Chevron Corporation 10-K 2004
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
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)
Registrants telephone number, including area code (925) 842-1000
(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 registrants 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 registrants 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 companys 2004 Annual Meeting of Stockholders (in Part III)
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 ChevronTexacos operations that are based on managements 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 companys 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 companys 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 companys ability to successfully implement the restructuring of its worldwide downstream organization and other business units; the companys 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.
Item 1. Business
(a) General Development of Business
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 companys 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 companys employees were employed in U.S. operations, of which approximately 3,400 were unionized.
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 worlds 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 companys 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.
Refer to pages FS-2 through FS-4 of this Annual Report on Form 10-K in Managements Discussion and Analysis of Financial Condition and Results of Operations for a discussion on the companys current business environment and outlook.
ChevronTexacos 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 worlds largest integrated petroleum companies comprise the companys 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 companys 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 companys 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.
The companys largest business segments are exploration and production (upstream) and refining, marketing and transportation (downstream). Chemicals is also a significant segment, conducted mainly by the companys 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. ChevronTexacos 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 companys 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 companys 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 companys 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 companys 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 companys oil and gas exploration and production operations and the safety of the companys employees. Political and community unrest has disrupted the companys production in the past, most recently in Nigeria and Venezuela.
A discussion of the companys capital and exploratory expenditures is contained on pages FS-11 and FS-12 of this Annual Report on Form 10-K.
Petroleum Exploration and Production
The following table summarizes the companys 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
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 companys 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 companys acreage is shown in the following table.
Acreage1 At December 31, 2003
(Thousands of Acres)
Refer to Table IV on page FS-56 of this Annual Report on Form 10-K for data about the companys 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.
Table V on page FS-57 of this Annual Report on Form 10-K sets forth the companys 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, ChevronTexacos 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 companys net additions to net proved reserves of crude oil and natural gas liquids and natural gas compared with net production during 2003.
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 companys 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 companys 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 companys proved developed Australian, Canadian, Colombian and Philippine reserves.
Details of the companys 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 companys net interest in productive and dry development wells completed in each of the past three years and the status of the companys 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.
Development Well Activity
The following table summarizes the companys 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 Managements 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
Details of the companys 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.
ChevronTexacos 2003 key upstream activities not discussed in Managements 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.
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 companys 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
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.
Nigeria: ChevronTexacos 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. ChevronTexacos 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 companys first project to use the Sasol Chevron Global Joint Ventures 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.
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, Angolas 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 companys concessions in Cabinda. Net production from ChevronTexacos 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 companys 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.
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: ChevronTexacos 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 Indonesias 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
cogeneration facility in support of CPIs operation in North Duri. In addition to the above interests, ChevronTexaco has a 25 percent nonoperated interest in South Natuna Sea Block B.
ChevronTexacos 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. ChevronTexacos 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 companys 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 companys 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 Peoples 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 Peoples 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.
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 PNZs hydrocarbon resources. The company, by virtue of its concession, has the rights to the Kingdoms 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 companys 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, ChevronTexacos 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 ChevronTexacos portfolio optimization process, the company intends in 2004 to evaluate opportunities to divest selected mature producing fields currently producing about 35,000 net
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 companys 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 companys 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 TCOs 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 TCOs 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 Venezuelas 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.
The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Prior to February 2003, ChevronTexacos 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 companys U.S. refineries and chemical plants. At the end of January 2003, the companys 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 Dynegys 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 companys 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 ChevronTexacos U.S. natural gas liquids production was sold to Dynegy. Refer to pages FS-10 and FS-11 on Form 10-K in Managements Discussion and Analysis of Financial Condition and Results of Operations for further comments on Dynegy.
Outside the United States, the majority of the companys natural gas sales occur in the United Kingdom, Australia, Canada, Latin America, and in the companys affiliate operations in Kazakhstan. International natural gas liquids sales primarily take place in the companys 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 Managements Discussion and Analysis of Financial Condition and Results of Operations for further information on the companys 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. ChevronTexacos capacity utilization at its U.S. fuels refineries averaged 95 percent in 2003, compared with 98 percent in 2002. ChevronTexacos 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 ChevronTexacos 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.
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.
The following table shows the companys 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 companys 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 companys 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 dIvoire, 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.
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 companys ownership interests in pipelines are summarized in the following table:
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: ChevronTexacos 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.
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 companys U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast
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.
ChevronTexacos 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 companys 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&Ms 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 companys mining operations in northeastern New Mexico, where production ceased in late 2002. Lower production from P&Ms 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.
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
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.
ChevronTexacos 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.
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 companys 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, ChevronTexacos 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.
ChevronTexacos 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 companys overall investment in this area is not significant to the companys consolidated financial position.
Virtually all aspects of the companys 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
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 companys U.S. capitalized environmental expenditures were $178 million, representing approximately 8 percent of the companys 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 companys 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 companys 2003 environmental expenditures, remediation provisions and year-end environmental reserves are contained in Managements 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.
The companys Internet Web site can be found at http://www.chevrontexaco.com/. Information contained on the companys Internet Web site is not part of this report.
The companys 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 companys 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 SECs Internet Web site: http://www.sec.gov/.
The location and character of the companys 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 companys 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 BAAQMDs air regulations at the companys Richmond Refinery.
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 Corporations Executive Officers have held one or more of such positions for more than five years.
The information on ChevronTexacos 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 Managements Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K.
The companys discussion of interest rate, foreign currency and commodity price market risk is contained in Managements 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 Managements Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K.
(a) Evaluation of Disclosure Controls and Procedures
(b) Changes in Internal Control Over Financial Reporting
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 companys 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 companys 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 companys 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 companys Internet Web site at http://www.chevrontexaco.com/.
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 companys 2004 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K.
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 companys 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 companys 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.
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 companys 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.
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 companys 2004 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(b) Reports on Form 8-K:
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars
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.
Index to Managements Discussion and Analysis,
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 Dynegys 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.
Comments related to earnings trends for the companys 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 companys oil and gas production levels and the companys ability to find or acquire and efficiently produce crude oil and natural gas reserves. Most of the companys 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
Company-specific factors influencing the companys 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 companys 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.
Key operating developments and events during 2003 and early 2004 included:
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 companys 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.
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 TCOs 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 companys 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 countrys 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 Venezuelas Atlantic continental shelf.
Global Natural Gas Projects In the Gulf of Mexico, the companys 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 companys 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 Peoples 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 companys Dynegy affiliate to exit the natural gas marketing and trading business. ChevronTexacos natural gas sale and purchase agreements with Dynegy were terminated at the end of January 2003.
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
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 companys 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
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 companys 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
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 companys 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 companys investment in its publicly traded Caltex Australia Limited affiliate to its estimated fair value.
Chemicals includes the companys Oronite division and equity earnings from the companys 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.
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-
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.
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 companys investments in Equilon and Motiva. Cash provided by operating activities during 2003 generated sufficient funds for the companys 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 companys 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-Texacos 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.
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 companys 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
Capital and Exploratory Expenditures
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.
Current Ratio current assets divided by current liabilities. Generally, two items adversely affected ChevronTexacos current ratio, but in the companys 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 companys 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 companys 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.
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 20042008 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 companys 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 buyers 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 companys 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 ChevronTexacos 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.
The following table summarizes the companys significant 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 companys 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 companys financial position, net income or cash flows in 2003.
The companys positions are monitored and managed on a daily basis by an internal risk control group to ensure compliance with the companys risk management policy that has been approved by the Audit Committee of the companys Board of Directors.
The derivative instruments used in the companys 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.
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 Unocals 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 companys 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 companys 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 courts 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 industrys 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 companys 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.
impact on the companys 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 companys 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 companys Tengizchevroil affiliate operates in Kazakhstan. The companys Caspian Pipeline Consortium (CPC) affiliate operates in Russia and Kazakhstan. The companys 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 companys 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 companys partially or wholly owned
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 companys 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 companys 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 managements 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:
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 companys 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 companys 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 companys 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 companys 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 worlds 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
income statement for the difference between the investments 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 investees financial performance and the companys ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investments 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.
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 managements best estimates and judgments.
The companys 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 companys 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 managements 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 companys 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 Companys 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
Millions of dollars, except per-share amounts
See accompanying Notes to Consolidated Financial Statements.
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See accompanying Notes to Consolidated Financial Statements.
Millions of dollars, except per-share amounts
See accompanying Notes to Consolidated Financial Statements.
Millions of dollars
See accompanying Notes to Consolidated Financial Statements.
Shares in thousands; amounts in millions of dollars
See accompanying Notes to Consolidated Financial Statements.
Shares in thousands; amounts in millions of dollars
See accompanying Notes to Consolidated Financial Statements.
Millions of dollars, except per-share amounts
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 companys 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 companys proportionate share of the dollar amount of the affiliates 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 companys 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