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Chevron Corporation 10-K 2004 Documents found in this filing:
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003 OR
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to Commission File Number 1-368-2
(Exact name of registrant as specified in its
charter)
Registrant’s telephone number, including area code (925) 842-1000
NONE
(Former name or former address, if changed since
last report.)
Securities registered pursuant to Section 12(b) of the Act:
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). þ Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter — $71,712,298,891 (As of June 30, 2003) Number of Shares of Common Stock outstanding as of February 29, 2004 — 1,069,736,866 DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2004 Annual Meeting and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2004 Annual Meeting of Stockholders (in Part III)
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CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF “SAFE HARBOR”
PROVISIONS OF THE
This Annual Report on Form 10-K of ChevronTexaco Corporation contains forward-looking statements relating to ChevronTexaco’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “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 and are difficult to predict. 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, ChevronTexaco 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; the results of operations and financial condition of equity affiliates; Dynegy Inc.’s ability to successfully complete its recapitalization and restructuring plans; inability or failure 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; potential disruption or interruption of the company’s production or manufacturing facilities due to war, accidents, political events, civil unrest or severe weather; 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); potential liability resulting from pending or future litigation; the company’s ability to successfully implement the restructuring of its worldwide downstream organization and other business units; the company’s ability to sell or dispose of assets or operations as expected; and the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies. 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. 2
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PART I Item 1. Business (a) General Development of Business Summary Description of ChevronTexaco ChevronTexaco Corporation,1 a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial and management support to U.S. and foreign subsidiaries that engage in fully integrated petroleum operations, chemicals operations, coal mining, power and energy services. The company operates in the United States and in more than 180 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 pipeline, marine vessel, motor equipment and rail car. Chemicals operations include the manufacture and marketing, by an affiliate, of commodity petrochemicals for industrial uses, and the manufacture and marketing, by a consolidated subsidiary, of 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 pages E-4 and E-5 of this Annual Report on Form 10-K. As of December 31, 2003, ChevronTexaco had 61,533 employees (including 10,951 service station employees), down about 4,500 from year-end 2002. Approximately 26,000, or 42 percent, of the company’s employees were employed in U.S. operations, of which approximately 3,400 were unionized. Overview of Petroleum Industry Petroleum industry operations and profitability are influenced by many factors, over some of which individual petroleum 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. The members of the Organization of Petroleum Exporting Countries (OPEC) 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 for natural gas is largely driven by the conditions of local, national and worldwide economies, although weather patterns and taxation relative to other energy sources also play a significant part. Variations in the components of refined products sales due to seasonality are not primary drivers of changes in the company’s overall earnings. Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. ChevronTexaco competes with fully integrated major petroleum companies, as well as independent and national petroleum companies for the acquisition of crude oil and natural gas leases and other properties, and for the equipment and labor required to develop and operate those properties. In its downstream business, ChevronTexaco also competes with fully integrated major petroleum companies and other independent refining and marketing entities in the sale or purchase of various goods or services in many national and international markets.
1 Incorporated
in Delaware in 1926 as Standard Oil Company of California, the
company adopted the name Chevron Corporation in 1984 and
ChevronTexaco Corporation in 2001. As used in this report, the
term “ChevronTexaco” and such terms as “the
company,” “the corporation,” “our,”
“we,” and “us” may refer to ChevronTexaco
Corporation, one or more of its consolidated subsidiaries, or to
all of them taken as a whole, but unless stated otherwise, it
does not include “affiliates” of
ChevronTexaco — i.e., those companies accounted for by
the equity method (generally owned 50 percent or less) or
investments accounted for by the cost method. All of these terms
are used for convenience only and are not intended as a precise
description of any of the separate companies, each of which
manages its own affairs.
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Refer to pages FS-2 through FS-4 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 business environment and outlook. ChevronTexaco Strategic Direction ChevronTexaco’s primary objective is to achieve sustained financial returns from its operations that will enable it to outperform its competitors. The company has set as a goal to generate the highest total stockholder return among a designated peer group for the five-year period 2000-2004. BP, ExxonMobil and Royal Dutch Shell — among the world’s largest integrated petroleum companies — comprise the company’s designated competitor peer group for this purpose. The company had the highest total stockholder return in this peer group for the 2000-2003 period. As a foundation for attaining this goal, the company has established four key priorities:
Supporting these four priorities is a focus on:
The Corporate Strategic Plan builds on this framework with strategies focused on appropriately balancing financial returns and growth. As a result of a rigorous evaluation of its entire portfolio of assets, the company is exploring potential asset transactions — sales, acquisitions or trades — to increase the efficiency and profitability of continuing operations and to enhance the economic value of its asset base. The company expects that its worldwide exploration and production business will continue to be its most important business, with development of its large worldwide proved and unproved natural gas reserves as a primary strategy to expand the company’s base of production and to capture economic value from emerging natural gas market opportunities. The company is also seeking to deliver improved and competitive returns from its worldwide downstream businesses. In January 2004, the company’s global downstream organization began operating along global functional lines rather than geographical functional lines in order to lower costs, improve efficiency and achieve sustained improvements in financial performance. On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation. The combination was accounted for as a pooling of interests, and each share of Texaco common stock was converted on a tax-free basis into the right to receive 0.77 shares of ChevronTexaco common stock. In the merger, ChevronTexaco issued approximately 425 million shares of common stock, representing about 40 percent of the outstanding ChevronTexaco common stock after the merger. Further discussion of the Texaco merger transaction is contained on page FS-5 and in Note 2 on page FS-30 of this Annual Report on Form 10-K. 4
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The company’s largest business segments are exploration and production (upstream) and refining, marketing and transportation (downstream). Chemicals is also a significant segment, conducted mainly by the company’s 50 percent-owned affiliate — Chevron Phillips Chemical Company LLC (CPChem). The petroleum activities of the company are widely dispersed geographically. The company has petroleum operations in North America, South America, Europe, Africa, Middle East, Central and Far East Asia, and Australia. CPChem has operations in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium. ChevronTexaco’s wholly owned Oronite fuel and lubricating oil additives business has operations in the United States, Mexico, France, the Netherlands, Singapore, India, Japan and Brazil. ChevronTexaco owns an approximate 26 percent equity interest in the common stock of Dynegy Inc. (Dynegy), an energy merchant engaged in power generation, natural gas liquids processing and marketing, and regulated energy delivery. The company also holds investments in Dynegy notes and preferred stock. During 2003, the company exchanged its $1.5 billion aggregate principal amount of Dynegy Series B preferred Stock, which was due for redemption at par value in November 2003, for cash and new Dynegy securities. Refer to pages FS-10 and FS-11 for further information relating to the company’s investment in Dynegy. Tabulations of segment sales and other operating revenues, earnings, income taxes and assets, by United States and International geographic areas, for the years 2001 to 2003 may be found in Note 9 to the consolidated financial statements beginning on page FS-34 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 14 and 15 on pages FS-38 to FS-40. The company’s worldwide operations can be affected significantly by changing economic, tax, regulatory and political environments in the various countries in which it operates, including the United States. 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 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. Political and community unrest has disrupted the company’s production in the past, most recently in Nigeria and Venezuela. Capital and Exploratory Expenditures A discussion of the company’s capital and exploratory expenditures is contained on pages FS-11 and FS-12 of this Annual Report on Form 10-K. 5
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Petroleum — Exploration and Production Liquids and Natural Gas Production The following table summarizes the company’s and affiliates’ net production of crude oil and natural gas liquids, natural gas, and oil-equivalent production for 2003 and 2002. Net Production1 of Crude Oil and Natural Gas Liquids and Natural Gas
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In 2003, ChevronTexaco conducted its 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, decreased by about 5 percent from the 2002 levels. Net worldwide production of natural gas, including affiliates, decreased about 2 percent in 2003. Net liquids and natural gas production in the United States were both down about 7 percent compared with 2002. The decline in U.S. production in 2003 was primarily attributable to declines in mature fields. In addition to normal field declines in 2003, oil-equivalent production decreased from the absence of 10,000 to 15,000 barrels per day of production the company deemed uneconomic to restore following storm damages in the Gulf of Mexico in late 2002. International net liquids production, including affiliates, decreased about 4 percent, whereas net natural gas production increased about 5 percent from 2002. In Indonesia, about 29,000 barrels per day of the year-to-year decline was related to the effect of lower cost-oil recovery volumes under production-sharing terms during 2003 and the expiration of a production sharing arrangement in the third quarter of 2002. For the past five years, the company’s worldwide oil-equivalent production has followed a downward trend with 2003 production at 89 percent of 1999 levels, equivalent to an average annual decline rate of slightly more than 2 percent. During this time period, increases in international oil-equivalent production were more than offset by decreases in the United States. For 2004, the company currently anticipates lower oil-equivalent production rates in the United States as a result of normal field declines, the effect of property sales and opportunity limitations. The ultimate level of worldwide production in 2004 remains uncertain due to the potential for constraints imposed by the Organization of Petroleum Exporting Countries (OPEC), and disruptions caused by weather, local civil unrest and other economic factors. At December 31, 2003, the company owned or had under lease or similar agreements undeveloped and developed oil and gas properties located throughout the world. The geographical distribution of the company’s acreage is shown in the following table. Acreage1 At December 31, 2003
(Thousands of Acres)
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Refer to Table IV on page FS-56 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 2003, 2002 and 2001. The following table summarizes gross and net productive wells at year-end 2003 for the company and its affiliates. Productive Oil and Gas Wells at December 31, 2003
Reserves and Contract Obligations Table V on page FS-57 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, 2003, 2002 and 2001. During 2004, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency, consistent with the reserve data reported on page FS-57 of this Annual Report on Form 10-K. In 2003, ChevronTexaco’s worldwide oil and oil-equivalent gas barrels of net proved reserves additions exceeded production, with a replacement rate of 108 percent of net production, including sales and acquisitions. Excluding sales and acquisitions, the replacement rate was 114 percent of net production. Reserve additions included extensions of the Guajira Contract in Colombia and the Danish Underground Consortium Contract in Denmark; initial booking of the Tahiti Field in the Gulf of Mexico; reservoir studies and analyses at the Tengiz and Karachaganak fields in Kazakhstan; and improved recovery activity primarily in Indonesia and the United States. 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 2003. 8
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The company sells crude oil and natural 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. During 2002, Dynegy purchased substantially all natural gas and natural gas liquids produced by the company in the United States, excluding Alaska, and supplied natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemical plants. The company reached an agreement with Dynegy to terminate the natural gas purchase and sale contracts and other related contracts at the end of January 2003. See pages FS-10 and FS-11 for further information on Dynegy. In the United States, the company is contractually committed to deliver to third parties and affiliates approximately 160 billion cubic feet of natural gas through 2006 from United States reserves. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed U.S. reserves. These contracts include variable-pricing terms. Outside the United States, the company is contractually committed to deliver to third parties approximately 600 billion cubic feet of natural gas through 2006 from Australian, Canadian, Colombian and Philippine reserves. The sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery and that in some cases consider inflation or other factors. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed Australian, Canadian, Colombian and Philippine reserves. Details of the company’s development expenditures and costs of proved property acquisitions for 2003, 2002 and 2001 are presented in Table I on page FS-53 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, 2003. 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” includes wells temporarily suspended. 9
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Development Well Activity
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, 2003. “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” includes wells temporarily suspended. Refer to the suspended wells discussion in “Litigation and Other Contingencies” in Management’s Discussion and Analysis of Financial Condition and Results of Operations on page FS-17 and Note 1, Summary of Significant Accounting Policies; “Properties, Plant and Equipment” on pages FS-28 and FS-29 for further discussion. Increases in the United States, Nigeria and Australia were partially offset by decreases in China and Angola. The wells are suspended pending a final determination of the commercial potential of the related oil and gas deposits. 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 under way or firmly planned, and (3) in some cases, securing final regulatory approvals for development. Exploratory Well Activity
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Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2003, 2002 and 2001 are presented in Table I on page FS-53 of this Annual Report on Form 10-K. Review of Ongoing Exploration and Production Activities in Key Areas ChevronTexaco’s 2003 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. The comments include reference to “net production,” which excludes partner shares and royalty interests. “Total production” includes these components. In addition to the activities discussed, ChevronTexaco was active in other geographic areas, but these activities were less significant. Consolidated Operations The United States exploration and production activities are concentrated in the Gulf of Mexico, California, Louisiana, Texas, New Mexico and the Rocky Mountains. As part of the ongoing effort to improve competitive performance and increase operating efficiency, the company announced plans in 2003 to sell interests in non-strategic producing properties in the United States. The majority of these properties are located in 15 states and the Outer Continental Shelf of the Gulf of Mexico. The company expects to retain about 400 core fields and anticipates the divestment program will be substantially completed in 2004. Gulf of Mexico: Combining the shelf and deepwater interests in the Gulf of Mexico, average daily net production during 2003 were 169,000 barrels of crude oil, 1 billion cubic feet of natural gas and 19,700 barrels of natural gas liquids. In deepwater, the company has an interest in three significant developments: Petronius, Genesis and Typhoon. Petronius, 50 percent-owned and operated, maintained a daily production of approximately 30,000 barrels of net oil-equivalent in 2003. The 57 percent-owned and operated Genesis averaged production of approximately 20,000 barrels of net oil-equivalent per day in 2003. Typhoon, which is 50 percent-owned and operated, had average production of approximately 14,000 barrels of net oil-equivalent per day in 2003, including production from the Boris field that utilizes the Typhoon production facility. In exploration, there were four new deepwater discoveries in 2003 — Sturgis and Perseus, in which the company has a 50 percent interest in each, and Tubular Bells and Saint Malo, which the company’s interest is 30 percent and 12.5 percent, respectively. The company drilled a well in the Tonga prospect in 2003. The data from this well is under evaluation. Additionally, under terms of an agreement with BP, ChevronTexaco earned the right to operate the Blind Faith discovery and increased its ownership to 50 percent. Appraisal work was completed in the Tahiti discovery. Mid-Continent: Onshore operations in the mid-continent United States are concentrated in Texas, Oklahoma, Kansas, Alabama and the Rocky Mountain states. Net production of natural gas averaged 822 million cubic feet per day through development drilling activity, combined with a focus on maintaining base production with workovers, artificial lift and facility optimization. Net production of crude oil and natural gas liquids averaged 32,000 barrels per day during the year. Capital spending was focused on natural gas development with major programs in the Rockies, East Texas and South Texas. Permian: Permian operations are located predominantly in southeastern New Mexico and West Texas. During 2003, daily net production averaged 110,500 barrels of crude oil and natural gas liquids and 257 million cubic feet of natural gas. San Joaquin Valley: ChevronTexaco is the largest producer in California. In 2003, average daily net production was 225,500 barrels of crude oil, 112 million cubic feet of natural gas and 4,800 barrels of natural gas liquids. Approximately 85 percent of the crude oil production is considered heavy oil (typically 11
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with an API gravity lower than 22 degrees). Heat
management continued to be a major focus for the oil assets,
enabling greater recovery of this resource.
Global Natural Gas Projects: In November 2003, ChevronTexaco received approval for a Deepwater Port License by U.S. government authorities to construct, own and operate a liquefied natural gas (LNG) receiving and regasification terminal, Port Pelican, to be located offshore Louisiana to serve the North American market. Efforts are under way in 2004 to obtain project approval. The company also filed permits to construct an LNG receiving and regasification terminal to be located approximately eight miles off the coast of Baja California, Mexico. ChevronTexaco is working with Mexican authorities to secure permit approvals for the project. b) Africa Nigeria: ChevronTexaco’s principal subsidiary in Nigeria, Chevron Nigeria Limited (CNL), operates and holds a 40 percent interest in 11 concessions, predominantly in the onshore and near-offshore regions of the Niger Delta. CNL operates under a joint venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns the remaining 60 percent interest. ChevronTexaco’s subsidiaries Chevron Oil Company Nigeria Limited (COCNL) and Texaco Overseas Nigeria Petroleum Company Unlimited (TOPCON) each hold a 20 percent interest in six additional concessions. TOPCON operates these concessions under a joint venture agreement with NNPC, which owns the remaining 60 percent interest. In 2003, daily net production from the 33 CNL-operated fields averaged 113,100 barrels of crude oil, 2,400 barrels of liquefied petroleum gas (LPG) and 50 million cubic feet of natural gas. Net production from five TOPCON operating fields during the year averaged approximately 7,200 barrels of crude oil per day. Onshore operations in the western Niger Delta were suspended in March 2003 as a result of community disturbance. Net onshore production capacity of about 45,000 barrels of oil per day remained shut-in at year-end while the company continued to evaluate options for safe and secure restoration of production. The onshore and offshore engineering, procurement and construction bids were received in 2003 for Phase 3 of the Escravos Gas Project, which includes adding a second gas plant and expanding processing capacity to 680 million cubic feet per day and is targeted for completion in 2007. ChevronTexaco holds a 40 percent working interest in the Escravos Gas Project, which has the capacity to process 285 million cubic feet of natural gas per day. Front-end engineering and design and site preparations have been completed for the planned gas-to-liquids (GTL) facility at Escravos. This proposed 33,000-barrel-per-day GTL project is the company’s first project to use the Sasol Chevron Global Joint Venture’s technology and operational expertise. Project start-up is expected to be in 2007. ChevronTexaco will ultimately hold about a 38 percent beneficial interest. The company also continued activities in the deepwater Agbami development. In 2003, a pre-unitization agreement was completed between ChevronTexaco and the Blocks 216 and 217 participants. Initial production is expected in 2007. Successful results were achieved in 2003 from the Aparo-3 appraisal well and the Nsiko-1 wildcat well in the deepwater Block OPL-249, in which the company is entitled to a variable equity interest over the life of the field. OPL-222 activities continued in 2003 with the successful completion of appraisal programs involving Usan-3, Usan-4 and Ukot-2, in which ChevronTexaco holds a 30 percent interest. Exploration activities on the shelf included the completion of the Okagba-2 appraisal well along with the successful Sonam-4 appraisal well. The company and its partners in the Brass River Consortium agreed to advance plans for the front-end engineering and design work for a new LNG facility at Brass River in Nigeria. 12
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Angola: ChevronTexaco is the largest producer of crude oil and natural gas in Angola and the first to produce in the deepwater. Cabinda Gulf Oil Company Limited (CABGOC), a wholly owned subsidiary of ChevronTexaco, is operator of two concessions, Blocks 0 and 14, off the west coast of Angola, north of the Congo River. Block 0, in which CABGOC has a 39 percent interest, is a 2,155-square-mile concession adjacent to the Cabinda coastline. Block 14, in which CABGOC has a 31 percent interest, is a 1,580-square-mile deepwater concession located west of Block 0. In Block 0, the company operates in three areas — A, B and C — composed of 21 fields producing 128,000 barrels per day of net liquids in 2003. Area A, comprising 16 fields that are currently producing, averaged daily net production of approximately 82,000 barrels of crude oil and 1,000 barrels of LPG in 2003. Area B, which has three fields producing, averaged net production of 37,000 barrels of crude oil per day. Area C averaged net production of 8,000 barrels of crude oil per day from two producing fields. In Block 14, net production in 2003 from the Kuito Field, Angola’s first deepwater producing area, averaged approximately 19,000 barrels of crude oil per day. The Benguela Belize-Lobito Tomboco development includes a phased development of the Benguela, Belize, Lobito and Tomboco fields, with Phase 1 currently estimated to start up by the end of 2005. Phase 2 involves the installation of subsea systems, pipelines and wells for the Lobito and Tomboco fields. The company is the operator and holds a 31 percent interest in Block 14. The Negage prospect is currently under evaluation for commerciality, and feasibility studies continue for the Gabela heavy oil field. ChevronTexaco has two other concessions in Angola. Block 2, in which the company operates and has a 20 percent interest, and Block FST, in which the company has a 16 percent nonoperated interest, had a combined net production of 7,100 barrels of crude oil per day in 2003. The Angola LNG Project is an integrated gas utilization project. ChevronTexaco and Sonangol, the state oil company of Angola, are co-leading the project in which the company has a 36 percent interest. Republic of Congo: ChevronTexaco has a 30 percent interest in NKossa, Nsoko and Moho-Bilondo exploitation permits and a 29 percent interest in the Marine VII Kitina and Sounda exploitation permits, all of which are in offshore Congo and adjacent to the company’s concessions in Cabinda. Net production from ChevronTexaco’s concessions in the Republic of Congo averaged 13,300 barrels of crude oil per day in 2003. An assessment of the Moho and Bilondo discoveries progressed during 2003, and a development decision is expected in 2004. Chad-Cameroon: ChevronTexaco is partner in a project to develop landlocked oil fields in southern Chad and transport crude oil by pipeline to the coast of Cameroon for export to world markets. At the end of 2003, the overall development project was substantially complete. The company’s first sales of Chad production occurred in late 2003. ChevronTexaco has a 25 percent interest in the upstream operations and has approximately a 23 percent interest in the pipeline. Equatorial Guinea: ChevronTexaco is a 45 percent partner and operator of Block L offshore the Republic of Equatorial Guinea. The first exploration well, Ballena-1, was completed in April 2003, and the partnership is currently progressing with the evaluation of the block. c) Asia-Pacific China: ChevronTexaco has a 33 percent interest in Block 16/08, located in the Pearl River Delta Mouth Basin. Daily net production from the six fields in this block averaged 14,700 barrels of crude oil per day in 2003. The company has a 25 percent interest in QHD-32-6 in Bohai Bay, which had 2003 average net production of 8,300 barrels of crude oil per day. Indonesia: ChevronTexaco’s interests in Indonesia are managed by two wholly owned subsidiaries, P.T. Caltex Pacific Indonesia (CPI) and Amoseas Indonesia (AI). CPI accounts for about 40 percent of Indonesia’s total crude oil output and holds an interest in five production-sharing contracts (PSCs). AI is a power generation company that operates the Darajat geothermal contract area in West Java and a 13
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cogeneration facility in support of CPI’s
operation in North Duri. In addition to the above interests,
ChevronTexaco has a 25 percent nonoperated interest in
South Natuna Sea Block B.
ChevronTexaco’s share of net production during 2003 was 251,000 barrels of oil-equivalent per day. CPI continues to execute projects that are designed to optimize production from its existing reservoirs. The Duri Field in the Rokan Block, under steamflood since 1985, is the largest steamflood project in the world, with net production averaging 116,000 barrels of crude oil per day in 2003. ChevronTexaco’s net production from South Natuna Sea Block B in 2003 was about 15,400 barrels of oil-equivalent per day. Thailand: ChevronTexaco operates Block B8/32 in the Gulf of Thailand with a 52 percent interest. During 2003, the company was awarded the exploration and production rights to two additional offshore concessions. The company’s interests in the newly acquired Blocks G4/43 and 9A are 85 percent and 52 percent, respectively. The company also holds a 33 percent interest in exploration Blocks 7, 8 and 9, which are currently inactive pending resolution of border issues between Thailand and Cambodia. Block B8/32 produces crude oil and natural gas from three fields: Tantawan, Maliwan and Benchamas. Daily net production in 2003 from these fields was 104 million cubic feet of natural gas and 24,600 barrels of crude oil. During the year, the company drilled 44 development wells and installed three platforms in Block B8/32. In early 2004, the company completed an upgrade of processing capacity at the Benchamas Field, increasing total capacity to approximately 65,000 barrels of crude oil per day (34,000 net barrels of crude oil per day). During 2004, an exploration program is planned to continue to evaluate the remaining areas of Block B8/32 and the recently acquired concessions. Cambodia: ChevronTexaco operates and holds a 70 percent interest in Block A, located offshore Cambodia in the Gulf of Thailand. Efforts are under way to reduce the company’s working interest in the block to 55 percent. The concession covers approximately 1 million net acres. In 2003, ChevronTexaco drilled one exploration well without commercial success. New 3D seismic data has been acquired and processed over a portion of the block, and the drilling of additional exploration wells is planned for 2004. Australia: ChevronTexaco has a one-sixth interest in the North West Shelf (NWS) Project in offshore Western Australia. Daily net production from the project during 2003 averaged 18,100 barrels of condensate, 282 million cubic feet of natural gas, 17,900 barrels of crude oil and 3,700 barrels of liquefied petroleum gas. Approximately 60 percent of the natural gas was sold, primarily under long-term contracts, in the form of liquefied natural gas (LNG) to major utilities in Japan and South Korea. The remaining natural gas was sold to the Western Australia domestic market. The Train 4 LNG expansion project, which is planned to increase LNG capacity by about 50 percent, is under construction and is expected to have first gas sales by September 2004. The NWS Venture was selected by the People’s Republic of China to be the supplier of LNG for the proposed Guangdong LNG Terminal Project. A 25-year LNG Sale and Purchase Agreement (SPA) for approximately 3.9 trillion cubic feet of natural gas is being negotiated, with first LNG cargoes expected in late 2006 or 2007. In parallel with the execution of the SPA, China National Offshore Oil Corporation (CNOOC) will have the opportunity to acquire participating interest in NWS reserves and production that will supply gas to Guangdong. The company is operator of and has a 57 percent interest in the undeveloped Gorgon area gas fields offshore northwest Australia. ChevronTexaco is actively pursuing long-term gas sales from Gorgon to Australian industrial customers and in international LNG markets, including China, Japan, South Korea and the west coast of North America. In 2003, the Western Australian government granted in-principle approval, through an act of parliament, for the development and construction of a multibillion-dollar gas processing facility on Barrow Island. This represented one of several milestones toward enabling production of natural gas resources in this area. Additionally, ChevronTexaco signed a Memorandum of Understanding with the Gorgon joint venture partners for the supply of LNG to the North America west coast, over a 20-year period (approximately 1.9 trillion cubic feet in total) beginning in 2008. In October 2003, the Gorgon joint venture partners announced an agreement with CNOOC to negotiate the sale of Gorgon LNG to the People’s Republic of China. The agreement, which is subject to the completion of formal contracts, enables CNOOC to purchase an equity stake in the Gorgon gas development project and to facilitate the sale of LNG into the Chinese market. 14
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In 2003, ChevronTexaco participated in the drilling of the Jansz-3 appraisal well in the Io-Jansz gas field discovery, offshore Western Australia, in which the company holds a 50 percent interest. Philippines: The company holds a 45 percent interest in the Malampaya natural gas field located about 50 miles offshore Palawan Island. The Malampaya gas-to-power project represents the first offshore production of natural gas in the Philippines. Daily net production was 140 million cubic feet of natural gas and 7,600 barrels of condensate. Middle East: Saudi Arabia Texaco Inc., a ChevronTexaco affiliate, holds a 60-year concession, originally signed in 1949, to produce onshore crude oil from the Partitioned Neutral Zone (PNZ), located between the Kingdom of Saudi Arabia and the State of Kuwait. The Kingdom of Saudi Arabia and the State of Kuwait each own an undivided 50 percent interest in the PNZ’s hydrocarbon resources. The company, by virtue of its concession, has the rights to the Kingdom’s undivided 50 percent interest in the hydrocarbon resources located in the onshore PNZ, on which it pays a royalty and other taxes on hydrocarbons produced. During 2003, average net production was 133,700 barrels of crude oil per day and 15 million net cubic feet of natural gas per day. The company also has an exploration agreement in Bahrain. The exploration concessions in Qatar expired in mid-2003. Kazakhstan: ChevronTexaco holds a 20 percent interest in the Karachaganak project. Phase 2 of the field development, which included construction of gas injection and liquids processing facilities, as well as a 400-mile pipeline that provides access to world markets, was substantially completed at year-end 2003. When fully operational in mid-2004, daily net production is expected to increase to approximately 40,000 barrels of liquids, including 27,900 barrels of processed liquids that will be exported via the company’s 15 percent-owned Caspian Pipeline. Daily net natural gas production is expected to increase to approximately 140 million cubic feet of natural gas. During 2003, Karachaganak net production averaged 21,400 barrels of liquids and 101 million cubic feet of natural gas per day. Also in 2003, ChevronTexaco sold its interest in the North Buzachi oil and gas field. Papua New Guinea: In 2003, ChevronTexaco sold its interests in Papua New Guinea and resigned operatorship of the Kutubu, Gobe and Moran oil fields. d) Other International Areas Europe: ChevronTexaco holds producing interests in 26 fields in Denmark, Norway and the United Kingdom with a combined daily net production of 167,900 barrels of crude oil and 477 million cubic feet of gas. In the United Kingdom, the daily net production was 115,600 barrels of crude oil and 378 million cubic feet of natural gas in 2003. This includes daily net production of 46,600 barrels of crude oil at the Captain Field, ChevronTexaco is the operator with an 85 percent interest. At Britannia, where ChevronTexaco holds a 32 percent interest and shares operatorship, daily net production averaged 10,300 barrels of crude oil and 204 million cubic feet of natural gas. At the Alba Field in the North Sea, where ChevronTexaco holds a 21 percent interest and operatorship, daily net production averaged 17,500 barrels of crude oil and 4 million cubic feet of natural gas. The Erskine Field, the first high-pressure/ high-temperature gas condensate field developed in the North Sea, reported net crude oil production of 9,400 barrels per day, and net natural gas production averaged 52 million cubic feet per day. ChevronTexaco is the operator and holds a 50 percent interest. In early 2004, the company reached agreements to sell its interests in the Galley, Orwell and Statfjord fields. Daily net production from the three fields in 2003 was 14,000 barrels of crude oil and 37 million cubic feet of natural gas. At the Draugen Field in Norway, ChevronTexaco’s 8 percent share of production during 2003 was 10,300 barrels of crude oil per day. The daily net production from the Danish Underground Consortium was 42,000 barrels of crude oil and 99 million cubic feet of gas. An agreement was announced in October 2003 extending the concession term from 2012 to 2042 and revising other terms of the concession. The agreement was subsequently ratified by the Danish parliament in December 2003. Canada: As part of ChevronTexaco’s portfolio optimization process, the company intends in 2004 to evaluate opportunities to divest selected mature producing fields — currently producing about 35,000 net 15
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barrels of oil-equivalent production per
day — and midstream assets in western Canada. This
decision does not affect strategically significant assets in
Canada, including the Athabasca Oil Sands Project, MacKenzie
Delta gas and east coast Canada exploration, development and
production activities.
In December 2003, ChevronTexaco was the successful bidder on a 50 percent working interest in eight new exploration licenses totaling 5.2 million acres in the Orphan Basin offshore Newfoundland. Excluding Athabasca, which is discussed separately on page 21 of this Annual Report on Form 10-K, daily net production in 2003 from the company’s Canadian operations was 73,100 barrels of crude oil and 110 million cubic feet of natural gas. Venezuela: The company operates the onshore Boscan Field under an Operating Services Agreement and receives operating expense reimbursement and capital recovery, plus interest and an incentive fee. Despite a general strike affecting the entire country in early 2003, total Boscan production averaged 98,900 barrels of crude oil per day for the year. In February 2003, ChevronTexaco was awarded the license for offshore Block 2 in the northeastern Plataforma Deltana, including Loran Field, an undeveloped natural gas discovery. The company plans to begin an exploration and delineation program in Block 2 in 2004. Currently the company holds a 60 percent interest. Argentina: ChevronTexaco operates in Argentina through its subsidiary Chevron San Jorge S.R.L. Chevron San Jorge holds more than 3.8 million exploration and production acres in the Neuquén and Austral basins with working interests ranging from approximately 19 percent to 100 percent in operated license areas. Farm-out agreements are under negotiation in three blocks. Net production in 2003 averaged 64,800 barrels of oil-equivalent per day. Brazil: ChevronTexaco holds working interests ranging from 20 to 68 percent in six deepwater blocks totaling 1.6 million acres at year-end 2003. Exploration is concentrated in the Campos and Santos basins. During 2003, one block was fully relinquished, and two blocks entered into an assessment phase to further evaluate the commercial potential. In the Frade Field, where the company has a 42.5 percent interest, front-end engineering and design work commenced in the fourth quarter of 2003. Colombia: ChevronTexaco currently operates three natural gas fields under two related contracts — the Guajira Association contract and the Build-Operate-Maintain-Transfer (BOMT) contract. The Guajira Association Contract, a 50-50 joint venture production-sharing agreement with the Colombian national oil company, Ecopetrol, expires in December 2004. A contract extension was signed in December 2003 whereby in 2005 ChevronTexaco will continue to operate the fields and receive 43 percent of the production for the economic life of the fields, as well as continue to operate the BOMT contract until it expires in 2016. Total natural gas production averaged 470 million cubic feet per day in 2003. e) Affiliate Operations Kazakhstan: The company’s 50 percent owned affiliate, Tengizchevroil (TCO), reached agreement with the Republic of Kazakhstan in September 2003 to expand operations at the Tengiz and Korolev fields. The agreement formalizes earlier understandings relating to the Sour Gas Injection/ Second Generation project. The project is expected to increase TCO’s crude oil production capacity from about 285,000 barrels per day to between 430,000 and 500,000 barrels per day in the second half of 2006. TCO 2003 total crude oil production of 280,000 barrels per day was marginally below 2002 production levels, which was attributable to TCO’s largest-ever planned maintenance turnaround during the year. Venezuela: ChevronTexaco has a 30 percent interest in the Hamaca integrated oil production and upgrading project located in Venezuela’s Orinoco Belt. Development drilling and major facility construction at Hamaca continued through 2003. Upon completion in third quarter 2004, the facility is expected to have upgrade capacity to 190,000 barrels per day of heavy crude oil, creating a lighter, higher-value crude oil. 16
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Petroleum — Natural Gas and Natural Gas Liquids The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Prior to February 2003, ChevronTexaco’s equity affiliate, Dynegy, purchased substantially all natural gas and natural gas liquids produced by the company in the United States, excluding Alaska, and supplied natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemical plants. At the end of January 2003, the company’s natural gas purchase and sale contracts with Dynegy were terminated. This was preceded by an agreement between ChevronTexaco and Dynegy to discontinue certain commercial arrangements as a result of Dynegy’s decision to exit the gas marketing and trading business. As a result, the company now markets its domestic natural gas production to a variety of third parties through its new unit, ChevronTexaco Natural Gas. The company’s long-term natural gas processing and liquids arrangements with Dynegy were not affected by the early termination of natural gas purchase and sale contracts. During 2003, nearly all of ChevronTexaco’s U.S. natural gas liquids production was sold to Dynegy. Refer to pages FS-10 and FS-11 on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further comments on Dynegy. Outside the United States, the majority of the company’s natural gas sales occur in the United Kingdom, Australia, Canada, Latin America, and in the company’s affiliate operations in Kazakhstan. International natural gas liquids sales primarily take place in the company’s Canadian upstream operations, with lower sales levels in Africa, Australia and Europe. Refer to “Selected Operating Data” on page FS-10 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information on the company’s natural gas and natural gas liquids sales volumes. Distillation operating capacity utilization in 2003, adjusted for sales and closures, averaged 91 percent in the United States (including asphalt plants) and 88 percent worldwide (including affiliates), compared with 94 percent in the United States and 89 percent worldwide in the prior year. ChevronTexaco’s capacity utilization at its U.S. fuels refineries averaged 95 percent in 2003, compared with 98 percent in 2002. ChevronTexaco’s capacity utilization of its wholly owned U.S. cracking and coking facilities, which are the primary facilities used to convert heavier products to gasoline and other light products, averaged 86 percent and 85 percent in 2003 and 2002, respectively. The company processed imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 75 percent of ChevronTexaco’s U.S. refinery inputs in 2003. Prior to October 2001, the company also had interests in eight U.S. refineries with a combined capacity of about 1.3 million barrels per day through its investments in the Equilon and Motiva affiliates. These investments were sold in February 2002, as required by the U.S. Federal Trade Commission for the merger of Chevron and Texaco. 17
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The daily refinery inputs over the last three years for the company and affiliate refineries are shown in the following table: Petroleum Refineries: Locations, Capacities and Inputs
(Inputs and Capacities in Thousands of Barrels
per Day)
Petroleum — Refined Products Marketing Product Sales: The company markets petroleum products throughout much of the world. The principal brands for identifying these products are “Chevron,” “Texaco” and “Caltex.” 18
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The following table shows the company’s and its affiliates’ refined products sales volumes, excluding intercompany sales, over the past three years: Refined Products Sales Volumes1
(Thousands of Barrels per Day)
In the United States, the company supplies, directly or through dealers and jobbers, more than 7,800 Chevron-branded motor vehicle retail outlets, of which about 1,000 are company-owned or -leased stations. The company’s gasoline market area is concentrated in the southern, southwestern and western states. According to the Lundberg Share of Market Report, ChevronTexaco ranks among the top three gasoline marketers in 14 states. In Canada — primarily British Columbia — the company’s Chevron-branded products are sold in 165 company-owned or-leased stations. Outside of the United States and Canada, ChevronTexaco supplies, directly or through dealers and jobbers, approximately 11,600 branded service stations in more than 80 countries. In the Asia-Pacific region, southern and East Africa, and the Middle East, ChevronTexaco uses the Caltex brand name. In Europe, the company has marketing operations in the United Kingdom, Ireland, the Netherlands, Belgium, Luxembourg and the Canary Islands. The company operates in Denmark and Norway through its 50 percent-owned affiliate, HydroTexaco, using the HydroTexaco brand. In West Africa, the company operates or leases to dealers in Cameroon, Côte d’Ivoire, Nigeria, Republic of Congo, Togo and Benin. In these regions, the company mainly uses the Texaco brand name. ChevronTexaco operates across the Caribbean, Central America, and South America with a significant presence in Brazil, using the Texaco brand name. In addition to the above activities, the company manages other marketing businesses globally. In global aviation fuel marketing, the company markets 440,000 barrels per day of aviation fuel in 80 countries, representing a worldwide market share of about 12 percent. The company is the leading marketer of jet fuels in the United States. ChevronTexaco markets residual fuel oils and marine lubricants in more than 65 countries and motor lubricants in more than 180 countries. 19
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Petroleum — Transportation Pipelines: ChevronTexaco owns and operates an extensive system of crude oil, refined products, chemicals, natural gas liquids and natural gas pipelines in the United States. The company also has direct or indirect interests in other U.S. and international pipelines. The company’s ownership interests in pipelines are summarized in the following table: Pipeline Mileage at December 31, 2003
The Caspian Pipeline Consortium (CPC) operates a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. Currently, CPC has seven transportation agreements in place which provide the capacity to transport approximately 600,000 barrels of crude oil per day. ChevronTexaco has a 15 percent ownership interest in CPC. Tankers: ChevronTexaco’s controlled seagoing fleet at December 31, 2003, is summarized in the following table. All controlled tankers were utilized in 2003. In addition, at any given time, the company has approximately 70 vessels under a voyage basis or as time charters of less than one year. Controlled Tankers at December 31, 2003
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 2003, the company’s U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast 20
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and the East Coast, and from California
refineries to terminals on the West Coast and in Alaska and
Hawaii.
The 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. 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 raised the demand for double-hull tankers. During 2003, ChevronTexaco operated a total of 20 double-hull tankers, which includes three additional double-hull tankers that the company took delivery of in 2003. The company is a member of many oil-spill-response cooperatives in areas around the world in which it operates. Chevron Phillips Chemical Company LLC (CPChem) is a 50-50 joint venture with ConocoPhillips Corporation. CPChem owns or has joint venture interests in 32 manufacturing facilities and six research and technical centers in the United States, Puerto Rico, Belgium, China, Mexico, Saudi Arabia, Singapore, South Korea and Qatar. A new olefins and polyolefins complex was commissioned in Qatar in 2003. The complex is owned and operated by Qatar Chemical Company Ltd., a joint venture between CPChem, with a 49 percent interest, and Qatar General Petroleum, which owns the remaining 51 percent. Also during 2003, a 50-50 joint venture with BP Solvay commenced operations of a new high-density polyethylene (HDPE) facility at a CPChem site in the Houston, Texas area. The jointly owned 700-million-pounds per-year HDPE facility is among the largest of its kind in the world and uses CPChem proprietary manufacturing technology. ChevronTexaco’s Oronite brand fuel and lubricant additives business is a leading developer, manufacturer and marketer of performance additives for fuels and lubricating oils. The company owns and operates facilities in the United States, France, the Netherlands, Singapore, Japan and Brazil and has equity interests in facilities in India and Mexico. The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated two surface mines and one underground mine at year-end 2003. In addition, final reclamation activities were under way at two mines that are scheduled to close. P&M also owns an approximate 30 percent interest in Inter-American Coal Holding N.V., which has interests in coal mining operations in Venezuela as well as in trading and transportation activities in Venezuela and Colombia. Sales of coal from P&M’s wholly owned mines and from its affiliates were 13.4 million tons, a decrease of 10 percent from 2002. The reduction resulted from the absence of sales in 2003 from the company’s mining operations in northeastern New Mexico, where production ceased in late 2002. Lower production from P&M’s surface mine, located near Gallup, New Mexico, also contributed to the decline. At year-end 2003, P&M controlled approximately 189 million tons of developed and undeveloped coal reserves, including significant reserves of environmentally desirable low-sulfur fuel. The company is contractually committed to deliver approximately 13 million tons of coal per year through the end of 2006 and believes it can satisfy these contracts from existing coal reserves. Other Activities — Synthetic Crude Oil In Canada, ChevronTexaco holds a 20 percent interest in the Athabasca Oil Sands Project (AOSP). Bitumen is extracted from oil sands and upgraded into synthetic crude oil using hydroprocessing technology. The integrated operation at AOSP commenced in April 2003 when the Scotford Upgrader 21
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started processing bitumen from Train 1 of
the Muskeg River Mine. Full operation with both processing
trains began in June. Bitumen production in the fourth quarter
of 2003 averaged approximately 130,000 barrels per day. Full
capacity is expected to reach 155,000 barrels per day.
ChevronTexaco’s Global Power Generation (GPG) has more than 20 years’ experience in developing and operating commercial power projects. With 13 power assets located in the United States, Asia and Europe, GPG manages the production of more than 3,500 megawatts of electricity in its facilities. All of the facilities are owned through joint ventures. The company operates efficient gas-fired cogeneration facilities, some of which produce steam for use in upstream operations to facilitate production of heavy oil. Worldwide Gasification Technology ChevronTexaco Worldwide Gasification Technology (WGT) is used to convert a wide variety of hydrocarbon feedstocks into clean synthesis gas. The synthesis gas can be used as a feedstock for basic chemicals or to generate electricity in low-emission power plants. ChevronTexaco has licensed its gasification technology to more than 60 plants worldwide. The 50-50 Sasol Chevron Global Joint Venture was established in October 2000 to develop a worldwide gas-to-liquids (GTL) business. Projects to build GTL plants are being considered for Qatar, Nigeria and Australia. The company’s core hydrocarbon technology efforts support the upstream, downstream, and power and gasification businesses. These activities include heavy oil recovery and upgrading, deepwater exploration and production, shallow water production operations, gas-to-liquids processing, hydrocarbon gasification to power, and new and improved refinery processes. Additionally, ChevronTexaco’s Technology Ventures Company focuses on the identification, growth and commercialization of emerging technologies that have the potential to change or transform how energy is produced or consumed. The range of business spans early-stage investing of venture capital in emerging technologies to developing joint venture companies in new energy systems, such as advanced batteries for distributed power and transportation systems and hydrogen fuel storage. During 2003, the company completed the worldwide implementation of a new information technology infrastructure encompassing computing, data management, security, and connectivity of partners, suppliers and employees. The architecture, known as “Net Ready,” provides the foundation for the company to cost-effectively and rapidly integrate advances in computing and network-based technology. ChevronTexaco’s research and development expenses were $238 million, $221 million and $209 million for the years 2003, 2002 and 2001, respectively. Because some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, ultimate success is not 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. 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 to govern not only the manner in which the company conducts its operations, but also the products it sells. ChevronTexaco expects more environmental-related 22
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regulations in the countries where it has
operations. Most of the costs of complying with the many laws
and regulations pertaining to its operations are embedded in the
normal costs of conducting its business.
In 2003, the company’s U.S. capitalized environmental expenditures were $178 million, representing approximately 8 percent of the company’s total consolidated U.S. capital and exploratory expenditures. 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 2004, the company estimates U.S. capital expenditures for environmental control facilities will be $260 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 ChevronTexaco and on the company’s 2003 environmental expenditures, remediation provisions and year-end environmental reserves are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages FS-16 to FS-18 of this Annual Report on Form 10-K. Web Site Access to SEC Reports The company’s Internet Web site can be found at http://www.chevrontexaco.com/. Information contained on the company’s Internet Web site is not part of this report. The company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on the company’s Web site, free of charge, as soon as reasonably practicable after such reports are filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s Internet Web site: http://www.sec.gov/. 23
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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 required by 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 VII on pages FS-53 to FS-59 of this Annual Report on Form 10-K. Note 15, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-40 of this Annual Report on Form 10-K. Richmond Refinery — Alleged Air Violations Chevron Products Company, a division of Chevron U.S.A. Inc., paid $228,275 to the Bay Area Air Quality Management District (BAAQMD) and $50,000 to the District Attorney of the County of Contra Costa, California, in settlement of 35 alleged violations of the BAAQMD’s air regulations at the company’s Richmond Refinery. Item 4. Submission of Matters to a Vote of Security Holders None. 24
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Executive Officers of the Registrant at March 1, 2004
25
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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 who 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.
The information on ChevronTexaco’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-51 of this Annual Report on Form 10-K.
The selected financial data for years 1999 through 2003 are presented on page FS-52 of this Annual Report on Form 10-K.
The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K. 26
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The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instruments,” beginning on page FS-15 and Note 8 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-33.
The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K.
None. Item 9A. Controls and Procedures (a) Evaluation of Disclosure Controls and Procedures
(b) Changes in Internal Control Over Financial Reporting
27
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PART III Item 10. Directors and Executive Officers of the Registrant The information on Directors appearing under the heading “Election of Directors — Nominees For Directors” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 25 and 26 of this Annual Report on Form 10-K for information about Executive Officers of the company. The company has a separately designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the Audit Committee are Sam Ginn (Chairperson), Franklyn G. Jenifer, Charles R. Shoemate, Thomas A. Vanderslice, and John A. Young, all of whom are independent under the New York Stock Exchange Corporate Governance Rules. Of these Audit Committee members, Sam Ginn, Charles R. Shoemate, Thomas A. Vanderslice, and John A. Young are audit committee financial experts as determined by the Board within the applicable definition of the Securities and Exchange Commission. The information contained under the heading “Stock Ownership Information — Section 16(a) Beneficial Ownership Reporting Compliance” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. ChevronTexaco believes all filing requirements were complied with during 2003. The company has adopted a code of business conduct and ethics for directors, officers (including the company’s Chief Executive Officer, Chief Financial Officer and Comptroller) and employees, known as the Business Conduct and Ethics Code (the “Code”). The Code is available on the company’s Internet Web site at http://www.chevrontexaco.com/. Item 11. Executive Compensation The information appearing under the headings “Executive Compensation” and “Directors Compensation” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K. Item 12. Security Ownership of Certain Beneficial Owners and Management The information appearing under the headings “Stock Ownership Information — Directors’ and Executive Officers’ Stock Ownership” and “Stock Ownership Information — Other Security Holders” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. The information contained under the heading “Equity Compensation Plan Information” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. Item 13. Certain Relationships and Related Transactions The information appearing under the heading “Board Operations — Certain Business Relationships Between ChevronTexaco and its Directors and Officers” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. 28
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Item 14. Principal Auditor Fees and Services The information appearing under the headings “Ratification of Independent Auditors — Principal Auditor Fees and Services” and “Ratification of Independent Auditors — Pre-Approval Policies and Procedures” in the Notice of the 2004 Annual Meeting of Stockholders and 2004 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act, in connection with the company’s 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. 29
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PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(b) Reports on Form 8-K:
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SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars
31
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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 9th day of March, 2004.
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 9th day of March, 2004.
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Index to Management’s Discussion and Analysis,
FS-1
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KEY FINANCIAL RESULTS
INCOME (LOSS) BY MAJOR OPERATING AREA BEFORE CHANGES IN ACCOUNTING PRINCIPLES
Net income includes net charges of
$196 million for the cumulative effect of
changes in accounting principles, primarily
$200 million for the adoption on January 1,
2003, of the Financial Accounting Standards
Board Statement No. 143, “Accounting for
Asset Retirement Obligations” (FAS 143).
Refer to Note 25 to the Consolidated
Financial Statements on page FS-50 for
additional discussion. Also in the first
quarter of 2003, the company recorded an
after-tax gain of $4 million for its share
of its affiliate Dynegy’s cumulative effect
of adoption of Emerging Issues Task Force
Consensus No. 02-3, “Issues Involved in
Accounting for Derivative Contracts Held
for Trading Purposes and Contracts Involved
in Energy Trading and Risk Management
Activities,” effective January 1, 2003.
Net income in each period presented
includes amounts for matters that
management characterizes as “special
items,” as described in the following
table.
SPECIAL ITEMS
Because of their nature and amount,
these special items are identified
separately to help explain the changes in
net income and segment income between
periods, as well as to help distinguish
the underlying trends for the company’s
core businesses. Special items are
discussed in detail for each major
operating area in the “Results of
Operations” section beginning on page
FS-6. “Restructuring and Reorganizations”
is described in detail in Note 12 to the
Consolidated Financial Statements on page
FS-37. The categories “Merger-Related
Expenses” and “Extraordinary Loss on
Merger-Related Asset Sales” are described
in detail in the “Texaco Merger
Transaction” section on page FS-5.
BUSINESS ENVIRONMENT AND OUTLOOK As shown in the “Special Items” table, large
net special-item charges adversely affected
net income in 2002 and 2001. In 2002, $2.3
billion of the $3.3 billion of net charges
related to the company’s investment in its
Dynegy Inc. affiliate. Refer to pages FS-10
and FS-11 for a discussion of these matters.
Approximately one-half of the $3.5 billion
of net charges in 2001 related to asset
impairments, primarily the result of
downward revisions to crude oil and natural
gas reserve quantities.
Apart from the effects of special
items, ChevronTexaco’s earnings depend
largely on the profitability of its
business segments in upstream –
exploration and production – and
downstream – refining, marketing and
transportation. Overall earnings trends
are typically less affected by results
from the company’s commodity chemicals
segment and other investments.
The company’s long-term competitive
position, particularly given the
capital-intensive and commodity-based
nature of the industry, is closely
associated with the company’s ability to
invest in projects that provide adequate
financial returns and to manage operating
expenses effectively. The company also
continuously evaluates opportunities to
dispose of assets that are not key to
providing long-term value, or to acquire
assets or operations complementary to its
asset base to help sustain the company’s
growth. In addition to the
asset-disposition and restructuring plans
announced in 2003, other such plans may
occur in future periods and result in
significant gains or losses. Refer to the
“Operating Developments” section on pages
FS-4 and FS-5 for a discussion that
includes references to the company’s asset
disposition activities.
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Comments related to earnings trends for the company’s major business areas
are as follows:
Upstream Year-to-year changes in exploration and production earnings align
most closely with industry price levels for crude oil and natural gas. Crude
oil and natural gas prices are subject to certain external factors over which
the company has no control, including product demand connected with global
economic conditions, industry inventory levels, production quotas imposed by
the Organization of Petroleum Exporting Countries (OPEC), weather-related
damages and disruptions, competing fuel prices and regional supply
interruptions that may be caused by military conflicts, civil unrest or
political uncertainties. The company monitors developments closely in the
countries in which it operates.
Longer-term trends in earnings for this segment are also a function of
other factors besides price fluctuations, including changes in the company’s
oil and gas production levels and the company’s ability to find or acquire and
efficiently produce crude oil and natural gas reserves. Most of the company’s
overall capital investment is in its upstream businesses, particularly outside
the United States. Refer to the “Capital and Exploratory Expenditures” on pages
FS-11 and FS-12 for discussion of the types of upstream investments targeted
for 2004. Investments in upstream projects oftentimes are made well in advance
of the start of the associated crude oil and natural gas production.
Industry price levels for crude oil in early 2003 reached a 12-year high,
reaching a peak of about $38 per barrel. Prices for West Texas Intermediate
(WTI), a benchmark crude, then averaged about $31 for the year, an increase of
about $5 from 2002. The WTI spot prices at the end of December 2003 and at the
end of February 2004 were about $32 and $36, respectively. Among other things,
these relatively high industry prices reflected increased demand from improved
economies in many countries and continued production curtailments by OPEC.
The average spot price of West Texas Intermediate, a benchmark crude oil, rose
19 percent between 2002 and 2003 and remained above $30 per barrel in early 2004.
Natural gas prices were also higher in 2003 than in 2002. Benchmark prices for Henry Hub U.S. natural gas averaged more than $5 per thousand cubic feet in 2003, versus about $3 in 2002. The 2003 year-end price was nearly $6 per thousand cubic feet, about a dollar higher than the year-earlier level. Prices in the United States are typically highest during the winter period, when demand for heating fuel is greatest. At the end of February 2004, the U.S. benchmark price was about $5 per thousand cubic feet. The trend toward higher U.S. natural gas prices is mainly the result of overall demand based upon the strength of
the economy and the declining levels of industry reserves and production in the United States.
Partially offsetting the benefit of higher crude oil and natural gas prices in 2003 was a 4 percent decline in the
company’s worldwide oil-equivalent production from the prior year. The decrease
was largely the result of lower production in the United States due to normal
field declines and production deemed uneconomic to restore following storm
damages in the Gulf of Mexico in the second half of 2002. International
oil-equivalent production was also down slightly — primarily the result of
lower liquids production in the company’s Indonesian operations. The reduced
net production in Indonesia was mainly due to the effect of higher prices on
cost-oil recovery volumes under production-sharing arrangements and the
expiration of a production-sharing agreement in the third quarter 2002.
The company’s oil-equivalent production level in future periods is
uncertain, in part because of production quotas set by OPEC and the potential
for production disruptions from civil unrest and changing geopolitics in the
countries in which the company operates and holds interests. Twenty-two percent
of the company’s net oil equivalent production in 2003 was in the OPEC-member
countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral
Zone between Saudi Arabia and Kuwait. Although the company’s production levels
in these areas were not constrained in
2003 by OPEC quotas, future production could be affected by OPEC-imposed
limitations. In Nigeria, about 45,000 barrels per day of the company’s net
production capacity has been shut-in in certain onshore areas since March 2003
because of security concerns. The company expects to re-enter this area during
2004 to begin repairing damaged equipment. OPEC production constraints could
possibly limit the eventual resumption of a portion or all of this production.
Downstream Refining, marketing and transportation earnings are closely tied to regional supply and demand for refined products and the associated effects on industry refining and marketing margins. The company’s core marketing areas are the western and southeastern United States, western Canada, the Asia-Pacific, northern Europe, Africa and Latin America. FS-3
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Company-specific factors influencing the company’s profitability in this
segment include the operating efficiencies of the refinery network, including
any downtime due to planned maintenance, refinery upgrade projects or operating
incidents.
Downstream earnings improved in 2003, compared with the prior year, on
higher refined product margins in most of the company’s operating areas. In
contrast, margins in the 2002 period were at their lowest levels since the
mid-1990s, as weak market conditions did not allow rising feedstock costs to be
fully recovered from consumers of refined products. Industry margins may be
volatile in the future, depending primarily on price movements for crude oil
feedstocks, the strength of the economies in which the company operates and
other factors.
Chemicals Earnings of $69 million in 2003 were lower than the year-ago period. Depressed earnings in both years reflected excess-supply conditions for the commodity chemicals industry that have kept product margins at low levels for a protracted period. A significant improvement in earnings is not expected in the near future. OPERATING DEVELOPMENTS
Key operating developments and events during 2003 and early 2004 included:
Upstream
year. Of the 1 billion barrels added, nearly 300 million were the result of
discoveries and extensions, including almost 200 million in the United States.
Contract extensions in Colombia and Denmark accounted for
approximately 200 million additional barrels. About 100 million barrels were added through
improved recovery techniques, primarily in Indonesia and the United States. Finally, the largest revisions resulted from
reservoir studies and analyses in Kazakhstan, increasing reserves 300 million barrels.
North America Plans were initiated to improve the competitive performance and operating efficiency of the company’s North America
exploration and production portfolio. These plans include the sale of certain
nonstrategic producing properties and royalty interests in the United States
and possibly western Canada. The company expects to retain about 400 core
fields. Additionally, the company expects to consolidate certain business
functions and office locations.
In late 2003, four new deepwater discoveries in the Gulf of Mexico — Perseus,
Sturgis, Tubular Bells and Saint Malo — were announced.
ChevronTexaco is the operator and holds a 50 percent working interest in both the Perseus and
Sturgis prospects. In the non-operated discoveries, the company holds a 30
percent interest in Tubular Bells and a 12.5 percent interest in Saint Malo.
Additionally at the Blind Faith discovery, an agreement was reached to assume
operatorship and increase the company’s working interest to 50 percent.
At the Tahiti prospect, a major discovery in the deepwater Gulf of Mexico, appraisal
drilling validated the presence of high-quality reservoir sand. ChevronTexaco
is the operator of the prospect and has a 58 percent working interest.
In late 2003, an appraisal well was drilled at the Great White discovery, a nonoperated
exploratory opportunity in the western Gulf of Mexico. The company has a 33
percent working interest in this prospect.
Australia A well was drilled during 2003 in the Io-Jansz natural gas
field, off the northwest coast of Western Australia. Test results provided
verification of the field’s extensive production potential. ChevronTexaco holds
a 50 percent equity interest in the WA-18-R permit area.
Nigeria In October 2003, successful results were announced from the
Aparo-3 appraisal well and the Nsiko-1 wildcat well in deepwater Block OPL-249,
where the company is entitled to a variable equity interest over the life of
the field. In addition, the company announced a significant extension of its 30
percent-owned Usan Field discovery. The drilling of the Usan-4 appraisal well,
located in deepwater Block OPL-222, confirmed the presence of commercial
quantities of oil as well as additional potential in previously untested
reservoirs. In early 2003, the company announced a gas discovery in the 46
percent-owned deepwater Block OPL-218, following completion of the Nnwa-2
appraisal well.
Earlier in the year, the company and its partners reached an agreement
that will govern future operations in the offshore Block OPL-216 concession.
The agreement is expected to enable the continued advancement of plans to
develop the Agbami Field. The company has varying funding obligations and
profit entitlement for the Block OPL-216 development according to the terms of
two production-sharing contracts in the concession.
Angola Major contracts were awarded for the first phase of development in
the Benguela, Belize, Lobito and Tomboco fields in deepwater Block 14. The
first phase will involve the drilling and completion of more than 30
development wells in the Benguela and Belize fields and the construction and
installation of drilling and production facilities that will form a new
production hub in Block 14. The company is the operator and holds a 31 percent
interest in Block 14.
Chad/Cameroon The company’s first cargo of crude oil from fields in
southern Chad was loaded at facilities offshore Cameroon for export to world
markets in late 2003. The crude oil produced in Chad is transported more than
600 miles by pipeline to a floating storage and offloading vessel located
several miles offshore. Full production capacity of 225,000 barrels per day is
expected to be reached in mid-2004. ChevronTexaco holds a 25 percent equity
interest in the Chad-Cameroon upstream operation and about a 23 percent
interest in the pipeline.
Kazakhstan The company’s 50 percent-owned affiliate, Tengiz-chevroil (TCO)
reached an agreement with the government of
FS-4
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Kazakhstan in the third quarter of 2003 to
expand operations at the Tengiz and Korolev
fields. The Sour Gas Injection/Second
Generation project is expected to increase
TCO’s oil production capacity from 285,000
barrels per day to between 430,000 and
500,000 barrels per day in the second half
of 2006. Also, a 400-mile pipeline was completed that will
enable production from the Karachaganak
Field to be exported to world markets via
the Caspian Pipeline when fully operational
in mid-2004.
Colombia An agreement was reached that
extends the company’s production rights in
northern natural gas fields. Under the
contract extension, ChevronTexaco holds a
43 percent interest with the remaining 57
percent held by the country’s national
petroleum company.
Venezuela ChevronTexaco was awarded the
license for the 60 percent-owned and
-operated Block 2 Plataforma Deltana, a
prospective natural gas region in
Venezuela’s Atlantic continental shelf.
Global Natural Gas Projects In the
Gulf of Mexico, the company’s permit
application was approved for plans to
develop the Port Pelican deepwater LNG
facility. The company also filed permits
for the construction of a LNG receiving and
regasification terminal offshore Baja
California, Mexico.
In September 2003, the Gorgon Joint
Venture, in which the company is a 57
percent owner, received in-principle
approval from the Western Australian
government through an act of parliament to
proceed with plans to construct a natural
gas processing facility on Barrow Island.
The decision represented a significant
milestone in the company’s plans to
commercialize its large Gorgon natural gas
resource base. Also in 2003, the Gorgon
Joint Venture announced an agreement with
the China National Offshore Oil Corporation
(CNOOC) in October to negotiate the sale of
Gorgon liquefied natural gas to the
People’s Republic of China. The agreement,
which is subject to the completion of
formal contracts, enables CNOOC to purchase
an interest in the Gorgon gas development
project and to facilitate the sale of LNG
into the Chinese market.
In Nigeria, the company and its
partners in the Brass River Consortium
agreed to advance plans for the front-end
engineering and design work for a new LNG
facility at Brass River. The studies are
expected to be completed in 2004.
A new U.S. wholesale natural gas
marketing unit became fully operational in
April 2003. This business unit was
established following a decision by the
company’s Dynegy affiliate to exit the
natural gas marketing and trading
business. ChevronTexaco’s natural gas
sale and purchase agreements with Dynegy
were terminated at the end of January
2003.
Downstream The company initiated a major restructuring
of its global refining, marketing, and
supply and trading organizations in order
to lower costs, improve efficiency and
achieve sustained improvements in its
financial performance relative to
competitors. The organization was changed
from a geographical to a global functional
alignment and was implemented at the
beginning of 2004.
Downstream asset dispositions,
including the sale of the El
Paso, Texas, refinery and
approximately 400 service stations in
various markets, were completed in 2003 to
improve returns by
focusing investment in areas with the
strongest long-term growth and returns.
Facility upgrade projects at refineries
in Pascagoula, Mississippi; Pembroke, United
Kingdom; and Rotterdam, Netherlands were
completed, resulting in increased product
yields and enabling the manufacture of
low-sulfur fuels. In the Philippines, the
Batangas Refinery was converted into a
finished-product terminal.
Chemicals In Qatar, a new olefins and polyolefins
complex was commissioned in 2003. The
complex is owned and operated through a
joint venture between the company’s 50
percent-owned equity affiliate, Chevron
Phillips Chemical Company (CPChem), and
Qatar General Petroleum. CPChem holds a 49
percent interest in the joint venture.
TEXACO MERGER TRANSACTION Basis of Presentation In October 2001,
Texaco Inc. (Texaco) became a wholly owned
subsidiary of Chevron Corporation
(Chevron) pursuant to a merger
transaction, and Chevron changed its name
to ChevronTexaco Corporation. Certain
operations that were jointly owned by the
combining companies are consolidated in
the accompanying financial statements.
These operations are primarily those of
the Caltex Group of Companies, which was
previously owned 50 percent each by
Chevron and Texaco. The combination was
accounted for as a pooling of interests,
and the accompanying audited consolidated
financial statements for all periods are
presented as if Chevron and Texaco had
always been combined.
Merger Effects Under mandate of the
Federal Trade Commission (FTC) as a
condition to its approval of the merger,
the company sold its interests in Equilon
and Motiva – joint ventures engaged in U.S.
downstream businesses – in February 2002,
resulting in cash proceeds of $2.2 billion.
Indemnification by ChevronTexaco against
certain Equilon and Motiva contingent
liabilities at the date of sale are
discussed in the “Guarantees,
Off-Balance-Sheet Arrangements and
Contractual Obligations, and Other
Contingencies” section beginning on page
FS-13. Other mandated asset dispositions
were also completed during 2002. Net income
and cash proceeds from these other asset
sales were not material. All such assets
sold as a result of the merger provided net
income of approximately $375 million in
2001. The net loss on assets sold under the
FTC mandate is presented in the 2001 income
statement as an extraordinary item.
The company incurred before-tax
merger-related expenses of approximately
$1.6 billion ($1.1 billion after tax) and
$576 million ($386 million after tax) in
2001 and 2002, respectively. Major expenses
included employee severance payments;
incremental pension and medical plan benefit
costs associated with workforce reductions;
legal, accounting, Securities and Exchange
Commission (SEC) filing and investment
banker fees; employee
and office relocations; and costs for
the elimination of redundant
FS-5
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facilities and operations. No significant merger-related expenses occurred in
2003.
RESULTS OF OPERATIONS
Major Business Areas The following section presents the results of operations
for the company’s business segments, as well as for the departments and
companies managed at the corporate level. To aid in the understanding of
changes in segment income between periods, the discussion is in two parts —
first, relating to the underlying operational trends and second, with respect
to special items that tended to obscure the underlying trends. In the following
discussions, the term “earnings” is defined as net income or segment income,
before the cumulative effect of changes in accounting principles.
U.S. Exploration and Production
The improvement in 2003 segment income from 2002 primarily was the result of higher prices for crude oil and natural
gas. Partially offsetting this effect was a decline in oil-equivalent production. The change between 2001 and
2002 reflected significantly lower natural gas realizations and lower
production in the 2002 period.
The company’s average 2003 U.S. liquids realization was $26.66 per barrel,
compared with $21.34 in 2002 and essentially the same in 2001. The average
natural gas realization was $5.01 per thousand cubic feet in 2003, compared
with $2.89 and $4.38 in 2002 and 2001, respectively.
Net oil-equivalent production averaged 933,000 barrels per day in
2003, down 7 percent from 2002 and 12 percent from 2001. The net liquids
component for 2003 averaged 562,000 barrels per day, a decline of 7 percent
from 2002 and 8 percent from 2001. Net natural gas production averaged 2.228
billion cubic feet per day in 2003, 7 percent lower than 2002 and 18 percent
lower than 2001. The oil-equivalent production decline in 2003 was associated
mainly with normal field declines and the absence of about 10,000 to 15,000
barrels per day of production the company deemed uneconomic to restore
following storm damages in the Gulf of Mexico in late 2002. The storms reduced
the company’s 2002 oil-equivalent production by about 20,000 barrels per day.
Net special-item charges of $64 million in 2003 reflected asset
impairments of $103 million — associated mainly with the write-down of assets
in anticipation of sale — and restructuring and reorganization charges of $38
million, which mainly were associated with employee severance costs. Offsetting
a portion of these charges were gains of $77 million from asset sales. Special
items in 2002 and 2001 included asset impairments caused by write-downs in
proved oil and gas reserve quantities for a number of fields. The amount in
2001 related primarily to the Midway Sunset Field in California’s San Joaquin
Valley, after the determination that lower-than-projected heavy oil recovery
would result from the steam-injection process.
International Exploration and Production
The earnings improvement from 2002 to 2003 included the benefit of higher crude oil and natural gas prices. Partially offsetting the improvements were the effects of lower oil-equivalent production and an unfavorable swing in foreign currency effects. Net foreign currency losses of $319 million in 2003 primarily related to a significant weakening of the U.S. dollar against the
FS-6
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currencies of Canada, Australia and the United Kingdom. Earnings improvement in
2002 vs. 2001 were marginally affected by a combination of factors, including
benefits from higher liquids realizations, higher natural gas production, and
lower exploration and income tax expenses, which were offset in part by the
effects of lower liquids production, lower natural gas realizations and higher
depreciation expense.
The average liquids realization, including equity
affiliates, was $26.79 per barrel in 2003, compared with $23.06 in 2002 and
$22.17 in 2001. The average natural gas realization was $2.64 per thousand
cubic feet in 2003, compared with $2.14 in 2002 and $2.36 in 2001.
Daily net liquids production of 1.246 million barrels in 2003 decreased
about 4 percent from 1.295 million barrels in 2002 and about 7 percent from
1.345 million barrels in 2001. The 2003 production decline included about
29,000 barrels per day in Indonesia, related primarily to the effect of lower
cost-oil recovery volumes under production-sharing terms during 2003, and the
expiration of a production-sharing arrangement in the third quarter 2002. New
production occurred in Chad in 2003 and higher volumes were produced in the
United Kingdom and Venezuela. The 2002 production decline from the prior year
included lower output in Indonesia, primarily due to changes in contractual
terms, and in Nigeria, which was mainly associated with OPEC constraints. These
effects were partially offset by increased production in Kazakhstan.
Net natural gas production of 2.064 billion cubic feet per day in 2003 was
up 5 percent from 2002 and more than 20 percent from 2001. During 2003, output
was higher in Australia, Kazakhstan, the Philippines and the United Kingdom. In
2002, areas with production increases from 2001 included the Philippines,
Kazakhstan, Nigeria and Australia.
Special items in 2003 were composed of benefits totaling $150 million
related to income taxes and property sales, partially offset by asset
impairments and charges for employee termination costs. In 2002, special items
included asset impairments connected with write-downs in quantities of proved
oil and gas reserves for fields in Africa and Canada. In 2001, special items
included a $247 million impairment of the LL-652 Field in Venezuela.
U.S. Refining, Marketing and Transportation
The U.S. refining, marketing and transportation earnings in 2003 reflected primarily a recovery in industry margins for refined products, especially on the West Coast. Margins in 2002 were very depressed and at one point, hovered near their 12-year lows. Results for 2001 included earnings of $375 million associated with assets that were later sold as a condition of the merger, which included the company’s Equilon and Motiva joint ventures.
Sales volumes for refined products of 1.514 million barrels per day in
2003 decreased about 5 percent from 2002. Demand was weaker for branded
gasoline, diesel and jet fuels, and there were lower sales under certain supply
contracts. Branded gasoline
sales volumes of 557,000 barrels per day were 4 percent lower than 2002. In 2002, branded gasoline sales increased approximately 4 percent compared with 2001 volumes. The average U.S. refined products sales realization of $39.93 per barrel in 2003 was up from the average of $32.63 per barrel and $36.26 per barrel in 2002 and 2001, respectively.
Special items in 2003 included $160 million for reserves for environmental
remediation and employee severance costs associated with the global downstream
restructuring and reorganization. These charges were partially offset by gains
primarily from the sale of service stations. In 2002, special items included
environmental remediation provisions and asset write-downs for certain refining and marketing assets, and a litigation charge.
International Refining, Marketing and Transportation
The international refining, marketing and transportation segment includes the company’s consolidated refining and marketing businesses, international marine operations, international supply and trading activities, and equity earnings of affiliates, primarily in the Asia-Pacific region.
As in the United States, the international downstream earnings increased
on improved refined-product margins for the industry. The decline in earnings
from 2001 to 2002 reflected not only the trend in refined product margins but
also about a $200 million unfavorable shift in foreign currency effects between
periods.
Total international refined products sales volumes were 2.224 million
barrels per day in 2003, up about 2 percent from
FS-7
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2.175 million in 2002 and about 9 percent lower than 2.454 million
in 2001. Weak economic conditions dampened demand in 2002.
Special items of $189 million in 2003 included charges
for the write-down of the Batangas Refinery in the Philippines
in advance of its conversion to a product terminal facility and
employee severance benefits associated with the global downstream restructuring and reorganization. In addition, special
charges of $70 million were recognized for the impairment of
assets in anticipation of their sale and the company’s share of
losses from an asset sale and asset impairment by an equity
affiliate. The special item in 2002 was for a write-down of the
company’s investment in its publicly traded Caltex Australia
Limited affiliate to its estimated fair value.
Chemicals
Chemicals includes the company’s Oronite division
and equity earnings from the company’s 50 percent-owned
Chevron Phillips Chemical Company LLC (CPChem) affiliate.
Protracted weak demand for commodity chemicals and industry oversupply conditions continued to suppress earnings for
this sector. Special items in 2001 included write-downs of the
CPChem Puerto Rico operations.
All Other
All Other consists of the company’s interest in Dynegy, coal
mining operations, power and gasification businesses, worldwide cash management and debt financing activities, corporate
administrative functions, insurance operations, real estate activities, and technology companies.
The change in net charges between 2002 and 2003 was
largely attributable to the differences in the effects of special
items. The 2003 period also included lower interest expense and
other corporate charges compared with 2002. Aside from the
effect of special items between 2001 and 2002, the net change also
reflected lower corporate charges and net interest expense, as well
as an increase in favorable tax adjustments of $245 million.
Special items in 2003 included a benefit of $365 million
from the exchange of the company’s investment in Dynegy preferred stock for cash and other Dynegy securities. This benefit
was partially offset by charges for asset write-downs of $84
million, primarily in the gasification business; $40 million for
the company’s share of an asset impairment by Dynegy; and
employee severance costs of $16 million.
Special items in 2002 included $2.3 billion related to Dynegy,
composed of $1.6 billion for the write-down of the company’s
investment in Dynegy common and preferred stock to its estimated fair value and $680 million for the company’s share of
Dynegy’s own special items for asset write-downs and revaluations
and a loss on an asset sale. Refer also to pages FS-10 and FS-11 for
“Information Relating to the Company’s Investment in Dynegy.”
Refer to “Texaco Merger Transaction” on page FS-5 for
information related to special items in 2001 for “Merger-Related
Expenses” and “Extraordinary Loss from Merger-Related Asset Sales.”
Consolidated Statement of Income In the following table,
amounts for special items by income statement category are
shown in order to assist in the explanation of changes in those
categories between periods. In addition to the effects of special
items shown in the table, separately disclosed on the face of
the Consolidated Income Statement are a 2003 gain from the
exchange of Dynegy Inc. securities, merger-related expenses,
FS-8
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write-down of investments in Dynegy Inc., the cumulative
effect of changes in accounting principles and the extraordinary
after-tax loss on the sale of assets mandated as a condition of the
merger. These matters are discussed elsewhere in MD&A and in
Notes 2 and 14 to the Consolidated Financial Statements on pages
FS-30 and FS-38.
Explanations follow for variations between years for the
amounts in the table above — after consideration of the effects of
special items — as well as for other income statement categories.
Refer to the preceding segment discussions in this section for
information relating to special items.
Sales and other operating revenues were $120 billion in 2003,
compared with $99 billion in 2002 and $104 billion in 2001.
Revenues increased in 2003 primarily from significantly higher
prices for crude oil, natural gas and refined products worldwide.
Total sales and operating revenues in 2002 declined from
2001 due to lower average realizations for crude oil and refined
products, as well as lower prices and sales volumes for natural gas
in the United States.
Income (loss) from equity affiliates increased in 2003, as
earnings improved for a number of affiliates, including Tengiz-chevroil, LG-Caltex and CPChem. In 2001, income from equity
affiliates included earnings from assets subsequently sold as a
condition of the merger.
Other income in 2003 reflected significantly higher foreign currency losses. Likewise, foreign currency effects largely
contributed to lower “Other income” in 2002 vs. 2001. Foreign
currency losses in 2003 — excluding foreign currency gains or
losses of affiliates which are included in “Income (loss) from
equity affiliates” — were $199 million, compared with a loss of $5
million and a gain of $121 million in 2002 and 2001, respectively. In 2003, losses resulted primarily from the weakening of
the U.S. dollar against the currencies of Canada, Australia and
the United Kingdom. In 2002, foreign currency losses related
to currencies of most countries in which the company has sig-
nificant operations appreciating against the U.S. dollar. Other
income in 2002 also reflected lower interest income.
Purchased crude oil and products costs of $72 billion in 2003
increased about 25 percent from 2002. The increase was the
result of significantly higher prices for crude oil, natural gas
and refined products. Crude oil and products purchase costs
decreased about 5 percent in 2002, primarily due to lower natural
gas prices and reduced natural gas volumes.
Operating, selling, general and administrative expenses of
$13 billion increased from $12 billion in 2002. About $800 million of the increase in 2003 resulted from higher freight rates
from international shipping operations and higher costs of
employee pension plans and
other employee-benefit
expenses. During 2002, operating, selling, general and administrative
expenses increased approximately
$95 million from 2001, primarily
from higher pension expense,
payroll and other employee-
benefit costs. Refer to Note
21, “Employee Benefit Plans,”
beginning on page FS-42 for
discussion of the costs associated
with the company’s pension plans
and other employee benefits in
the comparative periods.
Exploration expenses were
$571 million in 2003, $591 million in 2002 and $1 billion in
2001. Well write-offs were higher
in 2001 than in the other comparative periods.
Depreciation, depletion and
amortization expenses did not change materially for the reporting
periods after consideration of the effects from special items.
Merger-related expenses were $576 million and approximately
$1.6 billion in 2002 and 2001, respectively. No merger-related
expenses were recorded in 2003, reflecting the completion of
merger integration activities in 2002.
Taxes other than on income were $17.9 billion, $16.7 billion
and $15.2 billion in 2003, 2002 and 2001, respectively. The
increase in 2003 primarily reflected the weakening U.S. dollar in
2003 on foreign-currency-denominated duties in the company’s
European downstream operations. In 2002, the increase between
periods resulted from higher sales volumes in the United Kingdom along with currency effects of a weaker U.S. dollar in the
company’s European downstream operations.
Interest and debt expense was $474 million in 2003, compared with $565 million in 2002 and $833 million in 2001. The
declines between periods reflected lower average interest rates on
commercial paper and other variable rate debt and lower average
debt levels.
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Income tax expense corresponded to
effective tax rates of 43 percent in 2003
and 45 percent in 2002 and 2001, after
taking into account the effect of special
items. See also Note 16 on pages FS-40 and
FS-41, “Taxes,” in the Notes to the
Consolidated Financial Statements.
SELECTED OPERATING DATA
MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day;
MBOEPD = Thousands of barrels of oil equivalents per day; Bbl = Barrel;
MCF = Thousands of cubic feet.
Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of gas = 1 barrel of oil.
INFORMATION RELATED TO INVESTMENT IN DYNEGY INC. ChevronTexaco owns an approximate 26
percent equity interest in the common stock
of Dynegy – an energy merchant engaged in
power generation, natural gas liquids
processing and marketing, and regulated
energy delivery. The company also holds
investments in Dynegy notes and preferred
stock.
Investment in Dynegy Common Stock At
December 31, 2003, the carrying value of the
company’s investment in Dynegy common stock
was approximately $150 million. This amount
was about $425 million below the company’s
proportionate interest in Dynegy’s
underlying net assets. This difference
resulted from write-downs of the investment
in 2002 for declines in the market value of
the common shares below the company’s
carrying value that were deemed to be other
than temporary. The approximate $425 million
difference has been assigned to the extent
practicable to specific Dynegy assets and
liabilities, based upon the company’s
analysis of the various factors giving rise
to the decline in value of the Dynegy
shares. The company’s equity share of
Dynegy’s reported earnings is adjusted
quarterly to reflect the difference between
these allocated values and Dynegy’s
historical book values. The market value of
the company’s investment in Dynegy’s common
stock at December 31, 2003, was $415
million.
Investments in Dynegy Notes and
Preferred Stock At the beginning of 2003,
the company held $1.5 billion aggregate
principal amount of Dynegy Series B
Preferred Stock, which was due for
redemption at par value in November 2003. In
August, the company exchanged its preferred
stock for $225 million in cash, $225 million
face value of Dynegy Junior Unsecured
Subordinated Notes due 2016 and $400 million
face value of Dynegy Series C Convertible
Preferred Stock with a stated maturity of
2033.
The company recorded the Junior Notes
and Series C Preferred Stock on the date of
exchange at their fair values of $170
million and $270 million, respectively, for
a total of $440 million. Together with the
$225 million cash, the total amount recorded
on the date of exchange was $665 million. A
gain of $365 million was included in net income at that date for the
difference between the $665 million fair
value received and the net balance sheet
amount of $300 million associated with the
Series B shares.
At December 31, 2003, the estimated
fair values of the Junior Notes and Series
C shares totaled $530 million. The $90
million increase from the $440 million
recorded in August was recorded to
“Investments and Advances,” with an
offsetting amount in “Other Comprehensive
Income.” Future temporary changes in the
estimated fair values of the new securities
likewise will be reported in “Other
Comprehensive Income.” However, if any
future decline in fair value is deemed to
be other than temporary, a charge against
income in the period would be recorded.
Interest that accrues on the notes and
dividends payable
on the preferred stock is recognized
in income each period.
In addition to the $365 million gain
recorded in income in the third quarter
2003, the company recorded $170 million
directly to “Retained Earnings.” The
latter amount represented the company’s
approximate 26 percent equity share of a
gain recorded by Dynegy in connection with
the Series B exchange transaction. Under
the accounting rules applicable to
preferred
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stock redemptions, ChevronTexaco increased its earnings per
share in the third quarter 2003 by $0.16 for the effect of the $170
million recorded directly to “Retained Earnings.”
In February 2004, Dynegy announced agreement to sell its
Illinois Power subsidiary to Ameren Corporation. The sale is
conditioned upon, among other things, the receipt of approvals
from governmental and regulatory agencies. Pending these
approvals, the acquisition is expected to close in the fourth quarter
of 2004. The sale of Illinois Power triggers a mandatory prepayment provision in the Dynegy Junior Notes held by the company.
Under the terms of that provision, 75 percent of the net proceeds,
not including any amounts used for the payment of any debt
associated with Illinois Power, are to be used to retire at par, plus
accrued interest, the $225 million face value notes.
LIQUIDITY AND CAPITAL RESOURCES Cash,
cash equivalents and marketable securities totaled $5.3 billion and $3.8 billion at December 31, 2003 and 2002, respectively.
Cash provided by operating activities in 2003 was $12.3 billion,
compared with $9.9 billion in 2002 and $11.5 billion in 2001. The
2003 increase in cash provided by operating activities mainly
reflected higher earnings in the U.S. upstream and worldwide
downstream businesses. Cash provided by asset sales was $1.1
billion in 2003, $2.3 billion in 2002 and about $300 million in
2001. In 2002, the company received proceeds of $2.2 billion,
including dividends due, from the FTC-mandated sale of the
company’s investments in Equilon and Motiva. Cash provided by
operating activities during 2003 generated sufficient funds for the
company’s capital and exploratory expenditure program and the
payment of dividends to stockholders as well as contributing significantly to a reduction of $3.7 billion in debt levels, $1.4 billion
funding of the company’s pension plans and the increase in cash
and cash equivalents and marketable securities.
Dividends Payments of approximately $3 billion in 2003 and
2002 and $2.9 billion in 2001 were made for dividends or distributions for common stock, preferred stock and minority interests.
Debt, capital lease and minority interest obligations Chevron-Texaco’s total debt and capital lease obligations totaled $12.6
billion at December 31, 2003, down from $16.3 billion at year-end
2002. The company also had minority interest obligations of $268
million, down from $303 million at December 31, 2002.
The company’s debt and capital lease obligations due within
one year, consisting primarily of commercial paper and the current portion of long-term debt, totaled $6 billion at December
31, 2003, down from $9.5 billion at December 31, 2002. Of these
amounts, $4.3 billion and $4.1 billion, respectively, were reclassified to long-term at the end of each period. Settlement of the
obligations at year-end 2003 was not expected to require the use
of working capital in 2004, as the company had the intent and the
ability, as evidenced by committed credit facilities, to refinance
them on a long-term basis. The company’s practice has been to
continually refinance its commercial paper, maintaining levels it
believes appropriate.
At year-end 2003, ChevronTexaco had $4.3 billion in committed credit facilities with various major banks, which permit
the refinancing of short-term obligations on a long-term basis.
These facilities support commercial paper borrowings and also can
be used for other general credit requirements. No borrowings were
outstanding under these facilities during the year or at year-end
2003. In addition, the company had three existing effective “shelf”
registrations on file with the Securities and Exchange Commission
(SEC) that together would permit additional registered debt offerings up to an aggregate of $3.8 billion of debt securities.
In 2003, the company issued $1 billion of new long-term
debt and other financing obligations, including $750 million
of 3.375 percent ChevronTexaco Capital notes due in February
2008, $265 million of new Philippine debt and $19 million of
individually smaller issues. Proceeds from the ChevronTexaco
Capital Company note issue were used to retire commercial
paper. Repayments of long-term debt included $665 million of
Texaco Capital Inc. bonds, $143 million of Philippine debt, $110
million of ChevronTexaco Corporation 8.11 percent notes, $128
million of Nigerian debt and $91 million of individually smaller
issues. Additionally, a $210 million payment was made to the
Republic of Kazakhstan relating to the company’s 1993 acquisition of its interest in the TCO joint venture. Also included in the
company’s long-term debt levels was a noncash reduction of $50
million of ESOP debt.
ChevronTexaco’s senior debt is rated AA by Standard
and Poor’s Corporation and Aa2 by Moody’s Investor Service,
except for senior debt of Texaco Capital Inc., which is rated Aa3.
ChevronTexaco’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and Prime 1 by Moody’s, and the company’s
Canadian commercial paper is rated R-1 (middle) by Dominion
Bond Rating Service. All of these ratings denote high-quality,
investment-grade securities.
The company’s future debt level is dependent primarily on
results of operations, the capital-spending program and cash that
may be generated from asset dispositions. The company believes
it has substantial borrowing capacity to meet unanticipated cash
requirements and, for periods of low prices for crude oil and
natural gas and narrow margins for refined products and commodity chemicals, the company believes that it has the flexibility
to increase borrowings and/or modify capital-spending plans to
continue paying the common stock dividend and maintain the
company’s high-quality debt ratings.
Capital and exploratory expenditures for 2003 totaled $7.4
billion, including the company’s equity share of affiliates’ expenditures. Capital and exploratory expenditures were $9.3 billion
in 2002 and $12 billion in 2001. ChevronTexaco’s equity share
of affiliates’ expenditures were $1.1 billion, $1.4 billion and $1.7
billion in 2003, 2002 and 2001, respectively, and did not require
cash outlays by the company. Expenditures of $5.7 billion in
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2003 for exploration and production activities represented 77
percent of total outlays for the
year, compared with 68 percent
in 2002 and 59 percent in 2001.
International exploration and
production spending of $4.0 billion was 71 percent of worldwide
exploration and production
expenditures in 2003, compared
with 70 percent in 2002 and 66
percent in 2001, reflecting the
company’s continuing focus on
international exploration and
production activities.
Expenditures in 2003 were
$1.9 billion lower than the prior
year, primarily due to amounts
spent in 2002 for large lease
acquisitions in the North Sea
and the Gulf of Mexico, the
Athabasca Oil Sands Project in
western Canada, and additional
common stock investments in
Dynegy. The largest expenditures in 2003 included upstream
projects in Eurasia, West Africa and the Gulf of Mexico. Expenditures in 2002 included lower additional investments in equity
affiliates than in 2001 due to the absence of the company’s share
of expenditures for its Equilon and Motiva investments, which
were sold as a condition of the merger. The 2001 expenditures
included additional investments in TCO and Dynegy, including
the purchase of $1.5 billion of Dynegy preferred stock.
Including the share of spending by affiliates, the company estimates 2004 capital and exploratory expenditures at
$8.5 billion, which is about 15 percent higher than spending in
2003. About $6.4 billion, or 75 percent of the total, is targeted
for exploration and production activities, with $4.5 billion of
that outside the United States. The upstream spending is targeted for the most promising exploratory prospects in Nigeria,
Angola and deepwater Gulf of Mexico and major development
projects in Kazakhstan, Venezuela and Africa. Included in the
upstream expenditures is about $400 million to commercialize
the company’s international natural gas resource base, including
the construction of additional liquefied natural gas (LNG) facilities to help meet future demand for natural gas. Additional LNG
expenditures of about $100 million are included in other segments of the 2004 capital program.
Worldwide downstream spending is estimated to be $1.4
billion, with about $1 billion of the amount on refining and marketing and $400 million on supply and transportation projects.
Investments in chemicals are budgeted at $200 million. Estimates
for power and related businesses are $150 million. The remaining
$300 million is primarily for emerging technologies and information technology infrastructure.
Capital and Exploratory Expenditures
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Pension Obligations In 2003, contributions to the U.S. plans
totaled $1.2 billion. In early 2004, the company contributed $535
million to the U.S. pension plans. Additionally, the company
anticipates contributing about $50 million to the U.S. plans
during the remainder of the year. In years subsequent to 2004,
the company expects contributions to the U.S. pension plans of
about $250 million per year, approximately equal to the cost of
benefits earned in each year. In 2003, contributions to the international pension plans were $214 million and contributions of
$200 million are anticipated in 2004. The actual contribution
amounts are dependent upon investment returns, changes in
pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required
if investment returns are insufficient to offset increases in plan
obligations. Refer also to the discussion of pension accounting in
“Critical Accounting Estimates and Assumptions” beginning on
page FS-18.
FINANCIAL RATIOS Current Ratio — current assets divided by current liabilities.
Generally, two items adversely affected ChevronTexaco’s current
ratio, but in the company’s opinion do not affect its liquidity. First, current assets in all
years
included inventories valued on
a LIFO basis, which at year-end
2003 were lower than replacement costs, based on average
acquisition costs during the year,
by approximately $2.1 billion.
Second, the company benefits
from lower interest rates available on short-term debt by
continually refinancing its commercial paper; however, the
company’s proportionately large
amount of short-term debt in
2002 and 2001 kept its current
ratio at relatively low levels.
Interest
Coverage Ratio —
income before income tax
expense, plus interest and debt
expense and amortization of
capitalized interest, divided by
before-tax interest costs. The
company’s interest coverage ratio
was higher in 2003, primarily due
to higher before-tax income, lower average debt balances and
lower market interest rates.
Debt Ratio — total debt divided by total debt plus equity.
This ratio was approximately 26 percent at December 31, 2003,
compared with 34 percent a year earlier.
Financial Ratios
GUARANTEES, OFF-BALANCE-SHEET ARRANGEMENTS AND Direct or Indirect Guarantees*
At December 31, 2003, the company and its subsidiaries provided guarantees, either directly or indirectly, of $917 million in
guarantees for notes and other contractual obligations of affiliated companies and $256 million for third parties as described,
by major category, below. There are no amounts being carried as
liabilities for the company’s obligations under these guarantees.
Of the $917 million in guarantees provided to affiliates, $716
million relate to borrowings for capital projects or general corporate purposes. These guarantees were undertaken to achieve
lower interest rates and generally cover the construction period
of the capital projects. Approximately 75 percent of the amounts
guaranteed will expire in 2004, with the remaining guarantees
expiring by the end of 2015. Under the terms of the guarantees,
the company would be required to fulfill the guarantee should
an affiliate be in default of its loan terms, generally for the full
amounts disclosed. There are no recourse provisions, and no
assets are held as collateral for these guarantees.
The company provides guarantees of $201 million relating to
obligations in connection with pricing of power purchase agreements for certain of its cogeneration affiliates. Under the terms of
these guarantees, the company may be required to make payments
under certain conditions if the affiliate does not perform under
the agreements. There are no recourse provisions to third parties,
and no assets are held as collateral for these pricing guarantees.
Guarantees of $256 million have been provided to third
parties, including guarantees of approximately $110 million of
construction loans to host governments in the company’s international upstream operations. The remaining guarantees of
$146 million were provided principally as conditions of sale of
the company’s interest in certain operations, to provide a source
of liquidity to the guaranteed parties and in connection with
company marketing programs. No amounts of the company’s
obligations under these guarantees are recorded as liabilities.
About 75 percent of the total amounts guaranteed will expire
in 2004, with the remainder expiring after 2004. The company
would be required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms,
generally for the full amounts disclosed. Approximately $100 million of the guarantees have recourse provisions, which enable the
company to recover any payments made under the terms of the
guarantees from securities held over the guaranteed parties’ assets.
At December 31, 2003, ChevronTexaco had outstanding
guarantees for approximately $238 million of Equilon debt and
leases. Following the February 2002 disposition of its interest in
Equilon, the company received an indemnification from Shell
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Oil Company (Shell) for any claims arising
from the guarantees. Accordingly, the
company has not recorded a liability for
these guarantees. Approximately 50 percent
of the amounts guaranteed will expire within
the 2004–2008 period, with the guarantees of
the remaining amounts expiring by 2019.
Indemnifications The company also
provided certain indemnities of contingent
liabilities of Equilon and Motiva to Shell
and Saudi Refining Inc. in connection with
the February 2002 sale of the company’s
interests in those investments. The
indemnities cover certain contingent
liabilities, including those associated with
the Unocal patent litigation. The company
would be required to perform should the
indemnified liabilities become actual losses
and could be required to make maximum future
payments of $300 million. The company has
paid approximately $28 million under these
contingencies and has disputed approximately
$34 million in claims submitted by Shell
under these indemnities. Shell has requested
arbitration of this dispute, which is
expected to occur in mid-2004. There are no
recourse provisions enabling recovery of any
amounts from third parties nor are any
assets held as collateral. Within five years
of the February 2002 sale, at the buyer’s
option, the company also may be required to
purchase certain assets from Shell for their
respective net book values, as determined at
the time of the company’s purchase. Under
these terms, the company purchased two
lubricant facilities in late 2003 for
immaterial amounts.
The company has also provided
indemnities relating to contingent
environmental liabilities related to assets
originally contributed by Texaco to the
Equilon and Motiva joint ventures and
environmental conditions that existed prior
to the formation of Equilon and Motiva or
that occurred during the periods of
ChevronTexaco’s ownership interests in the
joint ventures. In general, the
environmental conditions or events that are
subject to these indemnities must have
arisen prior to December 2001. Claims
relating to Equilon must be asserted no
later than February 2009, and claims
relating to Motiva must be asserted no
later than February 2012. Under the terms
of the indemnities, there is no maximum
limit on the amount of potential future
payments. The company has not recorded any
liabilities for possible claims under these
indemnities. The company holds no assets as
collateral and has made no payments under
the indemnities.
The amounts payable for the
indemnities described above are to be net
of amounts recovered from insurance
carriers and others and net of liabilities
recorded by Equilon or Motiva prior to
September 30, 2001, for any specific
incident.
Securitization In other
off-balance-sheet arrangements, the
company securitizes certain retail and
trade accounts receivable in its downstream
business through the use of qualifying
special purpose entities (SPEs). At
December 31, 2003, approximately $1
billion, representing about 11 percent of
ChevronTexaco’s total current accounts
receivable balance, were securitized.
ChevronTexaco’s total estimated financial
exposure under these arrangements at
December 31, 2003, was approximately $75
million. These arrangements have the effect
of accelerating ChevronTexaco’s collection
of the securitized amounts. In the event
the SPEs experienced major defaults in the
collection of receivables, ChevronTexaco
believes that it would have no loss
exposure connected with third-party
investments in these securitization
arrangements.
Long-Term Unconditional Purchase
Obligations and Commitments, Throughput
Agreements, and Take-or-Pay Agreements The
company and its subsidiaries have certain
other 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
agreements typically provide goods and
services, such as pipeline and storage
capacity, utilities, and petroleum products,
to be used or sold in the ordinary course of
the company’s business. The aggregate
amounts of required payments under these
various commitments are: 2004 – $1.2
billion; 2005 – $1.1 billion; 2006 – $1
billion; 2007 – $1 billion; 2008 – $1
billion; 2009 and after – $1.9 billion.
Total payments under the agreements were
approximately $1.4 billion in 2003, $1.2
billion in 2002 and $1.5 billion in 2001.
The most significant take-or-pay agreement
calls for the company to purchase
approximately 55,000 barrels per day of
refined products from an equity affiliate
refiner in Thailand. This purchase agreement
is in conjunction with the financing of a
refinery owned by the affiliate and expires
in 2009. The future estimated commitments
under this contract are: 2004 – $700
million; 2005 – $800 million; 2006 – $800
million; 2007 – $800 million; 2008 – $800
million; 2009 – $800 million.
Minority Interests The company has
commitments related to preferred shares of
subsidiary companies that are accounted for
as minority interest. Texaco Capital LLC, a
wholly owned finance subsidiary, has issued
$65 million of Deferred Preferred Shares
Series C. Dividends of approximately $60
million on Series C, at a rate of 7.17
percent compounded annually, will be paid at
the redemption date in February 2005 unless
earlier redemption occurs. Early redemption
may result upon the occurrence of certain
specific events. MVP Production Inc., a
subsidiary, redeemed variable rate
cumulative preferred shares of $75 million
owned by one minority holder during 2003.
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The following table summarizes the
company’s significant contractual
obligations:
Contractual Obligations
1 $4,285 of short-term debt that
the company expects to refinance is
included in long-term debt. The repayment
schedule reflects the expiration of the
company’s committed credit facilities,
although the facilities may be renewed
upon expiration. 2 Includes guarantees of $385 of LESOP debt, $25 due in 2004 and
$360 due after 2007.
The company also has other obligations
connected with asset retirements and
pension plans that are not contractually
fixed as to timing and amount.
FINANCIAL AND DERIVATIVE INSTRUMENTS Commodity Derivative Instruments ChevronTexaco
is exposed to market risks
related to the volatility of crude oil,
refined products, natural gas and refinery
feedstock prices. The company uses
derivative commodity instruments to manage
its exposure to price volatility on a small
portion of its activity, including: firm
commitments and anticipated transactions
for the purchase or sale of crude oil;
feedstock purchases for company refineries;
crude oil and refined products inventories;
and fixed-price contracts to sell natural
gas and natural gas liquids.
The company also uses derivative
commodity instruments for trading purposes,
the results of which were not material to
the company’s financial position, net
income or cash flows in 2003.
The company’s positions are monitored
and managed on a daily basis by an internal
risk control group to ensure compliance with
the company’s risk management policy that
has been approved by the Audit Committee of
the company’s Board of Directors.
The derivative instruments used in the
company’s risk management and trading
activities consist mainly of futures
contracts traded on the New York Mercantile
Exchange and the International Petroleum
Exchange; crude oil and natural gas swap
contracts; options and other derivative
products entered into principally with
major financial institutions; and other oil
and gas companies. Virtually all
derivatives beyond those designated as
normal purchase and normal sale contracts
are recorded at fair value on the
Consolidated Balance Sheet with resulting
gains and losses reflected in income. Fair
values are derived principally from market
quotes and other independent third-party
quotes.
The aggregate effect of a 10 percent
change in prices for derivative contracts
for natural gas, crude oil and petroleum
products would be approximately $20
million. The hypothetical effect on these
contracts was estimated by calculating the
cash value of the contracts as the
difference between the hypothetical and
contract delivery prices, multiplied by the
contract amounts.
Foreign Currency The company enters
into forward exchange contracts, generally
with terms of 180 days or less, to manage
some of its foreign currency exposures.
These exposures include revenue and
anticipated purchase transactions, including
foreign currency capital expenditures and
lease commitments, forecasted to occur
within 180 days. The forward exchange
contracts are recorded at fair value on the
balance sheet with resulting gains and
losses reflected in income.
The aggregate effect on foreign
exchange contracts of a hypothetical 10
percent change to year-end exchange rates
would be approximately $35 million.
Interest Rates 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 are based on the difference
between fixed-rate and floating-rate
interest amounts calculated by reference to
agreed notional principal amounts. Interest
rate swaps related to a portion of the
company’s fixed-rate debt are accounted for
as fair value hedges, whereas interest rate
swaps relating to a portion of the company’s
floating-rate debt are recorded at fair
value on the balance sheet with resulting
gains and losses reflected in income. During
2003, no new swaps were initiated. At
year-end 2003, the weighted average maturity
of “receive fixed” interest rate swaps was
approximately five years. There were no
“receive floating” swaps outstanding at year
end.
A hypothetical 10 percent increase in
interest rates upon the interest rate swaps
would cause the fair value of the “receive
fixed” swaps to decline and the “receive
floating” swaps to increase. The aggregate
effect of these changes would be
approximately $10 million.
TRANSACTIONS WITH RELATED PARTIES ChevronTexaco enters into a number of
business arrangements with related parties,
principally its equity affiliates. These
arrangements include long-term supply or
offtake agreements. In January 2003,
ChevronTexaco and Dynegy agreed to
terminate the natural gas sale and purchase
agreements. Internationally, there are
long-term purchase agreements in place with
the company’s refining affiliate in
Thailand. Refer to page FS-14 for further
discussion. Management believes the
foregoing agreements and others have been
negotiated on terms consistent with those
that would have been negotiated with an
unrelated party.
LITIGATION AND OTHER CONTINGENCIES Unocal Patent Litigation Chevron, Texaco
and four other oil companies (refiners)
filed suit in 1995, contesting the validity
of a patent (‘393’ patent) granted to
Unocal Corporation (Unocal) for certain
reformulated gasoline blends. ChevronTexaco
sells reformulated gasolines 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 during the summer of
1996 that infringed on the claims of the
patent. In February 2001, the
U.S. Supreme Court concluded it would not
review the lower court’s ruling, and the
case was sent back to the District Court
for an accounting of all infringing
gasoline produced after August 1, 1996. The
District Court ruled that the
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per-gallon damages awarded by the jury are limited to infringement that occurs in California only. Additionally, the U.S. Patent
and Trademark Office (USPTO) granted three petitions by the
refiners to re-examine the validity of Unocal’s ‘393’ patent and
has twice rejected all of the claims in the ‘393’ patent. Those
rejections have been appealed by Unocal to the USPTO Board
of Appeals. The District Court judge requested further briefing
and advised that she would not enter a final judgment in this
case until the USPTO had completed its re-examination of the
‘393’ patent. During 2002 and 2003, the USPTO granted two
petitions for reexamination of another Unocal patent, the ‘126’
patent. The USPTO has rejected the validity of the claims of the
‘126’ patent, which could affect a larger share of U.S. gasoline
production. Separately, in March 2003, the Federal Trade
Commission (FTC) filed a complaint against Unocal alleging
that its conduct during the pendency of the patents was in violation of antitrust law. In November 2003, the Administrative Law
Judge dismissed the complaint brought by the FTC. The FTC has
appealed the decision.
Unocal has obtained additional patents that could affect a
larger share of U.S. gasoline production. ChevronTexaco believes
these additional patents are invalid, unenforceable and/or not
infringed. The company’s financial exposure in the event of
unfavorable conclusions to the patent litigation and regulatory
reviews may include royalties, plus interest, for production of
gasoline that is proved to have infringed the patents. The competitive and financial effects on the company’s refining and
marketing operations, although presently indeterminable, could
be material. ChevronTexaco has been accruing in the normal
course of business any future estimated liability for potential
infringement of the ‘393’ patent covered by the 1998 trial court’s
ruling. In 2000, prior to the merger, Chevron and Texaco made
payments to Unocal totaling approximately $30 million for the
original court ruling, including interest and fees.
MTBE Another issue involving the company is the petroleum industry’s use of methyl tertiary butyl ether (MTBE) as a
gasoline additive and its potential environmental impact through
seepage into groundwater. Along with other oil companies, the
company is a party to more than 60 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 release of MTBE
by the company or other parties. Additional lawsuits and claims
related to the use of MTBE, including personal-injury claims,
may be filed in the future. The company’s ultimate exposure
related to these lawsuits and claims is not currently determinable,
but could be material to net income in any one period. Chevron-Texaco has reduced the use of MTBE in gasoline it manufactures
in the United States, including the complete phase-out of MTBE
in California before the end of 2003.
Environmental 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 release of chemicals
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 following table
displays the annual changes to the company’s before-tax environmental remediation
reserves, including those for Superfund
sites. In 2003, the company recorded additional provisions
for estimated remediation costs, primarily at refined products
marketing sites and various closed or divested facilities in the
United States.
As of December 31, 2003, ChevronTexaco had been identified by the Environmental Protection Agency (EPA) or other
regulatory agencies under the provisions of the U.S. Superfund
law as a potentially responsible party or otherwise involved in the
remediation of 218 sites. The company’s remediation reserve for
these sites at year-end 2003 was $113 million. The Superfund law
provides for joint and several liability for all responsible parties.
Any future actions by the EPA and other regulatory agencies to
require ChevronTexaco 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.
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. Although 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 will have a
material adverse 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
FS-16
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impact on the company’s competitive
position relative to other petroleum or
chemicals companies.
Prior to January 1, 2003, additional
reserves for dismantlement, abandonment and
restoration of its worldwide oil, gas and
coal properties at the end of their
productive lives, which included costs
related to environmental issues, were
recognized on a unit-of-production basis.
Effective January 1, 2003, the company
implemented Financial Accounting Standards
Board Statement No. 143, “Accounting for
Asset Retirement Obligations” (FAS 143).
Under FAS 143, the fair value of a liability
for an asset retirement obligation is
recorded when there is a legal obligation
associated with the retirement of long-lived
assets and the liability can be reasonably
estimated. The liability balance for asset
retirement obligations at year-end 2003 was
$2.9 billion. Refer also to Note 25 on page
FS-50 related to FAS 143.
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, as the indeterminate settlement dates
for the asset retirements prevent estimation
of the fair value of the asset retirement
obligation.
Refer to “Environmental Matters”
below for additional information related
to environmental matters.
Income Taxes The company estimates its
income tax expense and liabilities annually.
These liabilities generally are not
finalized with the individual taxing
authorities until several years after the
end of the annual period for which income
taxes have been estimated. The U.S. federal
income tax liabilities have been settled
through 1996 for ChevronTexaco (formerly
Chevron), 1993 for ChevronTexaco Global
Energy Inc. (formerly Caltex), and 1991 for
Texaco. California franchise tax liabilities
have been settled through 1991 for Chevron
and through 1987 for Texaco. 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.
Global Operations ChevronTexaco and its
affiliates have operations in more than 180
countries. Areas in which the company and
its affiliates have major operations include
the United States, Canada, Australia, the
United Kingdom, Norway, Denmark, France,
Partitioned Neutral Zone between Kuwait and
Saudi Arabia, Republic of Congo, Angola,
Nigeria, Chad, Cameroon, Equatorial Guinea,
Democratic Republic of Congo, South Africa,
Indonesia, the Philippines, Singapore,
China, Thailand, Venezuela, Argentina,
Brazil, Colombia, Trinidad and Tobago, and
South Korea. The company’s Tengizchevroil
affiliate operates in Kazakhstan. The
company’s Caspian Pipeline Consortium (CPC)
affiliate operates in Russia and Kazakhstan.
The company’s Chevron Phillips Chemical
Company LLC affiliate manufactures and
markets a wide range of petrochemicals on a
worldwide basis, with manufacturing
facilities in the United States, Puerto
Rico, Singapore, China, South Korea, Saudi
Arabia, Qatar, Mexico and Belgium.
The company’s operations, particularly
exploration and production, can be affected
by changing economic, regulatory and
political environments in the various
countries in which it operates, including
the United States. As has occurred in the
past, actions could be taken by host
governments to increase public ownership of
the company’s partially or wholly owned
businesses and/or to impose additional taxes
or royalties on the company’s operations.
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.
Equity Redetermination 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. One such equity redetermination
process has been under way since 1996 for
ChevronTexaco’s interests in four producing
zones at the Naval Petroleum Reserve at Elk
Hills, California, for the time when the
remaining interests in these zones were
owned by the U.S. Department of Energy. A
wide range remains for a possible net
settlement amount for the four zones.
ChevronTexaco currently estimates its
maximum possible net before-tax liability at
approximately $200 million. At the same
time, a possible maximum net amount that
could be owed to ChevronTexaco is estimated
at about $50 million. The timing of the
settlement and the exact amount within this
range of estimates is uncertain.
Suspended Wells The company also
suspends the costs of exploratory wells
pending a final determination of the
commercial potential of the related oil and
gas fields. The ultimate disposition of
these well costs is dependent on the results
of future drilling activity and/or
development decisions. If the company
decides not to continue development, the
costs of these wells are expensed. At
December 31, 2003, the company had $658
million of suspended exploratory wells
included in properties, plant and equipment,
an increase of $208 million from 2002 and a
decrease of $30 million from 2001. The
increase in 2003 primarily reflects drilling
activities in the United States and Nigeria.
Other Contingencies ChevronTexaco
receives claims from and submits claims to
customers, trading partners, U.S. federal,
state and local regulatory bodies, host
governments, contractors, insurers and
suppliers. The amounts of these claims,
individually and in the aggregate, may be
significant and may take lengthy periods of
time to resolve.
The company and its affiliates also
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. These activities,
individually or together, may result in
gains or losses in future periods.
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 over time 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.
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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-owned
waste-disposal sites used by the company.
An obligation may arise when operations are
closed or sold and at non-ChevronTexaco
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, ChevronTexaco estimated its
worldwide environmental spending in 2003 at
approximately $1.1 billion for its
consolidated companies. Included in these
expenditures were $305 million of
environmental capital expenditures and $820
million of costs associated with the
control and abatement of hazardous
substances and pollutants from ongoing
operations.
For 2004, total worldwide environmental
capital expenditures are estimated at $430
million. These capital costs are in addition
to the ongoing costs of complying with
environmental regulations and the costs to
remediate previously contaminated sites.
It is not possible to predict with
certainty the amount of additional
investments in new or existing facilities or
amounts of incremental operating costs to be
incurred in the future to: prevent, control,
reduce or eliminate releases of hazardous
materials into the environment; comply with
existing and new environmental laws or
regulations; or remediate and restore areas
damaged by prior releases of hazardous
materials. Although these costs may be
significant to the results of operations in
any single period, the company does not
expect them to have a material effect on the
company’s liquidity or financial position.
CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS Management makes many estimates and
assumptions in the
application of generally accepted
accounting principles (GAAP) that may have
a material impact on the company’s
consolidated financial statements and
related disclosures and on the
comparability of such information over
different reporting periods. All such
estimates and assumptions affect reported
amounts of assets, liabilities, revenues
and expenses as well as disclosures of
contingent assets and liabilities.
Estimates and assumptions are based on
management’s experience and other
information available prior to the issuance
of the financial statements. Materially
different results can occur as
circumstances change and additional
information becomes known.
The discussion in this section of
critical accounting estimates or
assumptions is according to the disclosure
guidelines of the Securities and Exchange
Commission (SEC), wherein:
Besides those meeting the critical
criteria, the company makes many other
accounting estimates and assumptions in
preparing its financial statements and
related disclosures. Although not associated
with “highly uncertain matters,” these
estimates and assumptions are also subject
to revision as circumstances warrant, and
materially different results may sometimes
occur.
For example, the recording of deferred
tax assets requires an assessment under the
accounting rules that the future realization
of the associated tax benefits be “more
likely than not.” Another example is the
estimation of oil and gas reserves under SEC
rules that require “...geological and
engineering data (that) demonstrate with
reasonable certainty (reserves) to be
recoverable in future years from known
reservoirs under existing economic and
operating conditions, i.e., prices and costs
as of the date the estimate is made.” Refer
to Table V, “Reserve Quantity Information,”
on page FS-57 for the changes in these
estimates for the three years ending
December 31, 2003, and to Table VII,
“Changes in the Standardized Measure of
Discounted Future Net Cash Flows from Proved
Reserves,” on page FS-59 for estimates of
proved-reserve values for each year-end
2001–2003, which were based on year-end
prices at the time. Note 1 to the
Consolidated Financial Statements includes a
description of the “successful efforts”
method of accounting for oil and gas
exploration and production activities. The
estimates of crude oil and natural gas
reserves are important to the timing of
expense recognition for costs incurred.
The discussion of the critical
accounting policy for “Impairment of
Property, Plant and Equipment and
Investments in Affiliates” on pages FS-19
and FS-20 includes reference to conditions
under which downward revisions of proved
reserve quantities could result in
impairments of oil and gas properties.
This commentary should be read in
conjunction with disclosures elsewhere in
this discussion and in the Notes to the
Consolidated Financial Statements related to
estimates, uncertainties, contingencies and
new accounting standards. Significant
accounting policies are discussed in Note 1
to the Consolidated Financial Statements
beginning on page FS-28. The development and
selection of accounting estimates and
assumptions, including those deemed
critical, and the associated disclosures in
this discussion have been discussed by
management with the audit committee of the
Board of Directors.
The areas of accounting and the
associated critical estimates and
assumptions made by the company are as
follows:
Pension and Other Postretirement
Benefit Plans The determination of pension
plan expense and the requirements for
funding of the company’s major pension plans
are based on a number of actuarial
assumptions. Two critical assumptions are
the rate of return on pension plan assets
and the discount rate applied to pension
plan obligations. For other postretirement
employee benefit (OPEB) plans, which provide
for certain health care and life insurance
for qualifying retired employees and which
are not funded, critical assumptions in
determining OPEB expense are the discount
rate applied to benefit obligations and the
assumed health care cost-trend rates used in
the calculation of benefit obligations.
FS-18
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Note 21 to the Consolidated Financial
Statements, beginning on page FS-42,
includes information for the three years
ending December 31, 2003, on the components
of pension and OPEB expense and the
underlying discount rate assumptions as well
as on the funded status for the company’s
pension plans at the end of 2003 and 2002.
To determine the estimate of long-term
rate of return on pension assets, the
company employs a rigorous process that
incorporates actual historical asset-class
returns and an assessment of expected future
performance, and takes into consideration
external actuarial advice and asset-class
risk factors. Asset allocations are
regularly updated using pension plan
asset/liability studies, and the
determination of the company’s estimates of
long-term rates of return are consistent
with these studies. For example, at December
31, 2003 and 2002, the estimated long-term
rate of return on U.S. pension plan assets,
which account for about 70 percent of the
company’s pension plan assets, was 7.8
percent, as compared with 9 percent at the
end of 2001. The year-end market-related
value of U.S. pension-plan assets used in
the determination of pension expense was
based on the market values in the preceding
three months as opposed to the maximum
allowable period of five years under U.S.
accounting rules. Management considers the
three-month time period long enough to
minimize the effects of distortions from
day-to-day market volatility and still be
contemporaneous to the end of the year.
The discount rate used in the
determination of pension benefit obligations
and pension expense is based on high-quality
fixed income investment interest rates. At
December 31, 2003, the company calculated
the U.S. pension obligations using a 6.0
percent discount rate. The discount rates
used at the end of 2002 and 2001 were 6.8
percent and 7.3 percent, respectively.
An increase in the expected return on
pension plan assets or the discount rate
would reduce pension plan expense, and vice
versa. Total pension expense for 2003
was $697 million. As an indication of
interest-rate sensitivity to the
determination of pension expense, a 1
percent increase in the expected return on
assets of the company’s primary U.S. pension
plan, which accounted for about 61 percent
of the companywide pension obligation, would
have reduced total pension plan expense for
2003 by approximately $30 million. A 1
percent increase in the discount rate for
this same plan would have reduced total
benefit plan expense by approximately $120
million. The actual rates of return on plan
assets and discount rates may vary
significantly from estimates because of
unanticipated changes in the world’s
financial markets.
Based on the expected changes in
pension plan asset values and pension
obligations in 2004, the company does not
believe any significant funding of the
pension plans will be mandatory during the
year. For the U.S. plans, this determination
was made in accordance with the minimum
funding standard of the Employee Retirement
Income Security Act (ERISA). However, the
company made discretionary contributions of
$535 million to U.S. plans in early 2004.
Later in 2004, additional discretionary
payments of $200 million and $50 million for
the international and U.S. plans,
respectively, are anticipated.
Pension expense is included on the
Consolidated Statement of Income in
“Operating expenses” or “Selling, general
and administrative expenses” and applies to
all business segments. Depending upon the
funding status of the different plans,
either a long-term prepaid asset or a
long-term liability is recorded for plans
with overfunding or underfunding,
respectively. Any unfunded accumulated
benefit obligation in excess of recorded
liabilities is recorded in “Other
comprehensive income.” See Note
21 to the Consolidated Financial Statements
beginning on page FS-42 for the
pension-related balance sheet effects at
the end of 2003 and 2002.
For the company’s OPEB plans, expense
for 2003 was $228 million and was also
recorded as “Operating expenses” or
“Selling, general and administrative
expenses” in all business segments. The
discount rate applied to the company’s
U.S. OPEB obligations at December 31, 2003
was 6.0 percent – the same discount rate
used for U.S. pension obligations. The
assumed health care cost-trend rates used
to calculate OPEB obligations starting in
2003 was an 8.4 percent cost increase over
the previous year gradually dropping over
four years to a long-term ultimate
rate-increase assumption of 4.5 percent
for 2007 and thereafter. The health care
cost-trend increase assumption and
duration to reach that rate are company
estimates, developed in consultation with
external consultants, and are consistent
with the company’s actual experience.
As an indication of discount-rate
sensitivity to the determination of OPEB
expense in 2003, a 1 percent increase in
the discount rate for the company’s
primary U.S. OPEB plan, which accounted
for the significant majority of the
companywide OPEB obligation, would have
decreased OPEB expense by approximately
$10 million.
Impairment of Property, Plant and
Equipment and Investments in Affiliates The
company assesses its property, plant and
equipment (PP&E) for possible impairment
whenever events or changes in circumstances indicate
that the carrying value of the assets may
not be recoverable. Such indicators include
changes in the company’s business plans,
changes in commodity prices and for oil and
gas properties, significant downward
revisions of estimated proved reserve
quantities. If the carrying value of an
asset exceeds the future undiscounted cash
flows expected from the asset, an impairment
charge is recorded for the excess of
carrying value of the asset over its fair
value.
Determination as to whether and how
much an asset is impaired involves
management estimates on highly uncertain
matters such as future commodity prices, the
effects of inflation and technology
improvements on operating expenses and the
outlook for global or regional market supply
and demand conditions for crude oil, natural
gas, commodity chemicals and refined
products. However, the impairment reviews
and calculations are based on assumptions
that are consistent with the company’s
business plans and long-term investment
decisions.
The amount and income statement
classification of major impairments of PP&E
for the three years ending December 31,
2003, are included in the commentary on the
business segments elsewhere in this
discussion, as well as in Note 3 to the
Consolidated Financial Statements on pages
FS-30 and FS-31. An estimate as to the
sensitivity to earnings for these periods if
other assumptions had been used in the
impairment reviews and impairment
calculations is not practicable, given the
broad range of the company’s PP&E and the
number of assumptions involved in the
estimates. That is, favorable changes to
some assumptions might have avoided the need
to impair any assets in these periods,
whereas unfavorable changes might have
caused an additional unknown number of other
assets to become impaired.
Investments in common stock of
affiliates that are accounted for under the
equity method as well as investments in
other securities of these equity investees
are reviewed for impairment when the fair
value of the investment falls below the
company’s carrying value. When such a
decline is deemed to be other than
temporary, an impairment charge is recorded
to the
FS-19
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income statement for the difference between the investment’s carrying value and
its estimated fair value at the time. In making the determination as to whether
a decline is other than temporary, the company considers such factors as the
duration and extent of the decline, the investee’s financial performance and
the company’s ability and intention to retain its investment for a period that
will be sufficient to allow for any anticipated recovery in the investment’s
market value. Differing assumptions could affect whether an investment is
impaired in any period and the amount of the impairment and are not subject to
sensitivity analysis.
From time to time, the company performs
impairment reviews and determines that no
write-down in the carrying value of an asset
or asset group is required. For example,
when significant downward revisions to crude
oil and natural gas reserves are made for
any single field or concession, an
impairment review is performed to determine
if the carrying value of the asset remains
recoverable. Also, if the expectation of
sale of a particular asset or asset group in
any period has been deemed more likely than
not, an impairment review is performed, and
if the estimated net proceeds exceed the
carrying value of the asset or asset group,
no impairment charge is required. Such
calculations are reviewed each
period until the asset or asset group
is disposed of. Assets that are not impaired
on a held-and-used basis could possibly
become impaired if a decision was made to
sell such assets and the estimated proceeds
were less than the associated carrying
values.
Contingent Losses Management also makes
judgments and estimates in recording
liabilities for claims, litigation, tax
matters and environmental remediation.
Actual costs can frequently vary from
estimates for a variety of reasons. For
example, the costs from settlement of claims
and litigation can vary from estimates based
on differing interpretations of laws,
opinions on culpability and assessments on
the amount of damages. Similarly,
liabilities for environmental remediation
are subject to change because of changes in
laws, regulations and their interpretation;
the determination of additional information
on the extent and nature of site
contamination; and improvements in
technology.
Under the accounting rules, a
liability is recorded for these types of
contingencies if management determines the
loss to be both probable and estimable. The
company generally records these losses as
“Operating expenses” or “Selling, general
and administrative expenses” on the
Consolidated Statement of Income. Refer to
the business segment discussions elsewhere
in this discussion and in Note 3 to the
Consolidated Financial Statements on pages
FS-30 and FS-31 for the effect on earnings
from losses associated with certain
litigation and environmental remediation
and tax matters for the three years ended
December 31, 2003.
An estimate as to the sensitivity to
earnings for these periods if other
assumptions had been used in recording
these liabilities is not practical because
of the number of contingencies that must be
assessed, the number of underlying
assumptions and the wide range of
reasonably possible outcomes, in terms of
both the probability of loss and the
estimates of such loss.
NEW ACCOUNTING STANDARDS In January 2003, the Financial Accounting
Standards Board (FASB) issued
Interpretation No. 46, "Consolidation of
Variable Interest Entities” (FIN 46). FIN
46 amended Accounting Research Bulletin
(ARB) 51, “Consolidated Financial
Statements,” and established standards for
determining circumstances under which a
variable interest entity (VIE) should be
consolidated by its primary beneficiary.
FIN 46 also requires disclosures about VIEs
that the company is not required to
consolidate but in which it has a
significant variable interest. In December
2003, the FASB issued FIN 46-R, which not
only included amendments to FIN 46, but
also required application of the
interpretation to all affected entities no
later than March 31, 2004 for calendar-year
reporting companies. Prior to this
requirement, however, companies must apply
the interpretation to special-purpose
entities by December 31, 2003. The adoption
of FIN 46-R as it relates to
special-purpose entities did not have a
material impact on the company’s results of
operations, financial position or
liquidity, and the company does not expect
a material impact upon its full adoption of
the interpretation as of March 31, 2004.
ACCOUNTING FOR MINERAL INTERESTS INVESTMENT The SEC has questioned certain public
companies in the oil and gas and mining
industries as to the proper accounting for,
and reporting of, acquired contractual
mineral interests under FASB Statement No.
141, “Business Combinations” (FAS 141), and
FASB Statement No. 142, “Goodwill and
Intangible Assets” (FAS 142). These
accounting standards became effective for
the company on July 1, 2001, and January 1,
2002, respectively.
At issue is whether such mineral interest
costs should be classified on the balance
sheet as part of “Properties, plant and
equipment” or as “Intangible assets.” The
company will continue to classify these
costs as “Properties, plant and equipment”
and apportion them to expense in future
periods under the company’s existing
accounting policy until authoritative
guidance is provided.
For ChevronTexaco, the net book values of
this category of mineral interest investment
at December 31, 2003 and 2002, were $3.8
billion and $4.1 billion, respectively. If
reclassification of these balances becomes
necessary, the company’s statements of
income and cash flows would not be affected.
However, additional disclosures related to
intangible assets would be required as
prescribed under the associated accounting
standards.
FS-20
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REPORT OF MANAGEMENT To the Stockholders of ChevronTexaco Corporation Management of ChevronTexaco 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 auditors 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 auditors 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 and the independent auditors
have free and direct access to the Audit Committee without the presence of
management.
REPORT OF INDEPENDENT AUDITORS To the Stockholders and the Board of Directors of ChevronTexaco Corporation In our opinion, the consolidated financial statements listed in the index
appearing under Item 15(a)(1) on page 30 present fairly, in all material
respects, the financial position of ChevronTexaco Corporation and its
subsidiaries at December 31, 2003 and 2002, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2003 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 15(a) (2) on page 30 presents
fairly, in all material respects, the information set forth therein when read
in conjunction with the related consolidated financial statements. These
financial statements and the financial statement schedule are the
responsibility of the Company’s management; our responsibility is to express an
opinion on these financial statements and the financial statement schedule
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.
As discussed in Note 25 on page FS-50 to the financial statements, the Company
changed its method of accounting for asset retirement obligations as of January
1, 2003.
/s/ PricewaterhouseCoopers LLP FS-21
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Millions of dollars, except per-share amounts
See accompanying Notes to Consolidated Financial Statements.
FS-22
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Millions of dollars
See accompanying Notes to Consolidated Financial Statements.
FS-23
Table of Contents
Millions of dollars, except per-share amounts
See accompanying Notes to Consolidated Financial Statements.
FS-24
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See accompanying Notes to Consolidated Financial Statements.
FS-25
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Shares in thousands; amounts in millions of dollars
See accompanying Notes to Consolidated Financial Statements.
FS-26
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Shares in thousands; amounts in millions of dollars
See accompanying Notes to Consolidated Financial Statements.
FS-27
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NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General ChevronTexaco 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 activities. In addition,
ChevronTexaco holds investments in power
generation and gasification businesses.
Collectively, these companies operate in
more than 180 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 principles generally accepted in
the United States of America. 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 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 controlled 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. As part
of that accounting, the company recognizes
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 currently in income.
Deferred income taxes are provided for
these gains and losses.
Investments are assessed for possible
impairment when there are indications that
the fair value of the investment may be
below the company’s carrying value. When
such a condition is deemed to be other than
temporary, the carrying value of the
investment is written down to its fair
value, and the amount of the write-down is
included in net income. In making the
determination as to wheth | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
