Chevron Corporation 10-K 2007
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
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
Securities registered pursuant to Section 12(b) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Act. (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No 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 $136,407,118,275 (As of June 30, 2006)
Number of Shares of Common Stock outstanding as of February 23, 2007 2,157,780,998
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2007 Annual Meeting and 2007 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the companys 2007 Annual Meeting of Stockholders (in Part III)
CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevrons 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, schedules, estimates, budgets 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. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements 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; the inability or failure of the companys joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the companys net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest or severe weather; the potential liability for remedial actions under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from pending or future litigation; the companys acquisition or disposition of assets; government-mandated sales, divestitures, recapitalizations, changes in fiscal terms or restrictions on scope of company operations; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading Risk Factors in this report. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.
Chevron Corporation,1 a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and foreign subsidiaries that engage in fully integrated petroleum operations, chemicals operations, mining operations of coal and other minerals, power generation and energy services. The company conducts business activities in the United States and approximately 180 other countries. Exploration and production (upstream) operations consist of exploring for, developing and producing crude oil and natural gas and also marketing natural gas. Refining, marketing and transportation (downstream) operations relate to refining crude oil into finished petroleum products; marketing crude oil 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. Chemical operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives.
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, 2006, Chevron had nearly 62,500 employees (including about 6,600 service station employees). Approximately 28,800, or 46 percent, of the companys employees were employed in U.S. operations.
On August 10, 2005, the company acquired Unocal Corporation (Unocal), an independent oil and gas exploration and production company. This acquisition was accounted for under the rules of Financial Accounting Standards Board Statement No. 141, Business Combinations. Unocals principal upstream operations were in North America and Asia, including the Caspian region. Other activities included ownership interests in proprietary and common carrier pipelines, natural gas storage facilities and mining operations. Further discussion of the Unocal acquisition is contained in Note 2 beginning on page FS-34 of this Annual Report on Form 10-K.
Petroleum industry operations and profitability are influenced by many factors, and individual petroleum companies have little control over some of them. Governmental policies, particularly in the areas of taxation, energy and the environment have a significant impact on petroleum activities, regulating how companies are structured and 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 global economies, although weather patterns and taxation relative to other energy sources also play a significant part. Seasonality is not a primary driver to changes in the companys quarterly earnings during the year.
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. Chevron 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, Chevron also competes with fully integrated major petroleum companies and other independent refining, marketing and transportation entities in the sale or acquisition 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. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term Chevron and such terms as the company, the corporation, our, we and us may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise, it does not include affiliates of Chevron i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or investments accounted for by the cost method. 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-9 of this 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.
Chevrons primary objective is to create value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. As a foundation for achieving this objective, the company had established the following strategies, which continue into 2007:
The company will also continue to invest in renewable-energy technologies, with an objective of capturing profitable positions in important renewable sources of energy.
The upstream, downstream and chemicals activities of the company and its equity affiliates are widely dispersed geographically, with operations in North America, South America, Europe, Africa, the Middle East, Asia, and Australasia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2006, and assets as of the end of 2006 and 2005 for the United States and the companys international geographic areas are in Note 8 to the consolidated financial statements beginning on page FS-38 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 in Notes 12 and 13 on pages FS-41 to FS-43.
Total reported expenditures for 2006 were $16.6 billion, including $1.9 billion for Chevrons share of expenditures by affiliated companies, which did not require cash outlays by the company. In 2005 and 2004, expenditures were $11.1 billion and $8.3 billion, respectively, including the companys share of affiliates expenditures of $1.7 billion and $1.6 billion in the corresponding periods. The 2005 amount excludes the $17.3 billion acquisition of Unocal.
Of the $16.6 billion in expenditures for 2006, 77 percent, or $12.8 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2005 and 2004. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the three years, reflecting the companys continuing focus on opportunities that are available outside the United States.
In 2007, the company estimates capital and exploratory expenditures will be 18 percent higher at $19.6 billion, including $2.4 billion of spending by affiliates. About three-fourths, or $14.6 billion, is budgeted for exploration and production activities, with $10.6 billion of that amount outside the United States.
Refer also to a discussion of the companys capital and exploratory expenditures on page FS-13 of this Annual Report on Form 10-K.
The table on the following page summarizes the net production of liquids and natural gas for 2006 and 2005 by the company and its affiliates.
Net Production1 of Crude Oil and Natural Gas Liquids and Natural Gas
In 2006, Chevron conducted exploration and production operations in the United States and approximately 35 other countries. Worldwide oil-equivalent production of 2.67 million barrels per day in 2006, including volumes produced from oil sands in Canada and production under the Boscan operating service agreement in Venezuela, increased approximately 6 percent from 2005. The increase between periods was mostly attributable to the Unocal acquisition. Refer to the Results of Operations section beginning on page FS-6 for a detailed discussion of the factors explaining the 20042006 changes in production for crude oil and natural gas liquids and natural gas.
The company estimates that its average worldwide oil-equivalent production in 2007 will be approximately 2.6 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on scope of company operations, and production that may have to be shut in due to weather conditions, civil unrest, changing geopolitics or other disruptions to daily operations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Expected additions to production capacity in 2008 through 2010 may permit worldwide oil-equivalent production levels to increase from 2007 levels. Refer to the Review of Ongoing Exploration and Production Activities in Key Areas, beginning on page 9, for a discussion of the companys major oil and gas development projects.
Refer to Table IV on page FS-68 of this Annual Report on Form 10-K for data about the companys average sales price per unit of crude oil and natural gas produced as well as the average production cost per unit for 2006, 2005 and 2004.
The following table summarizes gross and net productive wells at year-end 2006 for the company and its affiliates:
Productive Oil and Gas Wells1 at December 31, 2006
Table V, beginning on page FS-68, provides a tabulation of the companys proved net oil and gas reserves, by geographic area, as of each year-end 2004 through 2006 and an accompanying discussion of major changes to proved
reserves by geographic area for the three-year period. During 2006, the company provided oil and gas reserves estimates for 2005 to the Department of Energy, Energy Information Agency. Such estimates are consistent with, and do not differ more than 5 percent from, the information furnished to the Securities and Exchange Commission on the companys Annual Report on Form 10-K. During 2007, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency, consistent with the reserve data reported in Table V.
At December 31, 2006, 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, 2006
(Thousands of Acres)
The company sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Most contracts generally commit the company to sell quantities based on production from specified properties, but certain natural gas sales contracts specify delivery of fixed and determinable quantities.
In the United States, the company is contractually committed to deliver to third parties and affiliates approximately 281 billion cubic feet of natural gas through 2009 from U.S. 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 a total of approximately 560 billion cubic feet of natural gas from 2007 through 2009 from Argentina, Australia, Canada, Colombia and the Philippines. 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 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 reserves in Argentina, Australia, Colombia and the Philippines. The company plans to meet its Canadian contractual delivery commitments of 27 billion cubic feet through third-party purchases.
Details of the companys development expenditures and costs of proved property acquisitions for 2006, 2005 and 2004 are presented in Table I on page FS-63 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, 2006. A development well is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
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, 2006. Exploratory wells are wells drilled to find and produce crude oil or natural 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 crude oil or natural gas in another reservoir or to extend a known reservoir beyond the proved area.
Exploratory Well Activity
Details of the companys exploration expenditures and costs of unproved property acquisitions for 2006, 2005 and 2004 are presented in Table I on page FS-63 of this Annual Report on Form 10-K.
Chevrons 2006 key upstream activities, also discussed in Managements Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2, are presented below. The comments below include references to total production and net production, which are defined under Production in Exhibit 99.1 on page E-11 of this Annual Report on Form 10-K. In addition to the activities discussed, Chevron was active in other geographic areas, but those activities are considered less significant.
The discussion below also references the status of proved reserves recognition for significant long-lead-time projects not yet on production and for projects recently placed on production. Reserves are not discussed for recent discoveries that have yet to advance to a project stage and for production in mature areas.
Upstream activities in the United States are concentrated in the Gulf of Mexico, Louisiana, Texas, New Mexico, the Rocky Mountains and California. Average daily net production during 2006 was 462,000 barrels of crude oil and natural gas liquids and 1.8 billion cubic feet of natural gas, or 763,000 barrels per day on an oil-equivalent basis. Refer to Table V beginning on page FS-68 for a discussion of the net proved reserves and different hydrocarbon characteristics for the companys major U.S. producing areas.
In the Gulf of Mexico deepwater areas, the companys producing fields during 2006 included:
The companys interests in the deepwater Typhoon and Boris fields were sold during 2006. The production platform at Typhoon capsized during Hurricane Rita in 2005 and was safely converted into an artificial reef prior to the sale.
During 2006, Chevron was engaged in other development and exploration activities in the deepwater Gulf of Mexico. Development work continued at the 58 percent-owned and operated Tahiti Field, where production start-up is expected in 2008. Development drilling commenced in February 2006, and well completion work is expected to be finalized during 2007. Initial booking of proved undeveloped reserves occurred in 2003, and the transfer of these reserves into the proved developed category is anticipated near the time of production start-up. With an estimated production life of 30 years, Tahiti is designed to have a maximum total daily production of 125,000 barrels of crude oil and 70 million cubic feet of natural gas.
At the 63 percent-owned and operated Blind Faith discovery, a subsea development plan utilizing a semi-submersible production system was approved by Chevron and its partner in late 2005, at which time the company made its initial booking of proved undeveloped reserves. Development drilling at Blind Faith commenced in early 2007. Reclassification of the reserves to the proved developed category is anticipated near the time of production start-up in 2008. Initial total daily production rates for the field are estimated at 30,000 barrels of crude oil and 30 million cubic feet of natural gas, thereafter rising to maximum rates of 40,000 barrels of crude oil and 35 million cubic feet of natural gas. The expected production life of the field is approximately 20 years.
In the fourth quarter 2006, the company announced its decision to participate in the ultra-deep Perdido Regional Development in the U.S. Gulf of Mexico. The development encompasses the installation of a producing host facility designed to service multiple fields, including Chevrons 33 percent-owned Great White, 60 percent-owned Silvertip and 58 percent-owned Tobago. Chevron has a 38 percent interest in the Perdido Regional Host. All of these fields and the production facility are partner-operated. First oil is expected to occur by 2010, with the facility capable of handling 130,000 barrels of oil-equivalent per day. The companys initial booking of proved undeveloped reserves occurred in 2006, and the phased reclassification of these reserves to the proved developed category is anticipated near the time of production start-up. The project has an expected life of approximately 25 years.
Exploration activities in 2006 included the announcement of a discovery early in the year at the 60 percent-owned and operated Big Foot prospect located in Walker Ridge Block 29. A sidetrack well at Big Foot was completed mid-year and encountered the same pay intervals as the discovery well. Additional appraisal drilling is planned for the first half of 2007.
At the 50 percent-owned and operated Jack discovery in Walker Ridge Block 758, a successful extended production flow test on the Jack #2 well was completed in mid-2006. Additional appraisal drilling is scheduled for the 20072008 time frame. Data evaluation continued in early 2007 at the nearby 41 percent-owned and operated Saint Malo prospect. Saint Malo was discovered in 2003, and an appraisal well was completed in 2004. Future appraisal drilling is being planned based on ongoing technical studies that are incorporating additional regional data. At the 25 percent-owned and nonoperated 2005 Knotty Head discovery, a successful sidetrack well was drilled during 2006. Additional appraisal drilling and possible development alternatives were being evaluated in early 2007. At the 30 percent-owned and nonoperated Tubular Bells prospect, an appraisal well in 2006 successfully tested the eastern portion of the reservoir structure. Additional appraisal work is being planned to further delineate the reservoir and to evaluate potential deeper targets. Plans were in progress in early 2007 at the 22 percent-owned and nonoperated Puma discovery to complete an in-progress appraisal well and to schedule additional appraisal drilling for 2007.
At the end of 2006, the company had not yet recognized proved reserves for any of the exploration projects discussed above.
Besides the activities connected with the development and exploration projects in the Gulf of Mexico area, Chevron also moved forward with the federal, state and local permitting process for construction of a natural gas import terminal at Casotte Landing in Jackson County, Mississippi. In February 2007, the company received approval from the Federal Energy Regulatory Commission to construct the facility. The terminal would be located adjacent to the companys Pascagoula Refinery and be designed to process imported liquefied natural gas (LNG) for distribution to industrial, commercial and residential customers in Mississippi, Florida and the Northeast. The terminal would have an initial natural-gas processing capacity of 1.3 billion cubic feet per day. A decision to construct the facility will be timed to align with the companys LNG supply projects.
The company also has contractual rights to 1 billion cubic feet per day of regasification capacity at the third party-owned Sabine Pass LNG terminal beginning in 2009. Also in the Sabine Pass area, the company has up to 1 billion cubic feet per day of pipeline capacity in a new pipeline that will be connected to the Sabine Pass LNG terminal. The new pipeline system will provide access to Chevrons Sabine and Bridgeline pipelines, which connect to the Henry Hub. Interconnect capacity of 600 million cubic feet per day has also been secured to an existing pipeline. The Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange (NYMEX) and is located on the natural gas pipeline system in Louisiana. Henry Hub interconnects to nine interstate and four intrastate pipelines.
Other U.S. Areas: Outside California and the Gulf of Mexico, the company manages operations in areas of the midcontinent United States that extend from the Rockies to southern Texas. In the Piceance Basin of northwestern Colorado, the company drilled 14 tight-gas delineation wells during 2006 on the Skinner Ridge properties. Development drilling is scheduled to begin in the second quarter 2007 with the delivery of two custom-built drilling rigs. Chevron also operates 10 offshore platforms and five producing natural gas fields in Alaskas Cook Inlet and owns nonoperated production on the North Slope. During 2006, the companys operations outside California and the Gulf of Mexico averaged daily net production of 141,000 barrels of crude oil and natural gas liquids and about 1 billion cubic feet of natural gas (315,000 barrels of oil-equivalent).
In Area B of Block 0, average daily net production from six producing fields was 52,000 barrels of crude oil and condensate and 7,000 barrels of LPG in 2006. Included in this production were 28,000 barrels of liquids per day from the Sanha condensate natural gas utilization and Bomboco crude oil project. Initial reclassification of reserves from proved undeveloped to proved developed for this project occurred in 2004 and is expected to continue during the drilling program that is scheduled for completion in 2007. Maximum total daily production from the Sanha and Bomboco fields reached 100,000 barrels of liquids in 2006.
In Block 14, net production from the Kuito, Belize, Lobito and Landana fields averaged 25,000 barrels of crude oil per day in 2006. Belize and Lobito are part of the Benguela Belize-Lobito Tomboco (BBLT) development project. Phase 1 of the BBLT project involved the installation of an integrated drilling and production platform and the
development of the Benguela and Belize fields. First oil was produced at the Belize Field in January 2006. Phase 2 of the project involved the installation of subsea production systems, pipelines and wells for the development of Lobito and Tomboco fields. First oil was produced from the Lobito Field in June 2006. Maximum total production for both phases of BBLT is estimated at 200,000 barrels of crude oil per day and is scheduled to occur in 2008. Proved undeveloped reserves for Benguela and Belize were initially recognized in 1998 and for Lobito and Tomboco in 2000. Certain proved developed reserves for Belize and Lobito were recognized in 2006, and additional BBLT reserves are expected to be reclassified to proved developed as project milestones are met. The concession period for these fields expires in 2027.
Another major project in Block 14 is the development of the Tombua and Landana fields. Construction on the project started in 2006. The maximum total daily production of 100,000 barrels of crude oil is expected to occur by 2010. First oil was produced from the Landana North reservoir in June 2006, using the BBLT infrastructure. Proved undeveloped reserves were recognized for Tombua and Landana in 2001 and 2002, respectively. Initial reclassification from proved undeveloped to proved developed for Landana occurred in 2006. Further reclassification is expected from 2009, when the Tombua-Landana facilities are completed, through 2012, when the drilling program is scheduled for completion. The concession for these fields expires in 2028. The total cost of the Tombua-Landana project is estimated at $3.8 billion.
Four exploration wells were drilled in Block 14 in 2006. One well resulted in a crude oil discovery at the deepwater Lucapa prospect. A second well appraised a prior-year discovery at Gabela, where development options are being studied. The remaining two wells are expected to be completed in the first-half 2007.
In Chevrons other two concessions, the nonoperated working interests are 20 percent in Block 2, which is adjacent to the northwestern part of Angolas coast, south of the Congo River, and 16 percent in the onshore FST area. Combined net production from these properties in 2006 was 4,000 barrels of crude oil per day.
In addition to the producing activities in Angola, Chevron has a 36 percent interest in the planned Angola LNG project, which will be integrated with natural gas production in the area. As of early 2007, participants in the Angola LNG project were finalizing the engineering, procurement, construction and commissioning contract for the 5-million-metric-ton-per-year onshore LNG plant to be located in the northern part of the country. Chevron and Sonangol, Angolas national oil company, are co-leaders of the project. Construction is expected to begin in late 2007. At the end of 2006, the company had not yet recognized proved reserves for the natural gas associated with this project.
Democratic Republic of the Congo: Chevron has an 18 percent nonoperated working interest in a production-sharing contract (PSC) off the coast of Democratic Republic of the Congo. Daily net production from seven fields averaged 3,000 barrels of crude oil in 2006.
Republic of the Congo: Chevron has a 32 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29 percent nonoperated working interest in the Kitina and Sounda exploitation permits, all of which are offshore Republic of the Congo. Net production from the Republic of the Congo fields averaged 11,000 barrels of crude oil per day in 2006. The Moho-Bilondo development continued in 2006, with first production expected in 2008. The development plan calls for crude oil produced by subsea well clusters to flow into a floating processing unit. Maximum total daily production of 80,000 barrels of crude oil is expected by 2010. Proved undeveloped reserves were initially recognized in 2001. Transfer to the proved developed category is expected near the time of first production. The Moho-Bilondo concession expires in 2030.
Angola-Republic of the Congo Joint Development Area: Chevron is operator and holds a 31 percent interest in the 14K/A-IMI Unit, located in a joint development area shared equally between Angola and Republic of the Congo. In 2006, Chevron submitted a conceptual field development plan to a committee of representatives from the two countries.
Chad/Cameroon: Chevron is a nonoperating partner in a project to develop crude oil fields in southern Chad and transport the crude oil by pipeline to the coast of Cameroon for export. Chevron has a 25 percent working interest in the producing operations and a 21 percent interest in the pipeline. Average daily net production from five fields in 2006 was 34,000 barrels of crude oil. The first of the satellite-field development projects was completed in the first quarter of 2006, and first oil was achieved in 2005 from the Nya Field and in March 2006 from the Moundouli Field. The second satellite-field development project, Maikeri, was approved for funding in the second half of 2006, with first oil anticipated for fourth quarter 2007. The Chad producing operations are conducted under a concession agreement that expires in 2030.
Libya: In 2005, the company was awarded Block 177 in Libyas first exploration license round under the Exploration and Production Sharing Agreement IV. Chevron is the operator and holds a 100 percent interest in the block.
Acquisition and evaluation of seismic data is scheduled for completion in late 2007. A drilling program is scheduled for 2008.
and OML 128. Agbami is designed as an all-subsea development, with the wells tied back to a floating production, storage and offloading (FPSO) vessel. The subsea wells will be connected to the FPSO by a system of flexible flowlines, manifolds and control umbilicals. All wells are to be drilled by a mobile drilling unit. Development drilling and completion operations were conducted throughout 2006.
During 2006, the Agbami development achieved the following major milestones: the FPSO hull was floated out of drydock in South Korea; topside modules fabricated in South Korea were installed on the FPSO and modules fabricated in Nigeria were received at the shipyard in South Korea. All other major equipment items were shipped to South Korea for installation, and manufacturing began on the equipment for the subsea wells. Completion of the FPSO and subsequent transport to Nigeria are expected in the fourth quarter 2007.
Agbamis maximum total daily production of 250,000 barrels of crude oil and natural gas liquids is expected to be reached within the first year after start-up in the second half 2008. The company initially recognized proved undeveloped reserves for Agbami in 2002. A portion of the proved undeveloped reserves will be reclassified to proved developed in advance of production start-up. The expected field life is approximately 20 years.
For Chevrons Aparo discovery in 2003 on OML 132 (formerly Oil Prospecting License [OPL] 213), the company entered into a joint-study agreement in 2004 with the partner group of the Bonga SW Field in OML 118 (formerly OPL 212) for the unitization and joint development of Aparo, which straddles OML 132 and OPL 249. Negotiation of final terms for a unitization agreement for this development was ongoing as of early 2007. Front-end engineering and design (FEED) continued through 2006, and discussions were under way in early 2007 with potential contractors. Development will likely involve an FPSO and subsea wells. Partners are expected to make the investment decision during 2007, with production start-up estimated to occur in 2011. Maximum total production of 150,000 barrels of crude oil per day is expected to be reached within one year of production start-up. The company recognized initial proved undeveloped reserves in 2006 for its approximate 20 percent nonoperated working interest in the unitized project.
The company holds a 30 percent nonoperated working interest in the Usan project, located offshore in OPL 222. FEED for the Usan Field continued through 2006 on a selected FPSO concept. Technical tendering for the major contracts were under way as of early 2007. Project partners expect to make the investment decision during 2007. The company recognized proved undeveloped reserves for the project in 2004. Production start-up is estimated for late 2011, before which time certain proved undeveloped reserves are expected to be reclassified to the proved developed category. Maximum total production of 180,000 barrels of crude oil per day is expected to be achieved within one year of start-up. The end date of the concession period will be determined after final regulatory approvals are obtained.
Chevron operates and holds a 95 percent interest in the 2003 Nsiko discovery, also on OPL 249. Two successful appraisal wells were drilled in 2004, with subsurface evaluations and field development planning ongoing in early 2007. The company expects FEED to begin in late 2007. Maximum total production of 100,000 barrels of oil per day is anticipated within one year of initial start-up, targeted for 2012. At the end of 2006, no proved reserves had been recognized for this project.
The Nnwa Field in OML 129 (formerly OPL 218) was discovered in 1999 and extends into two adjacent non-Chevron leased blocks. Chevrons nonoperated working interest in OML 129 is 46 percent. A later discovery in OML 129 was made in the Bilah Field. Commerciality of these fields is dependent upon resolution of the Nigerian Deepwater Gas fiscal regime and collaboration agreements with adjacent blocks. The Bilah Field discovery was under evaluation in early 2007 for further appraisal and the viability of a stand-alone condensate liquid recovery scheme.
Chevron is a participant in the South Offshore Water Injection Project, an enhanced crude-oil recovery project in the south offshore area of OML 90. The company operates and holds a 40 percent interest as part of the joint venture with NNPC. The objective of the project is to increase production by providing water injection, natural-gas lift and production debottlenecking in the South Offshore Asset Area (Okan and Delta fields). The 25-year-life project is in its development phase and by the end of 2006 was contributing incremental production of approximately 7,000 net barrels of crude oil per day. Maximum total production from this project is expected to be 35,000 barrels of crude oil per day in 2010. The major project milestones expected in 2007 include commencement of water injection from the new Delta South Water Inject Platform facility, drilling of 10 additional wells and the installation of pipelines. Initial recognition of proved developed and proved undeveloped reserves was made in 2005. Reclassification of proved reserves to the proved developed category is expected to occur after the evaluation of the water injection performance.
In May 2006, the company announced the discovery of crude oil at the Uge-1 well in the 20 percent-owned and nonoperated offshore OPL 214. Future drilling is contingent primarily on completing technical studies.
Chevron is involved in projects in Nigeria that support the companys strategic initiative to commercialize its significant natural gas resource base outside the United States. Construction began in early 2006 on the Phase 3A expansion of the Escravos Gas Plant (EGP). Engineering, procurement and construction are expected to continue through 2007, with start-up targeted for early 2009. The scope of EGP Phase 3A includes offshore natural gas gathering and compression infrastructure and a second plant, which potentially would increase processing capacity from 285 million to 680 million cubic feet of natural gas per day and increase LPG and condensate export capacity from 4,000 to 43,000 barrels per day. Proved undeveloped reserves associated with EGP Phase 3A were recognized in 2002. These reserves are expected to be reclassified to proved developed as various project milestones are reached and related projects are completed. The anticipated life of the project is 25 years. Chevron holds a 40 percent operated interest in this project.
Refer also to page 25 for a discussion on the planned gas-to-liquids facility at Escravos.
Chevron holds a 38 percent interest in the West African Gas Pipeline, which is expected to start up in the first-half 2007 and supply Nigerian natural gas to customers in Ghana, Benin and Togo for industrial applications and power generation. A 350-mile offshore segment of the West African Gas Pipeline connects to an existing onshore pipeline in Nigeria. Chevron is the managing sponsor in West African Pipeline Company Limited, which constructed, owns and will operate the pipeline.
In February 2006, Chevron signed a Project Development Agreement for a 19 percent nonoperated working interest in the Olokola LNG Project, which involves construction of a four-train, 22-million-metric-ton-per-year natural gas liquefaction facility and marine terminal located in a free trade zone between Lagos and Escravos. Chevron is expected to supply approximately 1.8 billion cubic feet per day of natural gas to the LNG plant. The project entered FEED in the first quarter 2006. The partners investment decision is scheduled for 2007, and initial production is targeted for 2012. The company had not recognized proved reserves for this project at the end of 2006.
Nigeria-São Tomé e Príncipe Joint Development Zone (JDZ): Chevron is the operator of JDZ Block 1 and holds a 46 percent interest following the sale of a 5 percent interest in 2006. In March 2006, the first exploration well was completed and encountered hydrocarbons. In early 2007, commercial options were being examined to determine the possible need for additional drilling.
On Barrow and Thevenard islands off the northwest coast of Australia, Chevron operates crude oil producing facilities that had combined net production of 5,000 barrels per day in 2006. Chevrons interest in this operation is 57 percent for Barrow Island and 51 percent for Thevenard Island.
Also off the northwest coast of Australia, Chevron is the operator of the Gorgon-area fields and has a 50 percent ownership interest across most of the Greater Gorgon Area. Chevron and its two joint-venture participants signed a Framework Agreement in 2005 that will enable the combined development of Gorgon and the nearby natural gas fields as one world-scale project. In early 2007, progress continued toward securing environmental regulatory approvals necessary for the development of the Greater Gorgon LNG project on Barrow Island. A two-train, 10-million-metric-ton-per-year LNG development is planned for the island, with natural gas supplied from the Gorgon and Jansz natural gas fields.
Elsewhere in the Greater Gorgon Area during 2006, concept studies were undertaken on the Wheatstone-1 natural gas discovery located northeast of the Gorgon Field. Appraisal drilling is scheduled for 2007. The company also announced in 2006 two significant natural gas discoveries at the 67 percent-owned Clio-1 and 50 percent-owned Chandon-1 exploration wells located offshore northwestern coast in the Greater Gorgon development area. Additional work on these two company-operated prospects includes a 3-D seismic survey program that started in late 2006 to better determine the potential of the natural gas find and subsequent development options.
Chevron was also awarded exploration rights to Blocks WA-374-P (Greater Gorgon Area) and WA-383-P (Exmouth West) in the Carnarvon Basin offshore Western Australia. Chevron holds a 50 percent operated interest in the blocks. Operations commenced in WA-374-P with the acquisition of 3-D seismic data. On WA-383-P, a three-year work program includes geotechnical studies and 2-D seismic work. In early 2007, the company was also named operator and awarded a 50 percent interest in exploration acreage in Block W06-12 in the Greater Gorgon Area. A three-year work program includes geotechnical studies, seismic surveys and drilling of an exploration well.
At the end of 2006, the company had not recognized proved reserves for any of the Greater Gorgon Area fields. Recognition is contingent on securing sufficient LNG sales agreements and achieving other key project milestones. The company has signed separate nonbinding Heads of Agreements totaling 4.2 million metric tons per year with three companies in Japan to supply LNG from the Gorgon project. As of early 2007, negotiations were continuing to finalize binding sales agreements. Purchases by each of these customers are expected to range from 1.2 million metric tons per year to 1.5 million metric tons per year of LNG over 25 years beginning after 2010.
Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project that is being developed in phases. During 2006, Karachaganak daily net production averaged 38,000 barrels of liquids and 143 million cubic feet of natural gas.
The Karachaganak operations are conducted under a 40-year concession agreement that expires in 2038. In 2006, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara pipelines allowed Karachaganak sales of approximately 143,000 barrels per day (27,000 net barrels) of processed liquids at prices available in world markets. A fourth train was approved in December 2006 that is designed to increase this export of processed liquids by 56,000 barrels per day (11,000 net barrels). The fourth train is expected to start up in 2009.
Phase III of Karachagnak field development is contingent upon the Republic of Kazakhstans identifying and enabling a commercially attractive outlet for the increased natural gas volumes. Timing for the recognition of Phase III proved reserves and an increase in production are uncertain, and both depend on achieving a natural gas sales agreement and finalizing a viable Phase III project design.
Refer also to page 23 for a discussion of Tengizchevroil, a 50 percent-owned affiliate with operations in Kazakhstan.
Russia: In 2005, OAO Gazprom, Russias largest natural gas producer, included Chevron on a list of companies that could continue discussions concerning the development and related commercial activities of the Shtokmanovskoye Field, a very large natural gas field offshore Russia in the Barents Sea. In October 2006, OAO Gazprom issued a public statement indicating its plan to develop Shtokmanovskoye without foreign partners. Refer also to page 24 for a discussion of the companys interest in a Russian joint venture.
Bangladesh: Chevron is the operator of four onshore blocks, with a 98 percent interest in Blocks 12, 13 and 14 and a 43 percent interest in Block 7. In 2006, the properties averaged daily net production of 126 million cubic feet of natural gas. Following a two-year development program, production from the Bibiyana Field in Block 12 is scheduled to start in the first-half 2007, reaching maximum total production of 500 million cubic feet per day by late 2010. The development program includes a gas processing plant with capacity of 600 million cubic feet per day and a natural gas pipeline. Initial proved reserves were recognized in 2005. In 2006, additional proved reserves were recognized based on additional development wells drilled during the year, and certain proved undeveloped reserves were reclassified to the proved developed category in recognition of imminent completion of the gas plant and pipeline infrastructure required for production start-up. The Bibiyana PSC expires in 2034.
Thailand: Chevron has both operated and nonoperated working interests in several different offshore blocks in Thailand. The companys daily net production averaged 73,000 barrels of crude oil and condensate and 856 million cubic feet of natural gas in 2006.
Operated interests include concessions with ownership interests ranging from 35 percent to 80 percent in Blocks 10 through 13 and B12/27, 52 percent-owned Blocks B8/32 and 9A, 60 percent-owned G4/43 and 71 percent-owned G4/48.
In the concession containing Blocks 10 through 13 and B12/27, debottlenecking of all central processing platforms was completed, which is expected to add more than 160 million cubic feet per day of natural gas processing capability. The company anticipates this additional capacity will be used when PTT Public Company Limited completes the third natural gas pipeline to shore in 2007. In late 2007, the company expects to complete the evaluation of a possible second natural gas central processing facility in Platong to support a Heads of Agreement signed in 2003 for additional natural gas sales to meet future natural gas demands in Thailand. This Platong Gas II Project, in which the company has a 70 percent interest, would add 330 million cubic feet per day of processing capacity in the Platong area, which spans Blocks 10, 10A, 11 and 11A in the Gulf of Thailand. The new facilities would include a central processing platform, pipelines and five initial wellhead platforms. First gas sales would occur in 2010. Proved reserves would be recognized throughout the 12-year project life as the required wellhead platforms are developed.
In Blocks B8/32 and 9A, crude oil is produced from six operating areas within the Pattani Field. First production from Lanta area in Block G4/43 is anticipated in the first-half 2007.
Chevron has a 16 percent nonoperated working interest in Blocks 14A, 15A, 16A and G9/48, known collectively as the Arthit Field. Development of Arthit is progressing with six wellhead platforms installed and 41 wells drilled in 2006. First production is planned for 2008.
In 2006, the company signed two exploration concessions, Blocks G4/48 and G9/48. Two delineation wells are scheduled to be drilled in Block G4/48 in 2007. One exploration well in Block G9/48 is required to be drilled by the first quarter 2009. As of early 2007, processing and interpretation of seismic data were under way in Block G9/48. Chevron also holds exploration interests in a number of blocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.
Vietnam: The company is operator in two PSCs offshore southwest Vietnam in the northern part of the Malay Basin. Chevron has a 42 percent interest in Blocks B and 48/95 and a 43 percent interest in Block 52/97. In April 2006, the company signed a 30-year PSC for Block 122 located offshore eastern Vietnam. The company has a 50 percent operated interest in this block and has undertaken a three-year work program for seismic acquisition and drilling of an exploratory well.
In July 2006, the company submitted a revised summary development plan to state-owned PetroVietnam for Blocks B, 48/95 and 52/97 for the Vietnam Gas Project. The final detailed development plan is expected to be submitted in the third quarter 2007, with FEED projected to begin by the end of 2007. First natural gas production is targeted for 2011 but is dependent on the progress of commercial negotiations. Maximum total production of approximately 500 million cubic feet of natural gas per day is projected within four years of the production start-up. Recognition of initial proved reserves is expected to follow execution of the gas sales agreements and anticipated project sanction in 2008. Total development cost for the project is approximately $3.5 billion.
China: Chevron has a 33 percent nonoperated working interest in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, a 25 percent nonoperated working interest in QHD-32-6 in Bohai Bay, and a 16 percent nonoperated working interest in the unitized and producing Bozhong 25-1 Field in Bohai Bay Block 11/19. Daily net production from the companys interests in China averaged 23,000 barrels of crude oil and condensate and 18 million cubic feet of natural gas in 2006. Production during 2006 included first natural gas in January from the HZ21-1 natural gas development project, located in Block 16/08. Chevron also has interests ranging from 36 percent to 50 percent in four prospective onshore natural gas blocks in the Ordos Basin totaling about 1.5 million acres.
Partitioned Neutral Zone (PNZ): Saudi Arabian Chevron Inc., a Chevron subsidiary, holds a 60-year concession that expires in 2009 to produce crude oil from onshore properties in the PNZ, which is located between the Kingdom of Saudi Arabia and the State of Kuwait. In September 2006, Chevron submitted to the Kingdom of Saudi Arabia a proposal to extend the concession agreement. Under the current concession, Chevron has the right to Saudi Arabias 50 percent undivided interest in the hydrocarbon resource and pays a royalty and other taxes on volumes produced. During 2006, average daily net production was 111,000 barrels of crude oil and 19 million cubic feet of natural gas. Facilities for the first phase of a steamflood project were completed in December 2005, and steam injection began in February 2006. The success of the first phase has led to the approval of funding for a second phase steamflood pilot project that is expected to be completed by late 2008. This pilot is a unique application of steam injection into a carbonate reservoir.
Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field located about 50 miles offshore Palawan Island. Daily net production in 2006 was 108 million cubic feet of natural gas and 6,000 barrels of condensate. Chevron also develops and produces steam resources under an agreement with the National Power Corporation, a Philippine government-owned company. The combined generating capacity is 634 megawatts.
In North Duri, located in the Rokan PSC, development is progressing on steamflood activity for the sequential development of three possible expansion areas. The first expansion involves the development of Area 12, in which the company has a 100 percent interest, and is planned to come onstream in 2008, with maximum total daily production estimated at 34,000 barrels of crude oil in 2012. Proved undeveloped reserves for North Duri were recognized in previous years, and reclassification from proved undeveloped to proved developed will occur during various stages of sequential project completion.
A drilling campaign is scheduled to continue through 2007 in South Natuna Sea Block B, with first oil from Kerisi Field expected in late 2007. In 2006, the company executed a farm-out agreement relinquishing five Indonesian PSCs in exchange for a 40 percent nonoperated working interest in the NE Madura III Block.
In early 2007, the company submitted preliminary plans of development to the government of Indonesia for the Bangka, Gendalo Hub and Gehem Hub deepwater natural gas projects, located in the Kutei Basin. These projects will
likely be developed in parallel, with first production for all projects targeted for 2013. The actual timing is partially dependent on government approvals, market conditions and the achievement of key project milestones.
The development concept for the 50 percent-owned and operated Sadewa project, located in the Kutei Basin is under evaluation and is expected to be completed in late 2007. Assuming the evaluation is positive, initial proved reserves recognition would be expected to occur in 2008, with first production expected in 2010.
Daily net production from all producing areas in Indonesia averaged 198,000 barrels of crude oil and 302 million cubic feet of natural gas in 2006.
e) Other International Areas
The company concentrates its exploration efforts in the Campos and Santos basins. In the nonoperated Campos Basin Block BC-20, two areas 38 percent-owned Papa-Terra (formerly RJS610) and 30 percent-owned RJS609 have been retained for development following the end of the exploration phase of this block. In the Papa-Terra area, the appraisal phase has been completed confirming hydrocarbons in three separate reservoirs. In June 2006, a field development plan was submitted to the government. FEED for the Papa-Terra Field is expected to commence in late 2007 after completing an appraisal program planned for mid-2007. In the RJS609 area, all appraisal drilling was completed to fulfill requirements for a Declaration of Commerciality that was filed in December 2006 for a new field, designated Maromba. Elsewhere in Campos, the company holds a 30 percent nonoperated working interest in the BM-C-4 Block, in which drilling of the final obligatory exploration well began in October 2006. As of early 2007, drilling of the Guarana prospect was ongoing, with completion and evaluation expected to occur later in 2007. In the 20 percent-owned and nonoperated Santos Basin BS-4 Block, the evaluation of an exploration campaign was completed in 2006, with the Declaration of Commerciality filed in December 2006 designating two new fields, Atlanta and Oliva.
Colombia: The company operates three natural gas fields in Colombia the offshore Chuchupa and the onshore Ballena and Riohacha. The fields are part of the Guajira Association contract, a joint venture agreement that was extended in 2003. At that time, additional proved reserves were recognized. The company continues to operate the fields and receives 43 percent of the production for the remaining life of each field as well as a variable production volume from a fixed-fee Build-Operate-Maintain-Transfer (BOMT) agreement based on prior Chuchupa capital contributions. The BOMT agreement expires in 2016. Net production averaged 174 million cubic feet of natural gas per day in 2006. New production capacity was commissioned in 2006 and will help meet the demand of the growing Colombian natural gas market.
Trinidad and Tobago: The company has a 50 percent nonoperated working interest in four blocks in offshore Trinidad, which include the Dolphin and Dolphin Deep producing natural gas fields and the Starfish discovery. Net natural gas production from Dolphin and Dolphin Deep in 2006 averaged 174 million cubic feet per day.
Natural gas supply to the Atlantic LNG Train 3 from the Dolphin Field began in 2005. In July 2006, Chevron delivered the first natural gas from the Dolphin Deep development to the Atlantic LNG Train 3 and Train 4. The initial phase of the development became fully operational during 2006 and supplied an average of 38 million net cubic feet of natural gas per day to Train 3 and 31 million net cubic feet of natural gas per day to Train 4. Proved reserves associated with the Train 4 gas sales agreement were recognized in 2004. Reserves associated with Trains 3 and 4 were transferred to the proved developed category in 2005. The contract period for Train 3 ends in 2023 and for Train 4 in 2026.
Chevron also holds a 50 percent operated interest in the Manatee area of Block 6d. After successful exploration drilling results in 2005, the company assessed alternative development strategies for the Loran Field in Venezuela and Manatee area in 2006. As of early 2007, negotiations were in progress between Trinidad and Tobago and Venezuela to unitize the Loran and Manatee discoveries.
Venezuela: As of October 2006, the companys operations at the Boscan and LL-652 fields were converted to two joint stock companies. From that date, these activities were treated as affiliate operations and accounted for under the equity method. Refer to page 23 for a further discussion of these operations.
The company also has ongoing exploration activity in two blocks offshore Plataforma Deltana, in which the company is operator and holds a 60 percent interest. In Block 2, which includes the Loran Field, evaluation and project development work continued during 2006. In the 100 percent-owned and operated Block 3, Chevron discovered natural gas in 2005. The discovery is in close proximity to the Loran natural gas field and provides significant resources that will be included in the detailed evaluation as a potential gas supply source for Venezuelas first LNG train. Seismic work elsewhere in Block 3 started in 2006. Chevron also has 100 percent interest in the Cardon III exploration block, located offshore western Venezuela north of the Maracaibo producing region. Seismic work in this block, which has natural gas potential, is planned for 2007.
Refer also to page 23 for a discussion of the Hamaca heavy oil production and upgrading project in Venezuela.
Canada: The companys assets in Canada include a 27 percent nonoperated working interest in the Hibernia Field offshore eastern Canada, a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) and exploration acreage in the Mackenzie Delta and Orphan Basin. Excluding volumes mined at the AOSP, daily net production in 2006 from the companys Canadian operations was 46,000 barrels of crude oil and natural gas liquids and 6 million cubic feet of natural gas. The company also owns a 28 percent operated interest in the Hebron project offshore eastern Canada. Negotiations with the government of Newfoundland and Labrador on commercial terms for the development of the field were suspended in April 2006, and the project team was demobilized. The timing for a possible resumption of negotiations was uncertain as of early 2007.
At the AOSP, which began operations in 2003, bitumen is mined from oil sands and upgraded into synthetic crude oil using hydroprocessing technology. Chevrons share of bitumen production in 2006 averaged 27,000 barrels per day.
In 2006, the company elected to participate in the first phase of expansion of the AOSP. The expansion is being designed to produce approximately 100,000 barrels of bitumen per day (20,000 net barrels) and upgrade it into synthetic crude oil at an estimated total cost of $10 billion. The expansion will increase total AOSP design capacity to approximately 255,000 barrels of bitumen per day by 2010. This phase of expansion includes the construction of mining and extraction facilities at the Jackpine Mine, for which net proved undeveloped oil sands reserves were recorded in 2006.
Net proved oil sands reserves at the end of 2006 were 443 million barrels, increasing from 2005 primarily due to the addition of reserves for the Jackpine Mine and proved developed oil sands reserves for the Muskeg River Mine. Securities and Exchange Commission regulations define these reserves as mining-related and not a part of conventional oil and gas reserves.
Chevron also holds a 60 percent operated interest in the Ells River In Situ Oil Sands Project in the Athabasca region. This project consists of heavy oil leases of more than 75,000 acres that were acquired in 2005 and 2006. The area contains significant volumes with the potential for recovery using Steam Assisted Gravity Drainage, a proven technology that employs steam and horizontal drilling to extract the bitumen through wells rather than through mining operations. Initial drilling began in January 2007.
Norway: At the 8 percent-owned and nonoperated Draugen Field, the companys share of production during 2006 was 6,000 barrels of crude oil per day. In the 30 percent-owned and nonoperated PL 324 Field, the first exploration well is planned for the first-half 2007. In the 40 percent-owned and operated PL 325, seismic data was acquired in 2006. Pending the results of the ongoing seismic processing, a first exploration well is planned for 2008. At PL 283, in which Chevron holds a 25 percent nonoperated working interest, an exploration well that tested natural gas in the Stetind prospect in 2006 will be followed by another exploration well in mid-2007.
Through an Area of Mutual Interest with a partner in the Barents Sea, Chevron was awarded a 40 percent nonoperated working interest in PL 397 in April 2006, encompassing six blocks located in the Nordkapp East Basin. A 3-D seismic survey was acquired and is planned to be processed in 2007.
United Kingdom: Offshore United Kingdom, the companys daily net production in 2006 from nine fields was 75,000 barrels of crude oil and 242 million cubic feet of natural gas. Of this volume, daily net production from the 85 percent-owned and operated Captain Field was 37,000 barrels of crude oil and from the co-operated and 32 percent-owned Britannia Field was 5,000 barrels of crude oil and 138 million cubic feet of natural gas. In December 2006, Chevron exchanged interests in the nonproducing North Sea Blocks 16/22 and 16/23 for an additional 2 percent interest in the Chevron-operated Alba Field, raising the companys total interest to 23 percent. Daily net production from this field averaged 11,000 barrels of crude oil in 2006.
As of early 2007, development activities were continuing at the Britannia satellite fields Callanish and Brodgar, in which Chevron holds 17 percent and 25 percent nonoperated working interests, respectively. A new platform and all subsea equipment and pipelines were installed in 2006. Production start-up from these two satellite fields is expected to occur in 2008. Together, these fields are expected to achieve maximum total daily production of 25,000 barrels of crude oil and 133 million cubic feet of natural gas several months after both fields start up. Proved undeveloped reserves were initially recognized in 2000. In 2006, proved undeveloped reserves were reclassified to the proved developed category. This project has an expected production life of approximately 15 years.
Production start-up occurred in June 2006 at the Area C project in the eastern portion of the Captain Field. The project included the installation of subsea infrastructure and the drilling of two new subsea wells. Maximum total production of 14,000 barrels of crude oil per day was achieved in September 2006. Initial proved undeveloped reserves were booked in 2004 and were reclassified as proved developed in 2006 following completion of development drilling. Further additions to proved reserves are expected to occur as the field matures.
The Alder discovery, west of the Britannia Field, is being evaluated and likely to be developed as a tieback to existing infrastructure. The company has a 70 percent operated interest in the project, which is expected to start up and reach maximum total daily production rates of 9,000 barrels of crude oil and 80 million cubic feet of natural gas in 2011. No proved reserves had been recognized as of year-end 2006.
In late 2006, the first well in a three-well program began drilling to evaluate the commercial potential of the Rosebank/Lochnagar discovery and adjacent acreage.
In early 2007, Chevron was awarded eight operated exploration blocks and two nonoperated blocks west of Shetland Islands in the 24th United Kingdom Offshore Licensing Round.
Kazakhstan: The company holds a 50 percent interest in Tengizchevroil (TCO), which is developing the Tengiz and Korolev crude oil fields located in western Kazakhstan under a 40-year concession that expires in 2033. Chevrons share of daily net production in 2006 averaged 135,000 barrels of crude oil and natural gas liquids and 193 million cubic feet of natural gas.
TCO is undergoing a significant expansion composed of two integrated projects referred to as the Second Generation Plant (SGP) and Sour Gas Injection (SGI). At a total combined cost of approximately $6 billion, these projects are designed to increase TCOs crude oil production capacity from 300,000 barrels per day to between 460,000 and 550,000 barrels per day in 2008. The actual production level within the estimated range is dependent partially on the effects of the SGI, which are discussed below. The start-up of the SGP/SGI project is expected in 2007.
SGP involves the construction of a large processing train for treating crude oil and the associated sour gas (i.e., high in sulfur content). The SGP design is based on the same conventional technology employed in the existing processing trains. Proved undeveloped reserves associated with SGP were recognized in 2001. During 2006, 55 wells were drilled, deepened and/or completed in the Tengiz and Korolev reservoirs to generate volumes required for the new SGP train, and reserves associated with the project were reclassified to the proved developed category. Over the next decade, ongoing field development is expected to result in the reclassification of additional proved undeveloped reserves to proved developed.
SGI involves taking a portion of the sour gas separated from the crude oil production at the SGP processing train and reinjecting it into the Tengiz reservoir. Chevron expects that SGI will have two key effects. First, SGI will reduce the sour gas processing capacity required at SGP, thereby increasing liquid production capacity and lowering the quantities of sulfur and gas that would otherwise be generated. Second, it is expected that over time SGI will increase production efficiency and recoverable volumes as the injected gas maintains higher reservoir pressure and displaces oil toward producing wells. Between 2007 and 2008, the company anticipates recognizing additional proved reserves associated with the SGI expansion. The primary SGI risks include uncertainties about compressor performance associated with injecting high-pressure sour gas and subsurface responses to injection.
Essentially all of TCOs production is exported through the Caspian Pipeline Consortium (CPC) pipeline that runs from Tengiz in Kazakhstan to tanker loading facilities at Novorossiysk on the Russian coast of the Black Sea. CPC is seeking stockholder approval for an expansion to accommodate increased TCO volumes beginning in 2009. During 2006, TCO continued the construction of expanded rail car loading and rail export facilities, which is expected to be completed by third quarter 2007. As of early 2007, other alternatives were also being explored to increase export capacity prior to expansion of the CPC pipeline.
Venezuela: Chevron has a 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuelas Orinoco Belt. The crude oil upgrading began in late 2004. In 2005, the facility reached total design capacity of processing and upgrading 190,000 barrels per day of heavy crude oil (8.5 degrees API gravity) into 180,000 barrels of lighter, higher-value crude oil (26 degrees API gravity). In 2006, daily net production averaged 36,000 barrels of liquids and 8 million cubic feet of natural gas. In late February 2007, the President of Venezuela issued a decree announcing the governments intention for the state-owned oil company, Petróleos de Venezuela S.A., to increase its ownership later this year in all Orinoco Heavy Oil Associations, including Chevrons 30 percent-owned Hamaca project, to a minimum of 60 percent. The impact on Chevron from such an action is uncertain but is not expected to have a material effect on the companys results of operations, consolidated financial position or liquidity.
The company operated the onshore Boscan Field for 10 years under an operating service agreement with Petróleos de Venezuela S.A. In October 2006, the contract was converted into a joint stock company, Petroboscan, in which Chevron is a 39 percent owner. At the same time, operatorship was transferred from Chevron to Petroboscan. No proved reserves had been recognized under the operating service agreement, but proved reserves associated with this new 20-year production contract were recorded in 2006. Under the operating service agreement, Boscan had average net production of 109,000 oil-equivalent barrels per day for the first nine months of 2006. Net production for the final three months of 2006 under the joint stock company was 30,000 oil-equivalent barrels per day.
The company operated the LL-652 Field for eight years under a risked-service agreement with a 63 percent interest until the contract was converted in October 2006 to a 25 percent-owned joint stock company, Petroindependiente. Under the new contract, Petroindependiente is the operator during the 20-year contract period. Located in Lake Maracaibo, LL-652s net production averaged 3,000 barrels of liquids per day and 25 million cubic feet of natural gas per day during 2006. Chevron had previously booked reserves for LL-652 under the risked-service agreement.
Russia: In October 2006, Chevron signed a framework agreement with OAO Gazpromneft, establishing a Russian joint venture for exploration and development activities focused in the Yamal-Nenets region of Western Siberia. Chevron will maintain a 49 percent joint-operated interest in the venture. Refer to page 17 for a discussion of the companys other activities in Russia.
The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Outside the United States, the majority of the companys natural gas sales occur in Australia, Indonesia, Latin America, Thailand and the United Kingdom and in the companys affiliate operations in Kazakhstan. International natural gas liquids sales take place in Africa, Australia and Europe. Refer to Selected Operating Data, on page FS-11 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. Refer also to Contract Obligations on page 7 for information related to the companys contractual commitments for the sale of crude oil and natural gas.
Downstream Refining, Marketing and Transportation
At the end of 2006, the companys refining system consisted of 20 fuel refineries and an asphalt plant. The company operated nine of these facilities, and 12 were operated by affiliated companies.
The daily refinery inputs for 2004 through 2006 for the company and affiliate refineries are as follows:
Petroleum Refineries: Locations, Capacities and Inputs
(Inputs and Capacities in Thousands of Barrels per Day)
Average crude oil distillation capacity utilization during 2006 was 90 percent, compared with 86 percent in 2005. In general, this increase resulted from less planned and unplanned downtime in 2006, due partly to downtime in 2005 that was attributable to hurricanes in the U.S. Gulf of Mexico. No downtime was caused by hurricanes in 2006. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 99 percent in 2006, compared with 90 percent in 2005, and cracking and coking capacity utilization averaged 86 percent and 76 percent in 2006 and 2005, respectively. Cracking and coking units, including fluid catalytic cracking units, are the primary facilities used in fuel refineries to convert heavier products into gasoline and other light products.
The companys U.S. West Coast, Gulf Coast and Salt Lake refineries produce low-sulfur fuels that meet 2006 federal government specifications. Investments required to produce low-sulfur fuels in Europe, Canada, South Africa and Australia were completed in 2006. The company is evaluating alternatives for clean-fuel projects in its Southeast Asia refineries.
In 2006, the company completed an expansion of the Pascagoula, Mississippi, refinerys Fluid Catalytic Cracking Unit to increase the production of gasoline and other light products. In addition, construction projects began at the El Segundo, California, refinery to increase heavy, sour crude oil processing capability and at the Pembroke, United Kingdom, refinery to increase the capability to process Caspian-blend crude oils. Completion of these projects is expected in 2007. Additional projects to upgrade the companys refineries in Mississippi and California were being evaluated in early 2007.
Also in 2006, GS Caltex, the companys 50 percent-owned affiliate, began construction of an upgrade project at the 650,000-barrel-per-day Yeosu refining complex in South Korea. At a total estimated cost of $1.5 billion, this project is designed to increase the yield of high-value refined products and reduce feedstock costs through the processing of heavy crude oil. Completion of the Yeosu project is expected in late 2007.
In April 2006, Chevron purchased a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to own and operate a new export refinery being constructed in Jamnagar, India. The 580,000-barrel-per-day-crude-oil-capacity refinery is expected to begin operation in December 2008. Chevron has future rights to increase its equity ownership to 29 percent. The new refinery would be the worlds sixth largest on a single site.
Refer to page FS-2 for a discussion of the pending disposition of the companys 31 percent interest in the Nerefco Refinery in the Netherlands.
Chevron processes imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 87 percent and 83 percent of Chevrons U.S. refinery inputs in 2006 and 2005, respectively.
The Sasol Chevron Global 50-50 Joint Venture was established in 2000 to develop a worldwide gas-to-liquids (GTL) business. Through this venture, the company is pursuing GTL opportunities in Qatar and other countries.
In Nigeria, Chevron Nigeria Limited and the Nigerian National Petroleum Corporation are developing a 34,000-barrel-per-day GTL facility at Escravos that will process natural gas supplied from the Phase 3A expansion of the Escravos Gas Plant (EGP). Plant construction began in 2005, and the first process modules are expected to be delivered to the site by the second half of 2007. The GTL plant is expected to be operational by the end of the decade. Refer also to page 15 for a discussion on the EGP Phase 3A expansion.
The company markets petroleum products throughout much of the world. The principal brands for identifying these products are Chevron, Texaco and Caltex.
The table on the following page shows the companys and affiliates refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2006.
Refined Products Sales Volumes1
(Thousands of Barrels per Day)
In the United States, the company markets under the Chevron and Texaco brands. The company supplies directly or through retailers and marketers almost 9,600 branded motor vehicle retail outlets, concentrated in the mid-Atlantic, southern and western states. Approximately 600 of the outlets are company-owned or -leased stations. By the end of 2006, the company was supplying more than 2,100 Texaco retail sites, primarily in the Southeast and West. All rights to the Texaco brand in the United States reverted to Chevron in July 2006.
Outside the United States, Chevron supplies directly or through retailers and marketers approximately 16,200 branded service stations, including affiliates, in about 75 countries. In British Columbia, Canada, the company markets under the Chevron brand. In Europe, the company has marketing operations under the Texaco brand primarily in the United Kingdom, Ireland, the Netherlands, Belgium and Luxembourg. In West Africa, the company operates or leases to retailers in Benin, Cameroon, Côte dIvoire, Nigeria, Republic of the Congo and Togo. In these countries, the company uses the Texaco brand. The company also operates across the Caribbean, Central America and South America, with a significant presence in Brazil, using the Texaco brand. In the Asia-Pacific region, southern, Central and East Africa, Egypt, and Pakistan, the company uses the Caltex brand.
The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex, using the GS Caltex brand. The companys 50 percent-owned affiliate in Australia operates using the Caltex, Caltex Woolworths and Ampol brands. In Scandinavia, the company sold its 50 percent interest in the HydroTexaco joint venture in 2006.
The company continued the marketing and sale of service station sites, focusing on selected areas outside the United States. In 2006, the company sold its interest in more than 450 service stations, primarily in the United Kingdom and Latin America. Since the beginning of 2003, the company has sold its interests in nearly 2,800 service station sites. The vast majority of these sites will continue to market company-branded gasoline through new supply agreements.
The company also manages other marketing businesses globally. Chevron markets aviation fuel in approximately 75 countries, representing a worldwide market share of about 12 percent, and is the leading marketer of jet fuels in the United States. The company also markets an extensive line of lubricant and coolant products in about 175 countries under brand names that include Havoline, Delo, Ursa and Revtex.
Refer to page FS-2 for a discussion of the possible disposition of the companys fuels marketing operations in the Netherlands, Belgium and Luxembourg regions.
Pipelines: Chevron owns and operates an extensive system of crude oil, refined products, chemicals, natural gas liquids and natural gas pipelines in the United States. The company also has direct or indirect interests in other U.S. and international pipelines. The companys ownership interests in pipelines are summarized in the following table.
In the United States during 2006, the company completed the sale of three refined-product pipeline systems in Texas and New Mexico as well as its interest in the Windy Hill natural gas storage project in northeastern Colorado. By year-end 2006, work to restore the companys Empire Terminal in Louisiana, which was damaged in the 2005 hurricanes, was substantially complete. During 2006, the company began a project to expand capacity at its Keystone natural gas storage facility by about 3 billion cubic feet to meet increased demand in the Permian Basin production region near the Waha Hub. The Waha Hub is a pricing point for natural-gas-basis swap-futures contracts traded on the New York Mercantile Exchange (NYMEX) and is located in West Texas south of the natural gas deposits in the San Juan and Permian Basins.
Chevron also has a 15 percent ownership interest in the Caspian Pipeline Consortium (CPC). CPC operates a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. At the end of 2006, CPC had transported an average of 664,000 barrels of crude oil per day, including 519,000 barrels per day from the Caspian region and 145,000 barrels per day from Russia.
In addition, the company has a 9 percent equity interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline, which transports Azerbaijan International Operating Company (AIOC) production from Baku, Azerbaijan, through Georgia to deepwater port facilities in Ceyhan, Turkey. Chevron holds a 10 percent nonoperated working interest in AIOC. The first tanker loading at the Ceyhan marine terminal on the Mediterranean Sea occurred in June 2006. The pipeline has a crude oil capacity of 1 million barrels per day and is expected to accommodate the majority of the AIOC production. Another crude oil production export route is the 515-mile Baku-Supsa pipeline, wholly owned by AIOC, with crude oil capacity to transport 145,000 barrels per day from Baku, Azerbaijan, to the terminal at Supsa, Georgia.
For information on projects under way related to the Chad/Cameroon pipeline, the West African Gas Pipeline and the expansion of the CPC pipeline, refer to pages 13, 15 and 23, respectively.
Tankers: At any given time during 2006, the company had approximately 70 vessels chartered on a voyage basis or for a period of less than one year. Additionally, all tankers in Chevrons controlled seagoing fleet were utilized during 2006. The following table summarizes cargo transported on the companys controlled fleet.
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 2006, 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. During the year, the company contracted for the building of four U.S. flagged product tankers, each capable of carrying 300,000 barrels of cargo. These tankers are scheduled for delivery from 2007 through 2010 and are intended to replace the existing three U.S. flag ships.
The international flag vessels were engaged primarily in transporting crude oil from the Middle East, Asia, Black Sea, Mexico and West Africa to ports in the United States, Europe, Australia and Asia. Refined products were also transported by tanker worldwide. During 2006, the company took delivery of two new double-hulled tankers with a total capacity of 2.5 million barrels and terminated the lease on its last single-hulled vessel.
In addition to the vessels described above, the company owns a one-sixth interest in each of seven liquefied natural gas (LNG) tankers transporting cargoes for the North West Shelf (NWS) project in Australia. Additionally, the NWS project has two LNG tankers under long-term time charter. In 2005, Chevron placed orders for two additional LNG tankers to support expected growth in the companys LNG business. These carriers are planned to be delivered in 2009.
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. At the end of 2006, 100 percent of the companys owned and bareboat-chartered fleet was double-hulled. 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 equally owned with ConocoPhillips Corporation. At the end of 2006, CPChem owned or had joint venture interests in 30 manufacturing facilities and six research and technical centers in the United States, Puerto Rico, Belgium, China, Saudi Arabia, Singapore, South Korea and Qatar.
In 2006, construction progressed on CPChems integrated, world-scale styrene facility in Al Jubail, Saudi Arabia. Jointly owned with the Saudi Industrial Investment Group (SIIG), the projects operational start-up is anticipated in late 2007. The styrene facility is located adjacent to CPChem and SIIGs existing aromatics complex in Al Jubail. Also during the year, CPChem continued development of plans for a third petrochemical project in Al Jubail. Preliminary studies are focused on the construction of a world-scale olefins unit, as well as related downstream units, to produce polyethylene, polypropylene, 1-hexene and polystyrene.
In addition, construction continued on the Q-Chem II project in 2006. The Q-Chem II project includes a 350,000-metric-ton-per-year polyethylene plant and a 345,000-metric-ton-per-year normal alpha olefins plant each utilizing CPChem proprietary technology and is located adjacent to the existing Q-Chem I complex in Mesaieed, Qatar. The Q-Chem II project also includes a separate joint venture to develop a 1.3-million-metric-ton-per-year ethylene cracker at Qatars Ras Laffan Industrial City, in which Q-Chem II owns 54 percent of the capacity rights. CPChem and its partners expect to start up the plants in early 2009. CPChem owns a 49 percent interest in Q-Chem II.
Chevrons 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, Brazil, France, Japan, the Netherlands and Singapore and has equity interests in facilities in India and Mexico.
Oronite provides additives for lubricating oil in most engine applications, such as passenger car, heavy-duty diesel, marine, locomotive and motorcycle engines, and additives for fuels to improve engine performance and extend engine life.
Chevrons mining companies in the United States produce and market coal, molybdenum, rare earth minerals and calcined petroleum coke. Sales occur in both U.S. and international markets.
The companys coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owns and operates two surface mines, McKinley, in New Mexico, and Kemmerer, in Wyoming, and one underground mine, North River, in Alabama. Sales of coal from P&Ms wholly owned mines were 12.6 million tons, down 1.0 million tons from 2005. Final reclamation activities continued in 2006 at the Farco surface mine in Texas.
At year-end 2006, P&M controlled approximately 225 million tons of proven and probable coal reserves in the United States, including reserves of environmentally desirable low-sulfur coal. The company is contractually committed to deliver between 11 million and 12 million tons of coal per year through the end of 2009 and believes it will satisfy these contracts from existing coal reserves.
Molycorp Inc. is the companys mining and marketing subsidiary for molybdenum and rare earth minerals. Molycorp owns and operates the Questa molybdenum mine in New Mexico and the Mountain Pass lanthanides mine in California. In addition, the company owns a 33 percent interest in Sumikin Molycorp, a manufacturer of neodymium compounds, located in Japan. During 2006, Molycorp performed environmental remediation activities at Questa and Mountain Pass, and at its closed rare-earth processing facility in Pennsylvania. The companys 35 percent interest in Companhia Brasileira de Metalurgia e Mineracao, a producer of niobium in Brazil, was sold in 2006.
At year-end 2006, Molycorp controlled approximately 60 million pounds of proven molybdenum reserves at Questa and 240 million pounds of proven and probable lanthanide reserves at Mountain Pass.
The company also owns the Chicago Carbon Company, a producer and marketer of calcined petroleum coke, which operates a 250,000-ton-per-year petroleum coke calciner facility in Lemont, Illinois.
Chevrons Global Power Generation (GPG) business has more than 20 years experience in developing and operating commercial power projects and owns 15 power assets located in the United States and Asia. GPG manages the production of more than 2,334 megawatts of electricity at 11 facilities it owns through joint ventures. The company operates gas-fired cogeneration facilities that use waste heat recovery to produce additional electricity or to support industrial thermal hosts. A number of the facilities produce steam for use in upstream operations to facilitate production of heavy oil.
The company has major geothermal operations in Indonesia and the Philippines and is investigating several advanced solar technologies for use in oil field operations as part of its renewable energy strategy. For additional information on the companys geothermal operations and renewable energy projects, refer to pages 19 and 30, respectively.
In September 2006, the company sold its interest in the 8-megawatt Amada Rayong power generation facility in Thailand.
Chevron Energy Solutions (CES) is a wholly owned subsidiary that provides public institutions and businesses with projects designed to increase energy efficiency and reliability, reduce energy costs and utilize renewable and alternative power technologies. CES has energy-saving projects installed in more than a thousand buildings nationwide. Major
projects completed by CES in 2006 include energy efficiency and renewable power installations for U.S. Postal Service facilities, the first megawatt-class hydrogen fuel cell cogeneration plant in California, and cogeneration and biomass facilities for a municipal water pollution control plant.
The companys Energy Technology Company supports Chevrons upstream and downstream businesses with technologies that span the hydrocarbon value chain from exploration to refining and marketing.
The Technology Ventures Company identifies, grows and commercializes emerging technologies with the potential to transform energy production and use. The business development portfolio includes biofuels, hydrogen infrastructure, advanced batteries, nano-materials and renewable energy applications.
In the second quarter 2006, the company completed the acquisition of a 22 percent interest in Galveston Bay Biodiesel L.P., which is building one of the first large-scale biofuel plants in the United States. During 2006, the company also entered into research alliances with the University of California, Davis and the Georgia Institute of Technology. Both are focused on converting cellulosic biomass into viable transportation fuels.
Chevrons research and development expenses were $468 million, $316 million and $242 million for the years 2006, 2005 and 2004, respectively.
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate successes are 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 U.S. federal, state and local environmental, health and safety laws and regulations, and similar laws and regulations in other countries. 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. Chevron 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 business.
In 2006, the companys U.S. capitalized environmental expenditures were $385 million, representing approximately 7 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 upstream and downstream segments and relate mostly to air- and water-quality projects and activities at the companys refineries, oil and gas producing facilities, and marketing facilities. For 2007, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $350 million. The future annual capital costs of fulfilling this commitment are uncertain and will be governed by several factors, including future changes to regulatory requirements.
Further information on environmental matters and their impact on Chevron and on the companys 2006 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-17 through FS-19 of this Annual Report on Form 10-K.
The companys Internet Web site can be found at http://www.chevron.com/. Information contained on the companys Internet Web site is not part of this Annual Report on Form 10-K.
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 soon after such reports are filed with or furnished to the Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the SECs Internet Web site: http://www.sec.gov/.
Chevron is a major fully integrated petroleum company with a diversified business portfolio, strong balance sheet, and a history of generating sufficient cash to fund capital and exploratory expenditures and to pay dividends. Nevertheless, some inherent risks could materially impact the companys financial results of operations or financial condition.
Chevron is primarily in a commodities business with a history of price volatility. The single largest variable that affects the companys results of operations is crude oil prices. Except in the ordinary course of running an integrated petroleum business, Chevron does not seek to hedge its exposure to price changes. A significant, persistent decline in crude oil prices may have a material adverse effect on its results of operations and its capital and exploratory expenditure plans.
The scope of Chevrons business will decline if the company does not successfully develop resources.
The company is in an extractive business; therefore, if Chevron is not successful in replacing the crude oil and natural gas it produces with good prospects for future production, the companys business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining rights to explore, develop and produce hydrocarbons in promising areas; drilling success; ability to bring long-lead-time, capital-intensive projects to completion on budget and schedule; and efficient and profitable operation of mature properties.
Chevron operates in both urban areas and remote and sometimes inhospitable regions. The companys operations and facilities are therefore subject to disruption from either natural or human causes, including hurricanes, floods and other forms of severe weather, war, civil unrest and other political events, fires, earthquakes, and explosions, any of which could result in suspension of operations or harm to people or the natural environment.
The company produces, transports, refines and markets materials with potential toxicity, and it purchases, handles and disposes of other potentially toxic materials in the course of the companys business. Chevron operations also produce by-products, which may be considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or as a result of new conclusions on the effects of the companys operations on human health or the environment.
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. As has occurred in the past, actions could be taken by governments to increase public ownership of the companys partially or wholly owned businesses and/or to impose additional taxes or royalties.
In certain locations, governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the companys continued presence in those countries. Internal unrest, acts of violence or strained relations between a government and the company or other governments may affect the companys operations. Those developments have, at times, significantly affected the companys related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2006, 24 percent of the companys proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC)-member countries including Indonesia, Nigeria and Venezuela. Approximately 25 percent of the companys net proved reserves, including affiliates, were located in OPEC countries at December 31, 2006. In December 2006, OPEC admitted Angola as a new member effective January 1, 2007. Oil-equivalent reserves at the end of 2006 in Angola represented 5 percent of the companys total.
Regulation of greenhouse gas emissions could increase Chevrons operational costs and reduce demand for Chevrons products.
Management believes it is reasonably likely that the scientific and political attention to issues concerning the existence and extent of climate change, and the role of human activity in it, will continue, with the potential for further regulation that affects the companys operations. Although uncertain, these developments could increase costs or reduce
the demand for the products the company sells. The companys production and processing operations (e.g., the production of crude oil at offshore platforms and the processing of natural gas at liquefied natural gas facilities) typically result in emissions of greenhouse gases. Likewise, emissions arise from midstream and downstream operations, including crude oil transportation and refining. Finally, although beyond the control of the company, the use of passenger vehicle fuels and related products by consumers also results in these emissions.
International agreements, domestic legislation and regulatory measures to limit greenhouse gas emissions are currently in various phases of discussion or implementation. These include the Kyoto Protocol, proposed federal legislation and current state-level actions. Some of the countries in which Chevron operates have ratified the Kyoto Protocol, and the company is currently complying with greenhouse gas emissions limits within the European Union. Although resolutions supporting cap and trade systems have been introduced in the U.S. Congress, no bill restricting greenhouse gas emissions has been passed to date.
In California, the Global Warming Solutions Act became effective on January 1, 2007. This law caps Californias greenhouse gas emissions at 1990 levels by 2020; directs the Air Resources Board, the responsible state agency, to determine greenhouse gas emissions in and outside California to adopt mandatory reporting rules for significant sources of greenhouse gases; delegates to the agency the authority to adopt compliance mechanisms (including market-based approaches); and permits a one-year extension of the targets under extraordinary circumstances. Related regulatory activity is under way within the California Public Utilities Commission. The company extracts crude oil and natural gas, operates refineries, and markets and sells gasoline in California. It is not known at this time whether or to what extent the state agencies regulations will affect the companys California operations.
Item 1B. Unresolved Staff Comments
The location and character of the companys crude oil, natural gas and mining 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-63 to FS-76 of this Annual Report on Form 10-K. Note 13, Properties, Plant and Equipment, to the companys financial statements is on page FS-43 of this Annual Report on Form 10-K.
Chevrons U.S. refineries are implementing a consent decree with the federal Environmental Protection Agency (EPA) and four state air agencies to resolve claims about Chevrons past application of New Source Review permitting programs under the Clean Air Act. The consent decree provides that Chevron will pay stipulated penalties for certain violations of the consent decree, if demand is made by the EPA. In July 2006, Chevrons refinery in Pascagoula, Mississippi exceeded its emission limit under the consent decree for particulate matter. The exceedance was reported at the time and the possibility of a penalty was discussed. In January 2007, the Mississippi Department of Environmental Quality (MDEQ) and the EPA issued a notice of violation and a request for payment of $210,000 in stipulated penalties for the July 2006 particulate matter exceedance. The company, the EPA and the MDEQ are in negotiation with regard to the nature and amount of the penalty demand.
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 Chevrons 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-24 of this Annual Report on Form 10-K.
In December 2006, the company authorized stock repurchases of up to $5 billion that may be made from time to time at prevailing prices as permitted by securities laws and other requirements and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. As of December 31, 2006, 1,336,000 shares had been acquired under this program for $100 million.
The selected financial data for years 2002 through 2006 are presented on page FS-62 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 in Note 7 to the Consolidated Financial Statements, Financial and Derivative Instruments, beginning on page FS-37.
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.
Item 9. Changes in and Disagreements With Auditors on Accounting and Financial Disclosure
(a) Evaluation of Disclosure Controls and Procedures
Chevron Corporations Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the companys disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)), as of December 31, 2006, have concluded that as of December 31, 2006, the companys disclosure controls and procedures were effective and designed to provide reasonable assurance that material information relating to the company and its consolidated subsidiaries required to be included in the companys periodic filings under the Exchange Act would be made known to them by others within those entities.
(b) Managements Report on Internal Control Over Financial Reporting
The companys management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). The companys management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the companys management concluded that its internal control over financial reporting was effective as of December 31, 2006.
The company managements assessment of the effectiveness of its internal control over financial reporting as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report that is included on page FS-26 of this Annual Report on Form 10-K.
(c) Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2006, there were no changes in the companys internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the companys internal control over financial reporting.
The information on Directors appearing under the heading Election of Directors Nominees For Directors in the Notice of the 2007 Annual Meeting of Stockholders and 2007 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 2007 Annual Meeting of Stockholders (the 2007 Proxy Statement), is incorporated by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 33 and 34 of this Annual Report on Form 10-K for information about Executive Officers of the company.
The information contained under the heading Stock Ownership Information Section 16(a) Beneficial Ownership Reporting Compliance in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
The information contained under the heading Board Operations Business Conduct and Ethics Code in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
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 Charles R. Shoemate (Chairperson), Linnet F. Deily, Robert E. Denham and Franklyn G. Jenifer, all of whom are independent under the New York Stock Exchange Corporate Governance Rules. Of these Audit Committee members, Charles R. Shoemate, Linnet F. Deily and Robert E. Denham are audit committee financial experts as determined by the Board within the applicable definition of the SEC.
There were no changes to the process by which stockholders may recommend nominees to the Board of Directors during the last fiscal year.
The information appearing under the headings Executive Compensation and Directors Compensation in the 2007 Proxy Statement is incorporated herein by reference in this Annual Report on Form 10-K.
The members of the Compensation Committee of the Board of Directors during the last fiscal year were Carla A. Hills (until her retirement on April 26, 2006), Robert J. Eaton, Samuel H. Armacost, Ronald D. Sugar and Carl Ware, none of whom is a present or former officer or employee of the company. In addition, during 2006, no officers had an interlock relationship, as that term is defined by the SEC, to report.
The information appearing under the heading Management Compensation Committee Report in the 2007 Proxy Statement is incorporated herein by reference in this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2007 Proxy Statement shall not be deemed filed for purposes of Section 18 of the Exchange Act nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933.
The information appearing under the heading Stock Ownership Information Security Ownership of Certain Beneficial Owners and Management in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
The information contained under the heading Equity Compensation Plan Information in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
The information appearing under the heading Board Operations in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
The information appearing under the headings Ratification of Independent Registered Public Accounting Firm Principal Accountant Fees and Services and Ratification of Independent Registered Public Accounting Firm Audit Committee Pre-Approval Policies and Procedures in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as part of this report:
(1) Financial Statements:
(2) Financial Statement Schedules:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 28th day of February, 2007.
David J. OReilly, Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 28th day of February, 2007.
INDEX TO MANAGEMENTS DISCUSSION AND ANALYSIS,
KEY FINANCIAL RESULTS
INCOME FROM CONTINUING OPERATIONS BY MAJOR
Refer to the Results of Operations section beginning on page FS-6 for a detailed discussion of financial results by major operating area for the three years ending December 31, 2006.
BUSINESS ENVIRONMENT AND OUTLOOK
Chevrons current and future earnings depend largely on the profitability of its upstream (exploration and production) and downstream (refining, marketing and transportation) business segments. The single biggest factor that affects the results of operations for both segments is movement in the price of crude oil. In the downstream business, crude oil is the largest cost component of refined products. The overall trend in earnings is typically less affected by results from the companys chemicals business and other activities and investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent and/ or unusual in nature. Chevron and the oil and gas industry at large are currently experiencing an increase in certain costs that exceeds the general trend of inflation in many areas of the world. This increase in costs is affecting the companys
operating expenses for all business segments and capital expenditures, particularly for the upstream business.
To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer adequate financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner are all important factors in this effort. Projects often require long lead times and large capital commitments. Changes in economic, legal or political circumstances can have significant effects on the profitability of a project over its expected life. In the current environment of higher commodity prices, certain governments have sought to renegotiate contracts or impose additional costs on the company. Other governments may attempt to do so in the future. The company will continue to monitor these developments, take them into account in evaluating future investment opportunities, and otherwise seek to mitigate any risks to the companys current operations or future prospects. In late February 2007, the President of Venezuela issued a decree announcing the governments intention for the state-owned oil company, Petróleos de Venezuela S.A., to increase its ownership later this year in all Orinoco Heavy Oil Associations, including Chevrons 30 percent-owned Hamaca project, to a minimum of 60 percent. The impact on Chevron from such an action is uncertain but is not expected to have a material effect on the companys results of operations, consolidated financial position or liquidity.
The company also continually evaluates opportunities to dispose of assets that are not key to providing sufficient long-term value, or to acquire assets or operations complementary to its asset base to help augment the companys growth. During the first quarter 2007, the company authorized the sale of its 31 percent ownership interest in the Nerefco Refinery and the associated TEAM Terminal in the Netherlands. The transaction is subject to signing of the sales agreement and obtaining necessary regulatory approvals. The company expects to record a gain upon close of the sale. In early 2007, the company was also in discussions regarding the possible sale of its fuels marketing operations in the Netherlands, Belgium and Luxembourg. Neither the refining nor marketing assets were classified as held-for-sale as of December 31, 2006, in accordance with the held-for-sale criteria of Financial Accounting Standards Board (FASB) Statement No. 144, Impairment or Disposal of Long-Lived Assets. Other asset dispositions and restructurings may occur in future periods and could result in significant gains or losses.
Comments related to earnings trends for the companys major business areas are as follows:
Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to 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 damage and disruptions, competing fuel prices, and regional supply interruptions that may be caused by military conflicts, civil unrest or political uncertainty.
Moreover, any of these factors could also inhibit the companys production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and business.
Price levels for capital and exploratory costs and operating expenses associated with the efficient production of crude oil and natural gas can also be subject to external factors beyond the companys control. External factors include not
only the general level of inflation, but also prices charged by the industrys product- and service-providers, which can be affected by the volatility of the industrys own supply and demand conditions for such products and services. The oil and gas industry worldwide experienced significant price increases for these items during 2005 and 2006, and an upward trend in prices may continue into 2007. Capital and exploratory expenditures and operating expenses also can be affected by uninsured damages to production facilities caused by severe weather or civil unrest.
Industry price levels for crude oil generally increased in the first half of 2006 and declined in the second half. Prices at the end of 2006 were slightly lower than at the beginning of the year. The spot price for West Texas Intermediate (WTI) crude oil, a benchmark crude oil, averaged $66 per barrel in 2006, an increase of approximately $9 per barrel from the 2005 average price. The rise in crude oil prices between years reflected, among other things, increasing demand in growing economies, the heightened level of geopolitical uncertainty in some areas of the world and supply concerns in other key producing regions. For early 2007 into late February, the WTI spot price averaged about $56 per barrel.
As was the case in 2005, a wide differential in prices existed in 2006 between high-quality, light-sweet crude oils (such as the U.S. benchmark WTI) and heavier types of crude. The price for the heavier crudes has been dampened because of ample supply and lower relative demand due to the limited number of refineries that are able to process this lower-quality feedstock into light products (i.e., motor gasoline, jet fuel, aviation gasoline and diesel fuel). The price
for higher-quality, light-sweet crude oil has remained high, as the demand for light products, which can be more easily manufactured by refineries from light-sweet crude oil, has been strong worldwide. Chevron produces heavy crude oil in California, Chad, Indonesia, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom North Sea. (Refer to page FS-11 for the companys average U.S. and international crude oil prices.)
In contrast to price movements in the global market for crude oil, price changes for natural gas are more closely aligned with regional supply and demand conditions. In the United States during 2006, benchmark prices at Henry Hub averaged about $6.50 per thousand cubic feet (MCF), compared with about $8 in 2005. For early 2007 into late February, prices averaged about $7 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. Natural gas prices in the United States are also typically higher during the winter period when demand for heating is greatest.
In contrast to the United States, certain other regions of the world in which the company operates have different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the companys production of natural gas. (Refer to page FS-11 for the companys average natural gas prices for the United States and international regions.) Additionally, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other markets because of the lack of infrastructure to transport and receive liquefied natural gas.
To help address this regional imbalance between supply and demand for natural gas, Chevron is planning increased
investments in long-term projects in areas of excess supply to install infrastructure to produce and liquefy natural gas for transport by tanker, along with investments and commitments to regasify the product in markets where demand is strong and supplies are not as plentiful. Due to the significance of the overall investment in these long-term projects, the natural gas sales prices in the areas of excess supply (before the natural gas is transferred to a company-owned or third-party processing facility) are expected to remain well below sales prices for natural gas that is produced much nearer to areas of high demand and can be transported in existing natural gas pipeline networks (as in the United States).
Besides the impact of the fluctuation in price for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is also a function of other factors, including the companys ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms, and the cost of goods and services.
Chevrons worldwide net oil-equivalent production in 2006, including volumes produced from oil sands and production under an operating service agreement, averaged 2.67 million barrels per day, or 6 percent higher than production in 2005. The increase between periods was largely due to volumes associated with the acquisition of Unocal in August 2005. The company estimates that oil-equivalent production in 2007 will average approximately 2.6 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the scope of company operations, and production disruptions that could be caused by severe weather, local civil unrest and changing geopolitics. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Most of Chevrons upstream investment is currently being made outside the United States. Investments in upstream projects generally are made well in advance of the start of the associated crude oil and natural gas production.
Approximately 24 percent of the companys net oil-equivalent production in 2006 occurred in the OPEC-member countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. In December 2006, OPEC admitted Angola as a new member effective January 1, 2007. Oil-equivalent production for 2006 in Angola represented 6 percent of the companys total. In October 2006, OPEC announced its decision to reduce OPEC-member production quotas by 1.2 million barrels of crude oil per day, or 4.4 percent, from a production level of 27.5 million barrels, effective
November 1, 2006. In December 2006, OPEC announced an additional quota reduction of 500,000 barrels of crude oil per day, effective February 1, 2007. OPEC quotas did not significantly affect Chevrons production level in 2006. The impact of quotas on the companys production in 2007 is uncertain.
In October 2006, Chevrons Boscan and LL-652 operating service agreements in Venezuela were converted to Empresas Mixtas (i.e. joint stock contractual structures), with Petróleos de Venezuela S.A., as majority shareholder. Beginning in October, Chevron reported its equity share of the Boscan and LL-652 production, which was approximately 90,000 barrels per day less than what the company previously reported under the operating service agreements. The change to the Empresa Mixta structure did not have a material effect on the companys results of operations, consolidated financial position or liquidity.
At the end of 2005 in certain onshore areas of Nigeria, approximately 30,000 barrels per day of the companys net production capacity remained shut-in following civil unrest and damage to production facilities that occurred in 2003. By the end of 2006, the company had resumed operations in portions of all the affected fields, and more than 20,000 barrels per day of production had been restored. In early 2007, additional production restoration activities continued in the area; however, intermittent civil unrest could adversely impact company operations in the future.
Refer to pages FS-6 through FS-7 for additional discussion of the companys upstream operations.
Downstream Earnings for the downstream segment are closely tied to global and regional supply and demand for refined products and the associated effects on industry refining and marketing margins. Other factors include the reliability and efficiency of the companys refining and marketing network, the effectiveness of the crude-oil and product-supply functions, and the economic returns on invested capital. Profitability can also be affected by the volatility of charter expenses for the companys shipping operations, which are driven by the industrys demand for crude oil and product tankers. Other factors that are beyond the companys control include the general level of inflation and energy costs to operate the companys refinery and distribution network.
The companys core marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia and sub-Saharan Africa. The company operates or has ownership interests in refineries in each of these areas, except Latin America. In 2006, earnings for the segment improved substantially, mainly as the result of higher average margins for refined products and improved operations at the companys refineries.
Industry margins in the future may be volatile and are influenced by changes in the price of crude oil used for refinery feedstock and by changes in the supply and demand for crude oil and refined products. The industry supply and demand balance can be affected by disruptions at refineries resulting from maintenance programs and unplanned outages, including weather-related disruptions; refined-product inventory levels; and geopolitical events.
Refer to pages FS-8 through FS-9 for additional discussion of the companys downstream operations.
Chemicals Earnings in the petrochemicals business are closely tied to global chemical demand, industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to follow crude oil and natural gas price movements, also influence earnings in this segment.
Refer to page FS-9 for additional discussion of chemicals earnings.
Key operating developments and other events during 2006 and early 2007 included:
United States In the Gulf of Mexico, the company announced in September 2006 the completion of a successful production test on the 50 percent-owned and operated Jack #2 well. The test was a follow-up to the 2004 Jack discovery and was the deepest well-test ever accomplished in the Gulf of Mexico.
Also in the Gulf of Mexico, the company announced in October its decision to develop the Great White, Tobago and Silvertip fields via a common producing hub, the Perdido Regional Host,
which will have a processing capacity of 130,000 barrels of oil-equivalent per day. First production from the 38 percent-owned Perdido Regional Host is anticipated by 2010. The companys ownership interests in the fields are Great White 33 percent, Tobago 58 percent and Silvertip 60 percent.
Angola In June 2006, the company produced the first crude oil from the offshore Lobito field, located in Block 14. Lobito is part of the 31 percent-owned and operated Benguela BelizeLobito Tomboco (BBLT) development project. As fields and wells are added over the next two years, BBLTs maximum production is expected to reach approximately 200,000 barrels of oil per day. Also in Block 14, the company produced first crude oil in June 2006
from the Landana North reservoir in the 31 percent-owned and operated Tombua-Landana development area. This initial production is tied back to the nearby BBLT production facilities. Tombua-Landana is the companys third deepwater development offshore Angola. Maximum production from the completed Tombua-Landana development is estimated at 100,000 barrels per day by 2010.
In early 2007, the company announced a discovery of crude oil at the 31 percent-owned and operated Lucapa-1 well in deepwater Block 14. The company plans to conduct appraisal drilling and additional geologic and engineering studies to assess the potential resource.
Australia In July 2006, the company discovered natural gas at the Chandon-1 exploration well offshore the northwestern coast in the Greater Gorgon development area. The companys interest in the property is 50 percent.
Also offshore the northwestern coast, the company announced in November 2006 a significant natural gas discovery at its Clio-1 exploration well. The company holds a 67 percent interest in the block where Clio-1 is located. Chevron will be undertaking further work, including a 3-D seismic survey program that started in late 2006, to better determine the potential of the gas find and subsequent development options.
In early 2007, the company was also named operator and awarded a 50 percent interest in exploration acreage in the Greater Gorgon Area. A three-year work program includes geotechnical studies, seismic surveys and drilling of an exploration well.
Azerbaijan The first tanker lifting of crude oil transported through the 9 percent-owned Baku-Tbilisi-Ceyhan (BTC) pipeline occurred in June 2006. The crude is being supplied by the Azerbaijan International Oil Company, in which the company has a 10 percent nonoperated working interest.
Brazil In June 2006, the company announced the decision to develop the 52 percent-owned and operated offshore Frade Field. Initial production is targeted by early 2009, with a maximum annual rate estimated at 90,000 oil-equivalent barrels per day in 2011.
Canada The company acquired heavy oil leases in the Athabasca region of northern Alberta, Canada in 2005 and 2006. The leases comprise more than 75,000 acres and contain significant volumes that have potential for recovery using Steam Assisted Gravity Drainage technology.
Also in Alberta, the company announced its decision in October 2006 to participate in the expansion of the Athabasca Oil Sands Project (AOSP). The expansion is expected to add 100,000 barrels per day of mining and upgrading capacity at an estimated total project cost of $10 billion. Completion of the expansion is planned for 2010, increasing total capacity of the project to approximately 255,000 barrels per day. The company holds a 20 percent nonoperated working interest in AOSP.
Nigeria In May 2006, the company announced the discovery of crude oil at the nonoperated Uge-1 exploration well in the 20 percent-owned offshore Oil Prospecting License 214. Future drilling is contingent primarily on the outcome of ongoing technical studies.
Norway In April 2006, the company was awarded the rights to six blocks in the 19th Norwegian Licensing Round. The 40 percent-owned blocks are located in the Nordkapp East Basin in the Norwegian Barents Sea. A 3-D seismic survey was acquired and is planned to be processed in 2007.
Thailand In early 2006, the company signed two petroleum exploration concessions in the Gulf of Thailand. Chevron has a 71 percent operated interest in one concession, which is in the proximity of the companys Tantawan and Plamuk fields. Initial drilling in the concession is scheduled during 2007. Drilling is projected by 2009 for the other concession, in which Chevron has a 16 percent nonoperated working interest.
United Kingdom In June 2006, the company produced the first crude oil from the 85 percent-owned and operated Area C in the Captain Field. The project reached maximum production of 14,000 barrels of crude oil per day in September 2006.
In early 2007, the company was awarded eight operated exploration blocks and two nonoperated blocks west of Shetland Islands in the 24th United Kingdom Offshore Licensing Round.
Vietnam In April 2006, the company signed a 30-year production-sharing contract with Vietnam Oil and Gas Corporation for Block 122 offshore eastern Vietnam. The company has a 50 percent interest in this block and has undertaken a three-year work program for seismic acquisition and drilling of an exploratory well.
United States In December 2006, the company completed the expansion of the Fluid Catalytic Cracking Unit at the companys refinery in Pascagoula, Mississippi, increasing the refinerys gasoline manufacturing capacity by about 10 percent. The company also submitted an environmental permit application for construction of facilities to increase gasoline output by another 15 percent.
India In April 2006, the company acquired a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to construct, own and operate a refinery in Jamnagar, India. The new refinery would be the worlds sixth largest, designed for a crude oil processing capacity of 580,000 barrels per day. Chevron and Reliance Industries also signed two memoranda of understanding to jointly pursue other downstream and upstream business opportunities. If discussions pursuant to the memoranda of understanding lead to definitive agreements, Chevron may increase its equity stake in Reliance Petroleum to 29 percent.
Biofuels In May 2006, the company announced that it had completed the acquisition of a 22 percent interest in Galveston Bay Biodiesel L.P., which is building one of the first large-scale biodiesel plants in the United States. The following month, the company entered into a research alliance with the Georgia Institute of Technology to pursue advanced technology aimed at making cellulosic biofuels and hydrogen into transportation fuels. In September, the company announced a research collaboration with the University of California, Davis aimed at converting cellulosic biomass into transportation fuels.
Common Stock Dividends and Stock Repurchase Program In April 2006, the company increased its quarterly common stock dividend by 15.5 percent to $0.52 per share. In November, the company completed its second $5 billion common stock buyback program since 2004 and in December authorized the acquisition of up to $5 billion of additional shares over a period of up to three years.
RESULTS OF OPERATIONS
Major Operating Areas The following section presents the results of operations for the companys business segments upstream, downstream and chemicals as well as for all other, which includes mining, power generation businesses, and the various companies and departments that are managed at the corporate level. Income is also presented for the U.S. and international geographic areas of the upstream and downstream business segments. (Refer to Note 8, beginning on page FS-38, for a discussion of the companys reportable segments, as defined in FASB No. 131, Disclosures About Segments of an Enterprise and Related Information.) This section should also be read in conjunction with the discussion in Business Environment and Outlook on pages FS-2 through FS-5.
U.S. upstream income of $4.3 billion in 2006 increased approximately $100 million from 2005. Earnings in 2006 benefited about $850 million from higher average prices on oil-equivalent production and the effect of seven additional months of production from the Unocal properties that were acquired in August 2005. Substantially offsetting these benefits were increases in operating expense and expenses for depreciation and exploration. Included in the operating expense increases were costs associated with the carryover effects of hurricanes in the Gulf of Mexico in 2005.
Income of $4.2 billion in 2005 was $230 million higher than 2004. The 2004 amount included gains of approxi-
mately $400 million from asset sales. Higher prices for crude oil and natural gas in 2005 and five months of earnings from the former Unocal operations contributed approximately $2 billion to the increase between periods. Approximately 90 percent of this amount related to the effects of higher prices on heritage-Chevron production. These benefits were substantially offset by the adverse effects of lower production, higher operating expenses and higher depreciation expense associated with the heritage Chevron properties.
The companys average realization for crude oil and natural gas liquids in 2006 was $56.66 per barrel, compared with $46.97 in 2005 and $34.12 in 2004. The average natural gas realization was $6.29 per thousand cubic feet in 2006, compared with $7.43 and $5.51 in 2005 and 2004, respectively.
Net oil-equivalent production in 2006 averaged 763,000 barrels per day, up 5 percent from 2005 and down 7 percent from 2004. The increase between 2005 and 2006 was due to the full-year benefit of production from the former Unocal
properties. The decrease from 2004 was associated mainly with the effects of hurricanes, property sales and normal field declines, partially offset by additional volumes from the former Unocal properties.
The net liquids component of oil-equivalent production for 2006 averaged 462,000 barrels per day, an increase of approximately 2 percent from 2005 and a decrease of 9 percent from 2004. Net natural gas production averaged 1.8 billion cubic feet per day in 2006, up 11 percent from 2005 and down 3 percent from 2004.
Refer to the Selected Operating Data table, on page FS-11, for the three-year comparative production volumes in the United States.
International Upstream Exploration and Production
International upstream income of approximately $8.9 billion in 2006 increased $1.3 billion from 2005. Earnings in 2006 benefited approximately $3.0 billion from higher prices for crude oil and natural gas and an additional seven months of production from the former Unocal properties. About 70 percent of this benefit was associated with the impact of higher prices. Substantially offsetting these benefits were increases in depreciation expense, operating expense and exploration expense. Also adversely affecting 2006 income were higher taxes related to an increase in tax rates in the U.K. and Venezuela and settlement of tax claims and other tax items in Venezuela, Angola and Chad. Foreign currency effects reduced earnings by $371 million in 2006, but increased income $14 million in 2005.
Income in 2005 was approximately $7.5 billion, compared with $5.8 billion in 2004, which included gains of approximately $850 million from property sales. Higher prices for crude oil and natural gas in 2005 and five months of earnings from the former Unocal operations increased income approximately $2.9 billion between periods. About 80 percent of this benefit arose from the effects of higher prices on heritage-Chevron production. Partially offsetting these benefits were higher expenses between periods for certain income tax items, including the absence of a $200 million benefit in 2004 relating to changes in income tax laws. Foreign currency effects increased income $14 million in 2005 but reduced income $129 million in 2004.
The companys average realization for crude oil and natural gas liquids in 2006 was $57.65 per barrel, compared with $47.59 in 2005 and $34.17 in 2004. The average natural gas realization was $3.73 per thousand cubic feet in 2006, compared with $3.19 and $2.68 in 2005 and 2004, respectively.
Net oil-equivalent production of 1.9 million barrels per day in 2006, including about 100,000 net barrels per day from oil sands in Canada and production under an operating service agreement in Venezuela prior to its conversion to a joint stock company, increased about 6 percent from 2005 and 13 percent from 2004. This trend was largely the result of the effects of the Unocal acquisition in August 2005, partially offset by the effect of normal field declines and property sales in 2004.
The net liquids component of oil-equivalent production was 1.4 million barrels per day in 2006, an increase of approximately 2 percent from 2005 and 2004. Net natural gas production of 3.1 billion cubic feet per day in 2006 was up 21 percent and 51 percent from 2005 and 2004, respectively.
Refer to the Selected Operating Data table, on page FS-11, for the three-year comparative of international production volumes.
U.S. Downstream Refining, Marketing and Transportation
U.S. downstream earnings of $1.9 billion in 2006 increased about $1 billion from 2005 and approximately $700 million from 2004. Average refined-product margins in 2006 were higher than in 2005, which in turn were also higher than in 2004. Refinery crude inputs were higher in 2006 than in the other comparative periods and also benefited earnings. However, earnings declined in 2005 from
a year earlier due mainly to increased downtime at the companys refineries, including the shutdown of operations at Pascagoula, Mississippi, for more than a month due to hurricanes in the Gulf of Mexico. The companys marketing and pipeline operations along the Gulf Coast were also disrupted for an extended period due to the hurricanes. Fuel costs were also higher in 2005 than in 2004.
Sales volumes of refined products in 2006 were approximately 1.5 million barrels per day, an increase of 1 percent from 2005 and relatively unchanged from 2004. The reported sales volume for 2006 was on a different basis than in 2005 and 2004 due to a change in accounting rules that became effective April 1, 2006, for certain purchase and sale
(buy/sell) contracts with the same counterparty. Excluding the impact of the accounting change, refined product sales in 2006 increased by approximately 6 percent and 3 percent from 2005 and 2004, respectively. Branded gasoline sales volumes of approximately 614,000 barrels per day in 2006 increased about 4 percent from 2005, largely due to the growth of the Texaco brand. In 2005, refined-product sales volumes decreased about 2 percent from 2004, primarily due to disruption related to the hurricanes.
Refer to the Selected Operating Data table, on page FS-11, for the three-year comparative refined-product sales volumes in the United States. Refer also to Note 14, Accounting for Buy/Sell Contracts, on page FS-43 for a discussion of the accounting for purchase and sale contracts with the same counterparty.
International Downstream Refining, Marketing and Transportation
International downstream income of $2 billion in 2006 increased about $250 million from 2005 and about $50 million from 2004. The increase in 2006 from 2005 was associated mainly with the
benefit of higher-refined product margins in Asia-Pacific and Canada and improved results from crude-oil and refined-product trading activities. The decrease in earnings in 2005 from 2004 was due mainly to lower sales volumes; higher costs for fuel and transportation; expenses associated with a fire at a 40 percent-owned, nonoperated terminal in the United Kingdom; and tax adjustments in various countries. These items more than offset an improvement in average refined-product margins between periods. Foreign currency effects improved income by $98 million and $7 million in 2006 and 2004, respectively, but reduced income by $24 million in 2005.
Refined-product sales volumes were 2.1 million barrels per day in 2006, about 6 percent lower than 2005. Excluding the accounting change for buy/sell contracts, sales were down 1 percent between 2005 and 2006. Refined-product sales volume of 2.3 million barrels per day in 2005 were about 4 percent lower than in 2004, primarily the result of lower gasoline trading activity and lower fuel oil sales. Refer to the Selected Operating Data table, on page FS-11, for the three-year comparative refined-product sales volumes in the international areas.
The chemicals segment includes the companys Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem). In 2006, earnings of $539 million increased about $200 million from both 2005 and 2004. Margins in 2006 for commodity chemicals at CPChem and for fuel and lubricant additives at Oronite were higher than in 2005 and 2004. The earnings decline from 2004 to 2005 was mainly attributable to plant outages and expenses in the Gulf of Mexico region due to hurricanes, which affected both Oronite and CPChem.
All Other consists of the companys interest in Dynegy Inc., mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.
Net charges of $516 million in 2006 decreased $173 million from $689 million in 2005. Excluding the effects of foreign currency, net charges declined $60 million between periods. Interest income was higher in 2006, and interest expense was lower.
Between 2004 and 2005, net charges increased $669 million. Excluding the effects of foreign exchange, net charges increased $574 million. Approximately $400 million of the increase was related to larger benefits in 2004 from
corporate-level tax adjustments. Higher charges in 2005 also were associated with environmental remediation of properties that had been sold or idled and Unocal corporate-level activities. Interest expense was higher in 2005 due to an increase in interest rates and the debt assumed with the Unocal acquisition.
CONSOLIDATED STATEMENT OF INCOME
Comparative amounts for certain income statement categories are shown below:
Sales and other operating revenues in 2006 increased over 2005 due primarily to higher prices for refined products. The increase in 2005 from 2004 was a result of the same factor plus the effect of higher average prices for crude oil and natural gas. The higher revenues in 2006 were net of an impact from the change in the accounting for buy/sell contracts, as described in Note 14 on page FS-43.
Increased income from equity affiliates in 2006 was mainly due to improved results for Tengizchevroil (TCO) and CPChem. The improvement in 2005 from 2004 was primarily due to improved results for TCO and Hamaca (Venezuela). Refer to Note 12, beginning on page FS-41, for a discussion of Chevrons investment in affiliated companies.
Other income of nearly $1.9 billion in 2004 included approximately $1.3 billion of gains from upstream property sales. Interest income contributed $600 million, $400 million and $200 million in 2006, 2005 and 2004, respectively. Average interest rates and balances of cash and marketable securities increased each year. Foreign currency losses were $260 million in 2006 and $60 million in both 2005 and 2004.
Crude oil and product purchases in 2006 increased from 2005 on higher prices for crude oil and refined products and the inclusion of Unocal-related amounts for a full year in 2006. The increase was mitigated by the effect of the accounting change in April 2006 for buy/sell contracts. Purchase costs increased 35 percent in 2005 from the prior year as a result of higher prices for crude oil, natural gas and refined products, as well as to the inclusion of Unocal-related amounts for five months.
Operating, selling, general and administrative expenses in 2006 increased 16 percent from a year earlier. Expenses associated with the former Unocal operations are included for the full year in 2006, vs. five months in 2005. Besides this effect, expenses were higher in 2006 for labor, transportation, uninsured costs associated with the hurricanes in 2005 and a number of corporate items that individually were not significant. Total expenses increased in 2005 from 2004 due mainly to the inclusion of former-Unocal expenses for five months, higher costs for labor and transportation, uninsured costs associated with storms in the Gulf of Mexico, and asset write-offs.
Exploration expenses in 2006 increased from 2005 mainly due to higher amounts for well write-offs and geological and geophysical costs for operations outside the United States, as well as the inclusion of expenses for the former Unocal operations for a full year in 2006. Expenses increased in 2005 from 2004 due mainly to the inclusion of Unocal-related amounts for five months.
Depreciation, depletion and amortization expenses increased from 2004 through 2006 mainly as a result of depreciation and depletion expense for the former Unocal assets and higher depreciation rates for certain heritage-Chevron crude oil and natural gas producing fields worldwide.
Interest and debt expense in 2006 decreased from 2005 primarily due to lower average debt balances and an increase in the amount of interest capitalized, partially offset by higher average interest rates on commercial paper and other variable-rate debt. The increase in 2005 over 2004 was mainly due to the inclusion of debt assumed with the Unocal acquisition and higher average interest rates for commercial paper borrowings.
Taxes other than on income were essentially unchanged in 2006 from 2005, with the effect of higher U.S. refined product sales being offset by lower sales volumes subject to duties in the companys European downstream operations.
The increase in 2005 from 2004 was the result of higher international taxes assessed on product values, higher duty rates in the areas of the companys European downstream operations and higher U.S. federal excise taxes on jet fuel resulting from a change in tax law that became effective in 2005.
Effective income tax rates were 46 percent in 2006, 44 percent in 2005 and 37 percent in 2004. The higher tax rate in 2006 included the effect of one-time charges totaling $400 million, including an increase in tax rates on upstream operations in the U.K. North Sea and settlement of a tax claim in Venezuela. Rates were higher in 2005 compared with the prior year due to an increase in earnings in countries with higher tax rates and the absence of benefits in 2004 from changes in the income tax laws for certain international operations. Refer also to the discussion of income taxes in Note 16 beginning on page FS-44.
SELECTED OPERATING DATA1,2
INFORMATION RELATED TO INVESTMENT IN
At year-end 2006, Chevron owned a 19 percent equity interest in the common stock of Dynegy Inc., a provider of electricity to markets and customers throughout the United States.
Investment in Dynegy Common Stock At December 31, 2006, the carrying value of the companys investment in Dynegy common stock was approximately $250 million. This amount was about $180 million below the companys proportionate interest in Dynegys underlying net assets. This difference is primarily the result of write-downs of the investment in 2002 for declines in the market value of the common shares below the companys carrying value that were deemed to be other than temporary. The difference had been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the companys analysis of the various factors associated with the decline in value of the Dynegy shares. The companys equity share of Dynegys reported earnings is adjusted quarterly when appropriate to recognize a portion of the difference between these allocated values and Dynegys historical book values. The market value of the companys investment in Dynegys common stock at December 31, 2006, was approximately $700 million.
Investments in Dynegy Preferred Stock In May 2006, the companys investment in Dynegy Series C preferred stock was redeemed at its face value of $400 million. Upon redemption of the preferred stock, the company recorded a before-tax gain of $130 million ($87 million after tax).
Dynegy Proposed Business Combination with LS Power Group Dynegy and LS Power Group, a privately held power plant investor, developer and manager, announced in September 2006 that the companies had executed a definitive agreement to combine Dynegys assets and operations with LS Power Groups power-generation portfolio and for Dynegy to acquire a 50 percent ownership interest in a development joint venture with LS Power. Upon close of the transaction, Chevron will receive the same number of shares of the new companys Class A common stock that it currently holds in Dynegy. Chevrons ownership interest in the combined company will be approximately 11 percent. The transaction is subject to specified conditions, including the affirmative vote of two-thirds of Dynegys common shareholders and the receipt of regulatory approvals.
LIQUIDITY AND CAPITAL RESOURCES
Cash, cash equivalents and marketable securities Total balances were $11.4 billion and $11.1 billion at December 31, 2006 and 2005, respectively. Cash provided by operating activities in 2006 was $24.3 billion, compared with $20.1 billion in 2005 and $14.7 billion in 2004.
The 2006 increase in cash provided by operating activities mainly reflected higher earnings in the upstream and downstream segments, including a full year of earnings from the former Unocal operations that were acquired in August 2005. Cash provided by operating activities was net of contributions to employee pension plans of $0.4 billion, $1.0 billion and $1.6 billion in 2006, 2005 and 2004, respectively. Cash provided by investing activities included proceeds from asset sales of $1.0 billion in 2006, $2.7 billion in 2005 and $3.7 billion in 2004.
Cash provided by operating activities and asset sales during 2006 was sufficient to fund the companys $13.8 billion capital and exploratory program, pay $4.4 billion of dividends to stockholders, repay approximately $2.9 billion in debt and repurchase $5 billion of common stock.
Dividends The company paid dividends of approximately $4.4 billion in 2006, $3.8 billion in 2005 and $3.2 billion in 2004. In April 2006, the company increased its quarterly common stock dividend by 15.5 percent to 52 cents per share.
Debt, capital lease and minority interest obligations Total debt and capital lease balances were $9.8 billion at
December 31, 2006, down from $12.9 billion at year-end 2005. The company also had minority interest obligations of $209 million, up from $200 million at December 31, 2005.
The $3.1 billion reduction in total debt and capital lease obligations during 2006 included the early redemption and maturity of several individual debt issues. In the first quarter, $185 million of Union Oil Company bonds matured. In the second quarter, the company redeemed approximately $1.7 billion of Unocal debt prior to maturity. In the fourth quarter, a $129 million Texaco Capital Inc. bond matured, and Union Oil Company bonds of $196 million were redeemed prior to maturity. Commercial paper balances at the end of 2006 were reduced $626 million from year-end 2005. In February 2007, a $144 million Texaco Capital Inc. bond matured.
The companys debt and capital lease obligations due within one year, consisting primarily of commercial paper and the current portion of long-term debt, totaled $6.6 billion at December 31, 2006, up from $5.6 billion at year-end 2005. Of these amounts, $4.5 billion and $4.9 billion were reclassified to long-term at the end of each period, respectively. At year-end 2006, settlement of the reclassified amount was not expected to require the use of working capital in 2007, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance the amounts on a long-term basis. The companys practice has been to maintain commercial paper levels it believes appropriate and economic.
At year-end 2006, the company had $5 billion in committed credit facilities with various major banks, which permitted the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowings and can be used for general corporate purposes. The companys practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the companys strong credit rating. No borrowings were outstanding under these facilities at December 31, 2006. In addition, the company has three existing effective shelf registration statements on file with the Securities and Exchange Commission that together would permit additional registered debt offerings up to an aggregate $3.8 billion of debt securities.
In 2004, Chevron entered into $1 billion of interest rate swap transactions, in which the company receives a fixed interest rate and pays a floating rate, based on the notional principal amounts. Under the terms of the swap agreements, of which $250 million and $750 million will terminate in September 2007 and February 2008, respectively, the net cash settlement will be based on the difference between fixed interest rates and floating interest rates.
The company has outstanding public bonds issued by Chevron Corporation Profit Sharing/Savings Plan Trust Fund, Chevron Canada Funding Company (formerly Chevron Texaco Capital Company), Texaco Capital Inc. and Union Oil Company of California. All of these securities are guaranteed by Chevron Corporation and are rated AA by Standard and Poors Corporation and Aa2 by Moodys Investors Service. The companys U.S. commercial paper is rated A-1+ by Standard and Poors and P-1 by Moodys, and the companys Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All of these ratings denote high-quality, investment-grade securities.
The companys future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. The company believes that it has substantial borrowing capacity to meet unanticipated cash requirements and that during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, it has the flexibility to increase borrowings and/or modify capital-spending plans to continue paying the common stock dividend and maintain the companys high-quality debt ratings.
Common stock repurchase program A $5 billion stock repurchase program initiated in December 2005 was completed in November 2006. During 2006, about 78.5 million common shares were repurchased under this program at a total cost of $4.9 billion.
In December 2006, the company authorized the acquisition of up to an additional $5 billion of its common shares from time to time at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. The program is for a period of up to three years and may be discontinued at any time. Under this program, the company acquired approximately 1.3 million shares in the open market for $100 million during December 2006 and through mid-February 2007 increased the total shares acquired to 8.2 million at a cost of $592 million.
Capital and exploratory expenditures Total reported expenditures for 2006 were $16.6 billion, including $1.9 billion for the companys share of affiliates expenditures, which did not require cash outlays by the company. In 2005 and 2004, expenditures were $11.1 billion and $8.3 billion, respectively, including the companys share of affiliates expenditures of $1.7 billion and $1.6 billion in the cor-
responding periods. The 2005 amount excludes the $17.3 billion acquisition of Unocal Corporation.
Of the $16.6 billion in expenditures for 2006, about three-fourths, or $12.8 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2005 and 2004. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the three years, reflecting the companys continuing focus on opportunities that are available outside the United States.
In 2007, the company estimates capital and exploratory expenditures will be 18 percent higher at $19.6 billion, including $2.4 billion of spending by affiliates. About three-fourths of the total, or $14.6 billion, is budgeted for
exploration and production activities, with $10.6 billion of this amount outside the United States. Spending in 2007 is primarily targeted for exploratory prospects in the deepwater Gulf of Mexico and western Africa and major development projects in Angola, Australia, Brazil, Kazakhstan, Nigeria, the deepwater Gulf of Mexico and an oil sands project in Canada.
Worldwide downstream spending in 2007 is estimated at $3.8 billion, with about $1.6 billion for projects in the United States. Capital projects include upgrades to refineries in the United States and South Korea and construction of liquefied natural gas tankers and gas-to-liquids facilities in support of associated upstream projects.
Investments in chemicals, technology and other corporate businesses in 2007 are budgeted at $1.2 billion. Technology investments include projects related to molecular transformation, unconventional hydrocarbons, oil and gas reservoir management and development of second-generation biofuel production.
Capital and Exploratory Expenditures
Pension Obligations In 2006, the companys pension plan contributions totaled approximately $450 million. Approximately $225 million of the total was contributed to U.S. plans. In 2007, the company estimates total contributions will be $500 million. Actual amounts are dependent upon plan-investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may 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-20.
Current Ratio current assets divided by current liabilities. The current ratio in all periods was adversely affected by the fact that Chevrons inventories are valued on a Last-In-First-Out basis. At year-end 2006, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $6 billion.
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 interest coverage ratio was higher in 2006 compared with 2005, primarily due to higher before-tax income and lower average debt balances. The companys interest coverage ratio was essentially unchanged between 2005 and 2004.
Debt Ratio total debt as a percentage of total debt plus equity. The decrease between 2005 and 2006 was due to lower average debt levels and an increase in stockholders equity. Although total debt was slightly higher at the end of 2005 than a year earlier due to the assumption of debt associated with the Unocal acquisition, the debt ratio declined as a result of higher stockholders equity
balances for retained earnings and the capital stock that was issued in connection with the Unocal acquisition.
Direct or Indirect Guarantees*
* The amounts exclude indemnifications of contingencies associated with the sale of the companys interest in Equilon and Motiva in 2002, as discussed in the Indemnifications section on page FS-15.
At December 31, 2006, the company and its subsidiaries provided guarantees, either directly or indirectly, of $296 million for notes and other contractual obligations of affiliated companies and $131 million for third parties, as described by major category below. There are no amounts being carried as liabilities for the companys obligations under these guarantees.
The $296 million in guarantees provided to affiliates related to borrowings for capital projects. These guarantees were undertaken to achieve lower interest rates and generally cover the construction periods of the capital projects. Included in these amounts are the companys guarantees of $214 million associated with a construction completion guarantee for the debt financing of the companys equity interest in the BTC crude oil pipeline project. Substantially all of the $296 million guaranteed will expire between 2007 and 2011, with the remaining expiring by the end of 2015. Under the terms of the guarantees, the company would be required to fulfill the guarantee should an affiliate be in default of its loan terms, generally for the full amounts disclosed.
The $131 million in guarantees provided on behalf of third parties relate to construction loans to governments of certain of the companys international upstream operations. Substantially all of the $131 million in guarantees expire by 2011, with the remainder expiring by 2015. The company would be required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms, generally for the full amounts disclosed.
At December 31, 2006, Chevron also had outstanding guarantees for about $120 million of Equilon debt and leases. Following the February 2002 disposition of its interest in Equilon, the company received an indemnification from Shell for any claims arising from the guarantees. The company has
not recorded a liability for these guarantees. Approximately 50 percent of the amounts guaranteed will expire within the 2007 through 2011 period, with the guarantees of the remaining amounts expiring by 2019.
Indemnifications The company 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 company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300 million. Through the end of 2006, the company paid approximately $48 million under these indemnities and continues to be obligated for possible additional indemnification payments in the future.
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 period of Texacos ownership interest 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 indemnities must be asserted either as early as February 2007 or no later than February 2009, and claims relating to Motiva indemnities must be asserted either as early as February 2007 or no later than February 2012. Under the terms of these 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 posts 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 applicable incident.
In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. Under the indemnification agreement, the companys liability is unlimited until April 2022, when the liability expires. The acquirer shares in certain environmental remediation costs up to a maximum obligation of $200 million, which had not been reached as of December 31, 2006.
Securitization The company securitizes certain retail and trade accounts receivable in its downstream business through the use of qualifying Special Purpose Entities (SPEs). At December 31, 2006, approximately $1.2 billion, representing about 7 percent of Chevrons total current accounts and notes receivable balance, were securitized. Chevrons total estimated financial exposure under these securitizations at December 31, 2006, was approximately $80 million. These arrangements have the effect of accelerating Chevrons collection of the securitized amounts. In the event that the SPEs experience major defaults in the collection of receivables, Chevron believes that it would have no loss exposure connected with third-party investments in these securitizations.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the companys business. The aggregate approximate amounts of required payments under these various commitments are: 2007 $3.2 billion; 2008 $1.7 billion; 2009 $2.1 billion; 2010 $1.9 billion; 2011 $0.9 billion; 2012 and after $4.1 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $3.0 billion in 2006, $2.1 billion in 2005 and $1.6 billion in 2004.