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, 2012
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 001-00368
(Exact name of registrant as specified in its charter)
6001 Bollinger Canyon Road,
San Ramon, California 94583-2324
(State or other jurisdiction of
incorporation or organization)
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code (925) 842-1000
Securities registered pursuant to Section 12 (b) of the Act:
Title of Each Class
Name of Each Exchange
on Which Registered
Common stock, par value $.75 per share
New York Stock Exchange, Inc.
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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
(Do not check if a smaller
Smaller reporting company 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 registrant’s most recently completed second fiscal quarter — $207,005,770,000 (As of June 29, 2012)
Number of Shares of Common Stock outstanding as of February 11, 2013 — 1,942,697,787
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2013 Annual Meeting and 2013 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2013 Annual Meeting of Stockholders (in Part III)
TABLE OF CONTENTS
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT
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 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,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets,” “outlook” 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, many of which are beyond the company’s 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: changing crude oil and natural gas prices; changing refining, marketing and chemicals margins; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; 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 or start-up of planned projects; the potential disruption or interruption of the company’s production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude oil production quotas that might be imposed by the Organization of Petroleum Exporting Countries; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes required by existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; 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” on pages 28 through 30 in this report. In addition, such results could be affected by general domestic and international economic and political conditions. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.
Item 1. Business
General Development of Business
Summary Description of Chevron
Chevron Corporation,* a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and international subsidiaries that engage in fully integrated petroleum operations, chemicals operations, mining activities, power generation and energy services. Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil and refined products; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lubricant additives.
A list of the company’s major subsidiaries is presented on pages E-4 and E-5. As of December 31, 2012, Chevron had approximately 62,000 employees (including about 3,700 service station employees). Approximately 31,000 employees (including about 3,400 service station employees), or 50 percent, were employed in U.S. operations.
Overview of Petroleum Industry
Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand. 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. Laws and governmental policies, particularly in the areas of taxation, energy and the environment affect where and how companies conduct their operations and formulate their products and, in some cases, limit their profits directly.
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 global 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 competes with fully integrated, major petroleum companies and other independent refining, marketing, transportation and chemicals entities and national petroleum companies in the sale or acquisition of various goods or services in many national and international markets.
Refer to pages FS-2 through FS-8 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s current business environment and outlook.
Chevron’s Strategic Direction
Chevron’s primary objective is to create shareholder value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. In the upstream, the company’s strategies are to grow profitably in core areas, build new legacy positions and commercialize the company’s equity natural gas resource base while growing a high-impact global natural gas business. In the downstream, the strategies are to improve returns and grow earnings across the value chain. The company also continues to utilize technology across all its businesses to differentiate performance, and to invest in profitable renewable energy and energy efficiency solutions.
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 they do 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.
Description of Business and Properties
The upstream and downstream activities of the company and its equity affiliates are widely dispersed geographically, with operations and projects* in North America, South America, Europe, Africa, Asia and Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2012, and assets as of the end of 2012 and 2011 — for the United States and the company’s international geographic areas — are in Note 10 to the Consolidated Financial Statements beginning on page FS-36. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 11 and 12 on pages FS-38 through FS-40.
Capital and Exploratory Expenditures
Total expenditures for 2012 were $34.2 billion, including $2.1 billion for the company’s share of equity-affiliate expenditures. In 2011 and 2010, expenditures were $29.1 billion and $21.8 billion, respectively, including the company’s share of affiliates’ expenditures of $1.7 billion in 2011 and $1.4 billion in 2010.
Of the $34.2 billion in expenditures for 2012, 89 percent, or $30.4 billion, was related to upstream activities. Approximately 89 and 87 percent was expended for upstream operations in 2011 and 2010, respectively. International upstream accounted for about 72 percent of the worldwide upstream investment in 2012, about 68 percent in 2011 and about 82 percent in 2010. These amounts exclude the acquisition of Atlas Energy, Inc., in 2011.
In 2013, the company estimates capital and exploratory expenditures will be $36.7 billion, including $3.3 billion of spending by affiliates. Approximately 90 percent of the total, or $33 billion, is budgeted for exploration and production activities, with $25.5 billion, or about 70 percent, of this amount for projects outside the United States.
Refer also to a discussion of the company’s capital and exploratory expenditures on page FS-12.
The table on the following page summarizes the net production of liquids and natural gas for 2012 and 2011 by the company and its affiliates. Worldwide oil-equivalent production was 2.610 million barrels per day, down about 2 percent from 2011. The decrease was mainly associated with normal field declines, the shut-in of the Frade Field in Brazil, and a major planned turnaround at the Tengizchevroil facilities in Kazakhstan. The start-up and ramp-up of several major capital projects — the Platong II natural gas project in Thailand, the Usan and Agbami 2 projects in Nigeria, and the Perdido, Tahiti 2 and Caesar/Tonga projects in the U.S. Gulf of Mexico — partially offset the decrease in net production from 2011. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the 2010 through 2012 changes in production for crude oil and natural gas liquids, and natural gas.
The company estimates its average worldwide oil-equivalent production in 2013 will be approximately 2.650 million barrels per day based on an average Brent price of $112 per barrel in 2012. This estimate is subject to many factors and uncertainties, including quotas that may be imposed by OPEC, price effects on entitlement volumes, changes in fiscal terms or restrictions on the scope of company operations, delays in project start-ups and ramp-ups, fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, civil unrest, changing geopolitics, delays in completion of maintenance turnarounds, greater-than-expected declines in production from mature fields, or other disruptions to operations. The longer-term outlook for production levels is also 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. 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 crude oil and natural gas development projects.
As used in this report, the term “project” may describe new upstream development activity, individual phases in a multiphase development, maintenance activities, certain existing assets, new investments in downstream and chemicals capacity, investments in emerging and sustainable energy activities, and certain other activities. All of these terms are used for convenience only and are not intended as a precise description of the term “project” as it relates to any specific governmental law or regulation.
Net Production of Crude Oil and Natural Gas Liquids and Natural Gas 1
Components of Oil-Equivalent
Crude Oil & Natural Gas
Liquids (Thousands of
Natural Gas (Millions
of Barrels per Day)
Barrels per Day)
of Cubic Feet per Day)
Trinidad and Tobago
Total Other Americas
Democratic Republic of the Congo
Republic of the Congo
Total Consolidated Companies
Total Including Affiliates4
1 Includes synthetic oil: Canada, net
Venezuelan affiliate, net
2 Located between Saudi Arabia and Kuwait.
3 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan and Petroboscan, Petroindependiente and Petropiar in Venezuela.
4 Volumes include natural gas consumed in operations of 586 million and 582 million cubic feet per day in 2012 and 2011, respectively. Total “as sold” natural gas volumes were 4,488 million and 4,359 million cubic feet per day for 2012 and 2011, respectively.
Average Sales Prices and Production Costs per Unit of Production
Refer to Table IV on page FS-67 for the company’s average sales price per barrel of crude oil, condensate and natural gas liquids and per thousand cubic feet of natural gas produced, and the average production cost per oil-equivalent barrel for 2012, 2011 and 2010.
Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2012 for the company and its affiliates:
Productive Oil and Gas Wells at December 31, 2012
Total Consolidated Companies
Total Including Affiliates
Multiple completion wells included above
Refer to Table V beginning on page FS-67 for a tabulation of the company’s proved net crude oil and natural gas reserves by geographic area, at the beginning of 2010 and each year-end from 2010 through 2012. Reserves governance, technologies used in establishing proved reserves additions, and major changes to proved reserves by geographic area for the three-year period ended December 31, 2012, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.
The net proved reserve balances at the end of each of the three years 2010 through 2012 are shown in the following table.
Net Proved Reserves at December 31
Liquids — Millions of barrels
Natural Gas — Billions of cubic feet
Total Natural Gas
Oil-Equivalent — Millions of barrels
At December 31, 2012, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company’s acreage is shown in the following table.
Acreage at December 31, 2012
(Thousands of Acres)
Total Consolidated Companies
Total Including Affiliates
The gross undeveloped acres that will expire in 2013, 2014 and 2015 if production is not established by certain required dates are 1,254, 3,629 and 3,141, respectively.
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 some natural gas sales contracts specify delivery of fixed and determinable quantities, as discussed below.
In the United States, the company is contractually committed to deliver to third parties 192 billion cubic feet of natural gas through 2015. The company believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third-party purchases. These commitments include a variety of pricing terms, including both indexed and fixed-price contracts.
Outside the United States, the company is contractually committed to deliver a total of 791 billion cubic feet of natural gas to third parties from 2013 through 2015 for operations in Australia, Colombia, Denmark and the Philippines. These 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. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves in these countries.
Refer to Table I on page FS-62 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2012, 2011 and 2010.
The following table 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, 2012. 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
Net Wells Completed
Total Consolidated Companies
Total Including Affiliates
Refer to Table I on page FS-62 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2012, 2011 and 2010.
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, 2012. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation and appraisal 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
Net Wells Completed
Total Consolidated Companies
Total Including Affiliates
Review of Ongoing Exploration and Production Activities in Key Areas
Chevron’s 2012 key upstream activities, some of which are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning on page FS-2, are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1 on page E-11.
The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not on production and for projects recently placed on production. Reserves are not discussed for exploration activities or recent discoveries that have not advanced to a project stage, or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment. Amounts indicated for project costs represent total project costs, not the company’s share of costs for projects that are less than wholly owned.
Chevron has exploration and production activities in most of the world’s major hydrocarbon basins. The company’s upstream strategy is to grow profitably in core areas, build new legacy positions and commercialize the company’s equity natural gas resource base while growing a high-impact global natural gas business. The map above indicates Chevron’s primary areas for exploration and production.
Upstream activities in the United States are concentrated in California, the Gulf of Mexico, Colorado, Louisiana, Michigan, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. Average net oil-equivalent production in the United States during 2012 was 655,000 barrels per day.
In California, the company has significant production in the San Joaquin Valley. In 2012, net daily production averaged 163,000 barrels of crude oil, 70 million cubic feet of natural gas and 4,000 barrels of natural gas liquids (NGLs). Approximately
86 percent of the crude oil production is considered heavy oil (typically with API gravity lower than 22 degrees).
During 2012, net daily production for the company’s combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region, was 153,000 barrels of crude oil, 395 million cubic feet of natural gas and 16,000 barrels of NGLs.
Chevron was engaged in various exploration and development activities in the deepwater Gulf of Mexico during 2012. The Jack and St. Malo fields are located within 25 miles of each other and are being jointly developed. Chevron has a 50 percent interest in the Jack Field, a 51 percent interest in the St. Malo Field and a 50.7 percent interest in the production host facility. Both fields are company operated. Drilling operations progressed during 2012, with five of 10 planned wells drilled. At the end of 2012, project activities were more than 57 percent complete, with subsea and floating production unit installation activities expected in second-half 2013. The facility is planned to have a design capacity of 177,000 barrels of oil-equivalent per day to accommodate production from the Jack/St. Malo development, which is estimated to have maximum total daily production of 94,000 barrels of oil equivalent, plus production from a nearby third-party field. Total project costs for the initial phase of development are estimated at $7.5 billion and start-up is expected in 2014. The fields have an estimated production life of 30 years. Proved reserves have been recognized for this project.
In 2012, an evaluation of additional development opportunities was initiated for the Jack and St. Malo fields. Stage 2, the first phase of future development work, is expected to include four additional development wells, two each at the Jack and the St. Malo fields. Front-end engineering and design (FEED) activities are planned to begin in mid-2013. At the end of 2012, proved reserves had not been recognized for the Jack/St. Malo Stage 2 project.
Fabrication and development drilling continued in 2012 for the 60 percent-owned and operated Big Foot project. The development plan includes a 15-slot drilling and production platform with water injection facilities and a design capacity of 79,000 barrels of oil equivalent per day. At the end of 2012, project activities were 68 percent complete, and topside module installation is planned for mid-2013. First production is anticipated in 2014. The field has an estimated production life of 20 years. Proved reserves have been recognized for this project.
Tahiti 2 is the second development phase for the 58 percent-owned and operated Tahiti Field, and is designed to increase recovery and return production to more than 100,000 barrels of crude oil per day. The project includes two additional production wells, three water injection wells and water injection facilities. Drilling commenced on the first production well in early 2012, and water injection began in first quarter 2012. Start-up of the first production well is expected by third quarter 2013. Proved reserves have been recognized for the Tahiti 2 project, and the field has an estimated production life of 30 years.
The company has a 42.9 percent nonoperated working interest in the Tubular Bells Field. Development drilling began in second quarter 2012, and plans include three producing and two injection wells, with a subsea tieback to a third-party production facility. First oil is anticipated in 2014, and maximum total daily production is expected to reach 40,000 to 45,000 barrels of oil-equivalent. The field has an estimated production life of 25 years. The initial recognition of proved reserves for the project occurred in 2012.
Chevron has a 20.3 percent nonoperated working interest in the Caesar and Tonga area. First production occurred in first quarter 2012, and maximum total daily production reached about 62,000 barrels of oil-equivalent by year-end 2012. Drilling operations on the fourth development well concluded in early 2013, and the well is expected to commence production in second quarter 2013.
The company has a 15.6 percent nonoperated working interest in the Mad Dog II Project. FEED commenced in second quarter 2012 and a final investment decision is expected in 2014. The project includes the construction and installation of a new production and drilling spar facility and is expected to add incremental maximum total daily production of 120,000 to 140,000 barrels of oil equivalent. At the end of 2012, proved reserves had not been recognized for this project.
In 2012, Chevron signed commercial agreements for the Stampede project allowing for the joint development of the Knotty Head and Pony fields. Chevron holds a 20 percent nonoperated working interest in this joint development. The project is expected to enter FEED by mid-2013. At the end of 2012, proved reserves had not been recognized for this project.
Deepwater exploration activities in 2012 included participation in three exploratory wells — one appraisal and two wildcats. Drilling began on an appraisal well at the
43.8 percent-owned and operated Moccasin discovery in fourth quarter 2012. Drilling activities were placed on hold in early 2013 for equipment repair and are expected to resume later this year. Moccasin and the 55 percent-owned and operated Buckskin discovery, located 12 miles apart, could be jointly developed upon the successful completion of additional appraisal drilling planned for 2013. A second Coronado wildcat well began drilling in second quarter 2012, targeting the lower Tertiary Wilcox formation. Drilling was completed in February 2013, and the results are under evaluation. Chevron also had a 20 percent nonoperated working interest in the Hummer Shallow wildcat well.
Chevron added 15 leases to the deepwater portfolio as a result of awards from the central Gulf of Mexico lease sale in mid-2012. In addition, Chevron submitted the highest bids on 28 additional deepwater leases at the western Gulf of Mexico lease sale in late 2012.
Besides the activities connected with development and exploration projects in the Gulf of Mexico, the company also has contracted liquefied natural gas (LNG) offloading, storage and regasification capacity at the Sabine Pass LNG facility and natural gas transportation capacity in a third-party pipeline system connecting the terminal to the U.S. natural gas pipeline grid.
Company activities in the mid-continental United States include operated and nonoperated interests in properties primarily in Colorado, New Mexico, Oklahoma, Texas and Wyoming. During 2012, the company’s net daily production in these areas averaged 90,000 barrels of crude oil, 600 million cubic feet of natural gas and 29,000 barrels of NGL's.
In West Texas, the company continues to pursue development of tight oil and liquids-rich shale resources in the Midland Basin’s Wolfcamp play and several plays in the Delaware Basin through use of advanced drilling and completion technologies. Additional production growth is expected from interests in these formations in future years. In October 2012, an acquisition of more than 350,000 gross acres in New Mexico augmented the company's leasehold position in the Delaware Basin and surrounding areas.
The company holds leases in the Marcellus Shale and Utica Shale, primarily located in southwestern Pennsylvania, Ohio, and West Virginia, and in the Antrim Shale in Michigan. During 2012, the company's net daily production in these areas averaged approximately 138 million cubic feet of natural gas. In 2012, development of the Marcellus Shale proceeded at a measured pace, focused on improving execution capability and reservoir understanding. Activities in the Utica Shale during 2012 included acquisition of regional seismic data in eastern Ohio to identify core areas. The company commenced drilling on four exploratory wells during the year. This initial activity was focused on acquiring data necessary for potential future development. The company also holds a 49 percent interest in Laurel Mountain Midstream, LLC, an affiliate that owns more than 1,200 miles of natural gas gathering lines servicing the Marcellus.
“Other Americas” is composed of Argentina, Brazil, Canada, Colombia, Suriname, Trinidad and Tobago, and Venezuela. Net oil-equivalent production from these countries averaged 230,000 barrels per day during 2012, including the company’s share of synthetic oil production.
Canada: Chevron has interests in oil sands projects and shale acreage in Alberta, shale acreage and an LNG project in British Columbia, exploration, development and production projects offshore in the Atlantic region, and exploration and discovered resource interests in the Beaufort Sea region of the Northwest Territories. Average net oil-equivalent production during 2012 was 69,000 barrels per day, composed of 25,000 barrels of crude oil, 4 million cubic feet of natural gas and 43,000 barrels of synthetic oil from oil sands.
The company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP). Oil sands are mined from both the Muskeg River and the Jackpine mines and bitumen is extracted from the oil sands and upgraded into synthetic oil. During 2012, ramp-up from the AOSP Expansion 1 Project continued to boost production toward the total daily design capacity of approximately 255,000 barrels. Additionally, a final investment decision was reached in mid-2012 on the Quest Project, a carbon capture and sequestration project that is designed to capture and store more than one million tons annually of carbon dioxide produced by bitumen processing at the AOSP by 2015.
In February 2013, Chevron acquired a 50 percent-owned and operated interest in the Kitimat LNG project and proposed Pacific Trail Pipeline, and a 50 percent nonoperated working interest in 644,000 total acres in the Horn River and Liard shale gas basins in British Colombia. The Kitimat project is planned to include a two-train, 10.0 million-metric-ton-per-year LNG facility, and at the time of acquisition, FEED activities were in progress.
Chevron holds a 26.9 percent nonoperated working interest in the Hibernia Field and a 23.6 nonoperated working interest in the unitized Hibernia Southern Extension (HSE) offshore Atlantic Canada. The HSE development is expected to increase the economic life of the Hibernia Field. Fabrication of topside and subsea equipment progressed in 2012. Full production start-up is expected in 2014. Proved reserves have been recognized for the initial wells drilled.
The company holds a 26.6 percent nonoperated working interest in the heavy-oil Hebron Field, also offshore Atlantic Canada. The development plan includes a concrete, gravity-based platform with a capacity of 150,000 barrels of crude oil per day. The maximum total daily crude oil production is expected to be 134,000 barrels. FEED activities were completed in 2012, and a final investment decision was made in December 2012. Project costs are estimated at $14 billion. The project has an expected economic life of 30 years, and first oil is expected in 2017. The initial recognition of proved reserves for the project occurred in 2012.
During 2012, drilling continued on a multiwell program on the 100 percent-owned and operated leases in the Duvernay shale formation in Alberta. The company also holds exploration licenses and leases in the Flemish Pass and Orphan basins offshore Atlantic Canada and the Beaufort Sea region of the Northwest Territories, including a 35.4 percent nonoperated working interest in the offshore Amauligak discovery.
In addition, Chevron holds interests in the Aitken Creek and Alberta Hub natural gas storage facilities, which have aggregate total capacity of approximately 100 billion cubic feet. These facilities are located in western Canada near the Duvernay, Horn River, Liard and Montney shale gas plays.
Greenland: In December 2012, Chevron relinquished its 29.2 percent nonoperated working interest in Exploration License 2007/26, which includes Block 4 offshore West Greenland.
Argentina: Chevron holds operated interests in four concessions in the Neuquen Basin. Working interests range from 18.8 percent to 100 percent. Net oil-equivalent production in 2012 averaged 22,000 barrels per day, composed of 21,000 barrels of crude oil and 4 million cubic feet of natural gas. During 2012, two exploratory wells targeting shale gas and tight oil resources were drilled in the Vaca Muerta formation in the El Trapial concession. In early 2013, a third exploratory well commenced drilling and the results of the previous wells were under evaluation. Chevron plans to drill three additional appraisal wells in 2013. The El Trapial concession expires in 2032.
Brazil: Chevron holds working interests in three deepwater fields in the Campos Basin: Frade (51.7 percent-owned and operated), Papa-Terra and Maromba (37.5 percent and 30 percent nonoperated working interests, respectively). Net oil-equivalent production in 2012 averaged 6,000 barrels per day, composed of 6,000 barrels of crude oil and 2 million cubic feet of natural gas.
In March 2012, production was suspended as a precautionary measure at the Frade Field while studies were conducted to better understand the geology in the area. Production is expected to partially resume in 2013 subject to necessary regulatory approvals. The concession that includes the Frade Field expires in 2025.
During 2012, construction activities and development drilling continued for the Papa-Terra project. The project includes a floating production, storage and offloading vessel (FPSO) and a tension leg wellhead platform, with a design capacity of 140,000 barrels of crude oil per day. First production is expected in second-half 2013. Proved reserves have been recognized for this project. Evaluation of the field development concept for Maromba continued in 2012 with submission of an initial Plan of Development to the authorities in September. At the end of 2012, proved reserves had not been recognized for this project. These concessions expire in 2032.
Colombia: The company operates the offshore Chuchupa and the onshore Ballena and Riohacha natural gas fields as part of the Guajira Association contract. In exchange, Chevron receives 43 percent of the production for the remaining life of each field and a variable production volume based on prior Chuchupa capital contributions. Daily net production averaged 216 million cubic feet of natural gas in 2012.
Suriname: In November 2012, Chevron acquired a 50 percent nonoperated working interest in Blocks 42 and 45 offshore Suriname. Under the agreements, the company would assume the role of operator in the event of commercial discoveries. In 2013, planned exploration activities include seismic data acquisition and processing.
Trinidad and Tobago: The company has a 50 percent nonoperated working interest in three blocks in the East Coast Marine Area offshore Trinidad, which includes the Dolphin and Dolphin Deep producing natural gas fields and the Starfish development. Net production in 2012 averaged 173 million cubic feet of natural gas per day. Development of the Starfish Field commenced in third quarter 2012, and first gas is expected in 2014. Natural gas from the project will supply existing contractual commitments. Proved reserves have been recognized for this project. Chevron also holds a 50 percent-owned and operated interest in the Manatee Area of Block 6(d) where the Manatee discovery comprises a single cross-border field with Venezuela's Loran Field in Block 2. In 2012, work continued on maturing commercial development concepts.
Venezuela: Chevron holds interests in two producing affiliates located in western Venezuela and one producing affiliate in the Orinoco Belt. Chevron has a 30 percent interest in the Petropiar affiliate that operates the Hamaca heavy-oil production and upgrading project located in Venezuela’s Orinoco Belt, a 39.2 percent interest in the Petroboscan affiliate that operates the Boscan Field in the western part of the country, and a 25.2 percent interest in the Petroindependiente affiliate that operates the LL-652 Field in Lake Maracaibo. The company’s share of net oil-equivalent production during 2012 from these operations averaged 68,000 barrels per day, composed of 64,000 barrels of liquids and 27 million cubic feet of natural
Chevron holds a 34 percent interest in the Petroindependencia affiliate that is working toward commercialization of Carabobo 3, a heavy-oil project located within the Carabobo Area of the Orinoco Belt. During 2012, work continued on conceptual engineering for the potential development project.
The company operates and has a working interest of 60 percent in Block 2 in the Plataforma Deltana area offshore eastern Venezuela, which includes the Loran Field. During 2012, work continued on maturing commercial development concepts.
In Africa, the company is engaged in upstream activities in Angola, Chad, Democratic Republic of the Congo, Liberia, Morocco, Nigeria, Republic of the Congo, Sierra Leone and South Africa. Net oil-equivalent production in Africa averaged 451,000 barrels per day during 2012.
Angola: Chevron holds company-operated working interests in offshore Blocks 0 and 14 and nonoperated working interests in offshore Block 2 and the onshore Fina Sonangol Texaco (FST) area. Net production from these operations in 2012 averaged 137,000 barrels of oil-equivalent per day.
The company operates the 39.2 percent-owned Block 0, which averaged 98,000 barrels per day of net liquids production in 2012. The Block 0 concession extends through 2030.
Work on the second development stage of the Mafumeira Field in Block 0 continued in 2012. Mafumeira Sul, a project to develop the southern portion of the field, reached a final investment decision in 2012. Development plans include a central processing facility, two wellhead platforms, subsea pipelines, and 34 producing and 16 water injection wells. First production is planned for 2015, with maximum total production expected to reach 110,000 barrels of crude oil and 10,000 barrels of liquefied petroleum gas (LPG) per day. The project is estimated to cost $5.6 billion. The initial recognition of proved reserves for this project occurred in 2012.
A project to develop the Greater Vanza/Longui Area of Block 0 is scheduled to enter FEED in second-half 2013. FEED activities continued during 2012 on the south extension of the N’Dola Field development with a final investment decision expected in 2014. The facility is planned to have a design capacity of 28,000 barrels of crude oil per day. At the end of 2012, proved reserves had not been recognized for these projects.
Work continued in 2012 on the final stage of the Nemba Enhanced Secondary Recovery Stage 1 and 2 Project in Block 0. Installation activities are scheduled to begin in 2013, and project start-up is expected in early 2015. Maximum total production is expected to reach 13,000 barrels of oil-equivalent per day. Proved reserves have been recognized for this project.
Also in Block 0, drilling commenced on a post-salt/pre-salt dual objective exploration well in Area A in late 2012 and was completed in early 2013. The results are under evaluation. An additional pre-salt exploration well in Area A is planned for second-half 2013, along with one pre-salt and one post-salt appraisal well in Area B.
In the 31 percent-owned Block 14, net production in 2012 averaged 28,000 barrels of liquids per day. Development and production rights for the various producing fields in Block 14 expire between 2023 and 2028.
In June 2012, the project to develop the Lucapa Field in Block 14 entered FEED. Development plans include an FPSO and 17 subsea wells. The facility is planned to have a design capacity of 80,000 barrels of crude oil per day. A final investment decision is expected in 2014. During the year, development alternatives were evaluated for the Malange Field, and the project is expected to enter FEED in mid-2013. At the end of 2012, proved reserves had not been recognized for these projects.
In addition to the exploration and production activities in Angola, Chevron has a 36.4 percent interest in Angola LNG Limited, which will operate an onshore natural gas liquefaction plant in Soyo, Angola. The plant is designed to process 1.1 billion cubic feet of natural gas per day, with expected average total daily sales of 670 million cubic feet of natural gas and up to 63,000 barrels of NGLs. The plant reached mechanical completion, and commissioning activities continued through 2012. The first LNG shipment from the plant is expected to occur in second quarter 2013. The project is
estimated to cost $10 billion. The anticipated economic life of the project is in excess of 20 years. Proved reserves have been recognized for the producing operations associated with this project.
The company also holds a 38.1 percent interest in a pipeline project that is designed to transport up to 250 million cubic feet of natural gas per day from Block 0 and Block 14 to the Angola LNG plant. Construction on the project continued in 2012, and the project is expected to be completed in 2014.
Angola-Republic of the Congo Joint Development Area: Chevron operates and holds a 31.3 percent interest in the Lianzi development zone, located in an area shared equally by Angola and the Republic of the Congo. A final investment decision for the Lianzi development project was reached in July 2012. The project scope includes four producing wells and three water injection wells with a subsea tieback to an existing platform in Block 14. First production is anticipated in 2015, and maximum total daily production is expected to be 46,000 barrels of crude oil. The initial recognition of proved reserves for the project occurred in 2012.
Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2012 averaged 3,000 barrels of oil-equivalent.
Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo) and a 29.3 percent nonoperated working interest in the Kitina permit area, all of which are offshore. The licenses for Kitina, Nsoko, Nkossa and Moho-Bilondo expire in 2014, 2018, 2027 and 2030, respectively. Net production averaged 19,000 barrels of oil-equivalent per day in 2012.
FEED activities for the Moho Nord project, located in the Moho-Bilondo development area, continued in 2012. The project includes a new facilities hub and a subsea tieback to the existing Moho-Bilondo floating production unit. Maximum total daily production is expected to be 127,000 barrels of crude oil per day. A final investment decision is expected in first quarter 2013 and start-up is planned for 2015. At the end of 2012, proved reserves had not been recognized for this project.
Chad/Cameroon: Chevron has a 25 percent nonoperated working interest in crude oil producing operations in southern Chad, and an approximate 21 percent interest in two affiliates that own an export pipeline that transports crude oil to the coast of Cameroon. Average daily net production from the Chad fields in 2012 was 23,000 barrels of oil-equivalent. The Chad producing operations are conducted under a concession that expires in 2030.
Nigeria: Chevron holds a 40 percent interest in 13 concessions, predominantly in the onshore and near-offshore regions of the Niger Delta. The company operates under a joint-venture arrangement in this region with the Nigerian National Petroleum Corporation, which owns a 60 percent interest. The company also owns varying interests in four operated and six nonoperated deepwater blocks. In 2012, the company’s net oil-equivalent production in Nigeria averaged 269,000 barrels per day, composed of 238,000 barrels of crude oil, 165 million cubic feet of natural gas and 4,000 barrels of LPG.
Chevron operates and holds a 67.3 percent interest in the Agbami Field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. During 2012, drilling continued on a 10-well, Phase 2 development program, Agbami 2, that is expected to offset field decline and maintain plateau production. The first well in this program commenced production in second quarter 2012. The leases that contain the Agbami Field expire in 2023 and 2024.
The company holds a 30 percent nonoperated working interest in the deepwater Usan project in OML 138. Production commenced in first quarter 2012, and total daily production at year-end 2012 was 81,000 barrels of crude oil and 3 million cubic feet of natural gas. The facilities have a maximum total production capacity of 180,000 barrels of crude oil per day. The production-sharing contract (PSC) expires in 2023.
Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. The project is expected to enter FEED in 2013. At the end of 2012, no proved reserves were recognized for this project.
In the Niger Delta, the company reached a final investment decision in early 2013 on the Dibi Long-Term Project that is designed to rebuild the Dibi facilities and replace the Early Production System facility. The facilities are planned to have a maximum production capacity of 70,000 barrels of crude oil per day, and start-up is expected in 2016.
Also in the Niger Delta, ramp-up activity continued at the Escravos Gas Plant (EGP). During 2012, construction continued on Phase 3B of the EGP project, which is designed to gather 120 million cubic feet of natural gas per day from eight offshore fields and to compress and transport the natural gas to onshore facilities. The Phase 3B project is expected to be completed in 2016. Proved reserves associated with this project have been recognized.
The 40 percent-owned and operated Sonam Field Development is designed to process natural gas through EGP, deliver 215 million cubic feet of natural gas per day to the domestic market and produce a total of 30,000 barrels of liquids per day. First production is expected in 2016. Proved reserves have been recognized for the project.
Chevron has a 75 percent-owned and operated interest in a gas-to-liquids facility at Escravos that is being developed with the Nigerian National Petroleum Corporation. The 33,000-barrel-per-day facility is designed to process 325 million cubic feet per day of natural gas supplied from the Phase 3A expansion of EGP. As of early 2013, overall work on the project was more than 89 percent complete and start-up is planned for late 2013. The estimated cost of the plant is $9.5 billion.
The company has a 40 percent-owned and operated interest in the Onshore Asset Gas Management project that is designed to restore approximately 125 million cubic feet per day of natural gas production from certain onshore fields that have been shut in since 2003 due to civil unrest. Construction was completed in third quarter 2012, and start-up commenced in late 2012.
In deepwater exploration, the company has a 27 percent nonoperated working interest in Oil Prospecting License (OPL) 223 where an exploration well was drilled in third quarter 2012. In addition, Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery in OML 140. Additional exploration activities are planned for 2013 and 2014.
Shallow-water exploration activities in 2012 included reprocessing 3-D seismic data from OML 86 and OML 88 and regional mapping activities.
With a 36.7 percent interest, Chevron is the largest shareholder in the West African Gas Pipeline Company Limited affiliate, which owns and operates the 421-mile West African Gas Pipeline. The pipeline supplies Nigerian natural gas to customers in Benin, Ghana and Togo for industrial applications and power generation and has the capacity to transport 170 million cubic feet per day.
Liberia: Chevron operates three deepwater blocks off the coast of Liberia. In July 2012, the company farmed down its interest from 70 percent to 45 percent in these blocks. Exploration wells were drilled in blocks LB-11 and LB-12 during 2012. In 2013, the company plans to mature drilling prospects based on the evaluation of 2012 drilling results and 3-D seismic data.
Morocco: In early 2013, the company entered into agreements to acquire a 75 percent operated interest in three deepwater areas offshore Morocco. The areas, Cap Rhir Deep, Cap Cantin Deep and Cap Walidia Deep, encompass approximately 7.2 million acres. Once the award is finalized, acquisition of seismic data is planned.
Sierra Leone: In September 2012, the company announced that it had been awarded operatorship and a 55 percent interest in a concession off the coast of Sierra Leone. The concession contains two deepwater blocks, with a combined area of approximately 1.4 million acres. Acquisition of 2-D seismic data is planned for 2013.
South Africa: In December 2012, the company entered into an agreement to seek shale gas exploration opportunities in the Karoo Basin in South Africa. This agreement allows Chevron and its partner to work together over a five-year period to obtain exploration permits in the 151 million-acre basin.
In Asia, the company is engaged in upstream activities in Azerbaijan, Bangladesh, Cambodia, China, Indonesia, Kazakhstan, the Kurdistan Region of Iraq, Myanmar, the Partitioned Zone located between Saudi Arabia and Kuwait, the Philippines, Russia, Thailand, and Vietnam. During 2012, net oil-equivalent production averaged 1,061,000 barrels per day.
Azerbaijan: Chevron holds an 11.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which produces crude oil from the Azeri-Chirag-Gunashli (ACG) project. The company’s daily net
production from AIOC averaged 28,000 barrels of oil-equivalent in 2012. AIOC operations are conducted under a PSC that expires in 2024.
During 2012, construction progressed on the next development phase of the ACG project, which will further develop the deepwater Gunashli Field. The total estimated cost of the project is $6 billion, with an incremental targeted maximum total daily production of 103,000 barrels of oil-equivalent. Production is expected to begin in late 2013. Proved reserves have been recognized for this project.
Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which owns and operates a crude oil export pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities at Ceyhan, Turkey. The BTC Pipeline has a capacity of 1.2 million barrels per day and transports the majority of ACG production. Another production export route for crude oil is the Western Route Export Pipeline, wholly owned and operated by AIOC, with capacity to transport 100,000 barrels per day from Baku, Azerbaijan, to a marine terminal at Supsa, Georgia.
Kazakhstan: Chevron participates in two major upstream developments in western Kazakhstan. The company holds a 50 percent interest in the Tengizchevroil (TCO) affiliate, which is operating and developing the Tengiz and Korolev crude oil fields under a concession that expires in 2033. Chevron’s net oil-equivalent production in 2012 from these fields averaged 286,000 barrels per day, composed of 218,000 barrels of crude oil, 301 million cubic feet of natural gas and 18,000 barrels of NGLs. During 2012, the majority of TCO’s crude oil production was 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. The balance was exported via rail to Black Sea ports.
In 2012, FEED activities were initiated for three projects. The Wellhead Pressure Management Project is designed to maintain production capacity and extend the production plateau from existing assets. The Capacity and Reliability Project is designed to reduce facility bottlenecks and increase plant efficiency and reliability. The Future Growth Project is designed to increase total daily crude oil production by 250,000 to 300,000 barrels of oil-equivalent and to increase the ultimate recovery of the reservoir. The project will expand the utilization of sour gas injection technology proven in existing operations. The final investment decisions on these projects are planned for late 2013. At the end of 2012, proved reserves have only been recognized for the Wellhead Pressure Management Project.
Also at TCO, start-up commenced on the Sulfur Expansion Project in December 2012. This project is designed to eliminate routine additions to sulfur inventory.
In June 2012, the company's nonoperated working interest in the Karachaganak Field was reduced from 20 percent to 18 percent as a result of a 2011 agreement with the Republic of Kazakhstan government. Operations and development of the field are conducted under a PSC that expires in 2038. During 2012, Karachaganak net oil-equivalent production averaged 61,000 barrels per day, composed of 37,000 barrels of liquids and 139 million cubic feet of natural gas. Access to the CPC and Atyrau-Samara (Russia) pipelines enabled approximately 35,000 net barrels per day of Karachaganak liquids to be exported and sold at world-market prices during 2012. The remaining liquids were sold into local and Russian markets. During 2012, work continued on identifying the optimal scope for the future expansion of the field. At the end of 2012, proved reserves had not been recognized for any further expansion.
Kazakhstan/Russia: Chevron has a 15 percent interest in the CPC affiliate. During 2012, CPC transported an average of approximately 657,000 barrels of crude oil per day, including 590,000 barrels per day from Kazakhstan and 67,000 barrels per day from Russia. During 2012, work continued on the 670,000-barrel-per-day expansion of the pipeline capacity with the mechanical completion of the offshore loading system. The $5.4 billion project is expected to be implemented in three phases, with capacity increasing progressively until reaching maximum capacity of 1.4 million barrels per day in 2016. The first increase in capacity of 400,000 barrels per day is expected in 2014.
Turkey: In December 2012, Chevron relinquished its 50 percent interest in License 3921 in the Black Sea.
Bangladesh: Chevron holds a 98 percent interest in two operated PSCs covering Block 12 (Bibiyana) and Blocks 13 and 14 (Jalalabad and Moulavi Bazar fields). The rights to produce from Jalalabad expire in 2024, from Moulavi Bazar in 2028 and from Bibiyana in 2034. Net oil-equivalent production from these operations in 2012 averaged 94,000 barrels per day, composed of 550 million cubic feet of natural gas and 2,000 barrels of liquids.
In April 2012, start-up of the Muchai compression project was achieved. This project supports additional natural gas production capacity of 80 million cubic feet per day from the Bibiyana, Jalalabad and Moulavi Bazar fields. The Bibiyana Expansion project achieved a final investment decision in July 2012. The project scope includes a gas plant expansion, additional development drilling and an enhanced liquids recovery unit, and is expected to increase total maximum daily production by more than 300 million cubic feet of natural gas and 4,000 barrels of condensate. First production is expected in 2014. The initial recognition of proved reserves for this expansion project occurred in 2012.
Cambodia: Chevron owns a 30 percent interest and operates the 1.2 million-acre Block A, located in the Gulf of Thailand. In 2012, the company progressed discussions on the production permit for development of Block A. The planned development consists of a wellhead platform and a floating storage and offloading vessel (FSO). A final investment decision is pending resolution of commercial terms. At the end of 2012, proved reserves had not been recognized for the project.
Myanmar: Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 28.3 percent nonoperated interest in a pipeline company that transports the natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. The company’s average net natural gas production in 2012 was 94 million cubic feet per day.
Thailand: Chevron has operated and nonoperated working interests in multiple offshore blocks in the Gulf of Thailand. The company’s net oil-equivalent production in 2012 averaged 243,000 barrels per day, composed of 67,000 barrels of crude oil and condensate and 1.1 billion cubic feet of natural gas. The company’s natural gas production is sold to the domestic market under long-term sales contracts.
The company holds operated interests in the Pattani Basin with ownership interests ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2020 and 2035. Chevron has a 16 percent nonoperated working interest in the Arthit Field located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040.
During 2012, the company drilled six exploration wells in the Pattani Basin, and four were successful. The company also holds exploration interests in the Thailand-Cambodia overlapping claim area that are inactive, pending resolution of border issues between Thailand and Cambodia.
Vietnam: Chevron is the operator of two PSCs in the Malay Basin off the southwest coast of Vietnam. The company has a 42.4 percent interest in a PSC that includes Blocks B and 48/95, and a 43.4 percent interest in a PSC for Block 52/97.
The Block B Gas Development Project is designed to produce natural gas from the Malay Basin for delivery to state-owned Petrovietnam. The project includes installation of wellhead and hub platforms, an FSO, a central processing platform and a pipeline to shore. FEED continued during 2012. Maximum total daily production is expected to be 490 million cubic feet of natural gas and 4,000 barrels of condensate. A final investment decision for the development is pending resolution of commercial terms. At the end of 2012, proved reserves had not been recognized for the development project.
During 2012, the company drilled two exploratory wells in Block 52/97, and both were successful.
China: Chevron has operated and nonoperated working interests in several areas in China. The company’s net oil-equivalent production in 2012 averaged 21,000 barrels per day, composed of 20,000 barrels of crude oil and condensate and 9 million cubic feet of natural gas.
The company operates and holds a 49 percent interest in the
Chuandongbei PSC, located in the onshore Sichuan Basin. The full development includes two new sour-gas processing plants with an aggregate inlet design capacity of 740 million cubic feet per day, connected by a natural gas gathering system to five fields. During 2012, the company continued construction of the first natural gas processing plant, and site preparation commenced for the second natural gas processing plant. The initial plant, with an expected maximum total production of 258 million cubic feet per day, is targeted for mechanical completion at the end of 2013. Planned maximum total natural gas production is 558 million cubic feet per day, and the total project cost is estimated to be $6.4 billion. Proved reserves have been recognized for this project. The PSC for Chuandongbei expires in 2037.
The company holds a 59.2 percent-owned and operated interest in deepwater Block 42/05 in the South China Sea, which covers exploratory acreage of approximately 1.3 million acres. During 2012, the company drilled two exploration wells in South China Sea deepwater Blocks 53/30 and 64/18, and both were unsuccessful. In November 2012, the company relinquished its interest in deepwater Blocks 53/30 and 64/18.
Additional 3-D seismic data was acquired over Block 42/05, and further exploration drilling is under evaluation. In 2012, Chevron entered into an agreement to acquire a 100 percent-owned and operated interest in shallow-water Blocks 15/10 and 15/28, which cover approximately 1.4 million exploratory acres. Government approval is expected in first-half 2013, and a 3-D seismic survey is expected to commence in mid-2013.
During 2012, the company drilled an initial exploratory well for shale gas in the Qiannan Basin. Evaluation of the well continues in early 2013. Additional drilling is planned for 2013.
The company also has nonoperated working interests of 32.7 percent in Blocks 16/08 and 16/19 in the Pearl River Mouth Basin and nonoperated working interests of 24.5 percent in the QHD 32-6 Field and 16.2 percent in Block 11/19 in the Bohai Bay.
Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field located 50 miles offshore Palawan Island. Net oil-equivalent production in 2012 averaged 24,000 barrels per day, composed of 120 million cubic feet of natural gas and 4,000 barrels of condensate. During 2012, plans progressed on Malampaya Phase 2 to drill two additional infill wells and to add depletion compression facilities. Start-up is planned for 2014. Proved reserves have been recognized for this project.
Chevron also develops and produces geothermal resources in southern Luzon, which supply steam to third-party, 637-megawatt power generation facilities. During fourth quarter 2012, Chevron sold 60 percent of its interest in these geothermal operations in order to secure a 25-year geothermal operating contract with the Philippine government for the continued development and operation of the steam fields. Chevron also has a 90 percent-owned and operated interest in the Kalinga geothermal prospect area in northern Luzon and is in the early phase of geological and geophysical assessments.
Indonesia: Chevron holds operated and nonoperated working interests in Indonesia. The company has 100 percent-owned and operated interests in the Rokan and Siak PSCs onshore Sumatra. Chevron also operates four PSCs in the Kutei Basin, located offshore East Kalimantan. These interests range from 62 percent to 92.5 percent. Chevron also has 51 percent operated working interests in two exploration blocks in western Papua, West Papua I and West Papua III, and a 25 percent nonoperated working interest in a joint venture in Block B in the South Natuna Sea.
The company’s net oil-equivalent production in 2012 from its interests in Indonesia averaged 198,000 barrels per day, composed of 158,000 barrels of liquids and 236 million cubic feet of natural gas. The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood since 1985 and is one of the world’s largest steamflood developments. The North Duri Development is divided into multiple expansion areas. Construction began on the Duri Area 13 expansion project in fourth quarter 2012. First production is scheduled for late 2013, and maximum total daily production of 17,000 barrels of crude oil is expected to be reached in 2016. The Rokan PSC expires in 2021.
During 2012, two deepwater development projects in the Kutei Basin progressed under a single plan of development. In the first of these projects, Chevron completed FEED for the Gendalo-Gehem deepwater natural gas project, and a final investment decision is expected during 2014. The project includes two separate hub developments, natural gas and condensate pipelines, and an onshore receiving facility. Maximum total daily production from the project is expected to be about 1.1 billion cubic feet of natural gas and 31,000 barrels of condensate. Gas from the project is expected to be used
domestically and for LNG export. The company’s working interest is approximately 63 percent. At the end of 2012, proved reserves had not been recognized for this project.
In the second of these projects, the company requested bids for all major contracts for the Bangka deepwater natural gas project. A final investment decision is expected in 2013. The project scope includes a subsea tieback to a floating production unit, and maximum total daily production is expected to be about 114 million cubic feet of natural gas and 4,000 barrels of condensate. The company’s working interest is 62 percent. At year-end 2012, proved reserves had not been recognized for this project.
In Sumatra, four exploration wells were drilled. Two wells were successful and the results for two wells are under evaluation in early 2013. Appraisal and exploration drilling is planned for 2013. In the West Papua exploration blocks, which are in close proximity to a third-party LNG facility, seismic data acquisition and processing was completed for West Papua I in 2012 and is planned for completion for West Papua III in 2013.
In West Java, the company operates and holds a 95 percent interest in the Darajat geothermal field, which supplies steam to a power plant with a total operating capacity of 259 megawatts. Chevron also operates and holds a 100 percent interest in the Salak geothermal field in West Java, which supplies steam to a power plant with a total operating capacity of 377 megawatts. In Sumatra, Chevron operates and holds a 95 percent interest in the North Duri Cogeneration Plant, supplying up to 300 megawatts of power to the company's Sumatra operations and steam in support of the Duri steamflood project. In the Suoh-Sekincau prospect area of Sumatra, the company holds a 95 percent-owned and operated interest in a license to explore and develop a geothermal prospect.
Kurdistan Region of Iraq: In July 2012, the company announced the acquisition of an 80 percent-owned and operated interest in two PSCs covering the Rovi and Sarta blocks in the Kurdistan Region of Iraq. The blocks cover a combined area of approximately 232,000 acres.
Partitioned Zone (PZ): Chevron holds a concession to operate the Kingdom of Saudi Arabia's 50 percent interest in the petroleum resources in the onshore area of the PZ between Saudi Arabia and Kuwait. The concession expires in 2039.
During 2012, the company's average net oil-equivalent production was 90,000 barrels per day, composed of 86,000 barrels of crude oil and 21 million cubic feet of natural gas. During 2012, the company continued a steam injection pilot project in the First Eocene carbonate reservoir that was initiated in 2009. A project to expand the steam injection pilot to the Second Eocene reservoir is expected to enter FEED by late 2013. Development planning also continued during 2012 on a full-field steamflood application in the Wafra Field. The Wafra Steamflood Stage 1 Project is expected to enter FEED in 2014. At the end of 2012, proved reserves had not been recognized for any of these steamflood developments.
Also in 2012, FEED activities continued on the Central Gas Utilization Project. The project is intended to increase natural gas utilization and eliminate routine flaring. A final investment decision is expected in 2014. At year-end 2012, proved reserves had not been recognized for this project.
In Australia, the company’s upstream efforts are concentrated off the northwest coast. During 2012, the average net oil-equivalent production from Australia was 99,000 barrels per day.
Chevron holds a 47.3 percent ownership interest across most of the Greater Gorgon Area and is the operator of the Gorgon Project, which combines the development of the Gorgon and nearby Io/Jansz natural gas fields. The development includes a three-train, 15.6 million-metric-ton-per-year LNG facility, a carbon sequestration project and a domestic natural gas plant. Maximum total daily production from the project is expected to reach approximately 2.6 billion cubic feet of natural gas and 20,000 barrels of condensate. Start-up of the first train is expected in late 2014, leading to the first LNG cargo in first quarter 2015. Total estimated project costs for the first phase of development are $52 billion. Proved reserves have been recognized for this project. The project's estimated economic life exceeds 40 years from the time of start-up.
Work on the Gorgon project continued during 2012. As of year-end 2012, more than 55 percent of the project activities had been completed. Key milestones achieved in 2012 were the arrival and installation of the first LNG plant modules, subsea wellhead trees and subsea pipelines. The development drilling program also progressed during 2012.
Chevron has signed binding, long-term LNG Sales and Purchase Agreements with six Asian customers for delivery of about 4.8 million metric tons of LNG per year, which brings delivery commitments to about 65 percent of Chevron’s share of LNG from this project. Discussions continue with potential customers to increase long-term sales to 85 percent of Chevron’s net LNG offtake. Chevron also has binding long-term agreements for delivery of about 65 million cubic feet per day of natural gas to Western Australian natural gas consumers starting in 2015, and the company continues to market additional natural gas quantities from the Gorgon Project.
An expansion project to develop a fourth train at the Gorgon LNG facility is expected to enter FEED in late 2013. At the end of 2012, proved reserves had not been recognized for the fields associated with this project.
Chevron is the operator of the Wheatstone Project, which includes a two-train, 8.9 million-metric-ton-per-year LNG facility and a domestic gas plant located at Ashburton North, along the northwest coast of Australia. The company plans to supply natural gas to the facilities from three company-operated licenses, containing the Wheatstone Field and nearby Iago Field. Maximum total daily production from these and third-party fields is expected to be about 1.6 billion cubic feet of natural gas and 30,000 barrels of condensate. Start-up of the first train is expected in 2016. Total estimated project costs for the first phase of development are $29 billion. Proved reserves have been recognized for this project. The project's estimated economic life exceeds 30 years from the time of start-up.
In 2012, construction and fabrication activities progressed, with a focus on delivering site infrastructure and key components of the platform and subsea equipment. Chevron signed additional commercial agreements that decreased Chevron's interest in the offshore licenses to 80.2 percent and in the LNG facilities to 64.1 percent. The company also executed agreements with Asian customers for the delivery of additional volumes of LNG. As of year-end 2012, more than 80 percent of Chevron’s equity LNG offtake was covered under long-term agreements with customers in Asia. In addition, the company has begun marketing its equity share of natural gas of approximately 120 million cubic feet per day to Western Australia natural gas consumers.
During 2012 and early 2013, the company announced seven natural gas discoveries in the Carnarvon Basin. These include natural gas discoveries at the 47.3 percent-owned and operated Pontus prospect in Block WA-37-L, the 50 percent-owned and operated Satyr prospect in Block WA-374-P, the 50 percent-owned and operated Pinhoe prospect in Block WA-383-P, the 50 percent-owned and operated Arnhem prospect in Block
WA-364-P, and the 50 percent-owned and operated Kentish Knock South prospect in Block WA-365-P. These discoveries are expected to contribute to potential expansion opportunities at company-operated LNG facilities.
Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. Daily net production from the project during 2012 averaged 20,000 barrels of crude oil and condensate, 428 million cubic feet of natural gas, and 4,000 barrels of LPG. Approximately 70 percent of the natural gas was sold in the form of LNG to major utilities in Asia, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. The concession for the NWS Venture expires in 2034.
The North Rankin 2 project continued to advance during 2012, with start-up expected in mid-2013. The project is designed to recover remaining low-pressure natural gas from the North Rankin and Perseus fields to meet gas supply needs and maintain NWS production capacity of about 2 billion cubic feet of natural gas and 39,000 barrels of condensate. Total estimated projects costs are $5.4 billion. Proved reserves have been recognized for the project. The project's estimated economic life exceeds 20 years from the time of start-up.
In October 2012, the company exchanged its 16.7 percent interest in the East Browse leases and its 20 percent interest in the West Browse leases for financial consideration and a 33.3 percent interest in the WA-205-P and WA-42-R blocks in the Carnarvon Basin and now holds a 100 percent interest in these blocks, which contain the Clio and Acme fields. The company retains other nonoperated working interests ranging from 24.8 percent to 50 percent in three other blocks in the Browse Basin. In Block WA-274-P, drilling in the fourth quarter 2012 resulted in a natural gas discovery at the Crown prospect.
In Europe, the company is engaged in upstream activities in Bulgaria, Denmark, Lithuania, the Netherlands, Norway, Poland, Romania, Ukraine and the United Kingdom. Net oil-equivalent production in Europe averaged 114,000 barrels per day during 2012.
Denmark: Chevron has a 12 percent working interest in the partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 fields in the Danish North Sea. Net oil-equivalent production in 2012 from DUC averaged 36,000 barrels per day, composed of 24,000 barrels of crude oil and 74 million cubic feet of natural gas. In July 2012, as part of a 30-year concession extension, the state-owned Danish North Sea Fund received a 20 percent ownership of the DUC in exchange for the previous 20 percent government profit-take arrangements and the company's interest was reduced from 15 percent to 12 percent. The concession expires in 2042.
Netherlands: Chevron operates and holds interests ranging from 34.1 percent to 80 percent in 10 blocks in the Dutch sector of the North Sea. In 2012, the company’s net oil-equivalent production was 9,000 barrels per day, composed of 2,000 barrels of crude oil and 42 million cubic feet of natural gas.
Norway: The company holds a 7.6 percent nonoperated working interest in the Draugen Field. The company’s net production averaged 3,000 barrels of oil-equivalent per day during 2012. Chevron is the operator and has a 40 percent working interest in exploration licenses PL 527 and PL 598. Both licenses are in the deepwater portion of the Norwegian Sea.
United Kingdom: The company’s average net oil-equivalent production in 2012 from 10 offshore fields was 66,000 barrels per day, composed of 46,000 barrels of liquids and 122 million cubic feet of natural gas. Most of the production was from three fields: the 85 percent-owned and operated Captain Field, the 23.4 percent-owned and operated Alba Field, and the 32.4 percent-owned and jointly operated Britannia Field.
Procurement and fabrication activities began in 2012 for the Clair Ridge project, located west of the Shetland Islands, in which the company has a 19.4 percent nonoperated working interest. The project is the second development phase of the Clair Field. Total planned design capacity is 120,000 barrels of crude oil per day, and the total estimated cost of the project is $7 billion. Production is scheduled to begin in 2016 and the project's estimated economic life exceeds 40 years from the time of start-up. Proved reserves have been recognized for the Clair Ridge project.
At the 70 percent-owned and operated Alder discovery, FEED activities progressed during 2012, and a final investment decision is planned for late 2013. The 40 percent-owned and operated Rosebank Project northwest of the Shetland Islands entered FEED in July 2012. A final investment decision is planned for 2014. Maximum total daily production is expected to reach 64,000 barrels of liquids and 42 million cubic feet of natural gas. At the end of 2012, proved reserves had not been recognized for these projects.
An unsuccessful exploration well was drilled at the Aberlour prospect west of the Shetland Islands. Full and partial block relinquishments were made during 2012 under Licenses P119 (Strathspey area), P1026, P1191 and P1194 (Aberlour).
Bulgaria: In June 2011, the Bulgarian government advised that Chevron had submitted a winning tender for a permit for exploration in a 1.1 million-acre area in northeast Bulgaria. In January 2012, prior to execution of the license agreement, the Bulgarian government announced the withdrawal of the decision awarding the permit and the Bulgarian parliament imposed a ban on hydraulic fracturing, a technology commonly used for shale development and production. Chevron continues to work with the government of Bulgaria to provide the necessary assurances to both the government and the public that hydrocarbons from shale can be developed safely and responsibly.
Lithuania: In October 2012, Chevron acquired a 50 percent interest in a Lithuanian exploration and production company. In 2013, the affiliate plans to commence shale exploration activities in the 394,000-acre Rietavas block.
Poland: Chevron holds four shale concessions in southeast Poland (Frampol, Grabowiec, Krasnik and Zwierzyniec). All four exploration licenses are 100 percent-owned and operated and comprise a total of 1.1 million acres. During 2012, drilling was completed on the first well in the Grabowiec concession and evaluation of this well continued into early 2013. An initial well was also drilled in the Frampol concession in 2012. Drilling of a well in the Zwierzyniec concession commenced in
December 2012, and continued exploratory drilling of the concessions is planned for 2013.
Romania: The company holds a 100 percent interest and operates the Barlad shale concession. This license is located in northeast Romania and covers 1.6 million acres. Drilling of an exploration well is planned for second-half 2013. In March 2012, three additional petroleum concession agreements, covering approximately 670,000 acres in southeast Romania, were approved by the government of Romania. Chevron holds a 100 percent interest and operates the concessions. Acquisition of 2-D seismic data across these concessions is expected to commence in second-half 2013.
Ukraine: In 2012, Chevron was the successful bidder for the right to exclusively negotiate a 50-year PSC with the government of Ukraine for the Oleska block in western Ukraine. Chevron is expected to operate and hold a 50 percent interest in the 1.6 million-acre concession. As of early 2013, the PSC and Joint Operating Agreement terms were being negotiated.
Sales of Natural Gas and Natural Gas Liquids
The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of natural gas and natural gas liquids in connection with its trading activities.
During 2012, U.S. and international sales of natural gas were 5.5 billion and 4.3 billion cubic feet per day, respectively, which includes the company’s share of equity affiliates’ sales. Outside the United States, substantially all of the natural gas sales from the company’s producing interests are from operations in Australia, Bangladesh, Europe, Kazakhstan, Indonesia, Latin America, Myanmar, Nigeria, the Philippines and Thailand.
U.S. and international sales of natural gas liquids were 157 thousand and 88 thousand barrels per day, respectively, in 2012. Substantially all of the international sales of natural gas liquids from the company's producing interests are from operations in Africa, Kazakhstan, Indonesia and the United Kingdom.
Refer to “Selected Operating Data,” on page FS-10 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s sales volumes of natural gas and natural gas liquids. Refer also to “Delivery Commitments” on page 7 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.
At the end of 2012, the company had a refining network capable of processing about 2.0 million barrels of crude oil per day. Operable capacity at December 31, 2012, and daily refinery inputs for 2010 through 2012 for the company and affiliate refineries are summarized in the table below.
Average crude oil distillation capacity utilization during 2012 was 88 percent, compared with 89 percent in 2011. At the U.S. refineries, crude oil distillation capacity utilization averaged 87 percent in 2012, compared with 89 percent in 2011. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 77 percent and 85 percent of Chevron’s U.S. refinery inputs in 2012 and 2011, respectively.
At the Pascagoula Refinery, construction progressed on a facility to produce approximately 25,000 barrels per day of premium base oil for use in manufacturing high-performance finished lubricants, such as motor oils for consumer and commercial applications. Mechanical completion is expected by year-end 2013. In July 2012, the company completed the sale of its idled 80,000-barrel-per-day Perth Amboy, New
Jersey, refinery, which was operating as a terminal.
At the refinery in El Segundo, a new processing unit designed to further improve the facility’s overall reliability, enhance high-value product yield and provide additional flexibility to process a broad range of crude slates came online in July 2012. Similar projects were progressed in 2012 at the Salt Lake City and Pascagoula refineries and are scheduled to be completed in late 2013.
Outside the United States, GS Caltex, a 50 percent-owned equity affiliate, reached mechanical completion of a 53,000-barrel-per-day gas oil fluid catalytic cracking unit at the Yeosu Refinery in South Korea in early 2013. The unit is designed to increase high-value product yield and lower feedstock costs. In 2012, construction was completed on modifications to the 64 percent-owned Star Petroleum Refinery in Thailand to meet regional specifications for cleaner fuels. Also in 2012, Caltex Australia Ltd., a 50 percent-owned equity affiliate, announced plans to convert the Kurnell, Australia, refinery to an import terminal in 2014.
Petroleum Refineries: Locations, Capacities and Inputs
(Crude-unit capacities and crude oil inputs in thousands of barrels per day; includes equity share in affiliates)
December 31, 2012
Salt Lake City
Total Consolidated Companies — United States
Map Ta Phut2
Total Consolidated Companies — International
Total Including Affiliates — International
Total Including Affiliates — Worldwide
Pembroke was sold in August 2011.
As of June 2012, Star Petroleum Refining Company crude input volumes are reported on a consolidated basis. Prior to June 2012, crude volumes reflect a 64 percent equity interest and are reported in equity affiliates.
Chevron holds 100 percent of the common stock issued by Chevron South Africa (Pty) Limited, which owns the Cape Town Refinery. A consortium of South African partners owns preferred shares ultimately convertible to a 25 percent equity interest in Chevron South Africa (Pty) Limited. None of the preferred shares had been converted as of February 2013.
Includes 1,000 and 2,000 barrels per day of refinery inputs in 2011 and 2010, respectively, for interests in refineries that were sold during those periods.
The company markets petroleum products under the principal brands of “Chevron,” “Texaco” and “Caltex” throughout many parts of the world. The following table identifies the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ended December 31, 2012.
Refined Products Sales Volumes
(Thousands of Barrels per Day)
Gas Oil and Kerosene
Residual Fuel Oil
Other Petroleum Products1
Total United States
Gas Oil and Kerosene
Residual Fuel Oil
Other Petroleum Products1
1 Principally naphtha, lubricants, asphalt and coke.
2 Includes share of equity affiliates’ sales:
In the United States, the company markets under the Chevron and Texaco brands. At year-end 2012, the company supplied directly or through retailers and marketers approximately 8,060 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 470 of these outlets are company-owned or -leased stations.
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 8,700 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. The company markets in Latin America using the Texaco brand. In the Asia-Pacific region, southern 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 equity affiliate, GS Caltex, and in Australia through its 50 percent-owned equity affiliate, Caltex Australia Limited.
The company continued its ongoing effort to concentrate downstream resources and capital on strategic assets. In 2012, Chevron completed the sale of the company's fuels marketing, finished lubricants and aviation fuels businesses in Spain as well as certain fuels marketing and aviation businesses in eight
countries in the Caribbean. The company's GS Caltex affiliate also completed the sale of certain power and other assets in South Korea. In addition, the company converted more than 240 company-operated service stations into retailer-owned sites in various countries outside the United States.
Chevron markets commercial aviation fuel at approximately 120 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the brand names Havoline, Delo, Ursa, Meropa and Taro in the United States and worldwide under the three master brands: Chevron, Texaco and Caltex.
Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) equity affiliate. At the end of 2012, CPChem owned or had joint-venture interests in 36 manufacturing facilities and two research development centers around the world.
CPChem’s 35 percent-owned equity affiliate, Saudi Polymers Company, announced commercial production at its new olefins and derivatives facility in Al-Jubail, Saudi Arabia, in October 2012. In the United States, CPChem commenced construction of a 1-hexene plant at the company’s Cedar Bayou complex in Baytown, Texas, with a design capacity of 250,000 metric tons per year. Start-up is expected in 2014. In 2012, CPChem also commenced front-end engineering and design for several projects on the U.S. Gulf Coast, which are expected to capitalize on advantaged feedstock sourced from emerging shale gas development in North America. These include an ethane cracker with an annual design capacity of 1.5 million metric tons of ethylene to be located at the Cedar Bayou complex in Baytown, Texas, and two polyethylene facilities to be located in Old Ocean, Texas, each with an annual design capacity of 500,000 metric tons.
Chevron’s Oronite brand lubricant and fuel additives business is a leading developer, manufacturer and marketer of performance additives for lubricating oils and fuels. The company owns and operates facilities in Brazil, France, Japan, the Netherlands, Singapore and the United States and has equity interests in facilities in India and Mexico. Oronite lubricant additives are blended into refined base oil to produce finished lubricant packages used primarily in engine applications such as passenger car, heavy-duty diesel, marine, locomotive and motorcycle engines, and additives for fuels that are blended to improve engine performance and extend engine life. In 2012, the company began construction on a project to expand the capacity of the existing additives plant in Singapore. The project is expected to double the plant's capacity since it was commissioned in 1999 and to begin commercial operations in 2014.
Pipelines: Chevron owns and operates an extensive network of crude oil, refined product, chemical, natural gas liquid and natural gas pipelines and other infrastructure assets in the United States. The company also has direct and indirect interests in other U.S. and international pipelines. The company’s ownership interests in pipelines are summarized in the following table.
Pipeline Mileage at December 31, 2012
Total United States
Includes company’s share of pipeline mileage owned by equity affiliates.
Excludes gathering pipelines relating to the crude oil and natural gas production function.
The company continues to lead the construction of a 136-mile, 24-inch crude oil pipeline from the planned Jack/St. Malo facility to a platform in Green Canyon Block 19 on the U.S. Gulf of Mexico shelf, where there is an interconnect to pipelines delivering crude oil into Texas and Louisiana. The project is expected to be completed by start-up of the production facility in 2014.
In December 2012, the company executed agreements to sell the 100 percent-owned and operated Northwest Products System. This system consisted of a 760-mile refined products pipeline running from Salt Lake City, Utah, to Spokane, Washington, a dedicated jet fuel pipeline serving the Salt Lake City International Airport, and three refined products terminals located in Idaho and Washington. The sale is pending regulatory approval and is expected to be completed in first-half 2013. In addition, the company is in the process of relinquishing its interest in the Trans Alaska Pipeline System.
Refer to pages 14, 15, 16 and 17 in the Upstream section for information on the Chad/Cameroon pipeline, the West African Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.
Tankers: All tankers in Chevron’s controlled seagoing fleet were utilized during 2012. During 2012, the company had 51 deep-sea vessels chartered on a voyage basis, or for a period of less than one year. The following table summarizes the capacity of the company’s controlled fleet.
Controlled Tankers at December 31, 20121
(Millions of Barrels)
(Millions of Barrels)
Consolidated companies only. Excludes tankers chartered on a voyage basis, those with dead-weight tonnage less than 25,000 and those used exclusively for storage.
Tankers chartered for more than one year.
The company’s U.S.-flagged fleet is engaged primarily in transporting refined products in the coastal waters of the United States.
The foreign-flagged vessels are engaged primarily in transporting crude oil from the Middle East, Southeast Asia, the Black Sea, South America, Mexico and West Africa to ports in the United States, Europe, Australia and Asia. The company’s foreign-flagged vessels also transport refined products and feedstocks to and from various locations worldwide.
In 2012, the company ordered eight new vessels, a combination of bareboat charters and new builds contracts, to modernize the fleet and increase LNG coverage. In addition to the vessels ordered in 2012, the company has prior contracts in place to build LNG carriers and a dynamic-positioning shuttle tanker to support future upstream projects. The company also owns a one-sixth interest in each of seven LNG carriers transporting cargoes for the North West Shelf Venture in Australia.
Mining: Chevron’s U.S.-based mining company concluded the divestment of its remaining coal mining operations. In 2012, the company completed the sale of its Kemmerer, Wyoming, surface coal mine and the sale of its 50 percent interest in Youngs Creek Mining Company, LLC, which was formed to develop a coal mine in northern Wyoming. Activities related to final reclamation continued in 2012 at the company-operated surface coal mine in McKinley, New Mexico.
Chevron also owns and operates the Questa molybdenum mine in New Mexico. At year-end 2012, Chevron had 160 million pounds of proven molybdenum reserves at Questa. Production and underground development at Questa continued at reduced levels in 2012 in response to weak prices for molybdenum.
Power Generation: Chevron’s Global Power Company manages interests in 11 power assets with a total operating capacity of more than 2,200 megawatts, primarily through joint ventures in the United States and Asia. Ten of these are efficient combined-cycle and gas-fired cogeneration facilities that utilize recovered waste heat to produce electricity and support industrial thermal hosts. The 11th facility is a wind farm, located in Casper, Wyoming, that is designed to optimize the use of a decommissioned refinery site for delivery of clean, renewable energy to the local utility.
Chevron also has major geothermal operations in Indonesia and the Philippines and is evaluating several advanced solar technologies for use in oil field operations as part of its renewable energy strategy. For additional information on the company’s geothermal operations and renewable energy projects, refer to page 19 in the Upstream section and “Research and Technology” below.
Chevron Energy Solutions (CES): CES is a wholly owned subsidiary that develops and builds sustainable energy projects that increase energy efficiency and production of renewable power, reduce energy costs, and ensure reliable, high-quality energy for government, education and business facilities. CES has developed hundreds of projects that have helped customers reduce their energy costs and environmental impact. In 2012, CES completed several public sector programs, including a first-of-its-kind microgrid at the Santa Rita jail in Alameda County, and renewable and efficiency programs for Huntington Beach City School District, South San Francisco Unified School District and Union City, all in California, plus Rootstown Local School District in Ohio. CES also completed an energy efficiency program at the Detroit Arsenal and a combined renewable power production and heating project at the Marine Corps Logistics Base in Albany, Georgia. CES is also guiding the work of the new Chevron Center for Sustainable Energy Efficiency in Qatar. In December 2012, CES and its partners inaugurated the first large scale solar testing in Qatar. The evaluation will help determine the most appropriate solar technologies for the Middle East.
Research and Technology: The company’s energy technology organization supports Chevron’s upstream and downstream businesses by providing technology, services and competency development in earth sciences; reservoir and production engineering; drilling and completions; facilities engineering; manufacturing; process technology; catalysis; technical computing; and health, environment and safety disciplines. The
information technology organization integrates computing, telecommunications, data management, security and network technology to provide a standardized digital infrastructure and enable Chevron’s global operations and business processes.
Chevron's venture capital investment group manages investments and projects in emerging energy technologies and their integration into Chevron’s core businesses. As of the end of 2012, the venture capital group continued to explore technologies such as next-generation biofuels, advanced solar and enhanced pipeline inspection methods. In 2012, the company continued evaluation of a solar-to-steam generation project in use to support enhanced-oil-recovery operations in Coalinga, California. This project was commissioned to test the viability of using solar power to produce steam to improve oil recovery.
In 2012, the company launched a new tank technology for storing water at hydraulic fracturing operations. These patent-pending modular metal tanks can be quickly assembled and taken apart for reuse at other wells. This enables drilling and fracturing without the need for water storage pits and is intended to result in enhanced safety, less land disturbance, smaller drill site pads and significantly lower costs. The first fully operational tank was brought into service in Ohio.
Chevron’s research and development expenses were $648 million, $627 million and $526 million for the years 2012, 2011 and 2010, respectively.
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate technical or commercial successes are not certain.
Environmental Protection: The company designs, operates and maintains its facilities to avoid potential spills or leaks and minimize the impact of those that may occur. Chevron requires its facilities and operations to have operating standards and processes and emergency response plans that address all credible and significant risks identified by site-specific risk and impact assessments. Chevron also requires that sufficient resources be available to execute these plans. In the unlikely event that a major spill or leak occurs, Chevron also maintains a Worldwide Emergency Response Team comprised of employees who are trained in various aspects of emergency response, including post-incident remediation.
To complement the company’s capabilities, Chevron maintains active membership in international oil spill response cooperatives, including the Marine Spill Response Corporation, which operates in U.S. territorial waters, and Oil Spill Response, Ltd. (OSRL), which operates globally. The company is a founding member of the Marine Well Containment Company, whose primary mission is to expediently deploy containment equipment and systems to capture and contain crude oil in the unlikely event of a future loss of control of a deepwater well in the Gulf of Mexico.
In addition, the company is a member of the Subsea Well Response Project (SWRP). SWRP’s objective is to further develop the industry’s capability to contain and shut in subsea well control incidents in different regions of the world.
Refer to Management's Discussion and Analysis of Financial Condition and Results of Operations on pages FS-15 and FS-16 for additional information on environmental matters and their impact on Chevron and on the company's 2012 environmental expenditures. Refer to page FS-15 and Note 24 on page FS-58 for a discussion of environmental remediation provisions and year-end reserves. Refer also to Item 1A. Risk Factors on pages 28 through 30 for a discussion of greenhouse gas regulation and climate change.
Web Site Access to SEC Reports
The company’s Internet Web site is www.chevron.com. Information contained on the company’s Internet Web site is not part of this Annual Report on Form 10-K. The company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge on the company’s Web site soon after such reports are filed with or furnished to the Securities and Exchange Commission (SEC). The reports are also available on the SEC’s Web site at www.sec.gov.
Chevron is a global energy company with a diversified business portfolio, a strong balance sheet, and a history of generating sufficient cash to pay dividends and fund capital and exploratory expenditures. Nevertheless, some inherent risks could materially impact the company’s financial results of operations or financial condition.
Chevron is exposed to the effects of changing commodity prices: Chevron is primarily in a commodities business that has a history of price volatility. The single largest variable that affects the company’s results of operations is the price of crude oil, which can be influenced by general 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 geopolitical risk. Chevron accepts the risk of changing commodity prices as part of its business planning process. As such, an investment in the company carries significant exposure to fluctuations in global crude oil prices.
During extended periods of historically low prices for crude oil, the company’s upstream earnings and capital and exploratory expenditure programs will be negatively affected. Upstream assets may also become impaired. The impact on downstream earnings is dependent upon the supply and demand for refined products and the associated margins on refined product sales.
The scope of Chevron’s 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 or through acquisitions, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining and renewing rights to explore, develop and produce hydrocarbons; drilling success; ability to bring long-lead-time, capital-intensive projects to completion on budget and on schedule; and efficient and profitable operation of mature properties.
The company’s operations could be disrupted by natural or human factors: Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations and facilities are therefore subject to disruption from either natural or human causes beyond its control, including hurricanes, floods and other forms of severe weather, war, civil unrest and other political events, fires, earthquakes, system failures, cyber threats and terrorist acts, any of which could result in suspension of operations or harm to people or the natural environment.
The company’s operations have inherent risks and hazards that require significant and continuous oversight: Chevron’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in the crude oil and natural gas industry. The company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. Chevron has implemented and maintains a system of corporate policies, behaviors and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. Nonetheless, in certain situations where Chevron is not the operator, the company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.
Chevron’s business subjects the company to liability risks from litigation or government action: 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 its business. Chevron's operations also produce byproducts, which may be considered pollutants. Often these operations are conducted through joint ventures over which the company may have limited influence and control. Any of these activities could result in liability or significant delays in operations arising from private litigation or government
action, either as a result of an accidental, unlawful discharge or as a result of new conclusions about the effects of the company’s operations on human health or the environment. In addition, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
For information concerning some of the litigation in which the company is involved, including information relating to Ecuador matters, see Note 13 to the Consolidated Financial Statements, beginning on FS-40.
The company does not insure against all potential losses, which could result in significant financial exposure: The company does not have commercial insurance or third-party indemnities to fully cover all operational risks or potential liability in the event of a significant incident or series of incidents causing catastrophic loss. As a result, the company is, to a substantial extent, self-insured for such events. The company relies on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that would arise from such an event or series of events. The occurrence of a significant incident or unforeseen liability for which the company is not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the company’s results of operations or financial condition.
Political instability and significant changes in the regulatory environment could harm Chevron’s business: The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses or to impose additional taxes or royalties.
In certain locations, governments have imposed or proposed restrictions on the company’s operations, export and exchange controls, burdensome taxes, and public disclosure requirements that might harm the company’s competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries, and internal unrest, acts of violence or strained relations between a government and the company or other governments may adversely affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2012, 21 percent of the company’s net proved reserves were located in Kazakhstan. The company also has significant interests in OPEC-member countries, including Angola, Nigeria and Venezuela and in the Partitioned Zone between Saudi Arabia
and Kuwait. Twenty-one percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2012.
Regulation of greenhouse gas emissions could increase Chevron’s operational costs and reduce demand for Chevron’s products: Continued political attention to issues concerning climate change, the role of human activity in it, and potential mitigation through regulation could have a material impact on the company’s operations and financial results.
International agreements and national or regional legislation and regulatory measures to limit greenhouse emissions are currently in various stages of discussion or implementation. These and other greenhouse gas emissions-related laws, policies and regulations may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted in each jurisdiction, the company’s activities in it and market conditions. Greenhouse gas emissions that could be regulated include those arising from the company’s exploration and production of crude oil and natural gas; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined products; the processing, liquefaction and regasification of natural gas; the transportation of crude oil, natural gas and related products and consumers’ or customers’ use of the company’s products. Some of these activities, such as consumers’ and customers’ use of the company’s products, as well as actions taken by the company’s competitors in response to such laws and regulations, are beyond the company’s control.
The effect of regulation on the company’s financial performance will depend on a number of factors including, among others, the sectors covered, the greenhouse gas emissions reductions required by law, the extent to which Chevron would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits, and the impact of legislation or other regulation on the company’s ability to recover the costs incurred through the pricing of the company’s products. Material price increases or incentives to conserve or use alternative energy sources could reduce demand for products the company currently sells and adversely affect the company’s sales volumes, revenues and margins.
Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period: In preparing the company’s periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevron’s management is required under
applicable rules and regulations to make estimates and assumptions as of a specified date. These estimates and assumptions are based on management’s best estimates and experience as of that date and are subject to substantial risk and uncertainty. Materially different results may occur as circumstances change and additional information becomes known. Areas requiring significant estimates and assumptions by management include measurement of benefit obligations for pension and other postretirement benefit plans; estimates of crude oil and natural gas recoverable reserves; accruals for estimated liabilities, including litigation reserves; and impairments to property, plant and equipment. Changes in estimates or assumptions or the information underlying the assumptions, such as changes in the company’s business plans, general market conditions or changes in commodity prices, could affect reported amounts of assets, liabilities or expenses.
Unresolved Staff Comments
The location and character of the company’s crude oil, natural gas and mining properties and its refining, marketing, transportation and chemicals facilities are described on page 3 under Item 1. Business. Information required by Subpart 1200 of Regulation S-K (“Disclosure by Registrants Engaged in Oil and Gas Producing Activities”) is also contained in Item 1 and in Tables I through VII on pages FS-62 through FS-75. Note 12, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-40.
Item 3. Legal Proceedings
Ecuador: Information related to Ecuador matters is included in Note 13 to the Consolidated Financial Statements under the heading Ecuador, beginning on page FS-40.
Certain Governmental Proceedings:
In 2011, the California Air Resources Board (CARB) made penalty demands with respect to four notices of violation against Chevron for alleged violations of CARB's fuel blend regulations at certain California terminals and refineries. In November 2011, the statute of limitations expired with respect to two of the notices of violation. On January 28, 2013, settlements were executed, which resolved the remaining two notices of violation. One settlement, with respect to the Richmond Refinery, resulted in the payment of a civil penalty in the amount of $192,500, and the other settlement, relating to
the San Jose and Sacramento terminals, resulted in the payment of a civil penalty in the amount of $205,000.
In July 2009, the Hawaii Department of Health (DOH) alleged that Chevron is obligated to pay stipulated civil penalties exceeding $100,000 in conjunction with commitments Chevron undertook to install and operate certain air emission control equipment at its Hawaii Refinery pursuant to a Clean Air Act settlement with the United States Environmental Protection Agency (EPA) and the DOH. Chevron has disputed many of the allegations.
The EPA indicated that it would assess Chevron's Salt Lake City Refinery a civil penalty for alleged violations of federal requirements and Utah's air quality laws. These alleged violations were the subject of an August 20, 2008, EPA Notice of Violation (NOV) for which no penalty was assessed at the time. It appears that the resolution of this NOV may result in the payment of a civil penalty exceeding $100,000.
The South Coast Air Quality Management District (SCAQMD) issued an NOV to Chevron's Huntington Beach, California, terminal seeking a civil penalty for alleged violations involving the repair of two holes in the roof of a tank at the terminal. On January 24, 2013, Chevron U.S.A. Inc. executed a settlement agreement with the SCAQMD and made payment of $100,000 to resolve the NOV issued to the Huntington Beach terminal.
In September and November 2012, Chevron's Richmond Refinery received from the Bay Area Air Quality Management District (BAAQMD) proposals to resolve 47 alleged NOVs related to air quality regulations. A single settlement agreement has been finalized covering 28 of those NOVs for payment of $145,600 in civil penalties. Resolution of the remaining NOVs is pending and may result in a civil penalty exceeding $100,000.
In April 2012, the South Coast Air Quality Management District (SCAQMD) issued a letter seeking to settle five separate and unrelated NOVs issued to Chevron's El Segundo Refinery in 2011 for alleged violations of various state and local rules relating to air emissions. On January 24, 2013, Chevron U.S.A. Inc. executed a settlement agreement with SCAQMD and made payment of $300,000 to resolve the five NOVs issued to the El Segundo Refinery.
Mine Safety Disclosures
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 C.F.R. § 229.104) is included in Exhibit 95 of this Annual Report on Form 10-K.
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The information on Chevron’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-20.
Chevron Corporation Issuer Purchases of Equity Securities
Total Number of
Number of Shares
Shares Purchased as
that May Yet be
Part of Publicly
Oct. 1 – Oct. 31, 2012
Nov. 1 – Nov. 30, 2012
Dec. 1 – Dec. 31, 2012
Total Oct. 1 – Dec. 31, 2012
Includes common shares repurchased from company employees for required personal income tax withholdings on the exercise of the stock options and shares delivered or attested to in satisfaction of the exercise price by holders of the employee stock options. The options were issued to and exercised by management under Chevron long-term incentive plans and Unocal stock option plans.
In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits, under which common shares would be acquired by the company through open market purchases (some pursuant to a Rule 10b5-1 plan) at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. As of December 31, 2012, 97,698,628 shares had been acquired under this program for $10 billion.
Item 6. Selected Financial Data
The selected financial data for years 2008 through 2012 are presented on page FS-61.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The index to Management’s Discussion and Analysis of Financial Condition and Results of Operations, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instruments,” beginning on page FS-14 and in Note 9 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-35.
Item 8. Financial Statements and Supplementary Data
The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
The company’s management has evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the company’s disclosure controls and procedures were effective as of December 31, 2012.
(b) Management’s Report on Internal Control Over Financial Reporting
The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The
company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s 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 company’s management concluded that internal control over financial reporting was effective as of December 31, 2012.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page FS-22.
(c) Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2012, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.
Item 9B. Other Information
Item 10. Directors, Executive Officers and Corporate Governance
Executive Officers of the Registrant at February 22, 2013
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 members of the Executive Committee.
Name and Age
Current and Prior Positions (up to five years)
Current Areas of Responsibility
Chairman of the Board and Chief Executive Officer (since 2010)
Chief Executive Officer
Vice Chairman of the Board (2009)
Executive Vice President (2008 to 2009)
Vice President and President of Chevron International Exploration
and Production Company (2005 through 2007)
Vice Chairman of the Board and Executive Vice President
Executive Vice President (2005 through 2009)
Worldwide Exploration and Production Activities and Global Gas Activities, including Natural Gas Trading
Executive Vice President (since 2011)
President of Chevron Asia Pacific Exploration and Production
Company (2008 through 2011)
Managing Director of Chevron Southern Africa Strategic Business
Unit (2003 to 2007)
Technology; Mining; Project
Executive Vice President (since 2006)
President of Global Supply and Trading (2004 to 2006)
Worldwide Refining, Marketing, Lubricants, and Supply and Trading Activities, excluding Natural Gas Trading; Chemicals
Executive Vice President (since 2011)
Vice President, Policy, Government and Public Affairs
(2007 through 2011)
Vice President, Health, Environment and Safety (2003 through 2007)
Strategy and Planning; Health, Environment and Safety; Policy, Government and Public Affairs
Vice President and Chief Financial Officer (since 2009)
Vice President and Treasurer (2007 through 2008)
Vice President, Policy, Government and Public Affairs
(2002 to 2007)
Vice President and General Counsel (since 2009)
Partner and Head of Global Competition Practice of Hunton & Williams LLP, a major U.S. law firm (2005 to 2009)
Law, Governance and Compliance
The information about directors required by Item 401 (a), (d), (e) and (f) of Regulation S-K and contained under the heading “Election of Directors” in the Notice of the 2013 Annual Meeting and 2013 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), in connection with the company’s 2013 Annual Meeting of Stockholders (the “2013 Proxy Statement”), is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 405 of Regulation S-K and contained under the heading “Stock Ownership Information — Section 16(a) Beneficial Ownership Reporting Compliance” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 406 of Regulation S-K
and contained under the heading “Board Operations — Business Conduct and Ethics Code” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(d)(4) and (5) of Regulation S-K and contained under the heading “Board Operations — Board Committee Membership and Functions” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
There were no changes to the process by which stockholders may recommend nominees to the Board of Directors during the last fiscal year.
Item 11. Executive Compensation
The information required by Item 402 of Regulation S-K and contained under the headings “Executive Compensation” and “Director Compensation” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(e)(4) of Regulation S-K and contained under the heading “Board Operations — Board Committee Membership and Functions” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(e)(5) of Regulation S-K and contained under the heading “Board Operations — Management Compensation Committee Report” in the 2013 Proxy Statement is incorporated herein by reference into 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 2013 Proxy Statement shall not be deemed to be “soliciting material,” or to be “filed” with the Commission, or subject to Regulation 14A or 14C or the liabilities of Section 18 of the Exchange Act nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 403 of Regulation S-K and contained under the heading “Stock Ownership Information — Security Ownership of Certain Beneficial Owners and Management” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 201(d) of Regulation S-K and contained under the heading “Equity Compensation Plan Information” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by Item 404 of Regulation S-K and contained under the heading “Board Operations — Transactions with Related Persons” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(a) of Regulation S-K and contained under the heading “Election of Directors — Independence of Directors” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
Item 14. Principal Accounting Fees and Services
The information required by Item 9(e) of Schedule 14A and contained under the heading “Proposal to Ratify the
Appointment of the Independent Registered Public Accounting Firm” in the 2013 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
Item 15. Exhibits, Financial Statement Schedules
The following documents are filed as part of this report:
(1) Financial Statements:
(2) Financial Statement Schedules:
Included on page 36 is Schedule II - Valuation and Qualifying Accounts.
The Exhibit Index on pages E-1 through E-2 lists the exhibits that are filed as part of this report.
Schedule II — Valuation and Qualifying Accounts
(Millions of Dollars)
Year Ended December 31
Employee Termination Benefits
Balance at January 1
Additions charged to expense
Balance at December 31
Allowance for Doubtful Accounts
Balance at January 1
Additions (reductions) to expense
Bad debt write-offs
Balance at December 31
Deferred Income Tax Valuation Allowance*