Chevron - 10-K annual report

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

 

OR

 

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)

 

 

Registrant’s 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 ofRegulation S-Kis not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-Kor any amendment to thisForm 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” inRule 12b-2of the Act. (Check one):

 

Large accelerated filerþ            Accelerated filero            Non-accelerated filer o

 

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2of 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 registrant’s 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 toRule 14a-6(b)under the Securities Exchange Act of 1934, in connection with the company’s 2007 Annual Meeting of Stockholders (in Part III)

 

 

 

 

 

 

This Annual Report onForm 10-Kof Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “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 company’s 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 orstart-up of planned projects; the potential disruption or interruption of the company’s 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 company’s 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,¹a 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 company’s major subsidiaries is presented on pages E-4and E-5 of this Annual Report onForm 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 company’s 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. Unocal’s 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 onpage FS-34of this Annual Report onForm 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 world’s swing producers of crude oil, and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and 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 company’s 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 thisForm 10-Kin Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion on the company’s current business environment and outlook.

 

 

Chevron’s 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 company’s international geographic areas — are in Note 8 to the consolidated financial statements beginning onpage FS-38of this Annual Report onForm 10-K.In addition, similar comparative data for the company’s 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 Chevron’s 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 company’s 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 company’s 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 company’s capital and exploratory expenditures onpage FS-13of this Annual Report onForm 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.

 

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 onpage FS-6for a detailed discussion of the factors explaining the 2004–2006 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 company’s major oil and gas development projects.

 

Refer to Table IV onpage FS-68of this Annual Report onForm 10-Kfor data about the company’s 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:

 

 

 

Table V, beginning onpage FS-68,provides a tabulation of the company’s 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 company’s Annual Report onForm 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 company’s acreage is shown in the following table.

 

 

 

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 company’s proved developed U.S. reserves. These contracts include variable-pricing terms.

 

Outside the United States, the company is contractually committed to deliver to third parties 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 company’s 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 company’s development expenditures and costs of proved property acquisitions for 2006, 2005 and 2004 are presented in Table I onpage FS-63of this Annual Report onForm 10-K.

 

The table below summarizes the company’s net interest in productive and dry development wells completed in each of the past three years and the status of the company’s development wells drilling at December 31, 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.

 

 

 

The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 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.

 

 

 

Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2006, 2005 and 2004 are presented in Table I onpage FS-63of this Annual Report onForm 10-K.

 

Chevron’s 2006 key upstream activities, also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning onpage 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 onpage E-11of this Annual Report onForm 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 onpage FS-68for a discussion of the net proved reserves and different hydrocarbon characteristics for the company’s major U.S. producing areas.

 

 

In the Gulf of Mexico deepwater areas, the company’s producing fields during 2006 included:

 

 

The company’s 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 productionstart-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 productionstart-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 productionstart-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 Chevron’s 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 company’s 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 productionstart-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 2007–2008 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 company’s 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 company’s 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 Chevron’s 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 Alaska’s Cook Inlet and owns nonoperated production on the North Slope. During 2006, the company’s 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 theTombua-Landanafacilities are completed, through 2012, when the drilling program is scheduled for completion. The concession for these fields expires in 2028. The total cost of theTombua-Landanaproject 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 Chevron’s other two concessions, the nonoperated working interests are 20 percent in Block 2, which is adjacent to the northwestern part of Angola’s 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 the5-million-metric-ton-per-yearonshore LNG plant to be located in the northern part of the country. Chevron and Sonangol, Angola’s 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 Libya’s 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.

 

Agbami’s maximum total daily production of 250,000 barrels of crude oil and natural gas liquids is expected to be reached within the first year afterstart-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 productionstart-up.The expected field life is approximately 20 years.

 

For Chevron’s 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 productionstart-upestimated 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 productionstart-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. Productionstart-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 ofstart-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 initialstart-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. Chevron’s 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). The25-year-lifeproject 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-1well 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 company’s 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, withstart-uptargeted 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 plannedgas-to-liquidsfacility 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. A350-mileoffshore 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-yearnatural 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. Chevron’s 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-yearLNG 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 theWheatstone-1natural 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 a3-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 of3-D seismic data. On WA-383-P, a three-year work program includes geotechnical studies and2-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 a40-yearconcession 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 Kazakhstan’s 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, Russia’s 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 company’s 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 productionstart-up.The Bibiyana PSC expires in 2034.

 

Thailand: Chevron has both operated and nonoperated working interests in several different offshore blocks in Thailand. The company’s 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 the12-yearproject 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 a30-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 productionstart-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 25-1Field in Bohai Bay Block 11/19. Daily net production from the company’s 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 a60-yearconcession 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 Arabia’s 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.

 

 

 

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 theBM-C-4Block, 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 company’s 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 Venezuela’s 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 company’s 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 company’s 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. Chevron’s 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 company’s 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. A3-D seismic survey was acquired and is planned to be processed in 2007.

 

United Kingdom: Offshore United Kingdom, the company’s 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 company’s 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. Productionstart-upfrom 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.

 

Productionstart-upoccurred 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-yearconcession that expires in 2033. Chevron’s 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 TCO’s 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. Thestart-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, deepenedand/orcompleted 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 TCO’s 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 Venezuela’s 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 government’s 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 Chevron’s 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 company’s 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 new20-yearproduction 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 the20-yearcontract period. Located in Lake Maracaibo,LL-652’snet 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 company’s 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 company’s natural gas sales occur in Australia, Indonesia, Latin America, Thailand and the United Kingdom and in the company’s affiliate operations in Kazakhstan. International natural gas liquids sales take place in Africa, Australia and Europe. Refer to “Selected Operating Data,” onpage FS-11in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s natural gas and natural gas liquids sales volumes. Refer also to “Contract Obligations” on page 7 for information related to the company’s contractual commitments for the sale of crude oil and natural gas.

 

At the end of 2006, the company’s 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:

 

 

 

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 company’s 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, refinery’s 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 company’s refineries in Mississippi and California were being evaluated in early 2007.

 

Also in 2006, GS Caltex, the company’s 50 percent-owned affiliate, began construction of an upgrade project at the650,000-barrel-per-dayYeosu 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. The580,000-barrel-per-day-crude-oil-capacityrefinery 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 world’s sixth largest on a single site.

 

Refer topage FS-2for a discussion of the pending disposition of the company’s 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 Chevron’s U.S. refinery inputs in 2006 and 2005, respectively.

 

The Sasol Chevron Global50-50 Joint Venture was established in 2000 to develop a worldwidegas-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 a34,000-barrel-per-dayGTL 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 company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2006.

 

 

 

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 d’Ivoire, 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 company’s 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 topage FS-2for a discussion of the possible disposition of the company’s 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 company’s ownership interests in pipelines are summarized in the following table.

 

 

 

 

 

 

 

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 Chevron’s controlled seagoing fleet were utilized during 2006. The following table summarizes cargo transported on the company’s controlled fleet.