&M's results from short-term fluctuations in coal prices and consumption levels.
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 chemicals 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 sciences, 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 1997 numbered more than 1,100, with approximately 500 additional employees working on research activities in the company's other operating units.
Chevron's research and development expenses were $179 million, $182 million and $185 million for the years 1997, 1996 and 1995, respectively.
Licenses under the company's patents are generally made available to others in the petroleum and chemicals industries. For example, in 1997 the company licensed 170,000 barrels a day of its hydroprocessing technology, which produces high-quality lubricant base oils and cleaner burning fuels. However, the company's business is not dependent upon licensing patents.
Environmental Protection: One of Chevron's goals is to be recognized worldwide for environmental excellence, and commitment to the environment remains an integral part of the company's business philosophy. In 1992, Chevron established a systematic approach for improving health, safety and environmental performance. The program is called "Protecting People and the Environment" and applies to operations worldwide. It emphasizes continuous improvement for significant long-term gains. The program defines 10 categories of performance, which are supported by 102 specific management practices to be integrated into local management systems. By year-end 1997, nearly all Chevron operations met their "Protecting People and the Environment" program goals by fully implementing the 102 management practices. In 1997, the company published a report called "Protecting People and the Environment - A Report on Chevron's Practices and Performance," which summarizes the company's health, environmental and safety practices and performance. Chevron's previous corporate health, safety and environmental report was published in 1994.
The company's oil and gas exploration activities, along with those of many other petroleum companies, have been hampered by drilling moratoria, imposed because of environmental concerns, in areas where the company has leasehold interests. Difficulties in obtaining necessary permits 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 U.S. or international petroleum concerns. The situation has, however, been a factor, among others, in the shift of the company's exploration efforts to areas outside of the United States.
As of January 1, 1995, the Clean Air Act Amendments of 1990 require that only reformulated gasoline (RFG) may be sold in the nine worst ozone areas in the United States but other areas have voluntarily opted into the RFG requirement. In addition, the California Air Resources Board required a more stringent reformulated gasoline be sold statewide in all service stations beginning on June 1, 1996. Since 1991, the company has spent about $1.7 billion in capital expenditures on air quality projects at its U.S. 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 Federal Oil Pollution Act of 1990 (OPA) created federal authority to direct private responses to oil spills, to improve preparedness and response capabilities, and to impose monetary damages on those who spill for all damages, including environmental restoration and loss of use of the resources during restoration. Under OPA, owners or operators of vessels operating in U.S. waters or transferring cargo in waters within the U.S. Exclusive Economic Zone are required to possess a Certificate of Financial Responsibility for each of these vessels. The Certificate is issued by the U.S. Coast Guard after the owner or operator has demonstrated the ability to meet Coast Guard guidelines for financial responsibility in the case of an oil spill. OPA also requires the scheduled phase-out, by year-end 2014, of all single hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone, which has and will continue to result in the utilization of more costly double-hull tankers. A separate single hull phase-out schedule under the International Maritime Organization's Regulation 13 is leading to the utilization of more costly double-hull tankers in all other parts of the world. Chevron has been actively involved in the Marine Preservation Association, a non-profit organization that funds the Marine Spill Response Corporation (MSRC). MSRC owns the largest inventory of oil spill response equipment in the nation and operates five strategically located U.S. coastal regional centers. In addition, the company is a member of many oil-spill response cooperatives in areas in which it operates around the world.
Chevron expects increased environmental-related regulations in the countries where it has operations. In the United States, 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 1997, the company's U.S. capitalized environmental expenditures were $177 million, representing approximately seven percent of the company's total consolidated U.S. capital and exploratory expenditures. The company's U.S. capitalized environmental expenditures were $157 million and $607 million in 1996 and 1995, 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 1998, the company estimates that U.S. capital expenditures for environmental control facilities will be approximately $193 million. The actual expenditures for 1998 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 remain close to the estimated 1998 levels.
Under provisions of the Superfund law, Chevron has been designated as a potentially responsible party (PRP) for remediation of a portion of 282 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 1997, the company's environmental remediation reserve related to Superfund sites amounted to $43 million. Forecasted expenditures for the largest of these sites, located in California, amounts to approximately 18 percent of the reserve.
The company's 1997 environmental expenditures, remediation provisions and year- end environmental reserves are discussed on pages FS-3 and FS-4 of this Annual Report on Form 10-K. These pages also contain additional discussion of the company's liabilities and exposure under the Superfund law and additional discussion of the effects of the Clean Air Act Amendments of 1990.
Item 2.
Item 2. Properties
The location and character of the company's oil, natural gas and coal properties and its refining, marketing, transportation and chemicals 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-32 to FS-37 of this Annual Report on Form 10-K. Note 13, "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 expense, by geographic area and industry segment for 1997, 1996 and 1995.
Item 3.
Item 3. Legal Proceedings
A. Cities Service Co. v. The Gulf Oil Corporation Oklahoma State District Court for the District of Tulsa. This is an action by Cities Service Company (now OXY USA Inc. as successor in interest) against Gulf Oil Corporation (now Chevron U.S.A. Inc.) and GOC Acquisition Corporation ("Gulf") alleging breach of contract, malicious breach of contract, and fraud arising out of a terminated merger agreement. The complaint was originally filed in August 1982 in Oklahoma State Court. Trial commenced April 15, 1996.
On July 18, 1996, the jury returned a verdict for Gulf on Cities' fraud and malicious breach of contract claims. On Cities' breach of contract claim, the court directed verdicts that (1) Gulf had breached the contract, (2) Cities was entitled to recover certain attorneys' fees related to the Gulf/Cities merger, and (3) Cities was entitled to recover the cost of a settlement with and repurchase of the stock from Mesa Petroleum Corporation if the jury found that the settlement and repurchase were done in reliance on the merger agreement with Gulf. In its verdict, the jury found against Gulf on the reliance issue. Accordingly, on July 19, 1996, the court entered a judgment of $742,206,906 against Gulf, which included $512,585,506 in prejudgment interest awarded by the court, which interest continues to accrue at 9.55 percent per year. No motions for relief from the judgment were filed in the trial court. On July 31, 1996, the court approved Gulf's supersedeas bond, thus staying enforcement of the judgment during pendency of Gulf's appeal.
On August 14, 1996, Gulf appealed from the judgment. On December 31, 1996, the Oklahoma Supreme Court granted the parties' motion to retain the appeal for decision, rather than having it transferred to the Oklahoma Court of Appeals. Gulf filed its opening brief on March 12, 1997; Cities filed its answering brief on June 23, 1997 and Gulf filed its reply brief on August 4, 1997.
B. Rangely Field Spills. In 1997 the United States Environmental Protection Agency ("EPA") and the Department of Justice indicated an intent to bring a civil action against the company seeking penalties under the Clean Water Act with respect to spills that have occurred at the company's operations at the Rangely Field, Colorado. The company intends to dispute that such operations have in fact resulted in liability under the Clean Water Act, as asserted by EPA.
C. Richmond Refinery Multimedia Inspection. In 1993, EPA conducted a multimedia inspection of the Chevron Products Company Richmond, California Refinery, which focused on compliance related to various areas, including the Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act and the Comprehensive Environmental Response Compensation and Liability Act. While certain aspects of the multimedia investigation have been closed, EPA has referred potential Clean Water Act violations of the refinery's NPDES permit to the Department of Justice for civil litigation.
The violations alleged involve 11 excursions of the NPDES permit's toxicity limit and numerous alleged violations of the by-pass prohibition contained in the permit. The company has strenuously contested the allegations relating to violations of the by-pass prohibitions, but does not contest the toxicity excursion allegations, which occurred over a five-year period. No litigation has been instituted thus far, and settlement discussions are taking place.
Other previously reported legal proceedings have been settled or the issues resolved so as not to merit further reporting.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted during the fourth quarter of 1997 to a vote of security holders through the solicitation of proxies or otherwise.
Executive Officers of the Registrant at March 1, 1998
Name and Age Executive Office Held Major Area of Responsibility - ------------------- -------------------------------- ----------------- K. T. Derr 61 Chairman of the Board since 1989 Chief Executive Officer Director since 1981 Executive Committee Member since 1986
J. N. Sullivan 60 Vice-Chairman of the Board Worldwide since 1989 Refining, Marketing Director since 1988 and Transportation Executive Committee Member Activities, since 1986 Chemicals, Real Estate, Environmental, Human Resources, Coal, Administrative Services, Aircraft Services
H. D. Hinman 57 Vice-President and General Law Counsel since 1993 Executive Committee Member since 1993
M. R. Klitten 53 Vice-President and Chief Finance Financial Officer since 1989 Executive Committee Member since 1989
R. H. Matzke 61 Vice-President since 1990 Overseas Exploration Director since 1997 and Production President of Chevron Overseas Petroleum Inc. since 1989 Executive Committee Member since 1993
D. J. O'Reilly 51 Vice-President since 1991 U.S. Refining, President of Chevron Products Marketing, Company since 1994 Logistics and Trading Executive Committee Member since 1994
J. E. Peppercorn 60 Vice-President since 1990 Chemicals President of Chevron Chemical Company since 1989 Executive Committee Member since 1993
P.J. Robertson 51 Vice-President since 1994 North American President of Chevron U.S.A. Exploration and Production Company since 1997 Production, Natural Executive Committee Member Gas Liquids since 1997
The Executive Officers of the Corporation consist of the Chairman of the Board, the Vice-Chairman of the Board, and such other officers of the Corporation who are either Directors or members of the Executive Committee, or are chief executive officers of principal business units. Except as noted below, all of the Corporation's Executive Officers have held one or more of such positions for more than five years.
H. D. Hinman - Partner, Law Firm of Pillsbury Madison & Sutro - 1973 - Vice-President and General Counsel, Chevron Corporation - 1993
D. J. O'Reilly - Vice-President for Strategic Planning and Quality, Chevron Corporation - 1991 - Vice-President, Chevron Corporation and President, Chevron U.S.A. Products Company - 1994
P.J. Robertson - President of Warren Petroleum Company - 1991 - Vice-President for Strategic Planning and Quality, Chevron Corporation -1994 - Executive Vice-President of Chevron U.S.A. Production Company - 1996 - Vice-President, Chevron Corporation and President of Chevron U.S.A. Production Company - 1997
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-31 of this Annual Report on Form 10-K.
Item 6.
Item 6. Selected Financial Data
The selected financial data for years 1993 through 1997 are presented on page FS-38 of this Annual Report on Form 10-K.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The index to Financial Statements, Supplementary Data and Management's Discussion and Analysis of Financial Condition and Results of Operations is presented on page FS-1 of this Annual Report on Form 10-K.
Item 8.
Item 8. Financial Statements and Supplementary Data
The index to Financial Statements, Supplementary Data and Management's Discussion and Analysis of Financial Condition and Results of Operations is presented on page FS-1 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 appearing under the heading "Nominees For Directors" in the Notice of Annual Meeting of Stockholders and Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the Company's 1998 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 31 and 32 of this Annual Report on Form 10-K for information about executive officers of the company.
The information contained under the heading "Compliance with Section 16 of the Exchange Act" in the Notice of Annual Meeting of Stockholders and Proxy Statement to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the Company's 1998 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K. Chevron believes all filing requirements were complied with during 1997.
Item 11.
Item 11. Executive Compensation
The information appearing under the heading "Executive Compensation," including the subheadings "Management Compensation Committee Report on Executive Compensation," "Summary Compensation Table," "Option Grants in Last Fiscal Year," "Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Value," "Long-Term Incentive Plan-1997 Performance Units Awards Table," "Pension Plan Table" and "Performance Graph," in the Notice of Annual Meeting of Stockholders and Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the Company's 1998 Annual Meeting of Stockholders, 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 appearing under the heading "Stock Ownership of Directors and Executive Officers" in the Notice of Annual Meeting of Stockholders and Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, as amended, in connection with the Company's 1998 Annual Meeting of Stockholders, 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.
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-14
Consolidated Statement of Income for the three years ended December 31, 1997 FS-14
Consolidated Balance Sheet at December 31, 1997 and 1996 FS-15
Consolidated Statement of Cash Flows for the three years ended December 31, 1997 FS-16
Consolidated Statement of Stockholders' Equity for the three years ended December 31, 1997 FS-17
Notes to Consolidated Financial Statements FS-18 to FS-31
(2) Financial Statement Schedules:
Caltex Group of Companies Combined Financial Statements C-1 to C-24
The Combined Financial Statements of the Caltex Group of Companies are filed as part of this report. All schedules are omitted because they are not applicable or the required information is included in the combined financial statements or notes thereto.
(3) Exhibits:
The Exhibit Index on pages 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:
(1) A Current Report on Form 8-K, dated December 22, 1997, was filed by the company on December 22, 1997. In this report Chevron included a press release issued by Caltex Petroleum Corporation, a 50 percent owned affiliate, on December 19, 1997, announcing that it elected to change the functional currency for its Korean and Japanese operations to the U.S. dollar, effective October 1, 1997.
(2) A Current Report on Form 8-K, dated January 29, 1998, was filed by the company on January 29, 1998. In this report Chevron announced its preliminary, unaudited earnings for the year ended December 31, 1997.
(3) A Current Report on Form 8-K, dated February 3, 1998, was filed by the company on February 3, 1998. In this report Chevron announced its revised, preliminary, unaudited earnings for the year ended December 31, 1997.
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 25th day of March 1998.
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 25th day of March 1998.
Principal Executive Officers (And Directors) Directors
KENNETH T. DERR* SAMUEL H. ARMACOST* - --------------------- ------------------- Kenneth T. Derr, Chairman of the Board Samuel H. Armacost
JAMES N. SULLIVAN* SAM GINN * - --------------------- ---------- James N. Sullivan, Vice-Chairman of the Board Sam Ginn
CARLA A. HILLS * ---------------- Carla A. Hills
J. BENNETT JOHNSTON* -------------------- J. Bennett Johnston
RICHARD H. MATZKE* ------------------ Principal Financial Officer Richard H. Matzke
MARTIN R. KLITTEN* CHARLES M. PIGOTT* - --------------------- ------------------ Martin R. Klitten, Vice-President Charles M. Pigott and Chief Financial Officer CONDOLEEZZA RICE* ----------------- Principal Accounting Officer Condoleezza Rice
STEPHEN J. CROWE* FRANK A. SHRONTZ* - -------------------- ----------------- Stephen J. Crowe, Comptroller Frank A. Shrontz
CHANG-LIN TIEN * ---------------- Chang-Lin Tien
GEORGE H. WEYERHAEUSER* ----------------------- George H. Weyerhaeuser
*By: /s/ LYDIA I. BEEBE JOHN A. YOUNG* - --------------------------- -------------- Lydia I. Beebe, Attorney-in-Fact John A. Young
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 October 30, 1996, filed as Appendix B to Chevron Corporation's Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 1997, and incorporated herein by reference.
10.2 Chevron Corporation Excess Benefit Plan, amended and restated as of July 1, 1996, filed as Exhibit 10 to Chevron Corporation's Report on Form 10-Q for the quarterly period ended March 31, 1997, and incorporated herein by reference.
10.3 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.
10.4 Chevron Restricted Stock Plan for Non-Employee Directors, as amended and restated effective April 30, 1997, filed as Appendix A to Chevron Corporation's Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 1997, and incorporated herein by reference.
10.5 Chevron Corporation Long-Term Incentive Plan, as amended and restated effective October 30, 1996, filed as Appendix C to Chevron Corporation's Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 1997, and incorporated herein by reference.
10.6 Chevron Corporation Salary Deferral Plan for Management Employees, effective January 1, 1997, filed as Exhibit 10 to Chevron Corporation's Report on Form 10-Q for the quarterly period ended June 30, 1997, and incorporated herein by reference.
EXHIBIT INDEX (continued)
Exhibit No. Description - ------- ---------------------------------------------------------------------
12.1 Computation of Ratio of Earnings to Fixed Charges (page E-1).
21.1 Subsidiaries of Chevron Corporation (page E-2).
23.1 Consent of Price Waterhouse LLP (page E-3).
23.2 Consent of KPMG Peat Marwick LLP (page E-4).
24.1 Powers of Attorney for directors and certain officers of Chevron to Corporation, authorizing the signing 24.15 of the Annual Report on Form 10-K on their behalf.
27.1 Financial Data Schedule
99.1 Definitions of Selected Financial Terms (page E-5).
Copies of above exhibits not contained herein are available, at a fee of $2 per document, to any security holder upon written request to the Secretary's Department, Chevron Corporation, 575 Market Street, San Francisco, California 94105.
INDEX TO MANAGEMENT'S DISCUSSION AND ANALYSIS CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page(s)
Management's Discussion and Analysis FS-2 to FS-13
Report of Management FS-13
Consolidated Income Statement FS-14
Report of Independent Accountants FS-14
Consolidated Balance Sheet FS-15
Consolidated Statement of Cash Flows FS-16
Consolidated Statement of Stockholders' Equity FS-17
Notes to Consolidated Financial Statements FS-18 to FS-31
Quarterly Results and Stock Market Data FS-31
Supplemental Information on Oil and Gas Producing Activities FS-32 to FS-37
Five-Year Financial Summary FS-38
FS-1
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 1997 HIGHLIGHTS * Net income was $3.256 billion for 1997, the second consecutive year of record earnings * Operating earnings were $3.180 billion, also a record * Annual return on capital employed, excluding special items, was 14.7 percent, the highest in more than a decade * Worldwide oil and gas reserves increased for the fifth consecutive year; international liquids production increased for the eighth consecutive year * Debt was reduced by more than $600 million * Annual dividend to the stockholders increased for the tenth consecutive year in 1997; another dividend increase was announced in January 1998
KEY FINANCIAL RESULTS
Chevron's net income for 1997 was a record $3.256 billion, up 25 percent from net income of $2.607 billion in 1996 and up 250 percent from $930 million in 1995. Net income benefited $76 million from special items in 1997 and was reduced by net special charges of $44 million in 1996 and $373 million in 1995.In addition, the adoption of a new accounting standard in 1995 reduced net income $659 million. After excluding these items, operating earnings for 1997 were $3.180 billion, up 20 percent from $2.651 billion earned in 1996 and up 62 percent from $1.962 billion in 1995. For the second year in a row, the company earned record profits. In spite of lower crude oil prices, the company reached its earnings goal of $3 billion, set in February 1996, one year ahead of target. Chevron's annual return on capital employed, excluding special items, was 14.7 percent, the highest in more than a decade.
OPERATING ENVIRONMENT AND OUTLOOK. The spot West Texas Intermediate (WTI) crude oil price averaged nearly $25.40 per barrel in December 1996 and began to decline in early 1997, trading in the $19-$21 range during most of the year until December 1997, when it dropped to $18.30 per barrel. The downward trend continued through January 1998, averaging about $16.70 per barrel. On February 20, 1998, the WTI spot price was $16.15 per barrel.
A number of factors continue to exert downward pressure on crude oil prices. Demand growth is slowing as a result of the Asian economic slowdown and the warm winters in the United States, Europe and Japan. At the same time, supplies have been increasing because of the start-up of new producing fields and higher OPEC quotas and production, resulting in an oversupplied world market. It is uncertain how long these conditions will continue. In addition, inventories are currently at high levels.
Lower crude oil prices in 1998 may lead to lower revenues and earnings than experienced in 1997, particularly in the company's exploration and production (upstream) operations. However, further production increases are expected in 1998 from new developments in West Africa and offshore eastern Canada, where the Hibernia oil field began production in November 1997, and from continued expansion of production from the Tengiz Field in Kazakhstan. The company has evaluated its capital spending programs under conservative price assumptions and, at the present time, expects to fully fund its planned $6.3 billion 1998 capital and exploratory expenditure program. However, should this low price environment become more severe and prolonged, the company has the ability to modify its planned expenditures accordingly.
In the international refining, marketing and transportation (downstream) segment, the company's Caltex affiliate's earnings have been, and will continue to be, affected by the decline in the value of Asian currencies. This has generally led to reduced refined products margins, as local prices have trailed the increased local currency costs of crude oil. In certain Asian countries, refined products prices are subject to government-prescribed increases and do not result in immediate recovery of local cost increases. In addition, the higher prices for refined products have caused demand for these products to decline. This trend has continued into 1998 and may slow the rate of growth in refined products demand that was previously expected in this region.
The U.S. chemicals industry entered a cyclical downturn in the latter half of 1995 that persisted throughout 1996 and 1997. Chevron has several major chemicals expansion projects under way to position the company to benefit from the next upturn in the chemicals industry by lowering its unit cost structure.
SIGNIFICANT DEVELOPMENTS. In April 1997, Chevron completed the sale of 10 percent of its 50 percent interest in the Tengizchevroil (TCO) joint venture to LUKARCO, a joint venture between the Russian oil company LUKoil and Arco. The FS-2
company recorded a gain of $32 million from that sale in the second quarter of 1997.
Total liquids production from the Tengiz Field in 1997 averaged about 155,000 barrels per day, an increase of 38 percent over 1996 average production. In July, TCO announced the construction of a fifth oil and gas processing train at Tengiz, which is expected to boost production capacity to 240,000 barrels per day. TCO continues to successfully move crude oil by pipeline, barge and railcar. In May 1997, Chevron acquired a 15 percent interest in the Caspian Pipeline Consortium, which intends to build a direct pipeline to the Black Sea to carry crude for TCO and other regional producers. Elsewhere in this region, the company signed an agreement with the Republic of Azerbaijan to explore the Absheron offshore block in the southern Caspian Sea.
In February 1998, the company announced a new Caspian region cooperative agreement with the Royal Dutch/Shell Group. The agreement establishes a framework for the two companies to jointly identify and develop new projects in the areas of exploration, production and transportation and in the sale of crude oil, gas liquids and natural gas.
The first Chevron production of crude oil from offshore Angola began from the Ndola and Sanha fields in April and August 1997, respectively. The company has a 39 percent interest in these fields. Also, the company announced two giant crude oil discoveries in Block 14, a contract area adjacent to the company's major areas of production, which are the company's first finds in that country's deep water. Chevron is operator and holds a 31 percent interest in Block 14.
Chevron and its partners successfully bid to operate the LL-652 oil field in Venezuela's Lake Maracaibo. Chevron, with a 30 percent interest, will operate the field under a 20-year contract beginning in 1998. The field currently is producing 10,000 barrels per day. The partners have submitted a development plan that is expected to increase the field's production to an estimated potential of 115,000 barrels per day by 2006.
The first liquefied petroleum gas (LPG) exports from the company's Escravos, Nigeria, joint venture gas project occurred in September. This project provides a commercial outlet for LPG derived from natural gas that is produced with the company's crude oil production. Chevron is planning a second phase of the project that will increase the amount of gas processed by 110 to 120 million cubic feet per day from its current level of 175 million cubic feet per day. In November, initial production began from the Hibernia oil development project, off the east coast of Newfoundland, in which Chevron has an approximate 27 percent interest. At year-end 1997, production from two wells had reached 60,000 barrels per day.
Chevron acquired 134 additional leases offshore Louisiana and Texas at federal sales during the year, furthering its intent to be a major participant in the development of the Gulf of Mexico's deep waters. The company's deepwater portfolio consists of 362 tracts in waters as deep as 8,500 feet, including an interest in the Genesis project, where first liquids production is expected in late 1998.
During 1997, the company continued development of international chemicals projects including a $650 million petrochemicals complex in Al-Jubail, Saudi Arabia, that is scheduled to be completed in 1999, and a plant in Singapore to manufacture additives for fuels and lubricating oils. In the United States, the company completed major expansion and debottlenecking projects at the Port Arthur, Texas, and Marietta, Ohio, plants.
Chevron sold its marketing interests in the United Kingdom, including its retail network of 450 stations and its lubricants and commercial fuels businesses, to Shell UK Ltd. in December. The company also divested its 50 percent equity interest in a 90,000-barrel-per-day catalytic cracking facility in Pembroke, Wales. In connection with these divestitures, the company also will close its 115,000-barrel-per-day refinery located near Milford Haven, Wales, and will sell its other remaining assets, thereby completing the company's withdrawal from the refining and marketing business in the United Kingdom.
YEAR 2000. At year 2000, a two-digit date of "00" may not be recognized by computer systems and applications developed in the 1970s and 1980s as the year 2000, causing systems to shut down or malfunction. Chevron has established a Year 2000 Project Team to coordinate the Year 2000 efforts of teams in the company's operating units to ensure that its computer systems and applications will function properly beyond 1999. Many of the company's information systems and software are Year 2000 compliant, and others are currently being assessed for compliance. A Year 2000 compliance assessment of the embedded technology in the company's facilities and operating systems is also under way. After these assessments are complete, plans for modification or replacement, testing, and certification will be developed and implemented to ensure the company's facilities and business activities will continue to operate safely and reliably, without interruption, after 1999. The teams also are monitoring the compliance efforts of suppliers, contractors, and trading partners with whom Chevron does business, to ensure that operations will not be adversely affected by the compliance problems of others. Until the assessments are complete, the company cannot state with certainty whether it has, or will have, significant Year 2000 issues. Additionally, the total amount of costs to be incurred cannot be reliably estimated at this time. However, based on the information currently available, the company has no reason to believe that Year 2000 issues will be material to its results of operations, consolidated financial position or liquidity.
ENVIRONMENTAL MATTERS. Virtually all aspects of the company's businesses 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 the company's operations and the products it sells. Most of the costs of complying with myriad laws and regulations pertaining to the company's operations and products are embedded in the normal costs of conducting its business.
Using definitions and guidelines established by the American Petroleum Institute, Chevron estimates its worldwide environmental spending in 1997 was about $893 mil-
FS-3
lion for its consolidated companies. Included in these expenditures were $237 million of environmental capital expenditures and $656 million of costs associated with the control and abatement of hazardous substances and pollutants from ongoing operations. The total amount also includes spending charged against reserves established in prior years for environmental cleanup programs, but not noncash provisions to increase these reserves or establish new ones during the year. For 1998, total worldwide environmental capital expenditures are estimated at $265 million. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.
In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities, as well as third- party waste disposal sites used by the company. An obligation to take remedial action may be incurred as a result of the enactment of laws, such as the federal Superfund law, the issuance of new regulations or as the result of the company's own policies in this area. Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition, an obligation may arise when operations are closed or sold, or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable under standards existing at the time but now require investigatory and/or remedial work to meet current standards.
The company retained certain environmental cleanup obligations when it sold the Port Arthur, Texas, refinery in 1995, and anticipated costs were accrued at the time of sale. Under the terms of the sales contract, these obligations were re- evaluated in 1997, resulting in the confirmation that previously recorded reserves were adequate.
During 1997, the company recorded $57 million of before-tax provisions ($35 million after tax) for environmental remediation efforts, including Superfund sites. Actual expenditures charged against these provisions and other previously established reserves amounted to $205 million in 1997. At year-end 1997, the company's environmental remediation reserves were $987 million, including $43 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 282 hazardous waste sites. The company has made provisions or payments in 1997 and prior years for approximately 188 of these sites. 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 exposures. 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.
It is likely the company will continue to incur additional charges beyond those reserved for environmental remediation relating to past operations. These future costs are indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties and the extent to which such costs are recoverable from third parties. While the amounts of future costs may be material to the company's results of operations in the period in which they are recognized, the company does not expect these costs to have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had or will have any significant impact on the company's competitive position relative to other domestic or international petroleum or chemicals concerns. Although environmental compliance costs are substantial, the company has no reason to believe they vary significantly from similar costs incurred by other companies engaged in similar businesses in similar areas. The company believes that such costs ultimately are reflected in the petroleum and chemicals industries' prices for products and services.
Over the past several years, the petroleum industry has incurred major capital expenditures to meet clean air regulations, such as the 1990 amendments to the Clean Air Act in the United States. For companies operating in California, where Chevron has a significant presence, the California Air Resources Board (CARB) has imposed even stricter requirements. Over the five-year period 1991- 1995, Chevron spent about $1.8 billion on capital projects to comply with air quality measures, the majority of which related to complying with CARB requirements for the manufacture of cleaner-burning gasoline. The bulk of this spending was completed in 1995, which resulted in a decrease in capitalized air quality expenditures from approximately $500 million in 1995 to $70 million in 1996 and $74 million in 1997.
In addition to the reserves for environmental remediation, 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. Many of these 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 1997 was $1.5 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. The company is a defendant in a lawsuit that Oxy U.S.A. brought in its capacity as successor in interest to Cities Service Company. The lawsuit claims damages resulting from the allegedly improper termination of a tender offer to purchase Cities' stock in 1982 made by Gulf
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Oil Corporation acquired, by Chevron in 1984. A trial with respect to the claims ended in July 1996 with a judgment against the company of $742 million, including interest that continues to accrue at a rate of 9.55 percent per year while the appeal is pending. The company has filed an appeal with the Oklahoma Supreme Court and posted a bond for 1.5 times the amount of the judgment. Although the ultimate outcome of this matter cannot be determined presently with certainty, the company believes that errors were committed by the trial court that should result in the judgment being reversed on appeal.
In a lawsuit in Los Angeles, California, brought in 1995, the company and five other oil companies are contesting the validity of a patent granted to Unocal Corporation (Unocal) for reformulated gasoline, which the company sells in California during certain months of the year. The first two phases of the trial were concluded in October and November 1997, with the jury upholding the validity of the patent and assessing damages at the rate of 5.75 cents per gallon of gasoline sold in infringement of the patent between March 1 and July 1, 1996. In the third phase of the trial, the judge heard evidence to determine if the patent is enforceable; the matter is currently under submission. While the ultimate outcome of this matter cannot be determined with certainty, the company believes Unocal's patent is invalid and any unfavorable rulings should be reversed upon appeal. However, should the jury's findings and Unocal's position ultimately be upheld, the company's exposure with respect to future reformulated gasoline sales would depend on the availability of alternate formulations and the industry's ability to recover additional costs of production through prices charged to its customers.
In June 1997, Caltex Petroleum Corporation received a claim from the U.S. Internal Revenue Service (IRS) for $292 million in excise taxes, $140 million in penalties and $1.6 billion in interest. The IRS claim relates to crude oil sales to Japanese customers beginning in 1980. Caltex is challenging the claim and fully expects to prevail. Caltex believes the underlying excise tax claim is wrong and therefore the claim for penalties and interest is wrong. The Caltex claim has been through the appeals process and will next move to court. In February 1998, Caltex provided an initial letter of credit for $2.33 billion to the IRS to pursue the claim. The letter of credit is guaranteed by Chevron and Texaco. In addition, a yet to be decided portion of the claim must be paid in order to proceed to court.
The company is the subject of other lawsuits and claims and other contingent liabilities including, along with other oil companies, actions challenging oil and gas royalty and severance tax payments based on posted prices. These lawsuits and other contingent liabilities 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 consolidated financial position or liquidity, although losses could be material with respect to earnings in any given period.
The company utilizes various derivative instruments to manage its exposure to price risk stemming from its integrated petroleum activities. All these instruments are commonly used in oil and gas trading activities and are relatively straightforward, involve little complexity and are generally 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 transactions. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities, including forward exchange contracts and interest rate swaps. Its control systems are designed to monitor and manage its financial exposures in accordance with company policies and procedures.
The company's operations can be affected by changing economic, regulatory and political environments in the various countries where it operates. Political uncertainty and civil unrest may, at times, threaten the safety of employees and the company's continued presence in a country. These factors are carefully considered when evaluating the level of current and future activity in such countries.
Chevron and its affiliates continue to review and analyze their operations and may close, sell, exchange, purchase or restructure assets to achieve operational or strategic benefits to improve competitiveness and profitability. These activities may result in significant losses or gains to income in future periods.
NEW ACCOUNTING STANDARDS. Effective December 1997, the company adopted two new accounting standards: Statement of Financial Accounting Standards (SFAS) No.128, "Earnings Per Share," and SFAS No. 129, "Disclosure of Information About Capital Structure." SFAS No. 128 requires Income Statement disclosure of both basic and diluted earnings per share in place of the primary and fully diluted earnings per share required previously. A footnote disclosure of the calculation method is also required. The adoption of SFAS No. 129 required no additional disclosures since the company previously met its requirements.
In June 1997, the Financial Accounting Standards Board (FASB) issued SFAS No. 130, "Reporting Comprehensive Income," and SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information." The company will begin reporting comprehensive income in compliance with SFAS No. 130 beginning with the first quarter 1998, while reporting under SFAS No. 131 initially will be presented in the financial statements for the year 1998. While the company is evaluating the criteria of SFAS No. 131 as they apply to Chevron's operations, it does not anticipate significant changes to its reportable segments. The statements require additional reporting and expanded disclosures but will have no effect on the company's results of operations, financial position, capital resources or liquidity.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosure about Pension and Other Postretirement Benefits" that revised disclosure requirements for pension and other postretirement benefits. It does not affect the measurement of the expense of the company's pension and other postretirement benefits.
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These new standards become effective for fiscal years beginning after December 15, 1997.
SPECIAL ITEMS. Net income is affected by transactions that are unrelated to, or are not necessarily representative of, the company's ongoing operations for the periods presented. These transactions, defined by management and designated "special items," can obscure the underlying results of operations for a year, as well as affect comparability between years. Following is a table that summarizes the gains or (losses), on an after-tax basis, from special items included in the company's reported net income.
Asset write-offs and revaluations in 1997 included $68 million of impairment write-downs of U.S. oil and gas properties, $10 million for chemical facilities and $8 million for telecommunications equipment. Asset write-offs in 1996 were related primarily to a $200 million estimated impairment provision in connection with the company's intent at that time to merge its United Kingdom refining and marketing operations with those of two other oil companies. Additionally, 1996 included $68 million of impairment write-downs of oil and gas properties and related pipeline investments, a $29 million adjustment to the 1995 provision for the loss anticipated from exiting the real estate development business, including additional amounts for environmental remediation, and $40 million for other asset write-offs. In 1995, asset write- offs of $304 million were recognized in connection with the company's decision to exit its real estate development business ($168 million), the completion of a comprehensive review of all the company's fixed asset records ($94 million), the write-down of assets made obsolete by the new facilities required to produce California-mandated reformulated gasolines ($38 million) and other miscellaneous write-offs ($4 million). Also effective in 1995, the company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The adoption of this standard required noncash charges amounting to $659 million after tax, mostly related to impairment write-downs of U.S. oil and gas producing properties.
Asset dispositions in 1997 increased earnings a net $183 million, including net gains of $190 million from the sales of U.S. oil and gas properties; $50 million from the sale of international oil and gas properties, including the sale of 10 percent of the company's ownership interest in the TCO joint venture in Kazakhstan; and $33 million from the sale of the company's interest in a chemical affiliate. Partially offsetting these gains were charges of $90 million to increase provisions for environmental, severance and other costs associated with the company's exit from the U.K. refining and marketing business and for lease termination costs on three oceangoing vessels and their write-down to fair market value. Asset dispositions in 1996 increased earnings $391 million and included a $279 million gain from the company's Caltex affiliate's sale of its interest in two Japanese refineries; a net $80 million gain from the sales of producing properties in the North Sea, Indonesia and the Gulf of Mexico; and a $32 million gain from the merger of the company's natural gas marketing business and natural gas liquids company with NGC Corporation (NGC).
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 of changes in statutory tax rates on deferred income taxes. Favorable U.S. income tax adjustments of $142 million and a Canadian tax settlement of $10 million benefited 1997 earnings, while 1996 earnings benefited $52 million from a U.S. federal tax audit settlement.
Environmental remediation provisions pertain to estimated future costs for environmental cleanup programs at certain of the company's service stations, marketing terminals, refineries, chemical locations, and oil and gas properties; divested operations in which Chevron has liability for future cleanup costs; and sites, commonly referred to as Superfund sites, for which the company has been designated a PRP by the EPA. Provisions for future environmental remediation costs amounted to $35 million in 1997, $54 million in 1996 and $90 million in 1995.
Restructurings and reorganizations in 1997 included $54 million for Chevron's share of the charge taken by its affiliate, NGC, primarily for asset write- downs and other costs associated with a planned restructuring of NGC's gas liquids and crude oil business and $6 million in connection with the reorganization of Chevron's North American exploration and production operations. Restructurings in 1996 resulted in charges of $14 million for various employee severance programs. Charges in 1995 were $50 million, including $12 million related to restructurings at Chevron's Caltex affiliate, and consisted primarily of employee severance provisions in connection with reorganizations of various business activities.
LIFO inventory liquidation gains (losses) result from the reduction of inventories in certain inventory pools valued under the Last-In, First- Out (LIFO) accounting method. These amounts include the company's equity share of Caltex LIFO inventory effects. Chevron's consolidated petroleum inventories were 79 million barrels at year-end 1997, 83 million barrels at year-end 1996 and 93 million barrels at year-end 1995.
Other special items in 1997 reduced earnings by $83 million and consisted primarily of net charges for litigation and other matters, including costs associated with the company's employee performance stock option program. Earnings were reduced a net $78 million in 1996, consisting primarily of litigation matters that were offset partially by a $12 million refund of federal lease costs. In 1995, other special items benefited earnings a net $84 million, when a gain of $86 mil-
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lion related to a sale of land by a Caltex affiliate in Japan and a refund of $27 million for federal lease costs were offset partially by litigation and other costs of $29 million.
RESULTS OF OPERATIONS. In 1997, the company performed very well operationally and achieved record earnings for the second consecutive year. The successful 1997 performance was led by U.S. refining, marketing and transportation, which more than doubled its operating earnings compared with last year, benefiting from increased refined products demand and improved sales margins, reflecting both lower crude costs and lower operating expenses.
International refining, marketing and transportation earnings also increased significantly in 1997. The higher earnings were primarily attributable to Chevron's 50 percent share of its Caltex affiliate's earnings and reflected significant after-tax currency gains, as Asian currencies generally weakened against the U.S. dollar.
Despite a 7 percent decline in crude oil prices compared with 1996, upstream operating earnings were down less than 4 percent from 1996 levels. International upstream exceeded last year's record profits and increased liquids production by 4 percent, marking the eighth consecutive year of increased production. The overall production increase and lower operating expenses nearly offset the decline in crude oil prices.
Net proved reserves increased despite higher production levels in 1997, reflecting the company's success in growing international operations and maintaining production levels in the United States. In 1997, the company estimates it replaced 115 percent of its worldwide oil and gas production through additions to proved reserves. Excluding the effects of any properties purchased or sold in 1997, the company's reserves replacement rate was 142 percent. Outside the United States, replacement of oil and gas production in Angola, Australia, Nigeria and Indonesia more than offset areas - such as Canada, the United Kingdom and Kazakhstan - where production and sales of producing interests exceeded reserve replacements. In the United States, the company replaced 100 percent of oil and gas production in 1997. Excluding the effects of any properties purchased or sold in 1997, U.S. operations replaced 120 percent of production, the highest rate since 1984.
Sales and other operating revenues were $40.6 billion in 1997, compared with $42.8 billion in 1996 and $36.3 billion in 1995. In 1997, revenues declined on lower crude oil and refined products prices and lower U.S. natural gas production. These factors were mitigated partially by increased refined products sales volumes and higher natural gas prices. Revenues improved in 1996 compared with 1995 primarily because of higher prices and sales volumes for crude oil and natural gas and higher prices for refined products, partially offset by lower refined products sales volumes and chemicals prices. Purchased crude oil and products costs were 11 percent lower in 1997 compared with 1996 because of lower crude oil, refined products and chemicals feedstock prices. Sharply higher crude oil, natural gas and refined products prices accounted for the 27 percent increase in purchased crude oil and products costs in 1996 compared with 1995.
Other income amounted to $679 million in 1997, $344 million in 1996 and $219 million in 1995 and in all years included net gains resulting from the disposition of assets, which caused other income to fluctuate from year to year.
Operating, selling and administrative expenses, excluding the effects of special items, declined 6 percent in 1997 to $6,549 million from $6,947 million in 1996. The reduction in operational expenses in 1997 was due to lower fuel, transportation and marketing costs, partially offset by the cost of the start- up and expansion of chemicals facilities. Operational expenses increased slightly in 1996 compared with 1995, largely because higher fuel and transportation costs and accruals for performance-based employee compensation costs more than offset continued reductions in other expenses. Operating expenses in 1995 were affected adversely by scheduled and unscheduled refinery shutdowns and maintenance.
Depreciation, depletion and amortization expense increased to $2,300 million in 1997 from $2,216 million in 1996 as a result of higher liquids production levels and SFAS No. 121 impairment write-downs of U.S. oil and gas properties. This was offset partially by lower expense from the reassessment and extension of the useful lives of certain U.S. chemicals assets. Expense declined in 1996 from $3,381 million in 1995, which included approximately $1 billion in additional expense from the implementation of SFAS No. 121.
Taxes on income were $2,246 million in 1997, $2,133 million in 1996 and $859 million in 1995, reflecting effective income tax rates of 41 percent, 45 percent and 48 percent for each of the three years, respectively. The lower tax rate in 1997, compared with 1996, primarily reflects a shift in the international earnings mix from higher tax-rate countries to lower tax-rate countries and shifts from foreign earnings to U.S. earnings. The lower tax rate in 1996, compared with 1995, reflects a shift in the international earnings mix from higher tax-rate countries to lower tax-rate countries and a favorable swing in prior-year tax adjustments. These effects were offset partially by a decrease in the proportion of equity earnings recorded on an after-tax basis.
Foreign currency effects increased net income $246 million in 1997 and decreased net income $26 million and $15 million in 1996 and 1995, respectively, and include the company's share of affiliates' foreign currency effects. The foreign currency gains for 1997 primarily occurred in Australia and in the Asian operating areas of Caltex, where the currencies generally weakened against the U.S. dollar. The largest currency impact was in Korea, mostly as a result of local net deferred tax benefits on local currency losses from U.S. dollar-
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denominated liabilities. The loss on foreign currency effects in 1996 resulted from fluctuations in the value of the United Kingdom and Australian currencies relative to the U.S. dollar, and in 1995, the loss was related to fluctuations in the value of the Canadian and Nigerian currencies.
Effective October 1, 1997, Caltex management changed the functional currency for its Korean and Japanese equity affiliates from their local currencies to the U.S. dollar, based on significantly changed economic facts and circumstances. Previously, the Korean petroleum industry operated in a regulated environment with domestic prices determined by a specific Korean won- based return on equity. During 1997, the pricing of petroleum products was moving toward a market-based return. This trend was accelerated in the fourth quarter 1997 by the severe devaluation of the won, which resulted in higher local currency costs for U.S. dollar-based crude oil and raw materials. In addition, during this period, Caltex's Korean affiliate significantly increased its U.S. dollar-based export sales, moving from a net importer of refined products to a net exporter in 1997.
Japan also has experienced evolving deregulation in its petroleum industry. While not as material as the Korean operations, Caltex management decided to change the functional currency of its Japanese equity affiliate to the U.S. dollar, effective the same date as the Korean change.
With the local currency as the functional currency, Caltex's total reported foreign currency losses of $62 million for the first nine months of 1997 from its Korean and Japanese affiliates compared with foreign currency losses of $46 million for the full year 1996. After the change in functional currency to the U.S. dollar, Caltex reported foreign currency gains of $167 million for the full year 1997 from operations in Korea and Japan. Prior to the change in functional currency, losses from the translation of U.S. dollar-denominated debt to local currency were offset partially by the tax benefit resulting from the deductibility of the losses for local tax purposes. After the change to the U.S. dollar functional currency, translation of the U.S. dollar-denominated debt does not generate any U.S. dollar exchange losses. However, the deductibility of the local currency losses arising from the debt continues to provide tax benefits that are translated to U.S. dollar income.
U.S. exploration and production earnings, excluding special items, declined 12 percent from record earnings in 1996 but were up 76 percent from 1995 levels. The earnings decline in 1997, relative to 1996, was a result of lower crude oil prices, lower natural gas production and higher exploration expenses. Earnings for 1996 more than doubled from 1995 levels due to higher crude oil and natural gas prices, which more than offset lower liquids production.
Net liquids production for 1997 averaged 343,000 barrels per day, up slightly from 341,000 barrels per day in 1996 but down 2 percent from 350,000 barrels per day in 1995. Net natural gas production in 1997 averaged about 1.85 billion cubic feet per day, compared with 1.88 billion cubic feet per day in 1996 and 1.87 billion cubic feet per day in 1995. The production declines since 1995 resulted from producing property sales and normal field declines, partially offset by new production. The company has several major long-term projects under way, primarily in the Gulf of Mexico, which should help mitigate the decline in its U.S. oil and gas production volumes.
The company's average crude oil realizations of $17.68 per barrel were $1.12 lower than the $18.80 averaged for 1996 but $2.34 more than the $15.34 per barrel averaged in 1995. Realizations remained steady at $15.00 to $16.00 per barrel during 1995. In 1996, Chevron's crude oil realizations increased steadily during the year, reaching an average of $21.93 in December, but declined in early 1997 to about $17.00 by April. Realizations fluctuated around that level until December 1997, when they dropped to $15.66 per barrel, and have continued to decline in early 1998.
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The company's average natural gas prices were $2.42 per thousand cubic feet in 1997, up 14 cents from $2.28 in 1996 and up 91 cents from the 1995 average of $1.51. Steady demand and low inventories caused by tight supplies buoyed prices during 1997, but warmer winter weather has softened demand early in 1998.
Exploration expenses were higher in 1997 than either 1996 or 1995, due to increased exploration activity in the Gulf of Mexico as the company evaluates its many prospects. Depreciation expense increased 13 percent in 1997 compared with 1996, primarily as a result of higher impairment write-offs, but declined 44 percent from 1995 levels when the implementation of SFAS No. 121 first required significant asset write-offs.
International exploration and production had record earnings for the second consecutive year. The strong earnings in 1997 primarily reflected higher crude oil sales volumes, which more than offset the decline in crude prices. In 1996, higher crude oil and natural gas sales volumes and higher crude oil prices accounted for the 41 percent increase in operating earnings compared with 1995.
International exploration and production operations, including production from equity affiliates, increased net liquids production by 4 percent, to 731,000 barrels per day in 1997. This was the eighth consecutive year of production increases, reflecting the company's successful strategy of growing its international operations. Kazakhstan, Nigeria and Congo were the principal sources of the increase. In 1996, net liquids production increased 8 percent over 1995 to 702,000 barrels per day. Production growth in Angola, Nigeria and Kazakhstan and new production in Congo accounted for most of the increase. Net natural gas production declined about 1 percent in 1997 to 576 million cubic feet per day compared with 1996 but was up nearly 2 percent from 1995 levels. Net natural gas production declines in 1997 occurred in Canada, Kazakhstan, the United Kingdom and Indonesia. Partially offsetting these declines was initial natural gas production in Nigeria, where the Escravos Natural Gas Project began operation in 1997. Net natural gas production volumes in 1996 were up 3 percent from 1995 levels.
The company's average international liquids prices, including equity affiliates, were $17.97 per barrel in 1997 compared with $19.48 in 1996 and $16.10 in 1995. Average natural gas prices rose to $2.10 per thousand cubic feet in 1997, compared with $1.86 and $1.73 in 1996 and 1995, respectively.
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Earnings included net foreign currency gains of $77 million for 1997 and losses of $27 million in 1996. These earnings impacts primarily reflected currency rate swings of the U.S. dollar relative to the Australian dollar and the British pound in 1997 and 1996. In 1995, the loss of $16 million reflected rate swings between the U.S. dollar and the Canadian and Nigerian currencies.
U.S. refining, marketing and transportation earnings, excluding special items, in 1997 were the highest since 1988. The significant improvement in earnings compared with 1996 and 1995 was driven by higher demand for refined products and improved sales margins, reflecting both lower crude oil costs and lower operating expenses. 1997 operating earnings were more than double 1996 earnings and nearly 9 times the 1995 level. U.S. downstream results were depressed in 1996 and 1995 by competitive conditions in many of the company's markets that did not allow the full recovery of higher crude oil costs and by the increased manufacturing cost of the California-mandated cleaner-burning gasolines. Market conditions were especially difficult late in 1996 when crude oil prices rose to their highest level since 1991. However, refinery performance in 1996 was improved from 1995, which had extensive scheduled and unscheduled downtime.
Refined products sales volumes increased 6 percent to 1.19 million barrels per day in 1997, compared with 1.12 million barrels per day in 1996 and 1995. About half this increase reflected higher-value gasoline sales volumes.
In 1997, average U.S. refined products sales realizations declined about $1.00, or 3 percent, to $28.93 per barrel from $29.94 in 1996 but improved from 1995 levels of $26.19, reflecting the trend in crude oil prices.
International refining, marketing and transportation earnings include international marine operations and equity earnings of the company's Caltex Petroleum Corporation affiliate in addition to earnings from its consolidated refining and marketing subsidiaries. Excluding special items, earnings of $367 million in 1997 more than doubled 1996 earnings of $167 million and were up 30 percent from $283 million earned in 1995. Equity earnings of Caltex were $252 million, $408 million and $294 million for 1997, 1996 and 1995, respectively. Excluding special items, the company's earnings from Caltex's activities were $247 million, $127 million and $213 million, respectively, for 1997, 1996 and 1995.
The higher 1997 operating earnings were largely attributable to Caltex and reflected currency gains of $177 million as Asian currencies generally weakened against the U.S. dollar. The largest currency impact was in Korea, mostly as a result of local net deferred tax benefits on currency losses from U.S. dollar- denominated liabilities. Partially offsetting Caltex's currency gains were inventory valuation losses associated with the recent decline in crude oil prices combined with higher provisions for the noncollectibility of receivables in Asia, together totaling about $50 million. Chevron's share of Caltex earnings in 1997 also included $5 million of favorable LIFO adjustments. Caltex experienced foreign currency losses of $24 million in 1996 and gains of $26 million in 1995. Also in 1996, Caltex earnings benefited $2 million from favorable adjustments to the carrying value of its petroleum inventories to reflect market values and included special gains of $279 million related to the sale of its interest in two Japanese refineries and $2 million of favorable LIFO adjustments. Caltex earnings in 1995 benefited $13 million in inventory adjustments and included net special gains of $81 million, primarily related to a land sale by a Caltex affiliate in Japan.
Results in all three years reflect generally weak industry conditions that have held down product prices and sales margins in the company's major areas of operations.
Chevron's international refined products sales volumes declined 6 percent in 1997 to 886,000 barrels per day from 944,000 barrels per day in 1996 and 969,000 barrels per day in 1995. The primary reason for the decline in 1997 and 1996 volumes was Caltex's sale of its interest in two Japanese refineries in early 1996. Total Caltex refined products sales volumes, excluding transactions with Chevron, decreased 4 percent to 1.15 million barrels per day in 1997, compared with 1.20 million barrels per day in 1996 and 1.33 million barrels per day in 1995.
Overall, international refining and marketing foreign currency effects resulted in gains of $169 million and $19 million in 1997 and 1995, respectively, and losses of $17 million in 1996.
Chemicals earnings, excluding special items, were $224 million in 1997, about flat with $228 million in 1996 but down 57 percent from record 1995 results of $524 million. Earnings for 1997 benefited from reduced depreciation expense, as a result of a reassessment and extension of the useful lives of certain assets. This benefit was offset by lower industry prices, higher feedstock and fuel costs, and expenses related to maintenance and expansion activities during the year. Industry overcapacity depressed margins for styrene, paraxylene and polystyrene in 1997, but margins improved for benzene and ethylene. Earnings for 1996 benefited from a nonrecurring receipt of insurance proceeds. A cyclical down-
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turn in the chemicals industry beginning late in 1995 caused earnings to fall substantially in 1996 and 1997. Although sales volumes remained strong for most of 1996 and 1997, lower prices and higher feedstock and fuel costs resulted in lower margins for most of the company's major chemical products compared with 1995.
Coal and other minerals earnings, excluding special items, were about flat at $50 million, compared with $48 million in 1996 and $47 million in 1995. Higher sales volumes and increases in affiliate income in 1997 were offset partially by higher operating costs compared with 1996. Coal earnings were depressed in 1996 and 1995 from an abundance of low-cost hydroelectric power in the western United States, resulting in low coal demand and low prices in both years. Sales in 1997 of approximately 19.6 million tons were up 23 percent from 16 million tons in 1996 and up 15 percent from 17 million tons in 1995. The increase in sales is primarily due to increased demand and low customer inventories.
Corporate and other activities include interest expense, interest income on cash and marketable securities, real estate and insurance operations, and corporate center costs. Corporate and other net operating charges, excluding special items, declined $41 million to $292 million in 1997 as a result of lower interest expense on reduced debt levels combined with higher interest income and lower insurance costs. In the two preceding years, corporate and other net operating charges were about flat at $333 million in 1996 and $330 million in 1995.
LIQUIDITY AND CAPITAL RESOURCES. Cash, cash equivalents and marketable securities totaled $1.670 billion at year-end 1997, up slightly from $1.637 billion at year-end 1996. Cash provided by operating activities in 1997 was $4.583 billion, compared with $5.770 billion in 1996 and $4.057 billion in 1995. Despite higher 1997 operating earnings, cash from operations declined from 1996 due to lower distributions from equity affiliates and increased working capital and other operating requirements. Distributions from the company's Caltex affiliate were high in 1996 because of its sale of refinery interests. In 1997, cash from operations and proceeds from asset sales were sufficient to fund the company's capital expenditures, dividend payments to stockholders and stock repurchases and also enabled the company to reduce its debt level.
In January 1998, the company announced an increase in the quarterly dividend on its common stock by 3 cents a share, or 5 percent, to 61 cents a share raising Chevron's annualized dividend rate to $2.44 a share. The company's debt and capital lease obligations totaled $6.068 billion at December 31, 1997, down $626 million from $6.694 billion at year-end 1996.
The company's short-term debt, consisting primarily of commercial paper and current portion of long-term debt, totaled $4.362 billion at December 31, 1997. Of the total short-term debt, $2.725 billion was reclassified to long- term debt at year-end 1997, an increase of $925 million from year-end 1996, reflecting an increase in the company's committed credit facilities with termination dates beyond one year. Settlement of these obligations is not expected to require the use of working capital in 1998 because the company has the intent and the ability, as evidenced by committed credit arrangements, to refinance them on along-term basis. The company's practice has been to continually refinance its commercial paper, maintaining levels it believes to be appropriate.
Significant debt transactions in 1997 included the scheduled first quarter maturity of $138 million of Swiss franc-denominated 4.625 percent debt and the third quarter early redemption of $142 million of 9.75 percent debentures originally due in 2017. The Employee Stock Ownership Plan also retired in January 1997, as scheduled, $50 million of 7.28 percent debt related to the Employee Stock Ownership Plan.
On December 31, 1997, Chevron had $4.050 billion in committed credit facilities with various major banks. These facilities support commercial paper borrowing and also can be used for general credit requirements. No borrowings were outstanding under these facilities during the year or at year-
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end 1997. In addition, Chevron and one of its subsidiaries each have existing "shelf" registrations on file with the Securities and Exchange Commission that together would permit registered offerings of up to $1.3 billion of debt securities.
The company's future debt level is dependent primarily on its capital spending program and its business outlook. The company currently expects its debt level to increase during 1998 and believes it has substantial borrowing capacity to meet unanticipated cash requirements.
The company's senior debt is rated AA by Standard & Poor's Corporation and Aa2 by Moody's Investors Service. Chevron's U.S. commercial paper is rated A-1+ by Standard & Poor's and Prime-1 by Moody's, and Chevron's Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. Moody's counterparty rating for Chevron is also Aa2. All these ratings denote high- quality, investment-grade securities.
In December 1997, Chevron announced that its Board of Directors approved the repurchase of up to $2 billion of its outstanding common stock. The company plans to use the repurchased stock for its employee stock option programs. At year-end 1997, the company had purchased 1,199,300 shares at an average cost of $76.49 per share.
FINANCIAL RATIOS. The current ratio is the ratio of current assets to current liabilities at year-end. Two items negatively affect Chevron's current ratio neither of which, in the company's opinion, affect its liquidity. Current assets in all years include inventories valued on a LIFO basis, which at year-end 1997 were lower than current costs by $1.1 billion. Also, the company continually refinances its commercial paper. At year-end 1997, approximately $600 million of commercial paper, after excluding $2.725 billion reclassified to long-term debt, is classified as a current liability although it is likely to remain outstanding indefinitely.
The interest coverage ratio is defined as income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. Chevron's interest coverage ratio improved significantly in 1997 due to higher before-tax income and lower interest expense. The company's debt ratio (total debt to total debt plus equity) decreased in 1997, as total debt decreased and stockholders' equity increased year to year, due to strong cash flow and net income.
CAPITAL AND EXPLORATORY EXPENDITURES. Worldwide capital and exploratory expenditures for 1997 totaled $5.541 billion, including the company's equity share of affiliates' expenditures. Capital and exploratory expenditures were $4.840 billion in 1996 and $4.800 billion in 1995. Expenditures for exploration and production accounted for 64 percent of total outlays in 1997, compared with 62 percent in 1996 and 57 percent in 1995. International exploration and production spending was 53 percent of worldwide exploration and production expenditures in 1997, down from 61 percent in 1996 and 68 percent in 1995, reflecting the company's efforts to slow the decline in its U.S. production while continuing its focus on growth of international exploration and production activities.
The company projects 1998 capital and exploratory expenditures at $6.3 billion, including Chevron's share of spending by affiliates. The 1998 program provides $4.0 billion for exploration and production investments, of which about 63 percent is for international projects. Several long-term development projects in the Gulf of Mexico account for a major portion of the projected $1.5 billion to be spent in U.S. exploration and production.
Refining, marketing and transportation expenditures are estimated at about $1.1billion, with $600 million of that planned for projects in the United States, a majority of which will be spent for marketing projects. Most of the international downstream capital program will be focused in Asia-Pacific countries, where the company's Caltex affiliate is upgrading its retail marketing system. The company plans to invest $830 million in the worldwide chemicals business.
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FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements relating to Chevron's operations that are based on management's current expectations, estimates and projections about the petroleum and chemicals industries. Words such as "expects," "intends," "plans," "projects," "believes," "estimates" and similar expressions are used to identify such forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecast in such forward-looking statements.
Among the factors that could cause actual results to differ materially are crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for the company's aromatics, olefins and additives products; inability of the company's joint venture partners to fund their share of operations and development activities; potential failure to achieve expected production from existing and future oil and gas development projects; potential disruption or interruption of the company's production or manufacturing facilities due to accidents or political events; potential liability for remedial actions under existing or future environmental regulations; and potential liability resulting from pending or future litigation. In addition, such statements could be affected by general domestic and international economic and political conditions.
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, its 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/Kenneth T. Derr /s/Martin R. Klitten /s/Stephen J. Crowe Chairman of the Board Vice President Comptroller and Chief Executive Officer and Chief Financial Officer February 20, 1998
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REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION
In our opinion, the accompanying consolidated balance sheet 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, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 3 to the consolidated financial statements, effective October 1, 1995, the company changed its method of accounting for the impairment of long-lived assets to comply with the provisions of Statement of Financial Accounting Standards No. 121.
/s/ Price Waterhouse LLP
San Francisco, California February 20, 1998
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Millions of dollars, except per-share amounts
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Chevron Corporation is an international company that, through its subsidiaries and affiliates, engages in fully integrated petroleum operations, chemical operations and coal mining in the United States and approximately 90 other countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; transporting crude oil, natural gas and products by pipelines, marine vessels and motor equipment; refining crude oil into finished petroleum products; and marketing crude oil, natural gas and refined petroleum products. Chemicals operations include the manufacture and marketing of a wide range of chemicals for industrial uses.
In preparing its consolidated financial statements, the company follows accounting policies that are in accordance with generally accepted accounting principles in the United States. This requires the use of estimates and assumptions that affect the assets and liabilities and the revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. While the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur.
The nature of the company's operations and the many countries in which it operates subject it to changing economic, regulatory and political conditions. Also, the company imports crude oil for its U.S. refining operations. The company does not believe it is vulnerable to the risk of a near-term severe impact as a result of any concentration of its activities.
Subsidiary and Affiliated Companies The consolidated financial statements include the accounts of subsidiary companies more than 50 percent owned. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method. Under this accounting, remaining unamortized cost is increased or decreased by the company's share of earnings or losses after dividends.
Oil and Gas Accounting The successful efforts method of accounting is used for oil and gas exploration and production activities.
Derivatives Gains and losses on hedges of existing assets or liabilities are included in the carrying amounts of those assets or liabilities and are ultimately recognized in income as part of those carrying amounts. Gains and losses related to qualifying hedges of firm commitments or anticipated transactions also are deferred and are recognized in income or as adjustments of carrying amounts when the underlying hedged transaction occurs. Cash flows associated with these derivatives are reported with the underlying hedged transaction's cash flows. If, subsequent to being hedged, underlying transactions are no longer likely to occur, the related derivatives gains and losses are recognized currently in income. Gains and losses on derivatives contracts that do not qualify as hedges are recognized currently in "Other income."
Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt securities. Those investments that are part of the company's cash management portfolio with original maturities of three months or less are reported as cash equivalents. The balance of the short-term investments is reported as "Marketable securities."
Inventories Crude oil, petroleum products and chemicals are stated at cost, using a Last- In, First-Out (LIFO) method. In the aggregate, these costs are below market. Materials, supplies and other inventories generally are stated at average cost.
Properties, Plant and Equipment All costs for development wells, related plant and equipment (including carbon dioxide and certain other injected materials used in enhanced recovery projects), and mineral interests in oil and gas properties are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. All other exploratory wells and costs are expensed.
Beginning in 1995, long-lived assets, including proved oil and gas properties, are assessed for possible impairment in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 121. Under this standard, the occurrence of certain events, such as a downward revision to proved oil and gas reserves, may trigger a review of affected assets for possible impairment. For proved oil and gas properties, the company would typically perform the review on an individual field basis. Impairment amounts are recorded as incremental depreciation expense in the period in which the specific event occurred.
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.
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Environmental Expenditures Environmental expenditures that relate to current ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals are generally based on the company's commitment to a formal plan of action, such as an approved remediation plan or the sale or disposal of an asset. For the company's U.S. and Canadian marketing facilities, the accrual is based on the probability that a future remediation commitment will be required. For oil and gas and coal producing properties, a provision is made through depreciation expense for anticipated abandonment and restoration costs at the end of the property's useful life.
For Superfund sites, the company records a liability for its share of costs when it has been named as a Potentially Responsible Party (PRP) and when an assessment or cleanup plan has been developed. This liability includes the company's own portion of the costs and also the company's portion of amounts for other PRPs when it is probable that they will not be able to pay their share of the cleanup obligation.
The company records the gross amount of its liability based on its best estimate of future costs using currently available technology and applying current regulations as well as the company's own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as an asset when receipt is reasonably assured.
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 currently included in income. 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.
Stock Compensation The company applies Accounting Principles Board (APB) Opinion No. 25 and related interpretations in accounting for stock options and presents in Note 18 pro forma net income and earnings per share data as if the accounting prescribed by SFAS No. 123 had been applied
NOTE 2. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION Net income is affected by transactions that are unrelated to or are not necessarily 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:
Other financial information is as follows:
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 $1,089, $1,122 and $917 at December 31, 1997, 1996 and 1995, respectively.
NOTE 3. ADOPTION OF STATEMENT OF FINANCIAL ACCOUNTING STANDARDS (SFAS) NO. 121, "ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF"
Effective October 1, 1995, the FS-19
company and its affiliates adopted SFAS No. 121 issued by the Financial Accounting Standards Board. The adoption of this standard required noncash charges to 1995 net income amounting to $659, or $1.01 per share, after related income tax benefits of $358, and was mostly related to impairment write-downs of U.S. oil and gas producing properties.
NOTE 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS
The Consolidated Statement of Cash Flows excludes the following noncash transactions:
During 1997, the company's Venice, Louisiana, natural gas facilities were contributed to a partnership with NGC Corporation. An increase in "Investments and advances" from this merger is considered a non cash transaction and primarily resulted from the contribution of properties, plant and equipment.
During 1996, the company merged substantially all of its natural gas liquids and natural gas marketing businesses with NGC Corporation. The company received cash, a note and shares of NGC Corporation common stock and participating preferred stock in exchange for its contribution of net assets to NGC. Only the cash received is included in the Consolidated Statement of Cash Flows as "Proceeds from asset sales.
Capital lease arrangements of $282 in 1995 were recorded as additions to "Properties, plant and equipment, at cost" and "Capital lease obligations."
There have been other noncash transactions that have occurred during the years presented. These include the acquisition of long-term debt in exchange for the termination of a capital lease obligation; the reissuance of treasury shares for management and employee compensation plans; and changes in assets, liabilities and stockholders' equity resulting from the accounting for the company's ESOP, minimum pension liability and market value adjustments on investments. The amounts for these transactions are not 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:
Certain amounts of cash flows in 1996 and 1995 have been reclassified to conform to the 1997 presentation.
NOTE 5. STOCKHOLDERS' EQUITY
Retained earnings at December 31, 1997 and 1996,include $2,272 and $2,357, respectively, for the company's share of undistributed earnings of equity affiliates.
In 1988, the company declared a dividend distribution of one Right for each outstanding share of common stock. The Rights will be exercisable, unless redeemed earlier by the company, if a person or group acquires, or obtains the right to acquire, 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer that would result in acquiring 10 percent or more of the outstanding shares of common stock, either event occurring without the prior consent of the company. Each Right entitles its holder to purchase stock having a value equal to two times the exercise price of the Right. The person or group who had acquired 10 percent or more of the outstanding shares of common stock without the prior consent of the company would not be entitled to this purchase opportunity.
The Rights will expire in November 1998, or they may be redeemed by the company at 5 cents per share prior to that date. The Rights do not have voting or dividend rights and, until they become exercisable, have no dilutive effect on the earnings of the company. Twenty million shares of the company's preferred stock have been designated Series A participating preferred stock and reserved for issuance upon exercise of the Rights. No event during 1997 made the Rights exercisable.
In December 1997, the company announced a repurchase program for up to $2 billion of the company's common stock. At December 31, 1997, the company had repurchased 1,199,300 shares at a cost of $92.
NOTE 6. FINANCIAL AND DERIVATIVE INSTRUMENTS
Off-Balance-Sheet Risk The company utilizes a variety of derivative instruments, both financial and commodity-based, as hedges to manage a small portion of its exposure to price volatility stemming from its integrated petroleum activities. Relatively straightforward and involving little complexity, the derivative instruments used consist mainly of futures contracts traded on the New York Mercantile Exchange and the International Petroleum Exchange and of natural gas swap contracts entered into principally with major financial institutions. The futures contracts hedge anticipated crude oil purchases and sales and product sales, generally forecast to occur within a 60-to 90-day period. Natural gas swaps are used primarily to hedge firmly committed sales, and the terms of the swap contracts held at year-end 1997 have an average remaining maturity of 51 months. Gains and losses on these derivative instruments offset and are recognized concurrently with gains and losses from the underlying commodities.
In addition, the company in 1997 and 1996 entered into managed programs using swaps and options to take advantage of perceived opportunities for favorable price movements in natural gas. The results of these programs are reflected currently in income and were not material in 1997 or 1996.
The company enters into forward exchange contracts, generally with terms of 90 days or less, as a hedge against
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some of its foreign currency exposures primarily anticipated purchase transactions forecast to occur within 90 days.
The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements, based on the difference between fixed-rate and floating- rate interest amounts calculated by reference to agreed notional principal amounts, are made either semiannually or annually, and are recorded monthly as "Interest and debt expense." At December 31, 1997, there were four outstanding contracts, with remaining terms of between 11 months and eight years.
Concentrations of Credit Risk The company's financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables.
The company's short-term investments are placed with various foreign governments and a wide array of financial institutions with high credit ratings. This diversified investment policy limits the company's exposure both to credit risk and to concentrations of credit risk. Similar standards of diversity and creditworthiness are applied to the company's counterparties in derivative instruments.
The trade receivable balances, reflecting the company's diversified sources of revenue, are dispersed among the company's broad customer base worldwide. As a consequence, concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. Letters of credit are the principal security obtained to support lines of credit or negotiated contracts when the financial strength of a customer is not considered sufficient.
Fair Value Fair values are derived either from quoted market prices where available or, in their absence, the present value of the expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end. At December 31, 1997 and 1996, the fair values of the financial and derivative instruments were as follows:
Long-term debt of $1,414 and $1,850 had estimated fair values of $1,481 and $1,915.
The notional principal amounts of the interest rate swaps totaled $1,050 and $1,199, with approximate fair values totaling $(16) and $(1). The notional amounts of these and other derivative instruments do not represent assets or liabilities of the company but, rather, are the basis for the settlements under the contract terms.
The company holds cash equivalents and U.S. dollar marketable securities in domestic and offshore portfolios. Eurodollar bonds, floating-rate notes, time deposits and commercial paper are the primary instruments held. Cash equivalents and marketable securities had fair values of $1,483 and $1,472. Of these balances, $828 and $727 classified as cash equivalents had average maturities under 90 days, while the remainder, classified as marketable securities, had average maturities of three years and one year.
For other derivatives the contract or notional values were as follows: Crude oil and products futures had net contract values of $4 and $57, approximating their fair values. Forward exchange contracts had contract values of $47 and $231, approximating their fair values. Gas swap contracts, based on notional gas volumes of approximately 75 and 78 billion cubic feet, had negative fair values totaling $(2) and $(8). Deferred gains and losses that have been accrued on the Consolidated Balance Sheet are not material.
NOTE 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC.
At December 31, 1997,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). In 1997, these operations were conducted primarily by two divisions: Chevron U.S.A. Production Company and Chevron Products Company. Prior to September 1, 1996, Chevron U.S.A. Inc.'s natural gas liquids operations were conducted by its Warren Petroleum Company division, and its natural gas marketing operations were conducted by Chevron U.S.A. Production Company. Beginning September 1, 1996, these operations are carried out through its 28 percent equity ownership in NGC Corporation. Summarized financial information for Chevron U.S.A. Inc. and its consolidated subsidiaries is presented below:
NOTE 8. LITIGATION
The company is a defendant in numerous lawsuits, including, along with other oil companies, actions challenging oil and gas royalty and severance tax payments based on posted prices. Plaintiffs may seek to recover large and sometimes unspecified amounts, and some matters may remain unresolved for several years. It is not practical to estimate a range of possible loss for the company's litigation matters, and losses could be material with respect to earnings in any given period. However, management is of the opinion that resolution of the lawsuits will not result in any significant liability to the company in relation to its consolidated financial position or liquidity.
OXY U.S.A. brought a lawsuit in its capacity as successor in interest to Cities Service Company, which involved claims for damages resulting from the allegedly improper termination of a tender offer to purchase Cities' stock in 1982 made by Gulf Oil Corporation, acquired by Chevron in 1984. A trial with respect to the claims ended in July 1996 with a judgment against the company of $742, including interest that
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continues to accrue at a rate of 9.55 percent per year. The company has filed an appeal and posted a bond for 1.5 times the amount of the judgment. While the ultimate outcome of this matter cannot be determined presently with certainty, the company believes that errors were committed by the trial court that should result in the judgment being reversed on appeal.
NOTE 9. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION
Chevron Transport Corporation (CTC), a Liberian corporation, is an indirect, wholly owned subsidiary of Chevron Corporation. CTC is the principal operator of Chevron's international tanker fleet and is engaged in the marine transportation of oil and refined petroleum products. Most of CTC's shipping revenue is derived by providing transportation services to other Chevron companies. Chevron Corporation has guaranteed this subsidiary's obligations in connection with certain debt securities where CTC is deemed to be an issuer. In accordance with the Securities and Exchange Commission's disclosure requirements, summarized financial information for CTC and its consolidated subsidiaries is presented below. This information was derived from the financial statements prepared on a stand-alone basis in conformity with generally accepted accounting principles.
Separate financial statements and other disclosures with respect to CTC are omitted as such separate financial statements and other disclosures are not material to investors in the debt securities deemed issued by CTC. There were no restrictions on CTC's ability to pay dividends or make loans or advances at December 31, 1997.
The 1997 decrease in "Other assets" and "Net equity" was primarily due to the 1997 assignment of an interest-bearing loan agreement to CTC's parent and an associated return of paid-in capital.
NOTE 10. GEOGRAPHIC AND SEGMENT DATA
The geographic and segment distributions of the company's identifiable assets, operating income, and sales and other operating revenues are summarized in the following tables:
Identifiable assets for the business segments include all assets associated with operations in the indicated geographic areas, including investments in affiliates. "Corporate and Other" identifiable assets consist primarily of cash and marketable securities, corporate real estate and information systems.
Operating income in 1995 included asset impairment write-downs of $998 in connection with the adoption of SFAS No. 121, as follows: U.S. Petroleum - $754; U.S. Chemicals - $20; U.S. Coal and Other Minerals - $97; International Petroleum - $127. Corporate and Other included other write-downs of $19.
Sales and other operating revenues for the petroleum segments are derived from the production and sale of crude oil, natural gas and natural gas liquids, and from the refining and marketing of petroleum products. The company also obtains revenues from the transportation and trading of crude oil and refined products. Chemicals revenues result primarily from the sale of petrochemicals, plastic resins, and lube oil and fuel additives. Coal and other minerals revenues relate primarily to coal sales. The company's real estate and insurance operations and worldwide cash management and financing activities are in "Corporate and Other." In 1996, the company completed the sale of most of its real estate development assets.
Sales and other operating revenues in the following table include both sales to unaffiliated customers and sales from the transfer of products between segments. Sales from the transfer
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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 and NGC Corporation are included in the "International Petroleum" and "United States Petroleum" segments, respectively. Information on the Caltex, Tengizchevroil and NGC affiliates is presented in Note 12. Other affiliates are either not material or not vertically integrated with a segment's operations.
NOTE 11. LEASE COMMITMENTS
Certain noncancelable 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, 1997, the future minimum lease payments under operating and capital leases are as follows:
Rental expenses incurred for operating leases during 1997, 1996 and 1995 were as follows:
Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging from one to 25 years and/or options to purchase the leased property during or at the end of the initial lease period for the fair market value at that time.
NOTE 12. INVESTMENTS AND ADVANCES
Chevron owns 50 percent each of P.T. Caltex Pacific Indonesia (CPI), an exploration and production company operating in Indonesia; Caltex Petroleum Corporation (CPC), which, through its subsidiaries and affiliates, conducts refining and marketing activities in Asia, Africa, the Middle East, Australia and New Zealand; and American Overseas Petroleum Limited, which, through its subsidiary, manages certain of the company's operations in Indonesia. These companies and their subsidiaries and affiliates are collectively called the Caltex Group.
Tengizchevroil (TCO) is a joint venture formed to develop the Tengiz and Korolev oil fields over a 40-year period. In April 1997, Chevron sold 10 percent of its interest in TCO to
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an affiliate of LUKoil, a Russian oil company, and Arco. The sale reduces Chevron's ownership to 45 percent. The investment in TCO at December 31, 1997 and 1996, included a deferred payment portion of $429 and $428, 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.
Chevron owns 28 percent of NGC Corporation (NGC), a gatherer, processor, transporter and marketer of energy products in North America and the United Kingdom, including natural gas, natural gas liquids, crude oil and electricity. The market value of Chevron's shares of NGC common stock at December 31, 1997, was $679 based on quoted market prices.
Investments in and advances to companies accounted for using the equity method, and other investments accounted for at or below cost, are as follows:
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 1997, 1996 and 1995, are as follows:
Effective October 1, 1997, Caltex's management changed the functional currency for its Korean and Japanese equity affiliates from their local currencies to the U.S. dollar, based on significantly changed economic facts and circumstances, primarily changing regulatory environments in those countries. Caltex's earnings in 1997 include significant foreign currency gains, mostly related to net deferred tax benefits resulting from local currency losses on the translation of U.S. dollar debt of affiliates.
The company's transactions with affiliated companies are summarized in the following table. These are primarily for the purchase of Indonesian crude oil from CPI, the sale of crude oil and products to CPC's refining and marketing companies, the sale of natural gas to NGC, and the purchase of natural gas and natural gas liquids from NGC.
"Accounts and notes receivable" in the Consolidated Balance Sheet include $145 and $258 at December 31, 1997 and 1996, respectively, of amounts due from affiliated companies. "Accounts payable" include $57 and $39 at December 31, 1997 and 1996, respectively, of amounts due to affiliated companies.
The following tables summarize the combined financial information for the Caltex Group and all of the other equity method companies together with Chevron's share. Amounts shown for the affiliates are 100 percent.
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NOTE 13. PROPERTIES,PLANT AND EQUIPMENT
Expenses for maintenance and repairs were $738, $626 and $833 in 1997, 1996 and 1995, respectively.
NOTE 14. TAXES
U.S. federal income tax expense was reduced by $93, $77 and $68 in 1997, 1996 and 1995, respectively, for low-income housing and other business tax credits.
In 1997, before-tax income, including related corporate and other charges, for U.S. operations was $2,054, compared with $1,631 in 1996 and a loss of $(331) in 1995, and for international operations was $3,448, $3,109 and $2,120 in 1997, 1996 and 1995, respectively.
The deferred income tax provisions included (costs) benefits of $(304), $(204) and $75 related to properties, plant and equipment in 1997, 1996 and 1995, respectively. Benefits were recorded in 1995 of $358 related to the impairment of long-lived assets and $91 related to the provision for the expected loss from exiting the real estate development business.
The company's effective income tax rate varied from the U.S. statutory federal income tax rate because of the following:
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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, 1997 and 1996, deferred taxes were classified in the Consolidated Balance Sheet as follows:
The reported deferred tax balances are composed of the following deferred tax liabilities (assets):
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 $4,500 at December 31, 1997. 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 $196 would be payable upon remittance of these earnings.
NOTE 15. SHORT-TERM DEBT
Redeemable long-term obligations consist primarily of tax-exempt variable- rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.
The company has entered into interest rate swaps on a portion of its short- term debt. At December 31, 1997 and 1996, the company had swapped notional amounts of $1,050 of floating rate debt to fixed rates. In addition, at December 31,1996, the company had swapped $149 of debt classified as "Current maturities of long-term debt" from a fixed rate to a floating rate. The effect of these swaps on the company's interest expense was not material.
NOTE 16. LONG-TERM DEBT
Chevron and one of its wholly owned subsidiaries each have "shelf" registrations on file with the Securities and Exchange Commission that together would permit the issuance of $1,300 of debt securities pursuant to Rule 415 of the Securities Act of 1933.
At year-end 1997, the company had $4,050 of committed credit facilities with banks worldwide, $2,725 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.
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At December 31, 1997, the company classified $2,725 of short-term debt as long-term, compared to $1,800 of short-term debt classified as long-term at December 31, 1996. The change results from a greater amount of the company's committed credit facilities with termination dates beyond one year. Settlement of these obligations is not expected to require the use of working capital in 1998, 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 December31, 1997, is as follows: 1998-$303, 1999-$121, 2000-$124, 2001-$137 and 2002-$148.
NOTE 17. EMPLOYEE BENEFIT PLANS
Pension Plans The company has defined benefit pension plans for most employees. The principal plans provide for automatic membership on a noncontributory basis. The retirement benefits provided by these plans are based primarily on years of service and on average career earnings or the highest consecutive three years' average earnings. The company's policy is to fund at least the minimum necessary to satisfy requirements of the Employee Retirement Income Security Act.
The net pension (credit) expense for all of the company's pension plans for the years 1997, 1996 and 1995 consisted of:
Settlement gains in 1997, 1996 and 1995, related to lump-sum payments, totaled $29, $28 and $7 respectively. Charges for termination benefits totaled $13 in 1997 and $5 in 1995. There were no charges in 1996.
At December 31, 1997 and 1996, the weighted average discount rates, the long- term rates for compensation increases used for estimating the benefit obligations, and the expected rates of return on plan assets were as follows:
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, 1997 and 1996, was as follows:
The net transition assets and liabilities generally are being amortized by the straight-line method over 15 years.
Profit Sharing/Savings 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. Charges to expense for the profit sharing part of the Profit Sharing/Savings Plan and the Savings Plus Plan, which was merged with the Profit Sharing/Savings Plan at the end of 1995, after shareholders' approval, were $79, $92 and $99 in 1997, 1996 and 1995, respectively. Commencing in October 1997, the company's Savings Plus Plan contributions are being funded with leveraged ESOP shares.
Employee Stock Ownership Plan (ESOP) In December 1989, the company established a leveraged 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 seven years.
As allowed by AICPA Statement of Position (SOP) 93-6, the company has elected to continue its practices, which are based on SOP 76-3 and subsequent consensus 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.
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The company recorded expense for the ESOP of $53, $61 and $67 in 1997, 1996 and 1995, respectively, including $61, $65 and $68 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 $57, $53 and $50 in 1997, 1996 and 1995, respectively.
The company made contributions to the ESOP of $55, $62 and $69 in 1997, 1996 and 1995, 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 $(8), $(4) and $(1) in 1997, 1996 and 1995, respectively. The ESOP shares as of December 31, 1997 and 1996 were as follows:
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 is an annual cash incentive plan that links awards to performance results of the prior year. The cash awards may be deferred by conversion to stock units or, beginning with awards deferred in 1996, stock units or other investment fund alternatives. Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, stock units and nonstock grants. Charges to expense for the combined management incentive plans, excluding expense related to LTIP stock options, which is discussed in Note 18, "Stock Options," were $55, $36 and $45 in 1997, 1996 and 1995, respectively.
Chevron Success Sharing In January 1995, the company established a program that provides eligible employees with an annual cash bonus if the company achieves certain financial and safety goals. The total maximum payout under the program is 8 percent of the employee's annual salary. Charges for the program were $116 and $72 in 1997 and 1996, respectively. There were no expenses accrued for the program in 1995.
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.
Nonpension postretirement benefits are not pre-funded by the company, but are paid when incurred. The accumulated postretirement benefit obligation (APBO) and unrecognized gains and losses for these plans are recorded in the Consolidated Balance Sheet as follows:
The company's net postretirement benefits expense was as follows:
For measurement purposes, separate health care cost-trend rates were utilized for pre-age 65 and post-age 65 retirees. The 1998 annual rates of change were assumed to be 3.4 percent and 9.2 percent, respectively, before gradually converging to the average ultimate rate of 5.1 percent in 2014 for both pre-age 65 and 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 costs for the year 1997 by $19 and would increase the December 31, 1997 APBO by $122.
At December 31, 1997, the weighted average discount rate was 7.0 percent, and the assumed rate of compensation increase related to the measurement of the life insurance benefit was 5.0 percent.
NOTE 18. STOCK OPTIONS
The company applies APB Opinion No. 25 and related Interpretations in accounting for stock options awarded under its Broad-Based Employee Stock
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Option Plan and its Long-Term Incentive Plan, which are described below. Had compensation cost for the company's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation," the company's net income and earnings per share for 1997, 1996 and 1995 would have been the pro forma amounts indicated below:
The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts. SFAS No. 123 does not apply to awards granted prior to 1995. In addition, certain options vest over several years, and awards in future years, whose terms and conditions may vary, are anticipated.
Long-Term Incentive Plan Stock options granted under the LTIP are generally awarded at market price on the date of grant and are exercisable not earlier than one year and not later than 10 years from the date of grant. However, a portion of the LTIP options granted in 1996 had terms similar to the broad-based employee stock options, which are described below. 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.
A summary of the status of stock options awarded under the company's LTIP, excluding awards granted with terms similar to the broad-based employee stock options, for 1997, 1996 and 1995 is presented below:
The weighted-average fair market value of options granted in 1997, 1996 and 1995 was $17.64, $14.18 and $9.06 per share, respectively. The fair market value of each option granted was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions for 1997, 1996 and 1995, respectively: risk-free interest rate of 6.1, 6.4 and 6.0 percent; dividend yield of 2.8, 3.3 and 3.9 percent; volatility of 15.2, 16.1 and 17.3 percent and expected life of seven years in all years.
As of December 31, 1997, 8,268,654 shares were under option at exercise prices ranging from $31.9375 to $80.9375 per share. The following table summarizes information about stock options outstanding under the LTIP, excluding awards granted with terms similar to the broad-based employee stock options, at December 31, 1997:
Broad-Based Employee Stock Options In 1996, the company granted to all eligible employees an option for 150 shares of stock or equivalents at an exercise price of $51.875 per share. In addition, a portion of the awards granted under the LTIP had terms similar to the broad-based employee stock options. When the options were issued in February 1996, vesting was contingent upon one of two conditions being met: if, by December 31, 1998, the price of Chevron stock closed at or above $75.00 per share for three consecutive business days or, alternatively, if the company had the highest annual total stockholder return of its competitor group for the years 1994 through 1998. The options vested in June 1997 when the share price performance condition was met.
Options for 7,204,800 shares, including similar-termed LTIP awards, were granted in 1996. Forfeitures of options for 302,500 shares reduced the outstanding option shares to 6,902,300 at December 31, 1996. In 1997, exercises of 4,171,300 and forfeitures of 516,050 had reduced the outstanding option shares to 2,214,950 at year-end 1997. Unexercised options expire on March 31,1999. Under APB Opinion No. 25, the company recorded expenses of $125 and $29 for these options in 1997 and 1996, respectively.
The fair market value of each option share on the date of grant under SFAS No.123 was estimated at $5.66 using a binomial option-pricing model with the following assumptions: risk-free interest rate of 5.1 percent, dividend yield of 4.2 percent, expected life of three years and a volatility of 20.9 percent.
In 1998, the company announced a new broad-based Employee Stock Option Program that granted to all eligible U.S. dollar payroll employees an option that varies from 100
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to 300 shares of stock dependent on the employee's salary or job grade. These options vest in two years or, if the company is No. 1 in total shareholder return among its competitor group for the years 1994 through 1998, in one year. Options for approximately 4 million shares were awarded at an exercise price of $76.3125 per share. The options expire on February 11, 2008. Non-U.S. dollar payroll employees, depending on the country of operation, received stock appreciation rights or performance units that are payable only in cash.
NOTE 19. EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued SFAS No. 128, "Earnings Per Share," which became effective for reporting periods ending after December 15, 1997. Under the previous standard, APB No. 15, the company presented a single earnings per share (EPS) amount that was calculated by dividing net income by the weighted-average number of shares outstanding for the period. Under the provisions of SFAS No. 128, the company will present basic and diluted EPS. Basic EPS includes the effects of award and salary deferrals that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these deferrals as well as the dilutive effects of outstanding stock options awarded under the LTIP and Broad-based Employee Stock Option Program (See Note 18. Stock Options). For purposes of comparability, all prior-period earnings-per-share data have been restated to conform with SFAS No. 128. The following table sets forth the computation of basic and diluted EPS:
Options to purchase 1,731,750 shares of common stock at $80.9375 per share were outstanding at year-end but were not included in the computation of diluted EPS because the options' exercise price was greater than the average market price of the common shares. These options expire October 29, 2007.
NOTE 20. OTHER CONTINGENT LIABILITIES AND COMMITMENTS
The U.S. federal income tax and California franchise tax liabilities of the company have been settled through 1987 and 1991, respectively.
In June 1997, the company's Caltex affiliate received a claim from the U.S. Internal Revenue Service (IRS) for $292 million in excise taxes, $140 million in penalties and $1.6 billion in interest. The IRS claim relates to crude oil sales to Japanese customers beginning in 1980. Caltex is challenging the claim and fully expects to prevail. Caltex believes the underlying excise tax claim is wrong and therefore the claim for penalties and interest is wrong. The Caltex claim has been through the appeals process and will next move to court. In February 1998, Caltex provided an initial letter of credit for $2.33 billion to the IRS to pursue the claim. The letter of credit is guaranteed by Chevron and Texaco. In addition, a yet to be decided portion of the claim must be paid in order to proceed to court. Caltex is involved with other IRS tax audits in which no claims have been made.
Settlement of open tax years is not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.
At December 31, 1997, the company and its subsidiaries, as direct or indirect guarantors, had contingent liabilities of $73 for notes of affiliated companies and $31 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: 1998-$313; 1999-$347; 2000-$289; 2001- $207; 2002-$176; 2003 and after-$752. Total payments under the agreements were $243 in 1997, $177 in 1996 and $173 in 1995.
The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior disposal or release of chemical or petroleum substances by the company or other parties. Such contingencies may exist for various sites including, but not limited to: Superfund sites and refineries, oil fields, service stations, terminals and land development areas, whether operating, closed or sold. The amount of such future cost is indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties and the extent to which such costs are recoverable from third parties. While the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs to
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have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures has had, or will have, any significant impact on the company's competitive position relative to other domestic or international petroleum or chemical concerns.
The company's operations, particularly oil and gas exploration and production, can be affected by changing economic, regulatory and political environments in the various countries, including the United States, in which it operates. In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company's continued presence in those countries. Internal unrest or strained relations between a host government and the company or other governments may affect the company's operations. Those developments have, at times, significantly affected the company's operations and related results and are carefully considered by management when evaluating the level of current and future activity in such countries.
Areas in which the company has significant operations include the United States, Canada, Australia, United Kingdom, Congo, Angola, Nigeria, Democratic Republic of Congo, Papua New Guinea, China, Indonesia and Venezuela. The company's Caltex affiliates have significant operations in Indonesia, Korea, Japan, Australia, Thailand, the Philippines, Singapore and South Africa. The company's Tengizchevroil affiliate operates in Kazakhstan.
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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 No. 69), this section provides supplemental information on oil and gas exploration and producing activities of the company in six separate tables. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the company's estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Congo and Democratic Republic of Congo. The "Other" geographic category includes activities in Australia, the United Kingdom North Sea, Canada, Papua New Guinea, Venezuela, China and other countries. Amounts shown for affiliated companies are Chevron's 50 percent equity share in P.T. Caltex Pacific Indonesia (CPI), an exploration and production company operating in Indonesia, and its 45 percent (50 percent prior to April 1997) equity share of Tengizchevroil (TCO), an exploration and production partnership operating in the Republic of Kazakhstan.
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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 1997, 1996 and 1995 are shown in the following table.
Net income from exploration and production activities as reported on Page FS-8 reflects income taxes computed on an effective rate basis. In accordance with SFAS No. 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest expense is excluded from the results reported in Table III and from the net income amounts on Page FS-8.
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TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1) - Continued
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TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1),(2) - Continued
TABLE IV - RESERVE QUANTITIES INFORMATION
The company's estimated net proved underground oil and gas reserves and changes thereto for the years 1997, 1996 and 1995 are shown in the following table. Proved reserves are estimated by the company's asset teams composed of earth scientists and reservoir engineers. These proved reserve estimates are reviewed annually by the corporation's reserves advisory committee to ensure that rigorous professional standards and the reserves definitions prescribed by the Securities and Exchange Commission are consistently applied throughout the company.
Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change over time as additional information becomes available.
Proved reserves do not include additional quantities recoverable beyond the term of the lease or contract unless renewal is reasonably certain, or that may result from extensions of currently proved areas, or from application of secondary or tertiary recovery processes not yet tested and determined to be economic.
Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.
"Net" reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.
Proved reserves for Tengizchevroil (TCO), the company's affiliate in Kazakhstan, do not include reserves that will be produced when a dedicated export system is in place. In April 1997, Chevron sold 10 percent of its interest in TCO, reducing its ownership to 45 percent.
In June 1997, a consortium, which Chevron will lead and have a 30 percent interest in, was successful in its bid to operate, under a risked service agreement, Venezuela's block LL-652, located in the northeast section of Lake Maracaibo. With an extensive operating program, the company plans to increase production to 115,000 barrels per day from a baseline production rate of 10,000 barrels per day.
Chevron is accounting for LL-652 as an oil and gas activity and has recorded 49 million barrels of proved crude oil reserves. No reserve quantities have been recorded for the company's Boscan service agreement, which began in 1996.
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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 No. 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 No. 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company's future cash flows or value of its oil and gas reserves.
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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."
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CALTEX GROUP OF COMPANIES COMBINED FINANCIAL STATEMENTS
December 31, 1997
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CALTEX GROUP OF COMPANIES COMBINED FINANCIAL STATEMENTS DECEMBER 31, 1997
INDEX
Page ------
General Information C-3 to C-6
Independent Auditors' Report C-7
Combined Balance Sheet C-8 to C-9
Combined Statement of Income C-10
Combined Statement of Stockholders' Equity C-11
Combined Statement of Cash Flows C-12
Notes to Combined Financial Statements C-13 to C-24
Note: Financial statement schedules are omitted as permitted by Rule 4.03 and Rule 5.04 of Regulation S-X.
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CALTEX GROUP OF COMPANIES GENERAL INFORMATION
The Caltex Group of Companies (Group) is jointly owned 50% each by Chevron Corporation and Texaco Inc. and was created in 1936 by its two owners to produce, transport, refine and market crude oil and petroleum 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, transporting, and marketing activities in the Eastern Hemisphere;
- - P. T. Caltex Pacific Indonesia, an exploration and production company incorporated and operating in Indonesia; and,
- - American Overseas Petroleum Limited, a company incorporated in the Bahamas, that, through its subsidiary, provides services for and manages certain exploration and production operations in Indonesia in which Chevron and Texaco have interests, but not necessarily jointly or in the same properties.
A brief description of each company's operations and other items follow:
Caltex Petroleum Corporation (Caltex) - -------------------------------------
Through its subsidiaries and affiliates, Caltex operates in approximately 60 countries, principally in Africa, Asia, the Middle East, New Zealand and Australia. Caltex is involved in all aspects of the downstream business: refining, distribution, shipping, storage, marketing, supply and trading operations. At year end 1997, Caltex had over 7,600 employees, of which approximately 3% were located in the United States.
The majority of refining and certain marketing operations are conducted through joint ventures. Caltex has equity interests in 13 refineries with a refining capacity of more than 900,000 barrels per day. Caltex continues to improve its refineries with investments designed to provide higher yields and meet environmental regulations. Additionally, it has interests in two lubricant refineries, six asphalt plants, 17 lubricating oil blending plants and more than 500 ocean terminals and depots. Caltex also has an interest in a fleet of vessels and owns or has equity interests in numerous pipelines. Caltex sales of crude oil and petroleum products were 1.4 million barrels per day in 1997.
Caltex and its affiliates maintain a strong marketing presence through a network of 7,900 retail outlets, of which 4,600 are branded as Caltex. It also operates 305 Star Mart convenience stores. A significant portion of the $2.3 billion that Caltex plans to invest over the next three years is targeted to stimulate retail growth and continue the roll-out of the company's new corporate and retail image.
Caltex introduced a new corporate and retail identity in 1996 and is actively pursuing its objective of reimaging over 3,000 branded sites by 2000. Underperforming stations with poor prospects for improvement are being eliminated. New Caltex Star Mart convenience stores anchor many high-volume station locations. Many stations also include new ancillary revenue centers such as quick-service restaurants, auto lube bays and brushless car washes.
In 1997, Caltex continued its refinery upgrade projects in the Philippines and Korea and enhanced its role in Australia through an affiliate's acquisition of the remaining 50% interest in Australian Petroleum Pty. Limited (APPL) thereby becoming the largest oil company in Australia. It also continued to make inroads into emerging countries such as China, Vietnam, Indonesia and India in selected product markets. Caltex increased its market share in Thailand by acquiring British Petroleum's retail service station network of 47 sites, and has entered the independent power producer market in Japan through an affiliate.
In addition to the retail initiatives, Caltex has created specialized business units that are helping Caltex operating companies position themselves for larger shares of the high-growth markets for lubricating oils and greases, aviation fuels, and liquefied petroleum gas. Caltex conducts international crude oil and petroleum product logistics and trading operations from a subsidiary in Singapore. Caltex is also active in the petrochemical business, particularly in Japan and Korea.
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CALTEX GROUP OF COMPANIES GENERAL INFORMATION
P. T. Caltex Pacific Indonesia (CPI) - ------------------------------------
CPI holds a Production Sharing Contract in Central Sumatra through the year 2021. CPI also acts as operator in Sumatra for eight other petroleum contract areas, with 33 fields, which are jointly held by Chevron and Texaco. Exploration is pursued through an area comprising 18.3 million acres with production established in the giant Minas and Duri fields, along with smaller fields. Gross production from fields operated by CPI for 1997 was over 765,000 barrels per day. CPI entitlements are sold to its stockholders, who use them in their systems or sell them to third parties. At year end 1997, CPI had approximately 6,100 employees, all located in Indonesia.
American Overseas Petroleum Limited (AOPL) - ------------------------------------------
In addition to providing services to CPI, AOPL, through its subsidiary Amoseas Indonesia Inc., manages selective contract areas for Texaco's and Chevron's undivided interests in Indonesia, excluding Sumatra. At year end, AOPL had approximately 250 employees, of which 6% were located in the United States.
Economic Uncertainties - ----------------------
During the second half of 1997, many of the countries in the Pacific Rim experienced major devaluations in their currencies compared to the U.S. dollar. The Group has significant operations (either subsidiary or affiliate) in most of the "currency crisis" areas (Indonesia, Korea, Philippines, Thailand and Malaysia), which are material to the Group's net income, cash flows and capital. Such operations accounted for approximately 84% of the Group's earnings in 1997. The economies and related oil consumption in the areas involved are being negatively affected by the crisis. In some cases, normal short-term trade related financing provided by international banks has been curtailed.
The devaluations in these five countries resulted in significant net exchange gains of $211 million, $73 million of pre-tax exchange losses offset by $284 million in net local tax benefits, inclusive of amounts applicable to equity affiliates. The tax benefits resulted from the increase in the amount of local currencies required to repay debt denominated in U.S. dollars. These tax benefits are reflected in the income statement but the increased local currency debt amounts are not, as there is no change in the U.S. dollar value of the debt. A significant portion of the tax benefit has been recorded as a deferred tax asset to be realized based on future local currency taxable income. Reported earnings include additional reserves for potential bad debts related to the currency crisis of $48 million.
Local currency selling prices for petroleum products in these markets could not be immediately increased to fully recover prior dollar margins. The most significant uncertainties that will affect Group operating results and cash flows in these areas in 1998 are the ability to raise local currency selling prices and restore dollar marketing margins, continued weak regional refining margins and reduced demand and liquidity concerns relative to its operating companies and their customers. Certain subsidiaries of Caltex Petroleum Corporation, beginning in January 1998, provided short-term trade financing of up to $500 million for a four-month period to its Korean affiliate. This support is considered temporary.
The Group is further focusing on cost management and its recurring capital investment in the areas involved. While the impact of the crisis on period operating results has been, and is expected to continue to be significant, the Group does not expect this will have a material effect on its consolidated financial position or liquidity.
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CALTEX GROUP OF COMPANIES GENERAL INFORMATION
Environmental Activities - ------------------------
The Group's activities are subject to various 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 as well as its own internal policies. The Group has an active program to ensure that 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.
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, 1997, the Group, including its equity share of affiliates, incurred total costs of approximately $160 million, including capital costs of $98 million and nonremediation related operating expenses of $62 million. The major component of the Group's expenditures is for the prevention of air pollution. As of December 31, 1997, the Group had accrued $110 million for various known remediation activities, including $88 million relating to the future cost of restoring and abandoning existing oil and gas properties.
While the Group has provided for known environmental obligations that are probable and reasonably estimable, the amount of future costs may be material to results of operations in the period in which they are recognized. However, the Group believes that future environmental expenditures will not materially affect its financial position or liquidity.
Year 2000 Compliance Issues - ---------------------------
The Group's computer systems, software and mechanical equipment containing embedded technology are impacted by the year 2000 programming problems. Older programs may incorrectly interpret this date causing systems And equipment to shut down, produce erroneous information or malfunction.
The Group has established various teams to address these issues. While it is not possible at this time to quantify the impact of this problem on the operations of the Group, evaluations are currently underway to assess the risks and compliance issues the Group is facing. Strategies are being developed to mitigate risks, and correct various system and mechanical problems already identified. The Group is also working with customers and suppliers to ensure that data interfaces, equipment, software and other issues have been properly identified and measures taken to protect the operations of the Group from problems outside the organization.
Much of the cost of compliance is included in planned system or equipment upgrades already scheduled or underway, although certain programs will be accelerated to ensure that major problems are properly addressed before the target dates. Other costs which are classified as incremental expenses will represent a redeployment of existing resources. At this time, estimates of the total incremental costs to be incurred to correct these issues are unavailable. However, the Group believes that the cost of compliance with these issues will not have a material effect on the Group's combined financial position, results of operations or liquidity.
Refining Synergies - ------------------
During 1997, Caltex' Thailand affiliate, Star Petroleum Refining Company (SPRC), and Rayong Refining Company (RRC), an affiliate of the Royal Dutch Petroleum Company, signed a Memorandum of Understanding to pursue an operating alliance to optimize the operations of the two nearby refineries as a single economic group. Significant economic benefits are possible from this arrangement. SPRC and RRC are currently evaluating various proposed structures and synergies, as well as conducting discussions with lenders to ensure proper concurrences are obtained. To date, discussions are still in the early stages and no legally binding agreements have been executed.
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CALTEX GROUP OF COMPANIES GENERAL INFORMATION
Supplemental Market Risk Disclosures - ------------------------------------
The Group uses derivative financial instruments for hedging purposes. These instruments principally include interest rate and/or currency swap contracts, forward and option contracts to buy and sell foreign currencies, and commodity futures, options, swaps and other derivative instruments. Hedged market risk exposures include certain portions of assets, liabilities, future commitments and anticipated sales. Positions are adjusted for changes in the exposures being hedged. Since the Group hedges only a portion of its market risk exposures, market risk exposure remains on the unhedged portion. The Notes to the financial statements provide data relating to derivatives and applicable accounting policies.
Debt and debt-related derivatives
The Group is exposed to interest rate risk on its short-term and long-term debt with variable interest rates (approximately $1.9 billion at December 31, 1997, before the effects of related net interest rate swaps of $0.4 billion). The Group seeks to balance the benefit of lower cost variable rate debt, having inherent increased risk, with more expensive, but less risky fixed rate debt. This is accomplished through adjusting the mix of fixed and variable rate debt, as well as the use of derivative financial instruments, principally interest rate swaps.
Based on the overall interest rate exposure on variable rate debt and interest rate swaps taken separately at December 31, 1997, a hypothetical 2% change in the interest rates would not materially affect the Group's combined financial position, net income or liquidity.
Crude oil and petroleum product hedging
The Group hedges a portion of the market risks associated with its crude oil and petroleum product purchases and sales. The Group uses established petroleum futures exchanges, as well as "over-the counter" hedge instruments, including futures, options, swaps, and other derivative products which reduce the Group's exposure to price volatility in the physical markets.
As a sensitivity, a hypothetical 13% change in crude oil and petroleum product prices would not result in a material loss on the outstanding derivatives at the end of 1997, in terms of the Group's financial position, results of operations or liquidity.
Currency-related derivatives
The Group is exposed to foreign currency exchange risk in the countries in which it operates. To hedge against adverse changes in foreign currency exchange rates against the U.S. dollar, the Group sometimes enters into forward exchange and option contracts. Depending on the exposure being hedged, the Group either purchases or sells selected foreign currencies. At year end 1997, the Group had net local currency purchase contracts of approximately $417 million to hedge certain specific transactions or net exposures including foreign currency denominated debt. A hypothetical 10% change in exchange rates against the U.S. dollar would not result in a net material change in the Group's operating results or cash flows from the derivatives and their related underlying hedged positions as of the end of 1997.
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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, 1997 and 1996, and the related combined statements of income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 1997. 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, 1997 and 1996 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 1997, in conformity with generally accepted accounting principles.
/s/KPMG Peat Marwick LLP
Dallas, Texas February 9, 1998
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 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. Intercompany transactions and balances have been eliminated. Subsidiaries include companies owned directly or indirectly more than 50 percent except cases in which control does not rest with the Group.
Chevron Corporation and Texaco Inc. (stockholders), through subsidiary companies, each own 50% of the common shares of the Group companies. The Group is primarily engaged in exploring, producing, refining, transporting and marketing crude oil and petroleum products in the Asia-Pacific and East-of-Suez Regions. The Group's accounting policies are in accordance with United States generally accepted accounting principles.
Translation of foreign currencies The U.S. dollar is the functional currency for all principal subsidiary and affiliate operations. Effective October 1, 1997, the Group changed the functional currency for its affiliates in Japan and Korea from the local currency to the U.S. dollar. Major changes in economic facts and circumstances, including a significant reduction in regulatory restrictions for petroleum products in those countries, supported this change in functional currency.
The change in functional currency is applied on a prospective basis. The U.S. dollar translated amounts of nonmonetary assets and liabilities at September 30, 1997 become the historical accounting basis for those assets and liabilities at October 1, 1997 and for subsequent periods. As a result of the change in functional currency, translation gains and losses on U.S. dollar denominated assets and liabilities of these affiliates will not arise in the Group's financial statements for periods after September 30, 1997. The $83 million cumulative translation adjustments for Korea and Japan at September 30, 1997 recorded prior to the change will remain as a separate component of stockholders' equity.
Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.
Short-term investments All highly liquid investments are classified as available for sale. Those with a maturity of three months or less when purchased are considered as "Cash equivalents" and those with longer maturities are classified as "Marketable securities".
Inventories Crude oil and petroleum product inventories are stated at cost, primarily determined using the last-in, first-out (LIFO) method. Costs include applicable acquisition and refining costs, duties, import taxes, freight, etc. Materials and supplies are stated at average cost. Inventories are valued at the lower of cost or current market.
Investments and advances Investments in affiliates in which the Group has an ownership interest of 20% to 50% or majority-owned investments where control does not rest with the Group, are accounted for by the equity method. The Group's share of earnings or losses of these companies is included in current results, and the recorded investments reflect the underlying equity in each company. Investments in other affiliates are carried at cost and 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 producing properties, including intangible development costs, are determined using the unit-of-production method. All other assets are depreciated by class on a straight-line basis using rates based upon the estimated useful life of each class.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 - Summary of significant accounting policies - continued
Maintenance and repairs necessary to maintain facilities in operating condition are charged to income as incurred. Additions and improvements that materially extend the life of assets are capitalized. Upon disposal of assets, any net gain or loss is included in income.
Derivative financial instruments The Group uses various derivative financial instruments for hedging purposes. These instruments principally include interest rate and/or currency swap contracts, forward and option contracts to buy and sell foreign currencies, and commodity futures, options, swaps and other derivative instruments. Hedged market risk exposures include certain portions of assets, liabilities, future commitments and anticipated sales. Prior realized gains and losses on hedges of existing nonmonetary assets are included in the carrying value of those assets. Gains and losses related to qualifying hedges of firm commitments or anticipated transactions are deferred and recognized in income when the underlying hedged transaction is recognized in income. If the derivative instrument ceases to be a hedge, the related gains and losses are recognized currently in income. Gains and losses on derivative contracts that do not qualify as hedges are recognized currently in other income.
Accounting for contingencies Certain conditions may exist as of the date financial statements are issued, which may result in a loss to the Group, but which will only be resolved when one or more future events occur or fail to occur. Assessing contingencies necessarily involves an exercise of judgment. In assessing loss contingencies related to legal proceedings that are pending against the Group or unasserted claims that may result in such proceedings, the Group evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material liability had been incurred and the amount of the loss can be estimated, then the estimated liability is accrued in the Group's financial statements. If the assessment indicates that a potentially material liability is not probable, but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable are disclosed.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the nature and amount of the guarantee would be disclosed. However, in some instances in which disclosure is not otherwise required, the Group may disclose contingent liabilities of an unusual nature which, in the judgment of management and its legal counsel, may be of interest to stockholders or others.
Environmental matters The Group's environmental policies encompass the existing laws in each country in which the Group operates and the Group's own internal standards. Expenditures that create future benefits or contribute to future revenue generation are capitalized. Future 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 undiscounted estimates using data primarily developed by third party experts. Costs of environmental compliance for past and ongoing operations, including maintenance and monitoring, are expensed as incurred. Recoveries from third parties are recorded as assets when realizable.
Reclassifications Certain amounts for 1996 have been reclassified to conform with the current year's presentation.
Note 2 - Asset Sale
Effective April 1, 1997 Caltex Trading and Transport Corporation, a subsidiary of the Group, sold its 40% interest in its Bahrain refining joint venture (Bapco) plus related assets to its partner, the Government of the State of Bahrain, at net book value of approximately $140 million.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 3 - Inventories
The excess of current cost over the reported value of inventory maintained on the LIFO basis was approximately $28 million and $125 million at December 31, 1997 and 1996, respectively.
During the periods presented, inventory quantities valued on the LIFO basis were reduced at certain locations. Inventory reductions, net of related market valuation adjustments ($14 million in 1997), decreased net income $5 million in 1997 and $1 million in 1995 and increased net income $4 million in 1996.
Certain inventories were recorded at market, which was lower than the LIFO carrying value. Adjustments to market reduced earnings $36 million in Earnings increased $29 million in 1996 and $25 million in 1995 due to recovery of market values over previous years' writedowns.
Note 4 - Equity in affiliates
Investments in affiliates at equity include the following:
The carrying value of the Group's investment in its affiliates in excess of its proportionate share of affiliate net equity is being amortized over approximately 20 years.
In 1995, Caltex Australia Limited (CAL), a subsidiary of the Group, combined its petroleum refining and marketing operations with those of Ampol Limited to form Australian Petroleum Pty. Limited (APPL) which owns and manages the combined refining and marketing operations. CAL contributed net assets at their carrying value of $419 million for its 50% equity interest in APPL and no gain or loss was recognized.
On December 31, 1997, CAL acquired the remaining 50% of APPL from its partner, a subsidiary of Pioneer International Limited, for approximately $186 million in cash plus the issuance of an additional 90 million shares of CAL stock. As a result of this transaction, the Group's equity in CAL has declined from 75% to 50% and its indirect equity in APPL has increased to 50% from 37.5%. This transaction was recorded as a purchase. CAL is now classified as an affiliate and the individual assets and liabilities have been excluded from the Group's consolidated financial statements for 1997.
Effective April 1, 1996, the Group sold its 50% investment in Nippon Petroleum Refining Company, Limited (NPRC) to its partner, Nippon Oil Company, Limited (NOC) for approximately $2 billion in cash. The Group's net income in 1996 includes a net after-tax gain of approximately $620 million related to this sale. The combined statement of income includes Group product sales to NOC of approximately $0.5 billion in the first quarter of 1996 and $2.1 billion in 1995.
During 1995, an affiliate sold certain property required by the local government. The Group's share (approximately $171 million) of the resulting gain was included in the Group's 1995 net income.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 4 - Equity in affiliates - continued
The remaining interest in Star Petroleum Refining Company, Ltd. (SPRC) is owned by a Thailand governmental entity. Provisions in the SPRC shareholders agreement limit the Group's control and provide for active participation of the minority shareholder in routine business operating decisions. The agreement also mandates reduction in Group ownership to a minority position by the year 2000, however, it is likely that this will be delayed in view of the current economic difficulties.
Shown below is summarized financial information for these affiliates (in millions of dollars):
Cash dividends received from these affiliates were $43 million, $89 million, and $76 million in 1997, 1996 and 1995, respectively.
Retained earnings as of December 31, 1997 and 1996, includes $1.4 billion and $1.0 billion, respectively, representing the Group's share of undistributed earnings of affiliates at equity.
Note 5 - Short-term debt
Short term debt consists primarily of demand and promissory notes, acceptance credits, overdrafts and the current portion of long-term debt. The weighted average interest rates on short-term financing as of December 31, 1997 and 1996 were 7.9% and 7.5%, respectively. Unutilized lines of credit available for short-term financing totaled $411 million as of December 31, 1997.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 6 - Long-term debt
Long-term debt, with related interest rates for 1997 and 1996 consist of the following:
Aggregate maturities of long -term debt for the next five years are as follows (in millions of dollars): 1998 - $62 (included in short-term debt); 1999 - $75; 2000 - $133; 2001- $379; 2002 - $174; 2003 and thereafter - $9.
Note 7 - Operating leases
The Group has operating leases involving various marketing assets for which net rental expense was $105 million, $92 million, and $91 million in 1997, 1996 and 1995, respectively.
Future net minimum rental commitments under operating leases having non- cancelable terms in excess of one year are as follows (in millions of dollars): 1998 - $44; 1999 - $36; 2000 - $32; 2001 - $34; 2002 - $33, and 2003 and thereafter - $48.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 8 - Employee benefit plans
The Group has various retirement plans. Generally, these plans provide defined benefits based on final or final average pay. The benefit levels, vesting terms and funding practices vary among plans.
The funded status of retirement plans, primarily foreign and inclusive of affiliates at equity, is as follows:
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 9 - Commitments and contingencies
On June 17, 1997, Caltex Petroleum Corporation (CPC) received a claim from the U.S. Internal Revenue Service (IRS) for $292 million in excise tax, along with penalties and interest bringing the total to approximately $2 billion. The IRS claim relates to crude oil sales to Japanese customers beginning in 1980. Prior to this time, CPC directly supplied crude oil to its Japanese customers, however, in 1980, a CPC subsidiary also became a contractual supplier of crude oil. The IRS position is that the additional supplier constituted a transfer of property, and was thus taxable. CPC is challenging the claim since the addition of another supplying company was not a taxable event. Additionally, CPC believes the claim is based on an overstated value. Finally, CPC disagrees with the imposition and calculation of interest and penalties. CPC believes the underlying excise tax claim is wrong, it also believes the related claim for penalties is wrong and the IRS claim for interest is flawed. CPC is challenging the claim and fully expects to prevail.
To litigate this claim, CPC has been required to maintain a letter of credit in the amount of $2.3 billion, including interest for 1998. This letter was provided to the IRS during February, 1998. For excise taxes, unlike income taxes, the taxpayer is required to pay a portion of the tax liability to gain access to the courts. The required cash payment will not have a material impact on the Group's financial position or liquidity.
CPC also is involved in IRS tax audits for years 1987-1993. While no claims have been asserted by the IRS for these years, in the opinion of management, adequate provision has been made for income taxes for all years either under examination or subject to future examination.
CPC and certain of its subsidiaries are named as defendants, along with privately held Philippine ferry and shipping companies and the shipping company's insurer, in various lawsuits filed in the U.S. and the Philippines on behalf of at least 3,350 parties, who were either survivors of, or relatives of persons who allegedly died in a collision in Philippine waters on December 20, 1987. One vessel involved in the collision was carrying CPC products in connection with a contract of affreightment. Although CPC had no direct or indirect ownership in or operational responsibility for either vessel, various theories of liability have been alleged against CPC. The major suit filed in the U.S. (Louisiana State Court) does not mention a specific monetary recovery although the pleadings contain a variety of demands for various categories of compensatory as well as punitive damages. Consequently, no reasonable estimate of damages involved or being sought can be made at this time. CPC sought to preclude the plaintiffs from pursuing the Louisiana litigation on various federal and procedural grounds. Having pursued these remedies in the federal court system without success (including a denial of a writ of certiorari by the U.S. Supreme Court), CPC management intends to continue to contest all of the foregoing litigation vigorously on various substantive and procedural grounds.
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 parties.
In the Group's opinion, while it is impossible to ascertain the ultimate legal and financial liability, if any, with respect to the above mentioned and other contingent liabilities, the aggregate amount that may arise from such liabilities is not anticipated to be material in relation to the Group's combined financial position or liquidity, or results of operations over a reasonable period of time.
In 1996, a CPC subsidiary entered into a contractual commitment, for a period of eleven years, to purchase petroleum products in conjunction with the financing of a refinery owned by an affiliate. Total future estimated commitments (in billions of dollars) for CPC under this and other similar contracts, based on current pricing and projected growth rates, are: 1998 - $0.7, 1999 - $0.8, 2000 - $0.8, 2001 - $0.8, 2002 - $0.7, and 2003 to expiration of contracts - $3.6. Purchases (in billions of dollars) under this and other similar contracts were $1.0, $0.8, and $0.5 in 1997, 1996 and 1995, respectively.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 9 - Commitments and contingencies - continued
CPC is contingently liable for sponsor support funding for both construction completion (maximum $192 million) and post-completion loan repayments (maximum $304 million) in connection with an affiliate's project finance obligations. While the project is operational, construction completion as defined includes achieving extended continuous operation and satisfying certain financial conditions, which contractually must be met or resolved by June 30, 1998. The post-completion support declines progressively as the related long-term loans are repaid (final payment due 2010). As of December 31, 1997, there have been no calls made by lenders on either type of sponsor support. However, CPC has provided short-term extended trade credit related to crude oil supply of approximately $144 million to the affiliate as of December 31, 1997. Discussions are ongoing with the lenders and the Group anticipates that some sponsor support will be required, including replacing existing extended trade credit. However, the Group believes that this support will not have a material impact on its combined financial position or liquidity, or results of operations over a reasonable period of time.
Note 10 - Financial Instruments
Certain Group companies are parties to financial instruments with off-balance sheet credit and market risk, principally interest rate risk. The Group's outstanding commitments for interest rate swaps and foreign currency contractual amounts are:
The Group enters into interest rate swaps in managing its interest 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 of up to eight years. Unrealized gains and losses on contracts outstanding at year-end 1997 and 1996 were not material.
The Group enters into forward exchange contracts to hedge against some of its foreign currency exposure stemming from existing liabilities and firm commitments. Contracts to purchase foreign currencies (principally Australian and Singapore dollars) hedging existing liabilities have maturities of up to four years. Unrealized gains and losses applicable to outstanding forward exchange contracts at December 31, 1997 and 1996 were not material.
The Group hedges a portion of the market risks associated with its crude oil and petroleum product purchases and sales. Established petroleum futures exchanges are used, as well as "over-the counter" hedge instruments, including futures, options, swaps, and other derivative products which reduce the Group's exposure to price volatility in the physical markets. The derivative positions are marked-to-market for valuation purposes. Gains and losses on hedges are deferred and recognized concurrently with the underlying commodity transactions. Derivative gains and losses not considered as a hedge are recognized currently in income. Open positions and related unrealized gains and losses on commodity-based derivative hedging contracts outstanding as of December 1997 and 1996 were not material.
The Group's long-term debt of $770 million and $713 million as of December 31, 1997 and 1996, respectively, had fair values of $731 million and $756 million as of December 31, 1997 and 1996, 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, marketable securities, notes and accounts receivable, and all current liabilities approximate fair value because of their short maturities
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 10 - Financial Instruments - continued
The Group had investments in debt securities available-for-sale at amortized costs of $82 million and $116 million at December 31, 1997 and 1996, respectively. The fair value of these securities at December 31, 1997 and 1996 approximates amortized costs. As of December 31, 1997 and 1996, investments in debt securities available-for-sale had maturities less than ten years. As of December 31, 1997 and 1996, the Group's carrying amount for investments in affiliates accounted for at equity included $12 million and $25 million, respectively, for after tax unrealized net gains on investments held by these companies.
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 its 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 concentration 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 is not considered sufficient. Credit losses have historically been within management's expectations.
Note 11 - Taxes
Taxes charged to income consist of the following:
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 11 - Taxes - continued
Income taxes have been computed on an individual company basis at rates in effect in the various countries of operation. The effective tax rate differs from the "expected" tax rate (U.S. Federal corporate tax rate) as follows:
Deferred income taxes are provided in each tax jurisdiction for temporary differences between the financial reporting and the tax basis of assets and liabilities. A valuation allowance has been established to adjust recorded deferred tax assets to amounts likely to be recoverable. Temporary differences and tax loss carryforwards which give rise to deferred tax liabilities (assets) are as follows:
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 11 - Taxes - continued
Deferred taxes are classified on the combined balance sheet as current assets of $29 million and noncurrent liabilities of $190 million as of December 31, 1997, and current assets of $10 million and noncurrent liabilities of $249 million as of December 31, 1996.
Undistributed earnings of subsidiaries and affiliates, for which no U.S. deferred income tax provision has been made, approximated $3.4 billion as of December 31, 1997 and $3.0 billion as of December 31, 1996. Such earnings have been or are intended to be indefinitely reinvested, and become taxable in the U.S. only upon remittance as dividends. It is not practical to estimate the amount of tax that may be payable on the eventual remittance of such earnings. Upon remittance, certain foreign countries impose withholding taxes which, subject to certain limitations, are available for use as tax credits against the U.S. tax liability.
Note 12 - Combined statement of cash flows
Changes in operating working capital consist of the following:
Net cash provided by operating activities includes the following cash payments for interest and income taxes:
The deconsolidation of Caltex Australia Limited as of December 31, 1997, as described in Note 4, results in a noncash reduction in the following combined balance sheet captions, which have not been included in the combined statement of cash flows:
Net working capital $ 60 Equity in affiliates 94 Long-term debt 45 Minority interest 109
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 12 - Combined statement of cash flows - continued
During 1995, Caltex Australia Limited exchanged, in a noncash investing transaction, its petroleum refining and marketing net assets of $419 million for an investment in Australian Petroleum Pty. Limited, an affiliate of the Group. No significant noncash investing or financing transactions occurred in 1996.
Net cash provided by operating activities in 1996 includes income tax payments relating to the sale of an investment in an affiliate. Proceeds from this sale are included in net cash provided by investing activities.
Note 13 - Oil and gas exploration, development and producing activities
The financial statements of Chevron Corporation and Texaco Inc. contain required supplementary information on oil and gas producing activities, including disclosures on affiliates at equity. Accordingly, such disclosures are not presented herein.
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