Item 1. Business
(a) General Development of Business
Summary Description of Chevron - ------------------------------ Chevron Corporation(1), a Delaware corporation, manages its investments in, and provides administrative, financial and management support to, U.S. and foreign subsidiaries and affiliates that engage in fully integrated petroleum operations, chemicals operations, coal mining and energy services. The company operates in the United States and approximately 100 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 commodity petrochemicals, plastics for industrial uses and fuel and lubricating oil additives.
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, 2000, Chevron had 34,610 employees, 73 percent of whom were employed in U.S. operations. Approximately 5,500, or 22 percent, of the company's U.S. employees are unionized.
- -------------------------------------------------------------------------------- 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 "anticipates," "expects," "intends," "plans," "projects," "believes," "seeks," "estimates" and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control, are difficult to predict and could cause actual results to differ from those expressed or forecasted in the forward-looking statements. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. 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 aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; 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 delays in the development, construction or start-up of planned projects; the ability to successfully consummate the proposed merger with Texaco and successfully integrate the operations of both companies; 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 litigation; significant investment or product changes under existing or future environmental regulations (including, particularly, regulations and litigation dealing with gasoline composition and characteristics); 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. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements. - --------------------------------------------------------------------------------
(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 it is stated otherwise, does not include "affiliates" of Chevron - i.e., those companies accounted for by the equity method (generally owned 50 percent or less), or investments accounted for by the cost method.
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 many factors, over some of which individual oil and gas companies have little control. Governmental policies, particularly in the areas of taxation, energy and the environment, have a significant impact on petroleum activities, regulating where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil and natural gas, petroleum products and petrochemicals are determined by supply and demand for these commodities. OPEC member countries are typically the world's swing producers of crude oil, and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and natural gas is largely driven by the condition 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.
Operating Environment - --------------------- Refer to page FS-2 of this Annual Report on Form 10-K in Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion on the company's current operating environment and outlook.
Chevron Strategic Priorities - ---------------------------- Chevron's strategic objective is to exceed the financial performance of its strongest industry competitors in terms of total stockholder return. The company's overriding goal is to achieve the highest total stockholder return in its peer group for the five-year period 2000 - 2004. To achieve its goal, the company has targeted a 15 percent annual growth rate in earnings per share for the three-year period 2000 - 2002, supported by worldwide liquids and natural gas production growth of 4 to 4.5 percent per year, and a minimum 12 percent return on capital employed.
To attain these financial and operational targets, the company has established four key priorities:
o Operational Excellence: Safe, reliable, efficient and environmentally sound operations throughout are the top priority for the company. The company seeks to ensure it achieves sustainable improvements in its operations.
o Cost Reduction: The company will continue to focus on ways of reducing costs across its activities. As examples, the company has seen ongoing successes in cost reduction in the areas of energy consumption and global procurement of goods and services.
o Capital Stewardship: The company is implementing work processes designed to ensure that it employs capital funding most efficiently. This involves decision-making tools aimed at selecting the most financially and strategically attractive projects. Additionally, the company has developed processes to ensure the execution of projects is efficient, bringing projects to completion on time and within budgeted expenditures.
o Profitable Growth: The company will seek continued growth in its core businesses - exploration and production, refining, marketing and transportation, and chemicals. The company is also looking to capture new opportunities, such as investing in power and gas through its Dynegy affiliate, new process technologies - including a method for converting natural gas to liquids - and information and Internet technologies.
Supporting these four priorities is a continued and improved focus on:
o Organizational Capability: The company has developed strategies to build capability systems to achieve top performance in the four priorities described above.
Chevron-Texaco Merger Agreement - ------------------------------- In October 2000, Chevron and Texaco announced an agreement to combine the two companies into an integrated global energy company. Upon approval by regulatory authorities and stockholders of both companies, and fulfillment of other conditions, Chevron will issue 0.77 of its common shares for each share of Texaco stock. The new company - ChevronTexaco Corporation - will have significantly enhanced positions in upstream and downstream operations, a global chemicals business, a growth platform in power generation, and industry-leading skills in technology innovation. Synergistic savings of at least $1.2 billion are expected within six to nine months of the merger.
In advance of the merger approval by various regulatory authorities, Chevron and Texaco work teams have been actively planning the integration of the two companies, subject to customary legal restrictions on exchange of data between competitors. In February 2001, the top 50 executives of the combined company were announced. At the same time, a proposed organization structure was outlined. The principal executive officers who will constitute a new Office of the Chairman will be Chairman and CEO David O'Reilly (currently Chairman and CEO of Chevron) and Vice Chairmen Richard Matzke (currently Vice Chairman of Chevron) and Glenn Tilton (currently Chairman and CEO of Texaco). Three corporate executive vice presidents will report to the office of the chairman and have individual responsibility for downstream (refining marketing and transportation); power, chemicals and technology; and administrative and corporate services. Upstream (exploration and production) businesses will report to Mr. Matzke.
On March 1, 2001, the European Union announced that it had approved the proposed merger. Approvals are pending from the U. S. Federal Trade Commission (FTC) and other agencies. Until consummation of the merger, Chevron and Texaco remain competitors and continue to conduct day-to-day business under the laws dealing with competitive practices for any independent company.
(b) Description of Business and Properties
The company's largest business segments are exploration and production (upstream) and refining, marketing and transportation (downstream). Chemicals is also a significant operation, conducted mainly by the company's affiliate - Chevron Phillips Chemical Company LLC. The petroleum activities of the company are widely dispersed geographically, with upstream and downstream operations in the United States and Canada and upstream operations in Nigeria, Angola, Chad, Equatorial Guinea, Republic of Congo, Democratic Republic of Congo, Australia, the United Kingdom, Norway, China, Papua New Guinea, Thailand, Argentina, Brazil and Venezuela. 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, Australia, Thailand, the Philippines, Singapore and South Africa. The company's Tengizchevroil affiliate conducts production activities in Kazakhstan. The company expects to expand its operations in the Caspian Region by exploring for crude oil and natural gas, expanding the production and transportation infrastructure, developing new crude oil and natural gas markets, and identifying other business opportunities.
The company's Dynegy Inc. (Dynegy) affiliate is one of the leading marketers of energy products and services in the United States with customers in the United States, Canada, the United Kingdom and other European countries. Its business activities include energy marketing; independent power generation; gathering, processing, selling and transportation of natural gas and natural gas liquids; and broadband trading. In February 2000, Dynegy merged with Illinova Corporation, an energy services holding company based in Illinois. The company expects that this merger will accelerate Dynegy's growth in the power generation and marketing business.
The company's Chevron Phillips Chemical Company LLC (CPCC) affiliate has operations in the United States, Belgium, China, South Korea, Singapore, Saudi Arabia and Mexico. CPCC commenced operations in July 2000 when Chevron combined most of its petrochemicals businesses with those of Phillips Petroleum Company into a 50-50 joint venture. The company's wholly owned Oronite additives business has operations in the United States, France, Netherlands, Singapore, Japan and Brazil.
Tabulations of segment sales and other operating revenues, earnings, income taxes and assets, by United States and International geographic areas, for the years 1998 to 2000, may be found in Note 10 to the consolidated financial statements beginning on page FS-21 of this Annual Report on Form 10-K. In addition, similar comparative data for the company's investments in and income from equity affiliates and property, plant and equipment are contained in Notes 13 and 14 on pages FS-24 to FS-25.
The company's worldwide operations can be affected significantly by changing economic, tax, 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. Management 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.
A discussion of the company's use of derivative financial instruments to manage its exposure to price risk stemming from its integrated petroleum activities is contained on page FS-6 of this Annual Report on Form 10-K.
Capital and Exploratory Expenditures
Worldwide capital and exploratory (C&E) expenditures totaled $5.153 billion in 2000, compared with $6.133 billion in 1999. Expenditures for consolidated worldwide exploration and production decreased by 35 percent between years. This decrease was driven by the absence in 2000 of two significant international exploration and production acquisitions in 1999, which totaled approximately $1.7 billion: the Rutherford-Moran Oil Corporation in Thailand and Petrolera Argentina San Jorge S.A. in Argentina. Consolidated international refining, marketing and transportation expenditures increased by 114 percent in 2000 driven by additional investments in the Caspian Pipeline Consortium, which continued construction of pipeline facilities linking the Tengiz Field in Kazakhstan with the Russian Black Sea port of Novorossiysk. Consolidated chemicals expenditures were 70 percent lower in 2000 following the formation of CPCC, which is accounted for under the equity method. All Other expenditures increased by over 300 percent between years as the company made an additional investment of about $300 million in Dynegy Inc.
The company's share of affiliates' capital expenditures increased by 24 percent between years to $967 million, driven by higher expenditures by the company's Tengizchevroil and Dynegy Inc. affiliates.
Chevron's C&E expenditures during 2000 and 1999 are summarized in the following table:
The company's 2001 C&E expenditures, including its share of equity affiliates' expenditures, are projected at $6 billion, 16 percent higher than 2000 spending levels. The company plans to invest $3.7 billion, or 62 percent of its total spending, in worldwide exploration and production, of which $1.2 billion will be expended in the United States. About $1.4 billion will be invested in worldwide refining, marketing and transportation activities. Investments in chemicals will be about $250 million with about $650 million targeted for all other activities, including power and natural gas facilities and distribution, and technology. The spending plans discussed above are for Chevron as a stand-alone entity and do not reflect the impact of the pending merger with Texaco. They also do
not include the acquisition of an additional 5 percent equity interest in the Tengizchevroil project in Kazakhstan, which closed in January 2001.
Petroleum - Exploration and Production
Liquids and Natural Gas Production The following table summarizes the company's and affiliates' net production of crude oil, natural gas liquids and natural gas for 2000 and 1999.
In 2000, Chevron conducted its worldwide exploration and production operations in the United States and approximately 25 other countries. Worldwide net crude oil and natural gas liquids production, including that of affiliates but excluding volumes produced under operating service agreements, increased for the eighth consecutive year by nearly 3 percent from the 1999 levels. Net liquids production in the United States fell slightly. International net liquids production, including affiliates, increased by about 4 percent in 2000 - the eleventh consecutive year of production increases. This increase was due primarily to a full year of production in Argentina and Thailand following acquisitions the company made in 1999; higher production from new fields in Angola; and
higher production in Australia. These increases were partially offset by production declines in Indonesia, Colombia and the United Kingdom.
Net production of natural gas, including affiliates, fell by 2 percent in 2000. United States production fell about 5 percent, as normal field declines more than offset new and enhanced production from the Gulf of Mexico shelf and deepwater Gulf of Mexico. International volumes increased 4 percent in 2000. Higher production from the Argentina and Thailand properties acquired in 1999 were slightly offset by lower production in Canada due to normal field declines.
Acreage At December 31, 2000, 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.
Refer to Table III on pages FS-34 to FS-36 of this Annual Report on Form 10-K for 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 2000, 1999 and 1998. The following table summarizes gross and net productive wells at year-end 2000 for the company and its affiliates.
Reserves and Contract Obligations Table IV on pages FS-36 and FS-37 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, 2000, 1999 and 1998. During 2001, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency. Those estimates are consistent with the reserve data reported on page FS-37 of this Annual Report on Form 10-K.
In 2000, Chevron's worldwide oil and equivalent-gas (BOE) barrels of net proved reserves additions exceeded production for the eighth consecutive year, with a replacement rate of 152 percent of net production, including sales and acquisitions. Excluding sales and acquisitions, the replacement rate was 132 percent of net production. The following table summarizes the company's net additions to net proved reserves of crude oil and natural gas liquids and natural gas, compared with net production during 2000.
The company sells crude oil and 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 Dynegy Inc. Outside the United States, the company is contractually committed to deliver approximately 110 billion cubic feet of natural gas through 2003 from Australian and U.K. reserves and approximately 375 billion cubic feet of natural gas post 2003 through 2020 from Australian reserves only. Substantially all of these contracts include variable-pricing terms. The company believes it can satisfy these contracts from quantities available from production of the company's proved developed Australian and U.K. natural gas reserves.
Development Activities - ---------------------- Details of the company's development expenditures and costs of proved property acquisitions for 2000, 1999 and 1998 are presented in Table I on page FS-33 of this Annual Report on Form 10-K.
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, 2000. 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.
Exploration Activities - ---------------------- 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, 2000.
"Exploratory wells" are wells drilled to find and produce oil or gas in unproved areas and 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. The company had $400 million of suspended exploratory wells included in properties, plant and equipment at year-end 2000, an increase of $26 million from 1999. Decreases in the United States were more than offset by increases in Angola, China and Canada. 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: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory drilling that is underway or firmly planned, and in some cases, (3) securing final regulatory approvals for development.
Details of the company's exploration expenditures and costs of unproved property acquisitions for 2000, 1999 and 1998 are presented in Table I on page FS-33 of this Annual Report on Form 10-K.
Review of Ongoing Exploration and Production Activities in Key Areas - -------------------------------------------------------------------- Chevron's 2000 key upstream activities not discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2 of this Annual Report on Form 10-K are presented below. In addition to the activities discussed, Chevron was active in other geographic areas, but these activities were of less significance.
A) United States
United States exploration and production activities are concentrated in about 300 fields located in the Gulf of Mexico, Texas, the Rocky Mountains, California and Alaska. Some of the company's more significant activities in the United States are described below.
Chevron has interests in three deepwater developments in the Gulf of Mexico. Genesis, Chevron's first deepwater operation, located in 2,600 feet of water, began production in January 1999. Chevron is operator and has a 57 percent interest in Genesis, which reached peak total production of 58,000 barrels of crude oil and 86 million cubic feet of gas per day in September 2000. Average total production for 2001 is estimated at 42,000 barrels of crude oil and 54 million cubic feet of gas per day. Chevron has a 40 percent interest in the Gemini deepwater development located in Mississippi Canyon Block 292 in 3,400 feet of water. Initial production occurred in June 1999. Total production from Gemini averaged 131 million cubic feet of gas per day in 2000. Typhoon is
Chevron's third deepwater development, in 2,000 feet of water, in the Gulf of Mexico. Initial production from Typhoon is scheduled for third quarter 2001. The platform will support production facilities for 40,000 barrels of oil and 60 million cubic feet of gas per day. Chevron is the operator with a 50 percent interest.
An aggressive 2000 well drilling program in the Gulf of Mexico Shelf enabled the company to develop opportunities to offset field declines in production to less than 2 percent between years. Chevron has interests in the Viosca Knoll Trend in the Gulf of Mexico shelf and in 2000 continued to focus on establishing production from additional gas reservoirs. Total production increased from 70 million cubic feet of gas per day at the beginning of the year to 240 million cubic feet of gas per day at year-end. Total production is expected to average 200 million cubic feet of gas per day in 2001. The 2001-2003 program will provide continued exploration and development of the Viosca Knoll area.
Development of the Destin Dome area of the Norphlet trend offshore Florida continues to be hampered by delays in obtaining regulatory approvals. A draft environmental impact statement (EIS) was issued August 1999 by the governing agencies indicating no significant environmental impacts had been found. In July 2000, Chevron and its partners in the Destin Dome development filed a lawsuit against the federal government to recover exploration expenses and future lost profits following continuing delays in obtaining the necessary development permits.
Onshore California, Chevron continued to expand its use of thermal enhanced recovery techniques to increase the production rate and the amount of oil ultimately recoverable from fields in the San Joaquin Valley, with efforts focused on the Cymric Field. Average 2000 production from the San Joaquin Valley fields was 104,000 barrels of oil and 112 million cubic feet of gas per day.
B) Africa
Nigeria: Chevron's principal subsidiary in Nigeria, Chevron Nigeria Limited (CNL), operates and holds a 40 percent interest in 11 concessions totaling 2.3 million acres, predominantly in the swamp and near offshore regions of the Niger Delta. During 1999, CNL's onshore and swamp area concessions were renewed for a second 30-year term. CNL's offshore concessions expire in 2008. The renewal process for the offshore concessions is provided for under the same statute as for the concessions renewed in 1999. Application for renewal must be made before one year of a concession's expiration. Based on the requirements of Nigerian law concerning concession renewal, as well as the prior industry and company experience with renewals, the company fully expects renewal of the offshore concessions to be approved. Chevron Oil Company Nigeria Limited (COCNL) holds a 20 percent interest in six concessions, covering 600,000 acres, operated by Texaco. Chevron Petroleum Nigeria Limited (CPNL) oversees and manages new venture activities in Nigeria. CPNL has a 30 percent interest in one deepwater Niger Delta block operated by Elf. CPNL interests in Benue Basin blocks were relinquished after the drilling of exploratory dry holes indicated a low probability of hydrocarbon presence. Chevron participated in Nigeria's deep- and ultra-deep water 2000 bid round. Chevron was awarded interests in three deepwater oil prospecting licenses, one as operator with a 50 percent interest and 30 percent non-operating interests in the other two. Chevron and its partners expect to develop work programs for the three newly acquired blocks during 2001.
Total 2000 production averaged 430,000 barrels of liquids per day from 33 CNL-operated fields and approximately 47,000 barrels of oil per day from the COCNL fields. Both production amounts were slightly higher than 1999.
Processing capacity at the Escravos gas plant increased to 285 million cubic feet per day with start-up of Phase 2 of the project in the fourth quarter 2000, representing another significant step toward reducing flaring of natural gas. Front-end engineering and design for Phase 3, which will expand gas-processing capacity to 680 million cubic feet per day, is expected to begin during the second quarter of 2001. Feasibility engineering and preliminary technical evaluations are nearing completion for a Gas-to-Liquids (GTL) plant proposed for construction in Escravos. The proposed 33,000 barrels-per-day Escravos project is expected to be the first project to use the technology and operational expertise of a global GTL joint venture between Chevron and Sasol Limited.
Chevron is the Managing Sponsor of a consortium of six energy companies that plans to develop a 600-mile gas transmission pipeline to connect suppliers in the Western Delta region of Nigeria to power generation and industrial customers in Benin, Ghana, and Togo. Subject to successful negotiation of concession conditions with the governments, commercial operations could commence by late 2003 or 2004.
Angola: The company is the operator of two concessions, Blocks 0 and 14, off the coast of Angola's Cabinda Province. Block 0 is a 2,100 square-mile concession adjacent to the Cabinda coastline in which Chevron has an approximate 39 percent interest. Block 14 is a 1,560-square-mile deepwater concession located west of Block 0, in which Chevron has a 31 percent interest.
Block 0 total crude oil production during 2000 averaged 448,000 barrels per day, down from an average of 460,000 in 1999, mainly due to normal field declines. Area A of Block 0 includes 23 major fields, with 15 fields currently producing. In 2000, 35 development wells were completed in Area A. The Kungulo and Vuko fields, part of the Area A Waterflood Major Project, achieved first injection from a new water injection platform in May 2000. Area B includes six major fields. The Kokongo, Lomba and the southern part of the Nemba Field have undergone the initial stages of development and are currently on production. In Area B, three additional infill wells in South Nemba resulted in 17,000 barrels of oil per day of incremental gross production. An additional infill program was initiated in Kokongo Field and will be completed during 2001. Future development plans also include installation of the North Nemba production and gas injection platform in 2001. North Nemba development drilling is expected to add over 40,000 barrels per day of gross production by 2002. Area C includes seven major fields. The N'Dola and Sanha fields are currently on production.
Six fields have been discovered in Block 14 - Kuito, Landana, Benguela, Belize, Tomboco and Lobito. The Kuito Field, Angola's first deepwater production, averaged over 61,000 barrels of oil per day in 2000. Kuito is being developed using a phased approach. Phases 1A and 1B well programs are complete and construction activities have commenced on Phase 1C, with first oil scheduled for the third quarter 2001. Tomboco and Lobito were two significant Block 14 discoveries made in 2000. These wells are located in the vicinity of three of the previously discovered fields. The appraisal drilling program for the Benguela, Belize and Tomboco Fields was completed in early 2000. Development plans call for a centralized drilling and production platform for the Benguela and Belize Fields. Tomboco will be a satellite to this facility. The impact of the nearby Lobito Field, discovered and appraised in 2000, will be included in engineering studies during 2001. Study of the Landana Field continues, with an appraisal well planned in 2001.
Republic of Congo: Chevron has interests in three partner-operated license areas - - Haute Mer, Marine VII and Mer Profonde Sud - in offshore Congo, adjacent to Chevron's concessions in Angola. Net production from Chevron's concessions in the Republic of Congo averaged about 25,000 barrels per day in 2000. In the Marine VII permit area, where Chevron has an interest of about 29 percent in the Kitina and Sounda Exploitation Permits, development of the Kitina Field continued and total production averaged about 27,000 barrels of oil per day. Further development work, including gas injection, is planned for 2001. In Haute Mer, where Chevron has a 30 percent interest, development of the Nkossa Field continued with the recompletion of several wells. Total production in the field, operated by Elf Congo, averaged about 66,000 barrels of oil and liquefied petroleum gas per day in 2000. Development planning for the Moho and Bilondo fields in the Haute Mer license continues with a development decision expected in mid-2001. Two wells were drilled in the Mer Profonde Sud exploration license in 2000, resulting in one non-commercial oil discovery and one dry hole. Continued participation in the permit, where Chevron has a 15 percent equity interest, is currently being re-evaluated with a decision planned for early 2001.
Chad/Cameroon: Chevron is a 25 percent partner in a consortium comprised of affiliates of ExxonMobil and Petronas in a project to develop the Doba oil fields in southern Chad and construct a pipeline to the coast of Cameroon for export of oil to world markets. This project is expected to cost approximately $3.5 billion and have a 20- to 30-year life. First production is expected in 2004.
Equatorial Guinea: In May, 2000 Chevron entered into a Production Sharing Contract with the Republic of Equatorial Guinea for Block L, located off the coast of the island of Bioko. The work program has an initial period of five years with two one-year extensions. A 3D seismic survey was initiated in December 2000.
C) Other International Areas
Caspian Region: The Tengizchevroil (TCO) partnership, formed in 1993, includes the Tengiz and Korolev oil fields located in western Kazakhstan. Chevron had a 45 percent interest in TCO in 2000. In January 2001, Chevron increased its ownership interest in TCO to 50 percent. In 2000, total crude oil production from the Tengiz Field increased for the seventh straight year, averaging 229,000 barrels of oil per day. TCO completed a three-year
plant expansion project in 2000 to increase TCO's processing and export capacity. The project will permit crude oil production to increase to approximately 260,000 barrels per day - the average gross production rate expected for 2001. TCO plans to bring the Korolev field on line in 2001 by extending its existing gathering system.
The Caspian Pipeline Consortium (CPC) was formed to build a crude oil export pipeline from the Tengiz Field to the Black Sea port of Novorossiysk at a projected total cost of $2.6 billion. When completed, the CPC pipeline will allow for the export of an initial capacity of 600,000 barrels of oil per day, expandable to 1.5 million barrels per day with additional pump stations, tankage and marine loading facilities. Chevron has a 15 percent ownership interest in CPC, which remains on schedule for a mid-2001 start-up.
Europe: Chevron holds interests in four producing fields offshore the United Kingdom and Norway: the Alba oil field, the Britannia gas condensate field, and non-operated interests in Statfjord and Draugen. Total production from the Alba Field averaged 80,000 barrels of crude oil per day in 2000. Chevron's interest in Alba is approximately 21 percent. Total production from the Britannia Field averaged 692 million cubic feet of gas per day and approximately 40,000 barrels per day of condensate during 2000. Chevron has an approximate 30 percent interest in Britannia and shares operatorship with Conoco. In Norway, the Draugen Field, in which Chevron has a 7.56 percent interest, produced an average of 203,000 barrels of oil per day in 2000. Statfjord, where Chevron has a 4.84 percent interest, produced an average of 180,000 barrels per day in 2000. In the 16th Licensing Round in April, Chevron was awarded three new high-potential licenses in the Norwegian Sea - one as operator.
Canada: Total production from the Hibernia Field offshore Newfoundland, in which Chevron holds an interest of about 27 percent, averaged approximately 144,000 barrels of crude oil per day in 2000, up from 100,000 barrels of crude oil per day in 1999. Also offshore Newfoundland, the company operates and holds a 28 percent interest in the Hebron Field, where a delineation well completed in 2000 confirmed previous hydrocarbon reservoirs and tested a new reservoir. At Fort Liard in the Northwest Territories, the K-29 discovery well came into production in April 2000. A second well came into production in early November. Combined December total production from the two wells averaged 108 million cubic feet per day of natural gas and byproducts. Chevron holds a 43 percent working interest in the Fort Liard pool. In the Mackenzie Delta region of northern Canada, Chevron formed two new joint venture partnerships to conduct exploration over a large area totaling more than one million gross acres. One partnership is with BP Canada Energy and covers two exploration concessions. The second partnership is with BP and Burlington Resources Canada Energy Ltd., and covers three exploration leases. Also in 2000, construction began on mining, extraction and upgrading facilities for the $2.4 billion Athabasca Oil Sands Project. The project is expected to begin production in late 2002 and reach 155,000 barrels of bitumen per day at peak production. The tar-like bitumen will be upgraded into high quality synthetic oil using hydroprocessing technology. Chevron has a 20 percent working interest in the project.
Australia: Chevron's primary interests in Australia involve a number of joint ventures. The largest is the North West Shelf (NWS) Project offshore Western Australia, where Chevron has an approximate 17 percent interest. Average total field production during 2000 from the North Rankin and Goodwyn fields in the NWS project was 1.5 billion cubic feet of gas per day and 99,000 barrels per day of condensate. Total oil production from the Wanaea/ Cossack, Lambert and Hermes fields averaged 116,000 barrels per day in 2000. Liquefied petroleum gas (LPG) production driven by the liquids-rich gas averaged 23,400 barrels per day in these fields. During 2000 a number of Japanese customers agreed to terms on Letters of Intent with the NWS partners, underpinning the proposed fourth liquefied natural gas (LNG) train, which would increase LNG production by about 50 percent. Chevron's other major area of activity is in permit areas that include the Barrow Island and Thevenard Island oil fields and the undeveloped Gorgon area gas fields, southwest of the NWS fields. Chevron operates a number of joint ventures with production facilities on Barrow Island and Thevenard Island, with interests varying from 25 percent to 50 percent. Chevron assumed operatorship of these areas from West Australian Petroleum Pty. Ltd. in late 1999. Total oil production from the Barrow Island and Thevenard Island oil fields in 2000, averaged 25,000 barrels per day, with Chevron's share of production being 6,600 barrels per day. In addition to the two major joint ventures above, Chevron has interests in the northern Browse Basin, and three new deepwater exploration permits in the offshore Canning Basin, near the NWS joint venture acreage. Chevron's interests vary from about 17 percent to 25 percent. During 2000, Chevron continued to pursue the Australia Gas Pipeline Project from Papua New Guinea to Queensland, Australia. This project will allow commercialization of Papua New Guinea natural gas reserves and recovery of substantial quantities of natural gas liquids (NGL).
Indonesia: Chevron's interests in Indonesia are managed by two affiliate companies, PT Caltex Pacific Indonesia (CPI) and Amoseas Indonesia (AI). Chevron owns 50 percent of both companies. CPI manages all of Chevron's interests in four production sharing contracts in Indonesia. Chevron's net share of total production of 705,000 barrels per day in 2000 was 158,000 barrels per day. CPI continues to implement enhanced oil recovery projects to extract more oil from its existing reservoirs. The Duri Field, under steamflood since 1985, is the largest steamflood in the world. Currently 9 of 13 phases are under steam injection, with the tenth phase scheduled for injection in late 2001. AI is a power generation company that operates the Darajat geothermal contract area in central Java and is constructing a cogeneration facility to support CPI's Duri steamflood. AI's geothermal field continued to provide steam to the national power company plant and a company-owned plant that produces electricity for the Java power grid. Further expansion of the Darajat geothermal reservoir complex is planned. The Darajat reservoir has proved reserves of steam to generate 350 megawatts for 30 years.
Thailand: Chevron operates Block B8/32 in the Gulf of Thailand. Chevron has an approximate 52 percent interest in the 734,000-acre block. Chevron also holds a 33 percent interest in adjacent exploration blocks 7, 8 and 9, which are currently inactive pending resolution of Thailand-Cambodia border issues. Block B8/32 is currently producing oil and natural gas from two fields, Tantawan and Benchamas. In December 2000, the Tantawan Field was producing at a rate of 38 million cubic feet of gas per day and 5,400 barrels of oil per day. The Benchamas Field was producing at an average rate of 110 million cubic feet of gas per day and 28,600 barrels of oil per day. In Block B8/32 development of the Maliwan Field is under-way, with the Maliwan A platform installation and initial production through the Benchamas facilities expected by November 2001. The Government of Thailand awarded a Production License Area (PLA) for North Jarmjuree in November 2000. Further delineation of the North Jarmjuree PLA is planned in 2001.
Argentina: Chevron holds over 4.2 million acres of exploration and production acreage in the Neuquen and Austral Basins of Argentina with working interest shares ranging from about 18 to 100 percent in operated license areas. In addition, Chevron holds a 14 percent interest in a major oil export pipeline from the Neuquen producing area to the Atlantic coast. At year-end 2000, properties in the Neuquen and Austral Basins were producing at total combined rates of 91,000 barrels of oil-equivalent per day. During 2000, Chevron strengthened its Neuquen Basin leasehold position by purchasing two exploration permits and two production concessions from Alberta Energy Company. Chevron's exploration and appraisal program in 2000 resulted in three oil and two gas discoveries that added over 50 million barrels to Chevron's proved and probable oil-equivalent reserves. Exploration plans include 15 wells and the acquisition of more than 250,000 acres of seismic data in 2001.
Brazil: As part of a strategy to expand its deepwater prospects and other interests in South America, the company acquired in 2000 a 65 percent interest in, and was designated operator of, exploration block BM-S-7.. A 25 percent non-operated interest was also acquired in exploration block BM-S-10. Both blocks are located in the Santos area of the Salt Basin. These two blocks bring Chevron's total exploration acreage in the Salt Basin to 4.1 million acres. Seismic programs for blocks BCUM-100 and BC-20 commenced in 2000 and three exploratory wells are planned for 2001. Chevron's interest in both these Petrobras-operated blocks is 50 percent. Current plans for BM-S-7and BM-S-10 are to acquire and evaluate geologic and seismic data in 2001 and 2002, with drilling commencing in 2003.
Venezuela: Chevron and Petroleos de Venezuela, S.A. (PDVSA) formed an alliance in 1995 to further develop the Boscan oil field and provide heavy crude oil to Chevron in the United States through several independent supply agreements. Chevron took over operations of the Boscan Field in 1996 under an Operating Services Agreement and receives operating expense reimbursement and capital recovery, plus interest and an incentive fee. Development drilling continued in the Boscan Field, with 41 wells completed during 2000. Average production from Boscan was at the 115,000 barrels-of-oil-per-day limit specified in the Operating Services Agreement for the second half of 2000. Chevron also is the operator and has a 27 percent interest in the LL-652 Field in Lake Maracaibo. The LL-652 Field objective is to increase production over the next few years through the application of secondary recovery technologies. LL-652 oil production during 2000 averaged 16,500 barrels per day, up from an average of 9,700 in 1999.
Petroleum - Natural Gas Liquids
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 Dynegy Inc. affiliate, in which the company had an approximate 26 percent interest at year-end 2000. Dynegy and Chevron have entered into long-term strategic alliances whereby Dynegy purchases substantially all natural gas and natural gas liquids produced by Chevron in the United States, excluding Alaska, and supplies natural gas and natural gas liquids feedstocks to Chevron's U.S. refineries and chemical plants. Outside the United States, natural gas liquids sales take place in the company's Canadian upstream operations, with lower sales levels in Africa, Australia and Europe. In 2000, U.S. sales volumes, including Chevron's share of Dynegy sales, comprised about 70 percent of the company's total worldwide natural gas liquids sales volume.
Chevron's total third-party natural gas liquids sales volumes over the last three years were as follows:
Petroleum - Refining
Based on refinery statistics published in the December 18, 2000 issue of The Oil and Gas Journal, Chevron had the fourth largest U.S. refining capacity. The company's 50 percent-owned Caltex Corporation affiliate owned or had interests in 10 operating refineries: Australia (2), Thailand, Korea, the Philippines, New Zealand, Singapore, Pakistan, Kenya and South Africa. In 2000, Caltex relinquished its 4.75 percent interest in a second refinery in Thailand. In 1999, Caltex sold its interest in two Japanese refineries owned by Koa Oil Company Limited.
Distillation operating capacity utilization in 2000, adjusted for sales and closures, averaged 90 percent in the United States (including asphalt plants) and 89 percent worldwide (including affiliate), compared with 91 percent in the United States and worldwide in the prior year. Chevron's capacity utilization at its U.S. fuels refineries averaged 94 percent in 2000, down slightly from 96 percent in 1999. 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 2000, up from 78 percent in the year earlier. The company processed imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for 70 percent of Chevron's U.S. refinery inputs in 2000.
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 - Refined Products Marketing
Product Sales: The company and its Caltex Corporation affiliate market petroleum products throughout much of the world. The principal trademarks for identifying these products are "Chevron" and "Caltex." The company's Fuel and Marine Marketing LLC (FAMM) affiliate, which was established in late 1998, markets marine fuel and lubricating oils in approximately 100 countries worldwide. Chevron has a 31 percent equity interest in FAMM.
The following table shows the company's and its affiliates' refined product sales volumes, excluding intercompany sales, over the past three years. The company's Canadian sales volumes consist of refined product sales, primarily in British Columbia, by the company's Chevron Canada Limited subsidiary. The 2000 and 1999 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 affiliates' sales consists of (1) the company's interest in Caltex, which maintains an interest in about 7,800 service stations (of which about 4,700 are controlled by Caltex), operating in more than 60 countries in the Asia-Pacific region, Africa and the Middle East, and (2) the company's interest in FAMM.
Retail Outlets: In the United States, the company supplies, directly or through dealer and jobbers, more than 8,000 motor vehicle retail outlets, of which about 1,400 are company-owned or -leased stations, and about 600 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 jet fuel and aviation gasoline in the western United States.
The company has continued to take advantage of growing demand for convenience goods and services. In 2000, non-fuel sales in company-operated stores increased 16 percent, compared with 1999.
In Canada - primarily British Columbia - the company's branded products are sold in approximately 170 stations (mainly owned or leased).
Petroleum - Transportation
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:
Tankers: Chevron's controlled seagoing fleet at December 31, 2000, is summarized in the following table. All controlled tankers were utilized in 2000. In addition, at any given time, the company has 30 to 40 vessels under charter on a term or voyage basis.
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 2000, the company's U.S. flag fleet was engaged primarily in transporting crude oil from Alaska 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.
The Federal Oil Pollution Act of 1990 requires the scheduled phase-out, by year-end 2010, of all single hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone. This has resulted in the utilization of more costly double-hull tankers. By the end of 2000, Chevron was operating a total of 16 double hull tankers. Chevron expects to take delivery of two additional double-hull tankers in 2003, also to be operated
under long-term bareboat charters. The company is a member of many oil-spill response cooperatives in areas in which it operates around the world.
At year-end 2000, two of the company's controlled international flag vessels continued to be used as floating storage vessels in its upstream operations offshore Cabinda Province, Angola. 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, and Asia. Refined products also were transported by tanker worldwide.
Chemicals
In July 2000, Chevron combined most of its petrochemicals businesses with those of Phillips Petroleum Co. to form Chevron Phillips Chemical Company (CPCC), headquartered in Houston, Texas. Each company owns 50 percent of the joint venture. CPCC owns or has joint venture interests in 34 manufacturing facilities in the United States, Belgium, China, Saudi Arabia, Singapore, South Korea and Mexico.
In November 2000, CPCC began operation of a 100,000 tons-per-year polystyrene plant in China. Also in 2000, CPCC and its joint-venture partner, the Saudi Industrial Venture Capital Group, achieved design capacity production at a petrochemical complex in Saudi Arabia with production of 480,000 tons of benzene and 220,000 of cyclohexane.
An olefins plant is under construction in Qatar and is expected to commence production in mid-2002 with an annual capacity of 1.1 billion pounds of ethylene and 1 billion pounds of polyethylene. CPCC has a 49 percent interest in this facility with the Qatar General Petroleum Corp owning the remaining 51 percent.
Following the merger with Phillips Petroleum Co., Chevron retained its "Oronite" fuel and lubricant additives business. Chevron Oronite owns five manufacturing facilities in the United States, France, Singapore, Japan and Brazil and has equity interests in facilities in India and Mexico.
The following table shows 2000 Chemicals revenues and net income and details on manufacturing facilities as of December 31, 2000.
Coal
The Company's wholly owned coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated four surface mines and one underground mine at year-end 2000. The Sebree Mine in Kentucky, which was idled in November 1998, was sold in 2000. P&M also owns an approximate 30 percent interest in Inter-American Coal Holding N.V., which has interests in mining operations in Venezuela.
Sales and other operating revenues in 2000 were $297 million from sales of 14.0 million tons of coal. The average selling price for coal from mines owned and operated by P&M was $21.22 per ton in 2000, compared with $22.73 per ton in 1999. Earnings in 2000 were affected negatively by a union work stoppage for several months during the year and operating and geologic complications at certain mines. At year-end 2000, P&M controlled approximately
218 million tons of developed and undeveloped coal reserves, including significant reserves of environmentally desirable low-sulfur fuel.
Electronic Commerce and Technology
In 1999, Chevron implemented a new growth initiative aimed at developing business opportunities capitalizing on Internet Web technology. The company established a subsidiary to leverage "e-business" opportunities in Chevron's business units. Additionally, the new subsidiary is involved in the development of new Internet "business to business" (B2B) ideas for use in the company's own operations and for potential development with other outside investors.
Chevron also established a technology ventures unit during 1999. The company makes equity investments in a broad portfolio of emerging technology companies with expertise in information technology, materials sciences and biotechnology. These investments are directed toward areas where the company could potentially be a customer.
Because some of these investments in e-business and new ventures may be in new or unproven technologies and business processes, ultimate success is not always certain. Although not all initiatives may prove to be economically viable, the company's overall investment in this area is not significant to the company's consolidated financial position.
Research and Environmental Protection
Research: The company's principal research laboratories are in Richmond and San Ramon, California and Houston, Texas. 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 San Ramon and Houston facilities conduct research and provide technical support in geology, geophysics, and 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 2000 numbered about 1,000. Chevron's research and development expenses were $171 million, $182 million and $187 million for the years 2000, 1999 and 1998, respectively.
Licenses under the company's patents are generally made available to others in the petroleum and chemicals industries, but the company does not derive significant income from licensing patents.
Environmental Protection: 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 change and increase in both number and complexity, and govern not only the manner in which the company conducts its operations, but also the products it sells. Chevron expects more environmental-related regulations in the countries where it has operations. Most of the costs of complying with the myriad laws and regulations pertaining to its operations are embedded in the normal costs of conducting its business.
In 2000, the company's U.S. capitalized environmental expenditures were $171 million, representing approximately 7 percent of the company's total consolidated U.S. capital and exploratory expenditures. The company's U.S. capitalized environmental expenditures were $121 million and $192 million in 1999 and 1998, 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 2001, the company estimates U.S. capital expenditures for environmental control facilities will be $179 million. The future annual capital costs of fulfilling this commitment are uncertain and will be governed by several factors, including future changes to regulatory requirements.
Further information on environmental matters and their impact on Chevron are contained in Management's Discussion and Analysis of Financial Condition and Results of Operation on page FS-4 of this Annual Report on Form 10-K. The company's 2000 environmental expenditures, remediation provisions and year-end environmental reserves are discussed on page FS-4 of this Annual Report on Form 10-K.
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. 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-33 to FS-38 of this Annual Report on Form 10-K. Note 14, "Properties, Plant and Equipment," to the company's financial statements is on page FS-25 of this Annual Report on Form 10-K. It presents information on the company's gross and net properties, plant and equipment, and related additions and depreciation expense, by geographic area and operating segment for 2000, 1999 and 1998.
Item 3.
Item 3. Legal Proceedings
A. El Segundo Refinery - Oil Spill Penalty The Los Angeles Regional Water Quality Control Board has proposed an administrative civil penalty for a jet fuel spill to groundwater resulting from a leak in an underground pipeline at the Company's El Segundo Refinery. The Company has remediated the spill and taken preventive steps to reduce the risk of future spills.
B. El Paso Refinery - Clean Air Act The Texas Natural Resources Conservation Commission and Chevron Products Company have agreed to enter into an Agreed Order with respect to alleged air violations at Chevron's El Paso Refinery. The alleged violations that are the subject of the Agreed Order have been corrected and the Company has agreed to pay an administrative civil penalty of $102,500.
C. Rangely Field - Clean Water Act Chevron Production Company, as operator of the Rangely Unit, and its working interest partners, have agreed to pay a $750,000 civil penalty associated with alleged clean water act violations associated with produced water and crude oil spills at the Rangely Production facility in northwestern Colorado. In addition, the Company and its partners have committed to spend approximately $3 million in facility upgrades to reduce the risk of spills from the injection line leaks. Chevron's share of these expenditures will be 60 percent. Chevron and its partners, the U.S. EPA and the Department of Justice have agreed to resolve the matter through a consent decree, which will govern issues associated with the injection line installation and leaks over the next five years.
D. Richmond Refinery - VOC Emissions The Company has entered into a Settlement Agreement with the Bay Area Air Quality Management District with respect to alleged violations of the air district's fugitive VOC emission rules at the Company's Richmond Refinery. The alleged violations involve emissions from connectors within the refinery. The Company has agreed under the Settlement Agreement to pay a penalty of $242,500 and has agreed to surrender two tons per year of emission reduction credits for volatile organic compounds.
E. Salt Lake Marketing Terminal - Air Emission Controls The Utah Division of Air Quality has proposed a civil penalty in conjunction with the loading of gasoline into tanker trucks without certain air emission controls. The Company is negotiating with the Division to resolve all issues relating to the alleged violations.
Other previously reported legal proceedings have been settled, not pursued, or the issues resolved 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 2000 to a vote of security holders through the solicitation of proxies or otherwise.
Executive Officers of the Registrant at March 1, 2001
Name and Age Executive Office Held Major Area of Responsibility - ------------------- ------------------------------ --------------------
D. J. O'Reilly 54 Chairman of the Board since 2000 Chief Executive Officer Director since 1998 Executive Committee Member since 1994
R. H. Matzke 64 Vice-Chairman of the Board Worldwide Exploration and since 2000 and Production Activities Director since 1997 President of Chevron Overseas Petroleum Inc. from 1989 to 2000 Executive Committee Member since 1993
D. W. Callahan 58 Executive Vice-President Chemicals, Coal, since 2000 Human Resources, Vice-President since 1999 Technology President of Chevron Chemical Company from 1999 to 2000 Executive Committee Member since 1999
H. D. Hinman 60 Vice-President and Law General Counsel since 1993 Executive Committee Member since 1993
G.L. Kirkland 50 President of Chevron U.S.A. North American Production Company since 2000 Exploration and Executive Committee Member Production since 2000
M. R. Klitten 56 Executive Vice-President Worldwide Refining, since 2000 Marketing and Vice-President since 1989 and Transportation Executive Committee Member Activities, since 1989 Global Procurement, Real Estate, Aircraft Services
P.J. Robertson 54 Vice-President since 1994 Overseas Exploration and President of Chevron Overseas Production Petroleum Inc. since 2000 Executive Committee Member since 1997
J.S. Watson 44 Vice-President and Chief Finance Financial Officer since 2000 Vice-President since 1998 Executive Committee Member since 2000
P.A. Woertz 47 Vice-President since 1998 U.S. Refining, Marketing, President of Chevron Products Logistics and Trading Company since 1998 Executive Committee Member since 1998
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.
D.W. Callahan - Senior Vice President, Chevron Chemical Company - 1991 - President, Chevron Chemical Company - 1999
G.L. Kirkland - General Manager, Asset Management, Chevron Nigeria Limited - 1996 - Chairman and Managing Director, Chevron Nigeria Limited - 1996 - President, Chevron USA Production Company - 2000
P.J. Robertson - 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
J.S. Watson - President, Chevron Canada Limited - 1996 - Vice-President, Strategic Planning, Chevron Corporation - 1998 - Vice-President and Chief Financial Officer, Chevron Corporation - 2000
P.A. Woertz - President, Chevron International Oil Company - 1996 - Vice President, Logistics and Trading, Chevron Products Company - 1996 - President, Chevron Products Company - 1998
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-11 of this Annual Report on Form 10-K.
Item 6.
Item 6. Selected Financial Data
The selected financial data for years 1996 through 2000 are presented on page FS-39 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 on pages 4 through 9 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 2001, is incorporated herein by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 21 and 22 of this Annual Report on Form 10-K for information about executive officers of the company.
Item 405 of Regulation S-K calls for disclosure of any known late filing or failure by an insider to file a report required by Section 16 of the Exchange Act. This disclosure is contained on page 12 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 2001 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance," and is incorporated herein by reference in this Annual Report on Form 10-K. Chevron believes all filing requirements were complied with during 2000.
Item 11.
Item 11. Executive Compensation
The information on pages 13 through 22 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 2001, is incorporated herein by reference in this Annual Report on Form 10-K.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information on page 12 of the Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 2001 appearing under the heading "Directors' and Executive Officers' Stock Ownership," 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-12
Consolidated Statement of Income for the three years ended December 31, 2000 FS-12
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2000 FS-12
Consolidated Balance Sheet at December 31, 2000 and 1999 FS-13
Consolidated Statement of Cash Flows for the three years ended December 31, 2000 FS-14
Consolidated Statement of Stockholders' Equity for the three years ended December 31, 2000 FS-15
Notes to Consolidated Financial Statements FS-16 to FS-32
(2) Financial Statement Schedules:
We have included on page 25 of this Annual report on Form 10-K, Financial Statement Schedule II - Valuation and Qualifying Accounts.
The Combined Financial Statements of the Caltex Group of Companies are filed as part of this report.
Caltex Group of Companies Combined Financial Statements C-1 to C-20
All schedules for the Caltex Group 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 27 and 28 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 was filed by the company on December 21, 2000. In this report, Chevron announced a change in the certifying accountant for the Chevron Profit Sharing/Savings Plan.
(2) A Current Report on Form 8-K was filed by the company on March 15, 2001. In this report, Chevron filed the company's 2000 audited financial statements, Management's Discussion and Analysis of Financial Condition and Results of Operations for 2000 and Supplementary Data.
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 28th day of March 2000.
Chevron Corporation
By DAVID J. O'REILLY* ----------------------------------------- David J. O'Reilly, 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 28th day of March 2001.
Principal Executive Officers (And Directors) Directors
DAVID J. O'REILLY* SAMUEL H. ARMACOST* - ---------------------------------------------- ------------------------------- David J. O'Reilly, Chairman of the Board Samuel H. Armacost
RICHARD H. MATZKE* SAM GINN * - ---------------------------------------------- ------------------------------- Richard H. Matzke, Vice-Chairman of the Board Sam Ginn
CARLA A. HILLS * ------------------------------- Carla A. Hills
J. BENNETT JOHNSTON* ------------------------------- J. Bennett Johnston
CHARLES M. PIGOTT* ------------------------------- Principal Financial Officer Charles M. Pigott
JOHN S. WATSON* FRANK A. SHRONTZ* - ---------------------------------------------- ------------------------------- John S. Watson, Vice-President, Finance Frank A. Shrontz and Chief Financial Officer CARL WARE* ------------------------------- Principal Accounting Officer Carl Ware
STEPHEN J. CROWE* JOHN A. YOUNG* - ---------------------------------------------- ------------------------------- Stephen J. Crowe, Vice-President John A. Young and Comptroller
*By: /s/ LYDIA I. BEEBE --------------------------------------------------- Lydia I. Beebe, Attorney-in-Fact
EXHIBIT INDEX Exhibit No. Description - -------- ---------------------------------------------------------------------- 3.1 Restated Certificate of Incorporation of Chevron Corporation, dated November 23, 1998, filed as Exhibit 3.1 to Chevron Corporation's Annual Report on Form 10-K for 1998 dated March 31, 1999, and incorporated by reference herein.
3.2 By-Laws of Chevron Corporation, as amended November 23, 1998, filed as Exhibit 3.2 to Chevron Corporation's Annual Report on Form 10-K for 1998 dated March 31, 1999, and incorporated by reference herein.
4.1 Rights Agreement dated as of November 23, 1998, between Chevron Corporation and ChaseMellon Shareholder Services L.L.C., as Rights Agent, filed as Exhibit 4.1 to Chevron Corporation's Current Report on Form 8-K dated November 23, 1998, and incorporated herein by reference.
4.2 Amendment No. 1 to Rights Agreement dated as of October 15, 2000, between Chevron Corporation and ChaseMellon Shareholder Services L.L.C., as Rights Agent, filed as Exhibit 4.2 to Chevron Corporation's Registration Statement on Form 8-A dated December 7, 2000, 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 Chevron Corporation Deferred Compensation Plan for Directors, as amended and restated effective January 1, 2001.
10.2 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.
10.3 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.
10.4 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.
10.7 Agreement and Plan of Merger dated as of October 15, 2000, among Texaco Inc., Chevron Corporation and Keepep Inc., filed as Exhibit 2.1 to a Current Report on Form 8-K filed by the company on October 16, 2000 and an amended Current Report on Form 8-K filed by the company on October 16, 2000.
10.8 Stock Option Agreement dated as of October 15, 2000 between Chevron Corporation and Texaco Inc., filed as Exhibit 2.2 to a Current Report on Form 8-K filed by the company on October 16, 2000 and an amended Current Report on Form 8-K filed by the company on October 16, 2000.
10.9 Stock Option Agreement dated as of October 15, 2000 between Chevron Corporation and Texaco Inc., filed as Exhibit 2.3 to a Current Report on Form 8-K filed by the company on October 16, 2000 and an amended Current Report on Form 8-K filed by the company on October 16, 2000.
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 PricewaterhouseCoopers LLP (page E-3).
23.2 Consent of KPMG (page E-4).
24.1 Powers of Attorney for directors and certain officers of to Chevron Corporation, authorizing the signing of the Annual Report on 24.12 Form 10-K on their behalf.
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-10
Quarterly Results and Stock Market Data FS-11
Report of Management FS-11
Report of Independent Accountants FS-12
Consolidated Statement of Income FS-12
Consolidated Statement of Comprehensive Income FS-12
Consolidated Balance Sheet FS-13
Consolidated Statement of Cash Flows FS-14
Consolidated Statement of Stockholders' Equity FS-15
Notes to Consolidated Financial Statements FS-16 to FS-32
Supplemental Information on Oil and Gas Producing Activities FS-33 to FS-38
Five-Year Financial Summary FS-39
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ----------------------------------------------------------- AND RESULTS OF OPERATIONS -------------------------
2000 KEY INDICATORS - -------------------
o Net income was $5.185 billion, the most profitable year in the company's history o Exploration and production operational earnings more than doubled to $4.5 billion o Average U.S. crude oil realization increased 69 percent to $27.20 per barrel o Average U.S. natural gas realization was up 87 percent to $4.04 per thousand cubic feet o International net liquids production increased for the 11th consecutive year - up over 4 percent o Worldwide net oil and gas reserve additions exceeded production for the eighth consecutive year o U.S. refining, marketing and transportation operational earnings doubled on higher margins and improved plant reliability o Annual dividends increased for the 13th consecutive year
Chevron's record net income of $5.185 billion in 2000 was up significantly over 1999 net income of $2.070 billion and 1998 net income of $1.339 billion. Special charges in 2000 included asset write-downs, environmental remediation reserve additions, prior-years' tax adjustments and litigation costs. Partially offsetting these charges were gains from the equity accounting effect of the issuance of additional common stock by the company's Dynegy equity affiliate, asset sales, insurance recoveries for property damage, actuarial calculations for the company's benefit plans and LIFO inventory adjustments. Net special charges in 1999 included losses from asset write-downs, environmental remediation provisions and restructuring charges, which were partially offset by benefits from the sale of assets, LIFO inventory gains, and net favorable adjustments for prior-years' taxes and litigation issues. In 1998, the net special charges included a loss provision of $637 million for litigation, substantially all of which pertained to a lawsuit against Gulf Oil Corporation by Cities Service filed in 1982 - prior to the Chevron-Gulf merger in 1984. Included in net income were foreign currency gains of $142 million in 2000, and losses of $38 million in 1999 and $47 million in 1998. Net income for the company's individual business segments is discussed in the Results of Operations section.
ENVIRONMENT AND OUTLOOK - ------------------------ Record earnings for Chevron in 2000 were largely the result of a substantial improvement in crude oil and natural gas prices, along with higher worldwide oil-equivalent production. Crude oil prices continued an upswing from 20-year lows that were experienced in late 1998. Natural gas prices - more sensitive to regional supply-demand balances - rose to historic highs in the U.S. spot market in late 2000. Capitalizing on these higher-price conditions, the company increased its worldwide oil-equivalent production by 5 percent - including the effect of volumes produced internationally under operating service agreements, and adjusting for the effects of higher prices on Chevron's share of net production under production-sharing contracts and variable royalty arrangements. The average spot price in 2000 for West Texas Intermediate (WTI), a benchmark crude oil, was $30.34 per barrel, up nearly 60 percent from $19.30 per barrel in 1999 and more than double the 1998 average price. The average U.S. Henry Hub spot natural gas price of $4.23 per thousand cubic feet increased 86 percent, compared with the 1999 average of $2.27, and was more than twice the 1998 level. The sharp rise in crude oil prices was primarily the result of the 1999 agreement among certain OPEC and non-OPEC oil producing countries to restrict production, as well as increased demand and lower petroleum inventories worldwide. Higher U.S. natural gas prices reflected a strengthened economy and sharply increased demand for natural gas from power generators, at the same time North American natural gas producers struggled to increase supply and maintain inventory levels. Although down from their highs in 2000, crude oil and natural gas prices remained strong in early 2001. In mid- February 2001, the price of WTI was about $30 per barrel. The Henry Hub spot natural gas price that peaked at $10.50 per thousand cubic feet in late December 2000 fell below $6.00 per thousand cubic feet by mid-February. It is uncertain how long these price levels will continue. Some factors
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that may affect future price changes include fluctuations in crude oil production by producing countries, unforeseen supply disruptions, increases or decreases in worldwide inventory levels, changes in demand for heating oil and natural gas as a result of winter weather conditions, electricity generating requirements, and the demand for refined products reflecting the overall strength of the world economies. High crude oil and natural gas prices enhance the company's revenues and earnings in exploration and production operations. However, these same conditions could adversely affect financial results in the refining and marketing and the chemicals businesses if the higher feedstock costs cannot be recovered through sufficient product price increases. Chevron's U.S. downstream margins and earnings improved substantially in 2000, despite higher crude oil feedstock costs and fuel expense for the company's refineries. Earnings in the future will depend on refined products margins in Chevron's primary U.S. operating areas- the West Coast, the South and the South-west- and on safe, reliable refining operations. Internationally, Caltex operations in the Asia-Pacific region continued to suffer from weak refined products margins, resulting from surplus refining capacity, higher feedstock costs and a highly competitive environment. Caltex may continue to be adversely affected by these conditions throughout 2001. The outlook for the company's chemicals businesses remains uncertain because of fluctuating feedstock costs, depressed demand and excess capacity conditions for commodity chemicals. While results early in 2000 benefited from price increases for certain products, the industry experienced a weakening of margins in the second half of the year. The company expects these conditions to continue in 2001. For the company as a whole in 2000, strong operating cash flows and a continued focus on cost control- mitigating the effect of higher operating expenses from increased fuel and utility costs- helped enable a 16 percent increase in the 2001 capital budget to $6 billion. Profitable growth from such a robust capital spending program is linked, among other things, to the company's continued success in operating safely and achieving excellence in stewardship over the company's global portfolio of world-class capital investment opportunities.
CHEVRON-TEXACO MERGER AGREEMENT - -------------------------------- Chevron and Texaco announced in October 2000 an agreement to combine the two companies into an integrated global energy company. Upon approval by regulatory authorities and stockholders of both companies, and fulfillment of other conditions, Chevron will issue 0.77 of its common shares for each share of Texaco common stock. The new company- ChevronTexaco Corporation- will have significantly enhanced positions in upstream and downstream operations, a global chemicals business, a growth platform in power generation, and industry-leading skills in technology innovation. Synergistic annual savings of at least $1.2 billion are expected within six to nine months of the merger. Chevron and Texaco anticipate that the U.S. Federal Trade Commission (FTC) will require asset dispositions as a condition of not challenging the merger. While the scope and method of such dispositions were unknown in late February, the companies anticipated that divestiture of certain U.S. refining, marketing and transportation businesses would be required to address market concentration issues. Merger-related fees and expenses, consisting primarily of U.S. Securities and Exchange Commission (SEC) filing fees; fees and expenses of investment bankers, attorneys and accountants; and financial printing and other related charges are estimated at $125 million for both companies. Substantially all of these costs will be incurred in 2001. Though not yet fully quantified, significant costs also will be incurred after the merger for integration-related expenses, including the elimination of duplicate facilities, operational realignment and severance payments for work-force reductions. The merger agreement provides for the payment of termination fees of as much as $1 billion by either party under certain circumstances. Chevron and Texaco also were granted options to purchase shares of the other, under the same conditions as the payments of the termination fees. Texaco granted Chevron an option to purchase 107 million shares of Texaco's common stock, at $53.71 per share. Chevron granted Texaco an option to purchase 127 million shares of Chevron's common stock, at $85.96 per share.
OTHER SIGNIFICANT DEVELOPMENTS - ------------------------------- Key operating highlights and events during 2000 and early 2001 to capture profitable growth opportunities included: Tengiz - Tengizchevroil's (TCO) total gross crude oil production averaged over 280,000 barrels per day in the fourth quarter 2000 - a record and exceeding the target of 260,000 barrels per day - as a result of processing plant expansion and the absence of turnaround work. For 2001, average gross production is expected to be about 260,000 barrels per day, considering the effect of planned shutdowns for maintenance and other operational activities. In January 2001, Chevron closed on its purchase of an additional 5 percent share in TCO, bringing the company's ownership interest to 50 percent. As a result of the purchase, Chevron will record an additional 177 million barrels of oil-equivalent reserves in 2001. Caspian Pipeline - Construction of a pipeline by the Caspian Pipeline Consortium (CPC), in which Chevron owns a 15 percent interest, remains on schedule for a mid-2001 start-up. The 900-mile pipeline will connect the Tengiz Field in western Kazakhstan to the Black Sea port of Novorossiysk. This pipeline will provide a less costly transportation alternative for the export of TCO's crude oil production. Angola - Chevron made two significant new oil discoveries - Tomboco and Lobito - in deepwater Block 14, where the company is operator and has a 31 percent ownership interest. While development plans for the two new discoveries are in the early stages, Tomboco and Lobito provide potential synergies with the development of two other Block 14 discoveries, Benguela and Belize. Chad-Cameroon - Chevron, with a 25 percent interest, and its partners began the development of the Doba oil fields in southern Chad and construction of a 650-mile pipeline from the fields to marine export facilities on the coast of Cameroon. This project is expected to cost $3.5 billion to develop and have a 20- to 30-year life. First production is expected in 2004. Nigeria - Chevron was awarded interests in three deepwater oil prospecting licenses (OPL) offshore Nigeria. Chevron, with a 50 percent interest, will serve as operator of OPL 250. The company also was awarded 30 percent nonoperating interests in OPL 214 and OPL 318. Work also continues on the initiative to convert natural gas into clean petroleum fuels
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and to significantly reduce the amount of flared natural gas at the company's producing operations. A gas-to-liquids facility, which will combine the technologies from Sasol Limited and Chevron, will be built adjacent to existing operations at Escravos. Thailand - The government of Thailand approved Chevron's plan for the development of North Jarmjuree, a 200-square-mile offshore production area located in Block B8/32. North Jarmjuree is the fourth production area granted within Block B8/32, which also includes the Tantawan, Benchamas and Maliwan fields. Chevron is operator and holds a 52 percent interest in Block B8/32. Canada - Chevron, as operator with a 43 percent interest, and its partners began production of natural gas from two wells at Fort Liard, Northwest Territories. Combined production is expected to average about 105 million cubic feet per day of natural gas and byproducts in 2001. Construction also began on the mining, extraction and upgrading facilities for the Athabasca Oil Sands Project, in which Chevron has a 20 percent interest. The project is expected to begin production in late 2002 and reach 155,000 barrels of bitumen per day at its peak. U.S. Gulf of Mexico - Two additional fields in the Viosca Knoll Carbonate Trend began producing a combined 106 million cubic feet of natural gas per day in November 2000. Chevron is the largest contiguous leaseholder in the Carbonate Trend, holding a majority interest in 54 leases. Oil and Gas Reserves Replacement - The company added 875 million barrels of oil-equivalent reserves during 2000, or 152 percent of production for the year, including the effects of sales and acquisitions. Among the major additions were about 130 million barrels each for the Tengiz Field in Kazakhstan and the Chad acquisition. More than 175 million barrels of the total amount were the result of successful discoveries in areas that included Thailand, Argentina, Nigeria, Angola, the United Kingdom and the U.S. Gulf of Mexico Shelf. Chevron Phillips Chemical Company - Effective July 1, 2000, Chevron and Phillips Petroleum Company (Phillips) formed Chevron Phillips Chemical Company LLC (CPCC), a 50-50 joint venture that combined most of the companies' petrochemicals businesses. At year-end 2000, CPCC had total assets of $6.7 billion.
ENVIRONMENTAL MATTERS - ---------------------- Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity and govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business. Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. 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 and at third-party waste-disposal sites used by the company. 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 at the time but now require investigative and/or remedial work to meet current standards. Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2000 at $910 million for its consolidated companies. Included in these expenditures were $212 million of environmental capital expenditures and $698 million of costs associated with the control and abatement of hazardous substances and pollutants from ongoing operations. For 2001, total worldwide environmental capital expenditures are estimated at $264 million. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites. The following table analyzes the annual changes to the company's before-tax environmental remediation reserves, including those for Superfund sites. For 2000, the company recorded additional provisions for estimated remediation costs at refined products marketing sites, chemicals manufacturing facilities, and various owned and previously owned refining facilities.
Under provisions of the Superfund law, the Environmental Protection Agency (EPA) has designated Chevron a potentially responsible party, or has otherwise involved the company, in the remediation of 315 hazardous waste sites. The company has made expense provisions or payments in 2000 and prior years for approximately 223 of these sites. No single site is expected to result in a material liability for the company. 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 potentially 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. Remediation reserves at year-end 2000, 1999 and 1998 for Superfund sites were $32 million, $33 million and $44 million, respectively. It is likely that the company will continue to incur additional liabilities, beyond those recorded, 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 amount 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 expen-
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ditures have had, or will have, any significant impact on the company's competitive position relative to other petroleum or chemical companies. The company maintains additional 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 related to environmental issues. Expense provisions are recognized on a unit-of-production basis. The amount of these reserves at year-end 2000 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 and chemicals facilities, 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.
LITIGATION AND OTHER UNCERTAINTIES - ---------------------------------- Chevron and five other oil companies filed suit in 1995 contesting the validity of a patent granted to Unocal Corporation for reformulated gasoline, which Chevron sells in California in certain months of the year. In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal's patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced in infringement of the patent. In May 2000, the Federal Circuit Court denied a petition for rehearing with the U.S. Court of Appeals for the Federal Circuit filed by Chevron and the five other defendants in this case. The defendant companies petitioned the U.S. Supreme Court in August 2000 for the case to be heard. In February 2001, the Supreme Court denied the petition to review the lower court's ruling. The defendants are pursuing other legal alternatives to have Unocal's patent ruled invalid. If Unocal's patent ultimately is upheld, the company's financial exposure includes royalties, plus interest, for production of gasoline that is proved to have infringed the patent. As a result of the March 2000 ruling, the company recorded a special after-tax charge of $62 million. The majority of this charge pertained to the estimated royalty on gasoline production in the early part of a four-year period ending December 31, 1999 - before Chevron modified its manufacturing processes to minimize the production of gasoline that allegedly infringed on Unocal's patented formulations. Subsequently, the company has been accruing in the normal course of business any future estimated liability for potential infringement of the patent covered by the trial court's ruling. In June 2000, Chevron paid $22.7 million to Unocal - $17.2 million for the original court judgment for California gasoline produced in violation of Unocal's patent from March through July 1996 and $5.5 million of interest and fees. Unocal has obtained additional patents for alternate formulations that could affect a larger share of U.S. gasoline production. Chevron believes these additional patents are invalid and unenforceable. However, if such patents ultimately are upheld, the competitive and financial effects on the company's refining and marketing operations, while presently indeterminable, could be material. Another issue involving the company is the ongoing public debate concerning the petroleum industry's use of MTBE and its potential environmental impact through seepage into groundwater. Along with other oil companies, the company is a party to lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior disposal or release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE may be filed in the future. Costs to the company related to these lawsuits and claims are not currently determinable. Chevron has eliminated the use of MTBE in gasoline it sells in certain areas. Chevron also receives claims from and submits claims to customers, trading partners, host governments, contractors, insurers and suppliers. The company is also party to numerous other lawsuits. In some of these matters, plaintiffs and claimants may seek to recover large and sometimes unspecified amounts. In others, they may seek to have the company perform specific activities, including remediation of alleged damages. These matters may remain unresolved for several years, and it is not practical to estimate a range of possible loss. Although losses or gains could be material to earnings in any given period, management believes that resolution of these matters will not materially affect the company's consolidated financial position or its liquidity. At year-end 2000, the value of the assets of the company's main U.S. pension plan exceeded the projected pension obligations by $657 million. This excess can be attributable to higher than expected returns on the investment of the plan assets over the past several years. If investment returns decline in the future and are insufficient to offset increases in the plan's obligations, pension expense may increase and additional funding may be required. Company operations, particularly exploration and production, can be affected by other changing economic, regulatory and political environments in the various countries in which it operates, including the United States. In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company's continued presence in those countries. Internal unrest or strained relations between a host government and the company or other governments may affect the company's operations. Those developments have, at times, significantly affected the company's related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries. Areas in which the company has significant operations include the United States, Canada, Australia, the United Kingdom, Norway, Republic of Congo, Angola, Nigeria, Chad, Equatorial Guinea, Democratic Republic of Congo, Papua New Guinea, China, Thailand, Venezuela, Argentina and Brazil. The company's Caltex affiliates have significant operations in Indonesia, Korea, Australia, Thailand, the Philippines, Singapore and South Africa. The company's Tengizchevroil affiliate operates in Kazakhstan. The company's Dynegy affiliate has operations in the United States, Canada, the United Kingdom and other European countries. The company and its affiliates continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated oil and gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period.
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FINANCIAL INSTRUMENTS - ---------------------- The company utilizes various derivative instruments, principally swaps and futures, 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 involve little complexity. (See Note 9 to the consolidated financial statements for further details.) Most of the activity in these instruments is intended to hedge physical 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.
NEW ACCOUNTING STANDARDS - ------------------------- The company adopted The Financial Accounting Standards Board (FASB) Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as amended by FAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133," effective January 1, 2001. Because of Chevron's limited use of derivative instruments (as described above), the company has elected not to account for its derivative instruments as hedges. Accordingly, upon adoption the fair values of the derivative instruments will be recorded as assets or liabilities on the balance sheet, and changes in fair values of these instruments beyond normal sales and purchases will be reflected in current income. The company may elect to apply hedge accounting, which has different financial statement effects, to possible future transactions involving derivative instruments, if significant. Such an election would reduce earnings volatility that might otherwise result if changes in fair values were recognized in current income. The adoption of FAS 133 and FAS 138 did not have a significant impact on the company's results of operations or financial position. In September 2000, the FASB issued Statement No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - A Replacement of FASB Statement No. 125" (FAS 140). FAS 140 is effective for transfers occurring after March 31, 2001, and for disclosures relating to securitization transactions and collateral for fiscal years ending after December 15, 2000. FAS 140 has no significant effect on Chevron's accounting or disclosures for the types of transactions in the scope of the new standard.
EMPLOYEE TERMINATION BENEFITS AND OTHER RESTRUCTURING COSTS - ----------------------------------------------------------- In 1999, the company implemented a staff reduction program in all of its operating segments across several business functions and accrued $220 million before tax for severance and other termination benefits for approximately 3,500 employees. Employees affected were primarily U.S.-based. All employee terminations were completed by June 30, 2000, and no significant adjustments were required for amounts previously accrued. Termination benefits for approximately 3,100 of the 3,500 employees were payable from the assets of the company's U.S. and Canadian pension plans. Most of the future savings connected with this program relate to the termination and relocation of U.S.-based employees.
RESULTS OF OPERATIONS - --------------------- Sales and other operating revenues were $50.6 billion in 2000, compared with $35.4 billion in 1999 and $29.9 billion in 1998. Revenues for 2000 and 1999 increased on sharply higher prices for crude oil, natural gas and refined products. The 2000 revenue increase was offset partially by the absence of chemicals revenues in the second half of the year due to the July 1 formation of the Chevron Phillips joint venture, which is accounted for under the equity method. Income from equity affiliates totaled $750 million in 2000, $526 million in 1999 and $228 million in 1998. Changes in earnings from Tengizchevroil and Caltex were the primary cause of the fluctuations between years. In 2000, increases in earnings from Tengizchevroil, Caltex and Dynegy were offset partially by losses from the Chevron Phillips joint venture. Other income totaled $787 million in 2000, $612 million in 1999 and $386 million in 1998. The fluctuations between years were the result of changes in net gains from asset sales and interest income from investments. Purchased crude oil and products costs in 2000 were 52 percent higher than in 1999 and 94 percent higher than in 1998 because of higher prices for crude oil, natural gas, refined products and chemicals feedstock. Prices fell precipitously in 1998 and did not begin to recover until the second quarter 1999. Offsetting some of the effect of higher prices in 2000 was the absence of costs as a result of the Chevron Phillips joint venture formation. Operating, selling, general and administrative expenses, excluding the effects of special items, increased to $6,487 million- from $6,169 million in 1999 and $6,251 million in 1998- primarily due to higher fuel costs. Mitigating this effect
was the absence of expenses associated with the chemicals operations contributed to the Chevron Phillips joint venture. Exploration expenses of $564 million in 2000 were $26 million, or 5 percent higher than 1999, and $86 million, or 18 percent higher than 1998. In 2000, increased drilling in the deepwater U.S. Gulf of Mexico led to a doubling of well write-offs for U.S. operations. This increase more than offset declines in international operations. Compared with 1998, both U.S. and international well write-offs in 1999 were significantly higher. Depreciation, depletion and amortization expense was $2,848 million in 2000, compared with $2,866 million in 1999 and $2,320 million in 1998. Depreciation expense associated with asset impairments in 2000 was $138 million, compared with $394 million in 1999 and $100 million in 1998. Increased production of crude oil and natural gas in 2000 and 1999 resulted in higher depreciation expense in the company's worldwide upstream operations. The overall 2000 expense reflects lower depreciation in chemicals (resulting from the Chevron Phillips joint venture formation) and other operations. Income tax expenses were $4,085 million in 2000, $1,578 million in 1999 and $495 million in 1998, reflecting effective income tax rates of 44 percent, 43 percent and 27 percent for each of the three years, respectively. The increase in the 2000 effective tax rate was primarily the result of lower
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after-tax earnings from equity affiliates as a proportion of before-tax income, the absence of tax benefits attributable to the 1999 utilization of capital losses and a decline in U.S. tax credits as a proportion of before-tax income. Partially offsetting these factors in 2000 were lower foreign income taxes as a percentage of income and a reduction in the impact of prior- year tax adjustments. The increase in the 1999 effective tax rate, compared with 1998, reflected a higher proportion of earnings from international operations that were taxed at higher rates; a lower beneficial impact from prior-period tax adjustments, settlement of outstanding issues, and permanent differences in 1999; and lower tax credits as a proportion of before-tax income. These factors were offset slightly by the effect of lower taxes on taxable income received from equity affiliates in 1999. Foreign currency gains in 2000 were $142 million, compared with losses of $38 million in 1999 and $47 million in 1998. During most of 2000, the U.S. dollar strengthened against the currencies of a number of countries - particularly Australia, the United Kingdom, Norway, Canada and certain countries in the Caltex operating area - before weakening late in the year. In 1999, the company's foreign exchange
losses occurred primarily in the company's operations in Canada and Australia and in the Australian operations of Caltex. The most significant losses in 1998 were in Caltex's operations in Korea, Thailand and Japan. U.S. exploration and production earnings in 2000 and 1999, excluding special items, were driven by sustained increases in crude oil and natural gas prices that began in early 1999. Expenses were higher in 2000, primarily for well write-offs, production-related taxes and operating expenses- largely associated with higher fuel costs. Gains from asset sales were lower than in 1999 and 1998. The company's average 2000 U.S. crude oil realization of $27.20 per barrel was $11.09 higher than in 1999 and $15.78
higher than 1998. The 2000 average U.S. natural gas realization was $4.04 per thousand cubic feet, $1.88 higher than in 1999 and double the prices in 1998. Net liquids production for the year averaged 312,000 barrels per day, down 1 percent from 1999 and 4 percent from 1998. Net natural gas production in 2000 averaged 1.558 billion cubic feet per day, down 5 percent from 1999 and 10 percent from 1998. The lower oil-equivalent production reflected normal field declines and asset sales, partially offset by new and enhanced production in the Gulf of Mexico deep water and other areas of the gulf. The decline in U.S. production in 2000 was mitigated by accelerating capital spending for fast-payout well workovers and development drilling projects that increased production and took advantage of the favorable price environment.
International exploration and production earnings, excluding special items, improved in 2000 and 1999 on higher crude oil and natural gas prices and steadily increasing production. Chevron's average liquids realization, including equity affiliates, was $27.12 per barrel in 2000, compared with $17.31 per barrel in 1999 and $11.77 per barrel in 1998. The average natural gas realization was $2.45 per thousand cubic feet in 2000, compared with $1.87 in 1999 and $1.94 in 1998.
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Net liquids production of 847,000 barrels per day in 2000 increased 4 percent from 811,000 barrels per day in 1999 and 8 percent from 1998. Production increases in Argentina, Angola, Australia and Thailand in 2000 more than offset lower volumes from Indonesia and Colombia. In 1999, increases in Angola and Kazakhstan, combined with production from properties acquired in Argentina and Thailand, offset declines in Australia, Indonesia and Nigeria. Net natural gas production of 911 million cubic feet in 2000 was up 4 percent from 1999 and nearly 40 percent from 1998. In 2000, production increases were primarily in Argentina and Thailand, partially offset by sharply lower production in Canada, due primarily to normal declines in mature fields. Increases in 1999 were from the Britannia Field in the United Kingdom, as well as from new production from the properties acquired in Thailand and Argentina. For 11 consecutive years through 2000, international production volumes and proved reserve quantities increased, reflecting the company's strategy of expanding its international upstream operations. Oil-equivalent production in 2000 increased over 9 percent- including volumes produced under various international operating service agreements, and adjusting for the effects of higher prices on Chevron's share of net production under production-sharing contracts and variable royalty arrangements. At year-end, oil-equivalent reserves were higher than year-end 1999 by 8 percent.
U.S. refining, marketing and transportation earnings, excluding special items, doubled in 2000 to $778 million and exceeded 1998 earnings of $633 million by 23 percent. Special items in 2000 included environmental remediation provisions for certain of the company's refining and marketing sites, some of which had been sold or closed in prior years. Earnings improved in 2000 on higher margins and more reliable West Coast refinery operations. Earnings in 1999 suffered from lower sales margins and operational problems at the company's California refineries, including a fire and, some months later, a detonation that did not result in a fire, at the Richmond Refinery. These incidents affected capacity and efficiency to produce blending components for diesel fuel, jet fuel and gasoline. These effects in 1999 were offset partially by increases in refined products sales volumes and higher proceeds from business interruption insurance. Refined products sales volumes of 1.327 million barrels per day in 2000 increased 2 percent over 1999 volumes and 7 percent from 1998 levels. The 2000 sales volumes reflected increases in higher- value gasoline and jet fuel volumes, more than offsetting a decline in sales of residual fuel oil. Additionally, sales in 2000 suffered from the effect of 1999 year-end stockpiling by customers in anticipation of possible Year 2000-related interruptions. U.S. refined products sales realizations were $39.32 per barrel, up 46 percent from 1999 realizations of $26.86, and up 76 percent from 1998's depressed levels. International refining, marketing and transportation earnings include results of the company's consolidated Canadian refining and marketing business, international marine operations, international supply and trading activities, and equity earnings of Caltex Corporation. Excluding special items, 2000 earnings of $116 million improved from $49 million in 1999, but were about 6 percent lower than the $123 million recorded in 1998. Earnings benefited from foreign exchange gains of $74 million in 2000, compared with losses of $21 million in 1999 and $69 million in 1998.
The Caltex component of segment results for the years 1998 through 2000 is shown in the table below.
Earnings for Caltex suffered from a very competitive operating environment, including excess refinery capacity in the Asia-Pacific region during 2000 and 1999 and weak sales margins in most of its areas of operations. Competitive pressures prevented refined products sales realizations from rising sufficiently to recover higher crude costs. International refined products sales volumes were 769,000 barrels per day in 2000, down nearly 8 percent from 832,000 barrels per day in 1999 and down 4 percent from 798,000 barrels per day in 1998. Lower trading volumes and the third quarter 1999 sale of a Caltex affiliate primarily were responsible for the decline in sales volumes in 2000. Higher Caltex sales volumes primarily were responsible for the 1999 increase.
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Chemicals earnings in 2000 included results from the company's Oronite division, the company's petrochemicals businesses prior to its contribution to CPCC in July 2000, and equity earnings in CPCC for the second half of the year. The special item for asset write-downs in 2000 was for this affiliate's impairment of assets in Puerto Rico. Operationally, commodity chemicals businesses suffered in the second half of 2000 from generally weak product demand, industry additions to manufacturing capacity and high raw material costs. Earnings in 1999 benefited from improved sales margins for major products, higher sales volumes and lower operating expenses. The 1998 results were adversely affected by plant shutdowns for expansions and storm damage repairs.
All Other consists of coal mining operations, the company's ownership interest in Dynegy Inc., worldwide cash management and debt financing activities, corporate administrative costs, insurance operations and real estate activities. Earnings, excluding special items, for the company's coal operations were $1 million in 2000, compared with $34 million in 1999 and $77 million in 1998. Earnings in 2000 were affected negatively by a union work stoppage for several months during the year and operating and geologic complications at certain mines. In 1999, results were lower than in 1998 primarily because of the absence of earnings from an affiliate sold in the first quarter of 1999, lower sales tonnage and prices for the remaining coal business, and adjustments to the carrying value of the operations that were under active negotiation for sale at that time. Chevron's share of Dynegy operating earnings was $119 million, a significant increase from $44 million in 1999 and $35 million in 1998. Significantly higher prices for natural gas and natural gas liquids and an increase in earnings from power generation activities were the primary reasons for the improved results. Net charges for the balance of the All Other segment, excluding special items, were $245 million in 2000, $351 million in 1999 and $137 million in 1998. Lower interest expense, higher interest income and decreases in other corporate expenses resulted in lower 2000 net charges than in 1999. The primary factors in the higher level of charges in 1999 as compared with 1998 were an increase in debt and lower cash balances, which caused interest expense to be higher, and reduced interest income.
LIQUIDITY AND CAPITAL RESOURCES - ------------------------------- Cash, cash equivalents and marketable securities totaled $2.6 billion at year-end 2000, up 29 percent from $2.0 billion at year-end 1999. Cash provided by operating activities in 2000 was $8.7 billion, compared with $4.5 billion in 1999 and $3.7 billion in 1998, benefiting from higher earnings. In addition, Chevron received a cash distribution in 2000 of $835 million from Chevron Phillips Chemical Co. after the joint venture obtained debt financing. Improved cash flows in 2000 permitted the company to reduce overall debt levels by $2.7 billion and repurchase $1.4 billion of the company's common shares. In 1999 and 1998, debt levels increased by $1.4 billion and $1.5 billion, respectively, as cash provided by operating activities and asset sales was not sufficient to fund the company's total cash requirements. In 1999, a payment of $775 million was also made to Occidental Petroleum in settlement of the Cities Service lawsuit. In 2000, the company paid dividends of $2.60 per share, compared with $2.48 per share in 1999 and $2.44 per share in 1998, increasing for the 13th consecutive year. In January 2001, the company declared a regular quarterly dividend of 65 cents a share on its common stock, unchanged from the previous quarter. The company's total debt and capital lease obligations were $6.232 billion at December 31, 2000, a decrease of 30 percent from $8.919 billion at year-end 1999. In early February 2001, the company announced a public offering to repurchase $350 million of 7.45 percent guaranteed notes maturing in 2004. At the close of the offering in late February, about $230 million had been acquired. At year-end 2000, Chevron had $3.250 billion in committed credit facilities with various major banks, $2.725 billion of which had termination dates beyond one year. These facilities support commercial paper borrowing and also can be used for general credit requirements. No borrowings were outstanding under these facilities during the year or at year-end 2000. In addition, Chevron has three existing "shelf" registrations on file with the Securities and Exchange Commission that together would permit registered offerings of up to $2.8 billion of debt securities. The company's debt due within 12 months, consisting primarily of commercial paper and the current portion of long-term debt, totaled $3.804 billion at December 31, 2000. Of this total short-term debt, $2.725 billion was reclassified to long-term debt at year-end 2000. Settlement of these obligations is not expected to require the use of working capital in 2001, as the company has the intent and the ability, as evidenced by committed credit arrangements, to refinance them on a long-term basis. The company's practice has been to continually refinance its commercial paper, maintaining levels it believes to be appropriate.
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To allow Chevron to continue active relationships with institutional investors in its commercial paper, the company instituted a program in 2000 under which it sells commercial paper and reinvests the borrowed funds in money-market instruments with similar terms. At December 31, 2000, the company had incremental short-term debt and investments of $84 million under this program. The company's future debt level is dependent primarily on its results of operations and capital-spending program. The company believes it has substantial borrowing capacity to meet unanticipated cash requirements. In December 1997, Chevron's Board of Directors approved the repurchase of up to $2 billion of the company's outstanding common stock for use in its employee stock option programs. In 2000, prior to suspending the program in October upon announcement of the merger agreement with Texaco, the company had repurchased 16.9 million shares at a cost of $1.406 billion. Total repurchases from the program's inception were 23.3 million shares at a cost of $1.890 billion.
FINANCIAL RATIOS - ----------------- The year-end current ratio is the ratio of current assets to current liabilities. Generally, two items adversely affect Chevron's current ratio, but in the company's opinion do not affect its liquidity. Current assets in all years included inventories valued on a LIFO basis, which at year-end 2000 were lower than current costs, based on average acquisition costs for the year, by nearly $2 billion. Also, the company benefits from lower interest available on short-term debt by continually refinancing its commercial paper. In past years, Chevron's proportionately large amount of short-term debt contributed to keeping its ratio of current assets to current liabilities at a relatively low level. However, at year-end 2000, only $94 million of commercial paper, after excluding $2.725 billion reclassified to long-term debt, was classified as a current liability. Strong cash flows during 2000 permitted the company to reduce the level of commercial paper required to fund its cash requirements. 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 2000, primarily due to higher before-tax income and lower interest expense as a result of lower debt levels. The company's debt ratio (total debt/total debt plus equity) declined about a third to 23.8 percent in 2000, due to the significant reduction in overall debt balances and an increase in equity for the year.
CAPITAL AND EXPLORATORY EXPENDITURES - ---------------------------------------- Worldwide capital and exploratory expenditures for 2000 totaled $5.153 billion, including the company's equity share of affiliates' expenditures. Capital and exploratory expenditures were $6.133 billion in 1999 and $5.314 billion in 1998. Expenditures for exploration and production activities represented 62 percent of total outlays in 2000, compared with 73 percent in 1999 and 59 percent in 1998. International exploration and production spending was 60 percent of worldwide exploration and production expenditures in 2000, compared with 80 percent in 1999 and 62 percent in 1998, reflecting the company's continuing focus on international exploration and production activities. Included in 1999 were expenditures of about $1.7 billion - mainly cash and assumption of debt - for the acquisition of Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A., exploration and production businesses in Thailand and Argentina, respectively. All Other expenditures in 2000 included an additional investment of about $300 million in Dynegy Inc. The company estimates 2001 capital and exploratory expenditures at $6.0 billion, including Chevron's share of spending by affiliates. This is up about 16 percent from 2000 spending levels. The 2001 program provides $3.7 billion for exploration and production investments, of which $2.5 billion is for international projects. Major areas of emphasis for exploration and production are Kazakhstan, Africa, Argentina, Thailand, Canada and the deep waters of the Gulf of Mexico. Successful implementation of the planned expenditure program for 2001 will depend upon many factors, including the ability of partners in many of these projects, some of which are national petroleum companies of producing countries, to fund their shares of project expenditures. Refining and marketing expenditures are estimated at about $900 million, with $600 million of that planned for projects in the United States, most of which will be spent to increase retail volumes and convenience store revenue as well as streamline distribution channels. The largest portion of the international refining and marketing capital program will be invested by the company's Caltex affiliate. Transportation expenditures are estimated at about $500 million, primarily for international pipelines related to expanded upstream production. Investments in power and natural gas facilities and distribution and in technology will total $650 million, most of which will be invested by the company's Dynegy affiliate. The company also plans to invest about $250 million in the worldwide chemicals business. The spending plans discussed above are for Chevron as a stand-alone entity and do not reflect the impact of the pending merger with Texaco. They also do not include the acquisition of an additional 5 percent equity in the Tengizchevroil project in Kazakhstan, which closed in January 2001.
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REPORT OF MANAGEMENT
TO THE STOCKHOLDERS OF CHEVRON CORPORATION
Management of Chevron is responsible for preparing the accompanying financial statements and for ensuring their integrity and objectivity. The statements were prepared in accordance with accounting principles generally accepted in the United States of America 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 PricewaterhouseCoopers LLP, independent accountants, selected by the Audit Committee and approved by the stockholders. Management has made available to PricewaterhouseCoopers 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/ David J. O'Reilly /s/ John S. Watson /s/ Stephen J. Crowe
David J. O'Reilly John S. Watson Stephen J. Crowe Chairman of the Board Vice President Vice President and Chief Executive Officer and Chief Financial Officer and Comptroller
February 26, 2001
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REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION
In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a)(1) on page 23 present fairly in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a)(2) on page 24 presents fairly, in all material respects, the information set forth therin when read in conjunction with the related consolidated statements. 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 auditing standards generally accepted in the United States of America, which 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, 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 our opinion.
/s/ PricewaterhouseCoopers LLP
San Francisco, California February 26, 2001
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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 manages its investments in, and provides administrative, financial and management support to, U.S. and foreign subsidiaries and affiliates that engage in fully integrated petroleum operations, chemicals operations and coal mining. Collectively, these companies, referred to as Chevron, operate in the United States and approximately 100 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 commodity petrochemicals, plastics for industrial uses, and fuel and lube oil additives. In preparing its consolidated financial statements, the company follows accounting policies that are in accordance with accounting principles generally accepted in the United States. This requires the use of estimates and assumptions that affect the assets, liabilities, 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. 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. Gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company's proportionate share of the dollar amount of the affiliate's equity are recognized currently in income. Deferred income taxes are provided for these gains and losses.
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." The adoption on January 1, 2001, of Financial Accounting Standards Board (FASB) Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities," (FAS 133), and FAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133," is not expected to have a significant effect on the company's results of operations or consolidated financial position.
Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt or equity 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." Short-term investments are marked-to-market with any unrealized gains or losses included in other comprehensive income.
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 The successful efforts method is used for oil and gas exploration and production activities. All costs for development wells, related plant and equipment, and proved 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. Costs also are capitalized for wells that find commercially producible reserves that cannot be classified as proved, pending one or more of the following: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory wells that are under way or firmly planned, and (3) securing final regulatory approvals for development. Otherwise, well costs are expensed if a determination cannot be made within one year following completion of drilling as to whether proved reserves were found. All other exploratory wells and costs are expensed. Long-lived assets, including proved oil and gas properties, are assessed for possible impairment by comparing their carrying values with the undiscounted future net before-tax cash flows. Impaired assets are written down to their estimated fair values, generally their discounted cash flows. For proved oil and gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country or concession basis. Impairment amounts are recorded as incremental depreciation expense in the period in which the event occurs. 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.
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Note 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued
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 their 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 are included in operating expense and sales are included in "Other income." Expenditures for maintenance, repairs and minor renewals to maintain facilities in operating condition are expensed as incurred. Major replacements and renewals are capitalized.
Environmental Expenditures Environmental expenditures that relate to 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, gas and coal producing properties, a provision is made through depreciation expense for anticipated abandonment and restoration costs at the end of a 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 ensured.
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 affiliates. 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.
Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are recognized on the basis of the company's net working interest (entitlement method).
Stock Compensation The company applies Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for stock options and presents in Note 20 pro forma net income and earnings per share data as if the accounting prescribed by FAS No. 123, "Accounting for Stock-Based Compensation," had been applied.
Note 2. FORMATION OF CHEVRON PHILLIPS CHEMICAL COMPANY LLC Effective July 1, 2000, Chevron and Phillips Petroleum Company (Phillips) formed Chevron Phillips Chemical Company LLC (CPCC) - a 50-50 joint venture that combined most of the petrochemicals businesses of Chevron and Phillips. Chevron is accounting for its interest using the equity method, in accordance with Accounting Principles Board (APB) Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." The net amount of assets and liabilities contributed to CPCC was reclassified to "Investments and advances" in the consolidated balance sheet. No gain or loss was recognized at the time of contribution, as the transaction represented the exchange of a consolidated business for an interest in a private joint venture and was not the culmination of the earnings process. The difference of approximately $100 between the carrying value of the investment and the amount of underlying equity in CPCC's net assets is being amortized as a benefit to income over the next 10 years. Chevron's share of CPCC's results of operations is recorded to "Income from equity affiliates." Because CPCC is a limited liability company, Chevron records the provision for income taxes and related tax liability applicable to its share of CPCC's income separately in its consolidated financial statements. The equity accounting treatment for Chevron's share of the net assets contributed to CPCC resulted in significant variances between 2000 and 1999 in the individual line captions appearing in the financial statements. The carrying amounts at July 1, 2000, of the principal assets and liabilities of the businesses Chevron contributed to CPCC were approximately $600 of net working capital; $2,100 of net properties, plant and equipment; and $100 of investments and advances. Upon formation, the joint venture obtained debt financing and made a cash payment of $835 to each owner.
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Note 3. 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.
In accordance with its policy, the company recorded impairments of assets to be held and used when changes in circumstances - primarily related to lower oil and gas prices, downward revisions of reserves and changes in the use of the assets - indicated that the carrying values of the assets could not be recovered through estimated future before-tax undiscounted cash flows. Asset impairments included in asset write-offs and revaluations were for assets held for use, except for U.S. coal assets, which were held for sale for approximately one year during 1998 and 1999. In late 1999, these assets were reclassified to held for use upon cessation of negotiations with potential buyers. The aggregate income statement effects from special items are reflected in the following table, including Chevron's proportionate share of special items related to equity affiliates.
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 $1,977, $871 and $584 at December 31, 2000, 1999 and 1998, respectively. At December 31, 1999, a liability of $85 remained for employee termination benefits relating to the restructuring charge recorded during the year. During 2000, these amounts were paid, all employee terminations were completed and no significant adjustments were required for amounts previously accrued.
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Note 4. CUMULATIVE EFFECT ON NET INCOME FROM ACCOUNTING CHANGES In April 1998, The American Institute of Certified Public Accountants (AICPA) released Statement of Position 98-5, "Reporting on the Costs of Start-up Activities"(SOP98-5), which introduced a broad definition of items to expense as incurred for start-up activities, including new products/services, entering new territories, initiating new processes or commencing new operations. Chevron was substantially in compliance with the pronouncement. However, Caltex capitalized these types of costs for certain projects. Chevron recorded its $25 share of the charge associated with Caltex's 1998 implementation of SOP 98-5, effective January 1, 1998. Also in 1998, Chevron changed its method of calculating certain Canadian deferred income taxes, effective January 1, 1998. The benefit from this change was $32. The net benefit to Chevron's 1998 net income from the cumulative effect of adopting SOP 98-5 by Caltex and the change in Chevron's method of calculating Canadian deferred taxes was immaterial.
Note 5. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS 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 in the following table.
The consolidated statement of cash flows excludes the following significant noncash transactions: Chevron contributed $2,800 of net noncash assets to Chevron Phillips Chemical Company LLC in 2000, as described in Note 2. The investment is accounted for under the equity method. During 1999, the company acquired the Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A. Only the net cash component of these transactions is included as "Capital expenditures." Consideration for the Rutherford-Moran transaction included 1.1 million shares of the company's treasury stock valued at $91. In 2000, $210 was reclassified from "Deferred credits and other noncurrent obligations" to "Accrued liabilities." The payment was remitted in January 2001.
Note 6. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC. At December 31, 2000, Chevron U.S.A. Inc. was Chevron's principal operating company, consisting primarily of its U.S. integrated petroleum operations (excluding most of the domestic pipeline operations). Through the first half of 2000, these operations were conducted primarily by three divisions: Chevron U.S.A. Production Company, Chevron Products Company and Chevron Chemical Company LLC. As described in Note 2, Chevron combined most of its petrochemicals businesses with those of Phillips Petroleum Company on July 1, 2000. Summarized financial information for Chevron U.S.A. Inc. and its consolidated subsidiaries is presented below.
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Note 7. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION LIMITED Effective July 1999, Chevron Transport Corporation, a Liberian corporation, was merged into Chevron Transport Corporation Limited (CTC), a Bermuda corporation, which assumed all of the assets and liabilities of Chevron Transport Corporation. CTC 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 issued by a third party. 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. In 2000, CTC's parent made an additional $30 capital contribution. There were no restrictions on CTC's ability to pay dividends or make loans or advances at December 31, 2000.
Note 8. STOCKHOLDERS' EQUITY Retained earnings at December 31, 2000 and 1999, include $2,301 and $2,048, respectively, for the company's share of undistributed earnings of equity affiliates. In 1998, the company declared a dividend distribution of one Right to purchase Chevron Participating Preferred Stock. The Rights become 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. The Chevron Series A Participating Preferred Stock that the holder of a Right is entitled to receive and the purchase price payable upon exercise of the Chevron Right are both subject to adjustment. 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. In October 2000, the Stockholder Rights agreement was amended to modify the 10 percent thresholds discussed above to 20 percent if the acquiring person is Texaco Corporation. The Rights will expire in November 2008, or they may be redeemed by the company at 1 cent per Right 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 per share of the company. Five million shares of the company's preferred stock have been designated Series A Participating Preferred Stock and reserved for issuance upon exercise of the Rights. No event during 2000 made the Rights exercisable. At December 31, 2000, 30 million shares of the company's authorized but unissued common stock were reserved for the issuance of shares under the Long-Term Incentive Plan (LTIP), which was approved by the stockholders in 1990. To date, all of the plan's common stock requirements have been met from the company's Treasury Stock, and there have been no issuances of reserved shares.
Note 9. 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 consist mainly of futures contracts traded on the New York Mercantile Exchange and the International Petroleum Exchange and of both crude and 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 forecasted to occur within a 60- to 90-day period. Crude oil swaps are used to hedge sales forecasted to occur within the next three years. The terms of the swap contracts have maturities of the same period. Natural gas swaps are used primarily to hedge firmly committed sales, and the terms of the swap contracts held at year-end 2000 had an average remaining maturity of 43 months. Gains and losses on these derivative instruments offset and are recognized in income concurrently with the recognition of the underlying physical transactions. The company enters into forward exchange contracts, generally with terms of 90 days or less, as a hedge against some of its foreign currency exposures, primarily anticipated purchase transactions forecasted to occur within 90 days. The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements, based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts, are made semiannually and are recorded monthly as "Interest and debt expense." At December 31, 2000, there were no outstanding contracts.
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Note 9. FINANCIAL AND DERIVATIVE INSTRUMENTS - - Continued
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 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, or negotiated contracts when the financial strength of a customer is not considered sufficient, are the principal securities obtained to support lines of credit.
Fair Value Fair values are derived either from quoted market prices or, if not available, 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. The fair values of the financial and derivative instruments at December 31, 2000 and 1999, are described below. Long-term debt of $2,147 and $2,449 had estimated fair values of $2,167 and $2,430. The notional principal amount of the interest rate swap for 1999 totaled $350, with an approximate fair value of $11. The notional amounts of 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 $2,301 and $1,762. Of these balances, $1,567 and $1,075 classified as cash equivalents had average maturities under 90 days, while the remainder, classified as marketable securities, had average maturities of approximately three years. For other derivatives the contract or notional values were as follows: Crude oil and products futures had net contract values of $10 and $143. Forward exchange contracts had contract values of $154 and $123. Gas swap contracts are based on notional gas volumes of approximately 39 and 44 billion cubic feet. Crude oil swap contracts are based on notional crude volumes of approximately 11 million barrels. Fair values for all of these derivatives were not material in 2000 and 1999. Deferred gains and losses that were accrued on the consolidated balance sheet were not material.
Note 10. OPERATING SEGMENTS AND GEOGRAPHIC DATA Chevron manages its exploration and production; refining, marketing and transportation; and chemicals businesses separately. The company's primary country of operation is the United States, its country of domicile. The remainder of the company's operations is reported as International (outside the United States), since its activities in no other country meet the requirements for separate disclosure.
Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the corporation on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments; instead, operating segments are billed only for direct corporate services. Nonbillable costs remain as corporate center expenses. After-tax segment operating earnings are presented in the following table.
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Note 10. OPERATING SEGMENTS AND GEOGRAPHIC DATA - Continued
Segment Assets Segment assets do not include intercompany investments or intercompany receivables. "All Other" assets consist primarily of worldwide cash and marketable securities, company real estate, information systems, Dynegy Inc. investment and coal mining operations. Segment assets at year-end 2000 and 1999 follow:
Segment Sales and Other Operating Revenues Revenues for the exploration and production segment are derived primarily from the production of crude oil and natural gas. Revenues for the refining, marketing and transportation segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, kerosene, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of crude oil and refined products. Prior to the July 2000 formation of the Chevron Phillips joint venture, chemicals segment revenues were derived from the manufacture and sale of petrochemicals, plastic resins, and lube oil and fuel additives. Subsequently, only revenues from the manufacture and sale of lube oil and fuel additives were included. "All Other" activities include corporate administrative costs, worldwide cash management and debt financing activities, coal mining operations, insurance operations, and real estate activities. Reportable operating segment sales and other operating revenues, including internal transfers, for the years 2000, 1999 and 1998 are presented in the following table. Sales from the transfer of products between segments are at estimated market prices.
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Segment Income Taxes Segment income tax expenses for the years 2000, 1999 and 1998 are as follows:
Other Segment Information Major equity affiliates are aligned for segment reporting as follows: P.T. Caltex Pacific Indonesia (CPI) and Tengizchevroil (TCO) - International exploration and production; Caltex Corporation - International refining, marketing and transportation; Chevron Phillips Chemical Company LLC - U.S. Chemicals; and Dynegy Inc. - All Other. Additional information for equity affiliates is in Note 13. Information related to properties, plant and equipment by segment is in Note 14.
Note 11. LITIGATION Chevron and five other oil companies filed suit in 1995 contesting the validity of a patent granted to Unocal Corporation for reformulated gasoline, which Chevron sells in California in certain months of the year. In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal's patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced in infringement of the patent. In May 2000, the Federal Circuit Court denied a petition for rehearing with the U.S. Court of Appeals for the Federal Circuit filed by Chevron and the five other defendants in this case. The defendant companies petitioned the U.S. Supreme Court in August 2000 for the case to be heard. In February 2001, the Supreme Court denied the petition to review the lower court's ruling. The defendants are pursuing other legal alternatives to have Unocal's patent ruled invalid. If Unocal's patent ultimately is upheld, the company's financial exposure includes royalties, plus interest, for production of gasoline that is proven to have infringed the patent. As a result of the March 2000 ruling, the company recorded a special after-tax charge of $62. The majority of this charge pertained to the estimated royalty on gasoline production in the early part of a four-year period ending December 31, 1999, before Chevron modified its manufacturing processes to minimize the production of gasoline that allegedly infringed on Unocal's patented formulations. Subsequently, the company has been accruing in the normal course of business any future estimated liability for potential infringement of the patent covered by the trial court's ruling. In June 2000, Chevron paid $22.7 to Unocal - $17.2 for the original court judgment for California gasoline produced in violation of Unocal's patent from March through July 1996 and $5.5 of interest and fees. Unocal has obtained additional patents for alternate formulations that could affect a larger share of U.S. gasoline production. Chevron believes these additional patents are invalid and unenforceable. However, if such patents are ultimately upheld, the competitive and financial effects on the company's refining and marketing operations, while presently indeterminable, could be material.
Note 12. 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:
Rental expenses incurred for operating leases during 2000, 1999 and 1998 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 1 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. At December 31, 2000, the future minimum lease payments under operating and capital leases were as follows:
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Note 13. INVESTMENTS AND ADVANCES Chevron owns 50 percent each of P.T. Caltex Pacific Indonesia (CPI), an exploration and production company operating in Indonesia; Caltex Corporation, 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. The company received dividends and distributions of $596, $268 and $254 in 2000, 1999 and 1998, respectively, including $244, $212 and $167 from the Caltex group. Tengizchevroil (TCO) is a joint venture formed in 1993 to develop the Tengiz and Korolev oil fields in Kazakhstan over a 40-year period. Chevron's ownership was 45 percent for the 1998 to 2000 period. Upon formation of the joint venture, the company incurred an obligation of $420, payable to the Republic of Kazakhstan upon 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. In January 2001, the company purchased an additional 5 percent of TCO. As a part of that transaction, the company paid $210 of the $420 obligation. The $420 was also included in the carrying value of the original investment, as the company believed, beyond a reasonable doubt, that its full payment would be made. At year-end 2000, Chevron owned 26.5 percent of Dynegy Inc., a gatherer, processor, transporter and marketer of energy products in North America and the United Kingdom. These products include natural gas, natural gas liquids, crude oil and electricity. Chevron's percentage ownership in Dynegy was reduced from about 28 percent during 2000, as a result of a Dynegy 10 million-share equity offering (at about $53 per share), in which Chevron did not participate. The market value of Chevron's share of Dynegy common stock at December 31, 2000, was $4,784, based on closing market prices. Chevron owns 50 percent of Chevron Phillips Chemical Company LLC, formed in July 2000 when the company merged most of its petrochemicals businesses with those of Phillips Petroleum Company. This business is described in more detail in Note 2. The company's transactions with affiliated companies are summarized in the table that follows. These are primarily for the purchase of Indonesian crude oil from CPI, the sale of crude oil and products to Caltex Corporation's refining and marketing companies, the sale of natural gas to Dynegy, and the purchase of natural gas and natural gas liquids from Dynegy.
Equity in earnings, together with investments in and advances to companies accounted for using the equity method, and other investments accounted for at or below cost, are as follows:
"Accounts and notes receivable" in the consolidated balance sheet include $494 and $277 at December 31, 2000 and 1999, respectively, of amounts due from affiliated companies. "Accounts payable" include $139 and $53 at December 31, 2000 and 1999, respectively, of amounts due to affiliated companies.
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NOTE 14. PROPERTIES, PLANT AND EQUIPMENT
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Note 15. TAXES U.S. federal income tax expense was reduced by $103, $89, $84 in 2000, 1999 and 1998, respectively, for low-income housing and other business tax credits. In 2000, before-tax income, including related corporate and other charges, for U.S. operations was $3,924, compared with $1,254 in 1999 and $728 in 1998. For international operations, before-tax income was $5,346, $2,394 and $1,106 in 2000, 1999 and 1998, respectively.
The company's effective income tax rate varied from the U.S. statutory federal income tax rate because of the following:
The increase in the 1999 effective tax rate from 1998 was due primarily to increased foreign taxes on higher foreign earnings in 1999 compared with 1998. Additional increases in the effective tax rate in 1999 were from tax credits as a smaller proportion of before-tax income in 1999 than in 1998. The other effects on the 1999 effective tax rate included settlement of outstanding issues, utilization of additional capital loss benefits and permanent differences, slightly offset by the effect of lower taxable income received from equity affiliates in 1999. 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. The reported deferred tax balances are composed of the following deferred tax liabilities (assets).
Investments and other for 2000 in the table above include deferred tax liabilities of $805 for investments, of which $482 is associated with the company's investment in Chevron Phillips Chemical Company. In 1999, most of the deferred tax liabilities associated with the company's assets contributed to the joint venture were reported as properties, plant and equipment. At December 31, 2000 and 1999, deferred taxes were classified in the consolidated balance sheet as follows:
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 $5,244 at December 31, 2000. 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 remit-
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tance 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 $226 would be payable upon remittance of these earnings.
Note 16. 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 periodically enters into interest rate swaps on a portion of its short-term debt. At December 31, 2000, there were no outstanding contracts. At December 31, 1999, the company had swapped notional amounts of $350 of floating rate debt to fixed rates. The effect of these swaps on the company's interest expense was not material.
Note 17. LONG-TERM DEBT Chevron has three "shelf" registrations on file with the Securities and Exchange Commission that together would permit the issuance of $2,800 of debt securities pursuant to Rule 415 of the Securities Act of 1933. At year-end 2000, the company had $3,250 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 borrowings under the terms of specific agreements may be based on the London Interbank Offered Rate, the Reserve Adjusted Domestic Certificate of Deposit Rate or bank prime rate. No amounts were outstanding under these credit agreements during the year or at year-end.
At December 31, 2000 and 1999, the company classified $2,725 of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 2001, as the company has both the intent and ability to refinance this debt on a long-term basis. Consolidated long-term debt maturing in each of the five years after December 31, 2000, is as follows: 2001-$267, 2002-$231, 2003-$182, 2004-$1,153 and 2005-$29. In early February 2001, the company announced a public offering to repurchase all of its 7.45 percent guaranteed notes maturing in 2004. At the expiration of the offering in mid-February, about $230 had been acquired.
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Note 18. OTHER COMPREHENSIVE INCOME The components of changes in other comprehensive income and the related tax effects are shown below.
NOTE 19. EMPLOYEE BENEFIT PLANS
Pension Plans The company has defined benefit pension plans for most employees and provides for certain health care and life insurance plans for active and qualifying retired employees. The company's policy is to fund the minimum necessary to satisfy requirements of the Employee Retirement Income Security Act for the company's pension plans. The company's annual contributions for medical and dental benefits are limited to the lesser of actual medical 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. Nonfunded pension and postretirement benefits are paid directly when incurred; accordingly, these payments are not reflected as changes in Plan assets in the following table. The status of the company's pension plans and other postretirement benefit plans for 2000 and 1999 is as follows:
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For measurement purposes, separate health care cost-trend rates were used for pre-age 65 and post-age 65 retirees. The 2001 annual rates of change were assumed to be 7.2 percent and 16.2 percent, respectively, before gradually converging to the average ultimate rate of 5.0 percent in 2021 for both pre-age 65 and post-age 65. A one-percentage-point change in the assumed health care rates would have had the following effects:
The components of net periodic benefit cost for 2000, 1999 and 1998 were:
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with accumulated benefit obligations in excess of plan assets were $416, $334 and $33, respectively, at December 31, 2000, and $428, $368 and $80, respectively, at December 31, 1999.
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 were $62, $61 and $60 in 2000, 1999 and 1998, respectively. The company's Savings Plus Plan contributions were 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. In June 1999, the ESOP borrowed $25 at 6.98 percent interest, using the proceeds to pay interest due on the existing ESOP debt. In July 1999, the company's leveraged ESOP issued notes of $620 at an average interest rate of 7.42 percent, guaranteed by Chevron Corporation. The debt proceeds were paid to Chevron Corporation in exchange for Chevron's assumption of the existing 8.11 percent ESOP long-term debt of $620. The ESOP provides a partial prefunding of the company's future commitments to the Profit Sharing/Savings Plan, which will result in annual income tax savings for the company. As permitted by AICPA Statement of Position 93-6, "Employers' Accounting for Employee Stock Ownership Plans," the company has elected to continue its practices, which are based on Statement of Position 76-3, "Accounting Practices for Certain Employee Stock Ownership Plans" 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. The company recorded expense for the ESOP of $25, $59 and $58 in 2000, 1999 and 1998, respectively, including $47, $49 and $56 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 $54, $33 and $57 in 2000, 1999 and 1998, respectively. The company made contributions to the ESOP of $64 and $60 in 1999 and 1998, respectively, to satisfy ESOP debt service in excess of dividends received by the ESOP. No contributions were required in 2000. The ESOP shares were pledged as collateral for its debt. Shares are released from a suspense account and allocated to the accounts of Plan participants, based on the debt service deemed to be paid in the
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year in proportion to the total of current year and remaining debt service. The (credit) charge to compensation expense was $(22), $10 and $2 in 2000, 1999 and 1998, respectively. The ESOP shares as of December 31, 2000 and 1999, 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 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 20, were $49, $41 and $28 in 2000, 1999 and 1998, respectively.
Chevron Success Sharing The company has a program that provides eligible employees with an annual cash bonus if the company achieves certain financial and safety goals. Until 2000, the total maximum payout under the program was 8 percent of the employee's annual salary. Charges for the program were $146, $47 and $51 in 2000, 1999 and 1998, respectively. In 2000, the maximum payout under the program increased to 10 percent.
NOTE 20. STOCK OPTIONS The company applies APB Opinion No. 25 and related interpretations in accounting for stock options awarded under its Broad-Based Employee Stock Option Programs 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 FAS No. 123, the company's net income and earnings per share for 2000, 1999 and 1998 would have been the pro forma amounts shown below.
The effects of applying FAS No. 123 in this pro forma disclosure are not indicative of future amounts. FAS 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.
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. The options vested in June 1997 when Chevron's share price closed above $75.00 for three consecutive days. Options for 7,204,800 shares, including similar-termed LTIP awards, were granted for this program in 1996. Outstanding option shares were 2,213,450 at December 31, 1997. In 1998, exercises of 1,361,000 and forfeitures of 10,800 had reduced the outstanding option shares to 841,650 at year-end 1998. In 1999, exercises of 740,725, forfeitures of 61,850 and expirations of 39,075 reduced the outstanding option shares to zero at March 31, 1999, the date of expiration. Under APB Opinion No. 25, the company recorded gains of $2 for these options in 1999. No gains or expenses for this program were recorded in 2000 and 1998. The fair market value of each option share on the date of grant under FAS 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 another broad-based Employee Stock Option Program that granted to all eligible employees an option that varied from 100 to 300 shares of stock or equivalents, dependent on the employee's salary or job grade. These options vested after two years in February 2000. Options for 4,820,800 shares were awarded at an exercise price of $76.3125 per share. Forfeitures of options for 854,550 shares reduced the outstanding option shares to 3,966,250 at December 31, 1999. In 2000, exercises of 611,201 and forfeitures of 290,682 had reduced the outstanding option balance to 3,064,367 at the end of the year. The options expire February 11, 2008. Under APB Opinion No. 25, the company recorded expenses of $(2), $4 and $2 for these options in 2000, 1999 and 1998, respectively. The fair value of each option share on the date of grant under FAS No. 123 was estimated at $19.08 using the average results of Black-Scholes models for the preceding 10 years. The 10-year averages of each assumption used by the Black-Scholes models were: risk-free interest rate of 7.0 percent, dividend yield of 4.2 percent, expected life of seven years and a volatility of 24.7 percent.
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NOTE 20. STOCK OPTIONS - Continued
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. 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. The weighted-average fair market value of options granted in 2000, 1999 and 1998 was $22.34, $20.40 and $21.10 per share, respectively. The fair market value of each option on the date of grant was estimated using the Black-Scholes option-pricing model with the following assumptions for 2000, 1999 and 1998, respectively: risk-free interest rate of 5.8, 5.5 and 4.5 percent; dividend yield of 3.0, 3.0 and 3.1 percent; volatility of 25.6, 20.1 and 28.6 percent and expected life of seven years in all years. As of December 31, 2000, 10,311,802 shares were under option at exercise prices ranging from $31.9375 to $99.75 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, 2000.
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 2000, 1999 and 1998 follows.
NOTE 21. OTHER CONTINGENCIES AND COMMITMENTS The U.S. federal income tax liabilities have been settled through 1993. The company's California franchise tax liabilities have been settled through 1991. Settlement of open tax years, as well as tax issues in other countries where the company conducts its businesses, 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, 2000, the company and its subsidiaries, as direct or indirect guarantors, had contingent liabilities of $25 for notes of affiliated companies and $179 for notes of others. The company and its subsidiaries have certain contingent liabilities relating 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 amounts of required payments under these various commitments are: 2001 - $375; 2002-$354; 2003-$333; 2004-$310; 2005-$252; 2006 and after-$946. Total payments under the agreements were $281 in 2000, $258 in 1999 and $201 in 1998.
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Note 21. OTHER CONTINGENCIES AND COMMITMENTS - Continued
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, including MTBE, by the company or other parties. Such contingencies may exist for various sites including, but not limited to: Superfund sites and refineries, oil fields, service stations, terminals and land development areas, whether operating, closed or sold. The amount of such future cost is indeterminable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. While the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs to have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have 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 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. However, the results of operations and financial position of certain equity affiliates may be affected by their business activities involving the use of derivative instruments. 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. Also for oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated oil and gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. Areas in which the company has significant operations include the United States, Canada, Australia, the United Kingdom, Norway, Congo, Angola, Nigeria, Chad, Equatorial Guinea, Democratic Republic of Congo, Papua New Guinea, China, Venezuela, Thailand, Argentina and Brazil. The company's Caltex affiliates have significant operations in Indonesia, Korea, Australia, Thailand, the Philippines, Singapore and South Africa. The company's Tengizchevroil affiliate operates in Kazakhstan. The company's Dynegy affiliate has operations in the United States, Canada, the United Kingdom and other European countries.
NOTE 22. EARNINGS PER SHARE (EPS) Basic EPS includes the effects of deferrals of salary and other compensation awards 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 20, "Stock Options"). The following table sets forth the computation of basic and diluted EPS.
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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" (FAS 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, Chad, Congo and Democratic Republic of Congo. The "Other" geographic category includes activities in Australia, Argentina, the United Kingdom North Sea, Canada, Papua New Guinea, Venezuela, Brazil, China, Thailand 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 equity share of Tengizchevroil (TCO), an exploration and production partnership operating in the Republic of Kazakhstan.
FS-33
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 2000, 1999 and 1998 are shown in the following table. Net income from exploration and production activities as reported on page FS-7 reflects income taxes computed on an effective rate basis. In accordance with FAS No. 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page FS-7.
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TABLE IV - RESERVE QUANTITY INFORMATION The company's estimated net proved underground oil and gas reserves and changes thereto for the years 2000, 1999 and 1998 are shown in the following table. Proved reserves are estimated by company 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 U.S. 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 as additional information becomes available. Proved reserves do not include additional quantities recoverable beyond the term of the lease or concession agreement or that may result from extensions of currently proved areas or from applying 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. Chevron operates under a risked service agreement Venezuela's Block LL-652, located in the northeast section of Lake Maracaibo. Chevron is accounting for LL-652 as an oil and gas activity and, at December 31, 2000, had recorded 57 million barrels of proved crude oil reserves. No reserve quantities have been recorded for the company's other service agreement in Venezuela, the Boscan Field.
FS-36
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 FAS 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 pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10 percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when 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 FAS 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.
FS-37
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, 2000
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CALTEX GROUP OF COMPANIES COMBINED FINANCIAL STATEMENTS DECEMBER 31, 2000
INDEX
Page ------
General Information C-3 to C-4
Independent Auditors' Report C-5
Combined Statement of Income C-6
Combined Statement of Comprehensive Income C-6
Combined Balance Sheet C-7
Combined Statement of Stockholders' Equity C-8
Combined Statement of Cash Flows C-9
Notes to Combined Financial Statements C-10 to C-20
Note: Financial statement schedules are omitted as permitted by Rule 4.03 and Rule 5.04 of Regulation S-X.
C-2
CALTEX GROUP OF COMPANIES GENERAL INFORMATION
The Caltex Group of Companies (Group) is jointly owned 50% each by Chevron Corporation and Texaco Inc. (collectively, the Stockholders) and was created in 1936 by its two owners to explore for, produce, transport, refine and market crude oil and petroleum products. The Group is comprised of the following companies:
o Caltex Corporation, a company incorporated in Delaware with its corporate headquarters in Singapore, that, through its many subsidiaries and affiliates, conducts refining, transporting, trading, and marketing activities in the Eastern Hemisphere;
o P. T. Caltex Pacific Indonesia, an exploration and production company incorporated and operating in Indonesia; and,
o American Overseas Petroleum Limited, a company incorporated in the Bahamas.
A brief description of each company's operations and other items follows. All reported amounts are in U.S. dollars.
Caltex Corporation (Caltex) - ---------------------------
Through its subsidiaries and affiliates, Caltex operates in approximately 57 countries, principally in Africa, Asia, the Middle East, New Zealand and Australia. These geographic areas comprise a broad diversity of mature, developing, and emerging markets. At the end of 2000, it had total assets of $7.7 billion, sales of 1.4 million barrels of crude oil and petroleum products per day, and total revenues of $18.4 billion for the year. Caltex is involved in all aspects of the downstream business: marketing, refining, distribution, transportation, storage, supply and trading operations; the corporation is also active in the petrochemical business through its affiliate in Korea. At year-end 2000, Caltex had more than 7,200 employees.
The majority of refining and certain marketing operations are conducted through joint ventures. Caltex has equity interests in 10 refineries with equity refining capacity of approximately 846,000 barrels per day. Additionally, it has interests in two lubricant refineries, 17 lubricant blending plants, and a network of ocean terminals and depots. Caltex also has an interest in a fleet of vessels, and owns or has equity interests in numerous pipelines. Caltex conducts international crude oil and petroleum product logistics and trading operations from a subsidiary in Singapore.
P. T. Caltex Pacific Indonesia (CPI) - ------------------------------------
CPI holds a Production Sharing Contract (PSC) 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. At the end of 2000, CPI had total assets of $2.5 billion, which generated total revenues of $2.0 billion for the year. Exploration is pursued over 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 2000 was over 707,000 barrels of crude oil per day. CPI entitlements are sold to its Stockholders, who use them in their systems or sell them to third parties. At year-end 2000, CPI had approximately 5,800 employees, all located in Indonesia.
American Overseas Petroleum Limited (AOPL) - ------------------------------------------
AOPL and its subsidiary, Amoseas Indonesia, Inc, provide services for CPI and manage certain geothermal steam operations and geothermal power generation projects in Indonesia in which Chevron and Texaco have interests. At year-end 2000, AOPL had approximately 186 employees, of which 9% were located in the United States.
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CALTEX GROUP OF COMPANIES GENERAL INFORMATION
Supplemental Market Risk Disclosures - ------------------------------------
The Group uses various derivative financial instruments for hedging and trading 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, exposure remains on the unhedged portion. The Notes to the Combined Financial Statements provide additional 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 and $2.2 billion, before the effects of related net interest rate swaps of $0.3 billion and $0.4 billion, at December 31, 2000 and 1999, respectively). The Group seeks to balance the benefit of lower cost variable rate debt, having inherent increased risk, with more expensive, but lower risk 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 at December 31, 2000 and 1999, a hypothetical change in the interest rates of 2% would change net income by approximately $23 million and $25 million in 2000 and 1999, respectively.
Crude oil and petroleum product derivatives - The Group uses established petroleum futures exchanges, as well as "over-the-counter" instruments, including futures, options, swaps, and other derivative products to hedge a portion of the market risks associated with its crude oil and petroleum product purchases and sales. The Group also enters into derivative contracts as part of its crude oil and petroleum product trading activities.
The Group had net open petroleum derivative purchase contracts of approximately $146 million and $127 million at December 31, 2000 and 1999, respectively. As a sensitivity for these contracts, a hypothetical 10% change in crude oil and petroleum product prices would change net income by approximately $10 million and $9 million in 2000 and 1999, respectively.
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 options contracts. Depending on the exposure being hedged, the Group either purchases or sells selected foreign currencies. The Group had net foreign currency purchase contracts of approximately $191 million and $279 million at December 31, 2000 and 1999, respectively, 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 in 2000 or 1999.
New Accounting Standard - -----------------------
Statement of Financial Accounting Standards No. 133 (SFAS No. 133), "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS No. 137 and No. 138, will be adopted by the Group beginning January 1, 2001. SFAS No. 133/138 require companies to record derivatives on the balance sheet as assets or liabilities and measure those derivatives at fair value. Changes in the fair values of derivatives are to be recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of exposure being hedged.
Based on its current level of activity with derivative instruments, the Group does not expect the adoption of SFAS No. 133/138 to have significant impact on results of operations, other comprehensive income or financial position.
C-4
Independent Auditors' Report ----------------------------
To the Stockholders The Caltex Group of Companies:
We have audited the accompanying combined balance sheets of the Caltex Group of Companies as of December 31, 2000 and 1999, and the related combined statements of income, comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2000, all expressed in United States of America dollars. 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 auditing standards generally accepted in the United States of America. 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, 2000 and 1999 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the combined financial statements, the Group changed its method of accounting for start-up costs in 1998 to comply with the provisions of the AICPA's Statement of Position 98-5 - "Reporting on the Costs of Start-up Activities".
/s/ KPMG KPMG
Singapore February 8, 2001
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C-7
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C-9
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 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% except cases in which control does not rest with the Group. The Group's accounting policies are in accordance with U.S. generally accepted accounting principles, and the Group's reporting currency is the U.S. dollar.
Translation of foreign currencies The U.S. dollar is the functional currency for all principal subsidiary and affiliate operations.
Estimates The preparation of financial statements in conformity with U.S. 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 Inventories are valued at the lower of cost or current market, except as noted below. Crude oil and petroleum product inventory costs are primarily determined using the last-in, first-out (LIFO) method, and include applicable acquisition and refining costs, duties, import taxes, freight, etc. Materials and supplies are stated at average cost. Certain trading-related inventory, which is highly transitory in nature, is marked-to-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. All costs for development wells, related plant and equipment, and proved 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. Costs are also capitalized for wells that find commercially producible reserves that cannot be classified as proved, pending one or more of the following: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory wells that are under way or firmly planned, and (3) securing final regulatory approvals for development. Otherwise, well costs are expensed if a determination cannot be made within one year following completion of drilling as to whether proved reserves were found. All other exploratory wells and costs are expensed.
Long-lived assets, including proved developed oil and gas properties, are assessed for possible impairment by comparing their carrying values to the undiscounted-future-net-before-tax cash flows. Impaired assets are written down to their fair values, generally their discounted cash flows. Impaired assets held for sale are recorded at their fair value less cost to sell. For proved oil and gas properties, the reviews are performed on a concession basis. Impairment amounts are recorded as incremental depreciation expense in the period in which the event occurs.
Depreciation, depletion and amortization expenses for capitalized costs relating to producing properties, including intangible development costs, are determined 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. 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.
Deferred credits Deferred credits primarily represent the Indonesian government's interest in specific property, plant and equipment balances. Under the Production Sharing Contract (PSC), the Indonesian government retains a majority equity share of current production profits. Intangible development costs (IDC) are capitalized for U.S. generally accepted accounting principles under the successful efforts method, but are treated as period expenses for PSC reporting. Other capitalized amounts are depreciated at an accelerated rate for PSC reporting. The deferred credit balances recognize the government's share of IDC and other reported capital costs that over the life of the PSC will be included in income as depreciation, depletion and amortization and will be applied against future production related profits.
Derivative financial instruments and energy trading contracts The Group uses various derivative financial instruments for hedging purposes. These instruments include interest rate and/or currency swap contracts, forward and options 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 non-monetary 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 instruments that do not qualify as hedges are recognized currently in income.
The Group also enters into energy contracts as a part of its crude oil and petroleum product trading activities. Trading contracts are recorded at market value and related gains and losses are recorded on a net basis in cost of sales and operating expenses as the market values change. The net gains and losses from trading contracts were not material to the Group's results of operations for 2000, 1999 and 1998.
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, is 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.
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. CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 - Summary of significant accounting policies - continued
Revenue recognition In general, revenue is recognized for crude oil, natural gas and refined product sales when title passes as specified in the sales contract.
Reclassifications Certain reclassifications have been made to the prior year amounts to conform to the 2000 presentation.
Note 2 - Accounting change
An affiliate of the Group capitalized certain start-up costs, primarily organizational and training, over the period 1992-1996 related to a grassroots refinery construction project in Thailand. These costs were considered part of the effort required to prepare the refinery for operations. With the issuance of the AICPA's Statement of Position 98-5, "Reporting on the Costs of Start-up Activities", these costs would be accounted for as period expenses. The Group elected early adoption of this pronouncement effective January 1, 1998 and accordingly, recorded a cumulative effect charge to income as of January 1, 1998 of $50 million representing the Group's share of the applicable start-up costs. Excluding the cumulative effect, the change in accounting for start-up costs did not materially affect net income for 1998.
Note 3 - Restructuring/Reorganization
Caltex recorded a charge to selling, general and administrative expenses of $37 million and $86 million in 1999 and 1998, respectively, for various restructuring and reorganization activities undertaken to realign its downstream operations along functional lines and reduce redundant operating activities. The charges included severance and other termination benefits of $23 million and $60 million for approximately 200 employees and 500 employees in 1999 and 1998, respectively. All affected employees had left Caltex by December 2000. The following table summarizes the restructuring/reorganization costs for 2000, 1999 and 1998 (millions of U.S. dollars):
The $9 million liability as of December 31, 2000 primarily relates to future lease commitments on vacated office space over the remaining lease term ending in 2002. Adjustments made in 2000 and 1999 to recorded liabilities were insignificant.
In addition to the above, 1999 net income included a $27 million after tax charge for restructuring activities of affiliates.
Note 4 - Assets Held for Disposal
The Group continually reviews its asset portfolio and periodically sells or otherwise disposes of various assets that no longer fit into the Group's strategic direction. The Group recorded a charge to earnings of approximately $4 million in 2000 and $30 million in both 1999 and 1998 related to various marketing assets (primarily service station land and buildings) which have been removed from operation and are awaiting disposal or sale as buyers are located. Carrying value of these assets, which is based on appraisals or estimated selling prices, as of December 31, 2000 is approximately $25 million. The effect of suspending depreciation on assets held for sale in 2000, 1999 and 1998 was not material.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 5 - Operating leases
The Group has operating leases involving various marketing assets for which net rental expense was $92 million, $112 million, and $103 million in 2000, 1999, and 1998, respectively.
Future net minimum rental commitments under operating leases having non-cancelable terms in excess of one year are as follows (in millions of U.S. dollars): 2001 - $42; 2002 - $16; 2003 - $7; 2004 - $6; 2005 - $6; and 2006 and thereafter - $23.
Note 6 - Taxes
Taxes charged to income consist of the following:
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:
For 2000, the increase in effective tax rate is primarily due to the larger proportion of earnings from higher tax rate foreign jurisdictions. For 1999, the increase in the effective tax rate resulting from the sale of investment in an affiliate is net of the effect of previously unrecorded foreign tax credit carry-forwards of $29 million.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 6 - Taxes - continued
Deferred income taxes are provided in each tax jurisdiction for temporary differences between the financial reporting and the tax basis of assets and liabilities. Temporary differences and tax loss carry-forwards which give rise to deferred tax liabilities (assets) are as follows:
A valuation allowance has been established to reduce deferred income tax assets to amounts which, in the Group's judgement are more likely than not (more than 50%) to be utilized against current and future taxable income when those temporary differences become deductible.
Undistributed earnings of subsidiaries and affiliates, for which no U.S. deferred income tax provision has been made, approximated $3.3 billion and $3.4 billion as of December 31, 2000 and December 31, 1999, respectively. 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. Excess U.S. foreign income tax credits are not recorded until realized.
Note 7 - Inventories
The reported value of inventory at December 31, 2000 and 1999 was less than its current cost by approximately $152 million and $104 million, respectively. In 2000 and 1998, certain inventories were recorded at market, which was lower than the LIFO carrying value. Adjustments to market reduced net income $4 million in 2000 and $18 million in 1998. In 1999, the market valuation adjustment reserves established in prior years were eliminated as market prices improved and the physical units of inventory were sold. Elimination of these reserves increased net income in 1999 by $71 million. At December 31, 2000, inventories were primarily reported at LIFO carrying cost except for approximately $39 million of trading inventory recorded at market.
Inventory quantities valued on the LIFO basis were reduced at certain locations during the periods presented. Such inventory reductions increased net income in 2000 and 1999 by $41 million each year and decreased net income by $4 million (net of a related market valuation adjustment of $1 million) in 1998.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 8 - 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 1999, Caltex Corporation sold its 50% interest in Koa Oil Company, Limited (Koa) with a net book value of approximately $219 million, to Nippon Mitsubishi Oil Corp, for approximately $237 million in cash. As a result of the sale, Caltex incurred additional U.S. tax liabilities of approximately $81 million.
The remaining interest in Star Petroleum Refining Company, Ltd. (SPRC) is owned by a governmental entity of the Kingdom of Thailand. 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 before the year 2001; however, this requirement has been delayed in view of the current economic difficulties in the region.
Shown below is summarized combined financial information for affiliates at equity (in millions of U.S. dollars):
Cash dividends received from these affiliates were $83 million, $71 million, and $50 million in 2000, 1999, and 1998, respectively.
The summarized combined financial information shown above includes the cumulative effect of the accounting change in 1998 as described in Note 2.
Retained earnings as of December 31, 2000 and 1999 includes $1.4 billion which represents the Group's share of undistributed earnings of affiliates at equity.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 9 - 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, 2000 and 1999 were 6.9% and 6.5%, respectively. Unutilized lines of credit available for short-term financing totaled $1.0 billion as of December 31, 2000.
Note 10 - Long-term debt
Long-term debt, with related interest rates for 2000 and 1999 consists of the following:
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 11 - 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 six years. Net unrealized (losses) and gains on contracts outstanding at December 31, 2000 and 1999 were ($1 million) and $4 million, respectively.
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) to hedge existing liabilities have maturities of up to two years. Net unrealized losses applicable to outstanding forward exchange contracts at December 31, 2000 and 1999 were $37 million and $5 million, respectively.
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. Gains and losses on hedges are deferred and recognized concurrently with the underlying commodity transactions. Deferred (losses) and gains on hedging contracts outstanding at year-end were ($4 million) in 2000 and $4 million in 1999.
The Group's recorded value of fixed interest rate debt exceeded the fair value by $27 million and $22 million as of December 31, 2000 and 1999, 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 other current liabilities approximate fair value because of their short maturities.
The Group had investments in debt securities available-for-sale at amortized costs of $11 million and $120 million at December 31, 2000 and 1999, respectively. The fair value of these securities at December 31, 2000 and 1999 approximated amortized costs. As of December 31, 2000 and 1999, investments in debt securities available-for-sale had maturities of less than ten years. The Group's carrying amount for investments in affiliates accounted for at equity included $1 million and $2 million, as of December 31, 2000 and 1999, 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 counter-parties to financial instruments. For financial instruments with institutions, the Group does not expect any counter-party 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.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 12 - Employee benefit plans
The Group has various retirement plans, including defined benefit pension plans, covering substantially all of its employees. The benefit levels, vesting terms and funding practices vary among plans. The following provides a reconciliation of benefit obligations, plan assets, and funded status of the various plans, primarily foreign.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 12 - Employee benefit plans - continued
Other post-retirement benefits are comprised of contributory healthcare and life insurance plans. A one percentage point change in the assumed health care cost trend rate of 10% would change the post-retirement benefit obligation by $9 million and would not have a material effect on aggregate service and interest components.
Note 13 - Commitments and contingencies
Caltex is involved in tax audits in the United States and in certain other jurisdictions. The Internal Revenue Service's audit for the years 1987-1993 has been administratively settled and Caltex will receive a refund of tax and interest for these years. In jurisdictions outside the United States, the tax authorities' audits are in various stages of completion. In the opinion of management, adequate provision has been made for income taxes for all years under examination or subject to future examination.
Caltex 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 products for Caltex (Philippines) Inc. (a subsidiary of Caltex) in connection with a contract of affreightment. Although Caltex had no direct or indirect ownership in or operational responsibility for either vessel, various theories of liability have been alleged against Caltex. The major suit filed in the U.S. (Louisiana State Court) was dismissed in December 2000 on forum non conveniens grounds and is currently under appeal by the plaintiffs. Caltex will vigorously contest this appeal. Caltex is actively pursuing dismissal of all Philippine litigation on the strength of a Philippine Supreme Court decision absolving it of any responsibility for the collision. No reasonable estimate of damages involved or being sought can be made at this time.
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.
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CALTEX GROUP OF COMPANIES NOTES TO COMBINED FINANCIAL STATEMENTS
Note 13 - Commitments and contingencies - continued
A Caltex subsidiary has a contractual commitment until 2007 to purchase petroleum products in conjunction with the financing of a refinery owned by an affiliate. Total future estimated commitments under this contract, based on current pricing and projected growth rates, are approximately $0.8 billion per year. Purchases (in billions of U.S. dollars) under this and other similar contracts were $1.0, $0.7 and $0.8 in 2000, 1999, and 1998 respectively.
Caltex is contingently liable for sponsor support funding for a maximum of $193 million in connection with an affiliate's project finance obligations. The project has been operational since 1996 and has successfully completed all mechanical, technical and reliability tests associated with the plant physical completion covenant. However, the affiliate has been unable to satisfy a covenant relating to a working capital requirement. As a result, a technical event of default exists which has not been waived by the lenders. The lenders have not enforced their rights and remedies under the finance agreements and they have not indicated an intention to do so. The affiliate is current on these financial obligations and anticipates resolving the issue with its secured creditors during further restructuring discussions. During 2000, Caltex and the other sponsor provided temporary short-term extended trade credit related to crude oil supply with an outstanding balance owing to Caltex at December 31, 2000 of $124 million.
Note 14 - Oil and gas exploration, development and producing activities
The financial statements of Chevron Corporation and Texaco Inc. contain required supplementary information on oil and gas producing activities, including disclosures on affiliates at equity. Accordingly, such disclosures are not presented herein.
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