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, 2013
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 — $228,635,687,380 (As of June 28, 2013)
Number of Shares of Common Stock outstanding as of February 10, 2014 — 1,909,130,328
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2014 Annual Meeting and 2014 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2014 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 27 through 29 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 operations, and power 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 page E-4. As of December 31, 2013, Chevron had approximately 64,600 employees (including about 3,200 service station employees). Approximately 32,000 employees (including about 3,000 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 and build new legacy positions. In the downstream, the strategies are to deliver competitive returns and grow earnings across the value chain. The company also continues to apply commercial excellence to enable the success of the upstream and downstream strategies, 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, 2013, and assets as of the end of 2013 and 2012 — for the United States and the company’s international geographic areas — are in Note 11 to the Consolidated Financial Statements beginning on page FS-35. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 12 and 13 on pages FS-37 through FS-39.
Capital and Exploratory Expenditures
Total expenditures for 2013 were $41.9 billion, including $2.7 billion for the company’s share of equity-affiliate expenditures. In 2012 and 2011, expenditures were $34.2 billion and $29.1 billion, respectively, including the company’s share of affiliates’ expenditures of $2.1 billion in 2012 and $1.7 billion in 2011.
Of the $41.9 billion in expenditures for 2013, 90 percent, or $37.9 billion, was related to upstream activities. Approximately 89 percent was expended for upstream operations in both 2012 and 2011. International upstream accounted for about 78 percent of the worldwide upstream investment in 2013, about 72 percent in 2012 and about 68 percent in 2011. These amounts exclude the acquisition of Atlas Energy, Inc. in 2011.
In 2014, the company estimates capital and exploratory expenditures will be $39.8 billion, including $4.8 billion of spending by affiliates. Approximately 90 percent of the total, or $35.8 billion, is budgeted for exploration and production activities, with $27.9 billion, or about 78 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 2013 and 2012 by the company and its affiliates. Worldwide oil-equivalent production of 2.597 million barrels per day in 2013 was essentially unchanged from 2012. The benefits of lower maintenance-related downtime and higher reliability at the Tengizchevroil facilities in Kazakhstan, and ramp-ups at the Usan Project in Nigeria, in the Marcellus Shale in western Pennsylvania and in the Delaware Basin in New Mexico were offset by normal field declines. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the 2011 through 2013 changes in production for crude oil and natural gas liquids, and natural gas.
The company estimates its average worldwide oil-equivalent production in 2014 will be approximately 2.610 million barrels per day based on an average Brent price of $109 per barrel in 2013. 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; Petroboscan, Petroindependiente and Petropiar in Venezuela; and Angola LNG in Angola.
4 Volumes include natural gas consumed in operations of 524 million and 522 million cubic feet per day in 2013 and 2012, respectively. Total “as sold” natural gas volumes were 4,668 million and 4,552 million cubic feet per day for 2013 and 2012, respectively.
Average Sales Prices and Production Costs per Unit of Production
Refer to Table IV on page FS-64 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 2013, 2012 and 2011.
Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2013 for the company and its affiliates:
Productive Oil and Gas Wells at December 31, 2013
Total Consolidated Companies
Total Including Affiliates
Multiple completion wells included above
Refer to Table V beginning on page FS-64 for a tabulation of the company’s proved net crude oil and natural gas reserves by geographic area, at the beginning of 2011 and each year-end from 2011 through 2013. 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, 2013, 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 2011 through 2013 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, 2013, 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, 2013
(Thousands of Acres)
Total Consolidated Companies
Total Including Affiliates
The gross undeveloped acres that will expire in 2014, 2015 and 2016 if production is not established by certain required dates are 2,627, 2,430 and 701, 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 285 billion cubic feet of natural gas through 2016. 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 871 billion cubic feet of natural gas to third parties from 2014 through 2016 from operations in Australia, Colombia, Denmark, the Netherlands 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-59 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2013, 2012 and 2011.
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, 2013. 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-59 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2013, 2012 and 2011.
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, 2013. “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 2013 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-6, 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-10.
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 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 2013 was 657,000 barrels per day.
In California, the company has significant production in the San Joaquin Valley. In 2013, net daily production averaged 162,000 barrels of crude oil, 69 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 2013, net daily production for the company’s combined interests in the Gulf of Mexico averaged 143,000 barrels of crude oil, 347 million cubic feet of natural gas and 15,000 barrels of NGLs.
Chevron was engaged in various exploration and development activities in the deepwater Gulf of Mexico during 2013. The Jack and St. Malo fields are being jointly developed with a host floating production unit (FPU) located between the two fields. Chevron has a 50 percent interest in the Jack Field and a 51 percent interest in the St. Malo Field. Both fields are company-operated. Chevron's interest in the production host facility was reduced to 40.6 percent in 2013, after the owners of a third-party oil field acquired an interest in the host. The facility has a design capacity of 170,000 barrels of crude oil and 42 million cubic feet of natural gas per day to accommodate production from the Jack/St. Malo development and third-party tiebacks. Development drilling activities continued during the year, and the FPU was moored at the offshore location in fourth quarter 2013. At the end of 2013, project activities were 74 percent complete and first oil is expected in late 2014. Total project costs for the initial phase of development are estimated at $7.5 billion. Proved reserves have been recognized for this project.
In 2013, work continued on the evaluation of additional development opportunities 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 began in mid-2013, and a final investment decision is expected in 2015. At the end of 2013, proved reserves had not been recognized for the Jack/St. Malo Stage 2 Project.
Production from the Jack/St. Malo development is expected to ramp up to a total daily rate of 94,000 barrels of crude oil and 21 million cubic feet of natural gas. The Jack and St. Malo fields have an estimated production life of 30 years.
Fabrication continued in 2013 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 75,000 barrels of crude oil and 25 million cubic feet of natural gas per day. At the end of 2013, project activities were 84 percent complete, and the platform is expected to be towed to the location in third quarter 2014. Total project costs are estimated at $5.1 billion, and first production is anticipated in 2015. 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 from the main producing interval by adding
two production wells, three water injection wells and water injection facilities. Start-up of the first production well occurred in fourth quarter 2013. Additional infill drilling is scheduled for the Tahiti Field from 2014 through 2016. The next development phase, the Tahiti Vertical Expansion Project, is being planned, with FEED expected in 2015. At the end of 2013, proved reserves had not been recognized for the infill drilling or the Tahiti Vertical Expansion Project. The Tahiti 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 continued during 2013, and plans include three producing and two injection wells, with a subsea tieback to a third-party production facility. First oil is planned for third quarter 2014, with total production expected to reach 44,000 barrels of oil-equivalent per day. The field has an estimated production life of 25 years. Proved reserves have been recognized for this project.
The company has a 15.6 percent nonoperated working interest in the Mad Dog Field. The next development phase, the Mad Dog II Project, is planned to develop the southern portion of the Mad Dog Field. The project was recycled in 2013 and is expected to reenter FEED in late 2014. At the end of 2013, proved reserves had not been recognized for this project.
Chevron holds a 20 percent nonoperated working interest in the Stampede Project, which includes the joint development of the Knotty Head and Pony fields. The development plans include a tension leg platform with a planned design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas per day. The project entered FEED in second quarter 2013, and a final investment decision is expected in fourth quarter 2014. At the end of 2013, proved reserves had not been recognized for this project.
Pre-FEED activities continue at the 55 percent-owned and operated Buckskin Project. The project is expected to enter FEED in 2015. The Moccasin discovery, located 12 miles from Buckskin, is a potential tieback opportunity into Buckskin.
Deepwater exploration activities in 2013 included participation in six exploratory wells — three appraisal and three wildcat. Drilling of the first appraisal well at the 43.8 percent-owned and operated Moccasin discovery was
completed in third quarter 2013. Drilling of an appraisal well at the Buckskin discovery is expected to be completed in second quarter 2014. Drilling at the 40 percent-owned and operated Coronado prospect resulted in a crude oil discovery in the Lower Tertiary Wilcox formation in first quarter 2013. Drilling commenced on the first Coronado appraisal well in December 2013. The company also completed drilling a wildcat well at the 30 percent-owned and operated Rio Grande prospect in December 2013 and at the 67.5 percent-owned and operated Oceanographer prospect in January 2014.
Chevron added eight leases to its deepwater portfolio as a result of awards from the central Gulf of Mexico lease sale held in first quarter 2013. In addition, Chevron acquired three deepwater leases from the western Gulf of Mexico lease sale held in third quarter 2013.
Company activities in the midcontinental United States include operated and nonoperated interests in properties primarily in Colorado, New Mexico, Oklahoma, Texas and Wyoming. During 2013, the company’s net daily production in these areas averaged 96,000 barrels of crude oil, 610 million cubic feet of natural gas and 28,000 barrels of NGLs.
In West Texas, the company continues to pursue development of shale and tight 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 June 2013, the company reached a joint development agreement covering 104,000 total acres in the Delaware Basin. In East Texas, the company continued development, at a managed pace, of multiple stacked reservoirs, including the Travis Peak, Cotton Valley, Bossier and Haynesville zones, during 2013.
The company holds leases in the Marcellus Shale and the Utica Shale, primarily located in southwestern Pennsylvania, eastern Ohio, and the West Virginia panhandle, and in the Antrim Shale and Collingwood/Utica Shale in Michigan. During 2013, the company's net daily production in these areas averaged 220 million cubic feet of natural gas. In 2013, development of the Marcellus Shale continued at a measured pace, focused on improving execution capability and reservoir understanding. Activities in the Utica Shale during 2013 included drilling seven exploratory wells. This initial activity was focused on acquiring data necessary for potential future development.
“Other Americas” is composed of Argentina, Brazil, Canada, Colombia, Greenland, Suriname, Trinidad and Tobago, and Venezuela. Net oil-equivalent production from these countries averaged 226,000 barrels per day during 2013.
Canada: Chevron has interests in oil sands projects and shale acreage in Alberta; shale acreage and a liquefied natural gas (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 2013 was 71,000 barrels per day, composed of 27,000 barrels of crude oil, 9 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. Construction work progressed during 2013 on the Quest Project, a carbon capture and sequestration project that is designed to capture and store more than one million tons of carbon dioxide produced annually by bitumen processing at the AOSP by 2015.
In February 2013, Chevron acquired a 50 percent-owned and operated interest in the Kitimat LNG and Pacific Trail Pipeline projects, 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 LNG Project is planned to include a two-train, 10.0 million-metric-ton-per-year LNG facility. The total production capacity for the project is expected to be 1.6 billion cubic feet of natural gas per day. Activities during 2013 included FEED, early site preparation and LNG marketing activities.
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) areas offshore Atlantic Canada. The HSE development is expected to increase the economic life of the Hibernia Field. During 2013, two subsea water injection wells began drilling, and installation of subsea equipment was initiated. Full production start-up is expected in 2015. Proved reserves have been recognized for this project.
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 design capacity of 150,000 barrels of crude oil per day. Procurement and construction activities progressed in 2013. Project costs are estimated at $14 billion. The project has an expected economic life of 30 years, and first oil is expected in 2017. Proved reserves have been recognized for this project.
In 2013, the company acquired 86,000 total additional acres in the Duvernay shale formation in Alberta. Drilling for these tight resources continued in 2013, with completion of a
multiwell program. Nine wells were completed and tied into production facilities by early 2014.
The company also holds a 40 percent nonoperated working interest in exploration rights for two blocks in the Flemish Pass Basin offshore Newfoundland. During 2013, the company relinquished its license in the Orphan Basin located offshore Newfoundland and Exploration License 1109 located offshore Labrador. The company also holds two exploration licenses in the Beaufort Sea region of the Northwest Territories and a 40 percent nonoperated working interest in the 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 2013, Chevron acquired a 29.2 percent interest in and operatorship of two blocks located in the Kanumas Area, offshore the northeast cost of Greenland. Blocks 9 and 14 cover 1.2 million acres. The acquisition of seismic data is planned for 2014.
Argentina: Chevron holds operated interests in four concessions in the Neuquen Basin, with working interests ranging from 18.8 percent to 100 percent, and a 50 percent nonoperated working interest in one concession. Net oil-equivalent production in 2013 averaged 19,000 barrels per day, composed of 18,000 barrels of crude oil and 6 million cubic feet of natural gas. During 2013, the company completed four exploratory wells in El Trapial concession, targeting oil and gas in the Vaca Muerta Shale. Chevron plans to continue production testing the wells during 2014. El Trapial concession expires in 2032.
In addition, Chevron signed agreements during 2013 to advance the Loma Campana Project to develop the Vaca Muerta Shale. In 2013, 109 wells were drilled, and the drilling plan includes more than 140 wells in 2014.
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 2013 averaged 6,000 barrels per day, composed of 5,000 barrels of crude oil and 2 million cubic feet of natural gas.
In second quarter 2013, the company received regulatory approval to partially resume production at the Frade Field. A plan to resume production from additional existing wells has been submitted for regulatory approval. The concession that includes the Frade Field expires in 2025.
First production from the initial well occurred in fourth quarter 2013 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 and 35 million cubic feet of natural gas per day. The concession that contains the Papa-Terra Field expires in 2032. Additional development drilling is planned for 2014.
Evaluation of the field development concept for Maromba continues. At the end of 2013, proved reserves had not been recognized for this project. The concession containing the Maromba Field expires in 2032.
In May 2013, Chevron was awarded a 50 percent interest in and operatorship of Block CE-M715. The deepwater block covers 81,000 total acres and is located in the Ceará Basin offshore equatorial Brazil. Acquisition of seismic data is planned for 2014.
Colombia: The company operates the offshore Chuchupa and the onshore Ballena and Riohacha natural gas fields and 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 2013.
Suriname: Chevron holds a 50 percent nonoperated working interest in Blocks 42 and 45 offshore Suriname. In 2013, seismic data was acquired for Block 45. The data is being processed in 2014 to plan for the drilling of an exploration well in 2015.
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 2013 averaged 173 million cubic feet of natural gas per day. Development of the Starfish Field continued during 2013, and first gas is expected in 2015. Natural gas from the project is planned to 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 2013, cross-border agreements were signed between the governments of Trinidad and Tobago and Venezuela, and work continued on maturing commercial development concepts.
Venezuela: Chevron's production activities are performed by two affiliates in western Venezuela and one 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 western Venezuela, 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 2013 from these operations averaged 65,000 barrels per day, composed of 61,000 barrels of liquids and 26 million cubic feet of natural gas.
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. Project activities in 2013 focused on assessing development alternatives.
The company operates and holds a 60 percent interest in Block 2 and a 100 percent interest in Block 3 in the Plataforma Deltana area offshore eastern Venezuela. The Loran Field in Block 2 and the Manatee Field in Trinidad and Tobago form a single, cross-border field that lies along the maritime border of Venezuela and Trinidad and Tobago. During 2013, cross-border agreements were signed between the governments of Venezuela and Trinidad and Tobago, and 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, the Republic of the Congo, Sierra Leone and South Africa. Net oil-equivalent production in Africa averaged 437,000 barrels per day during 2013.
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) concession area. In addition, Chevron has a 36.4 percent interest in Angola LNG Limited. Net production from these operations in 2013 averaged 133,000 barrels of oil-equivalent per day.
The company operates the 39.2 percent-owned Block 0, which averaged 90,000 barrels per day of net liquids production in 2013. The Block 0 concession extends through 2030.
Construction activities on Mafumeira Sul, the second development stage for the Mafumeira Field in Block 0, progressed in 2013. Development plans include a central processing facility, two wellhead platforms, subsea pipelines, and 34 producing and 16 water injection wells. The facility has a design capacity of 150,000 barrels of liquids and 350 million cubic feet of natural gas per day. First production is planned for 2015, and ramp-up to full production is expected to continue until 2017. The project is estimated to cost $5.6 billion. Proved reserves have been recognized for this project.
A project to develop the Greater Longui Area of Block 0 is expected to enter FEED in first-half 2014. FEED activities progressed during 2013 on the south extension of the N’Dola Field development and work continues toward a final investment decision. The facility is planned to have a design capacity of 28,000 barrels of crude oil and 50 million cubic feet of natural gas per day. At the end of 2013, proved reserves had not been recognized for these projects.
Work continued in 2013 on the Nemba Enhanced Secondary Recovery Stage 1 & 2 Project in Block 0. Installation of the platform was completed in early 2014, and project start-up is expected in 2015. Total daily production is expected to be 12,000 barrels of crude oil. Proved reserves have been recognized for this project.
Also in Block 0, drilling of an exploration well in Area A was completed in early 2013 and resulted in a discovery in the post-salt Vermelha interval. Plans for future development are under evaluation. Drilling of an appraisal well in the Minzu Pinda reservoir commenced in late 2013 and is planned to be completed in second quarter 2014. A pre-salt exploration well in Area A is planned for first-half 2014.
The company operates and holds a 31 percent interest in a production-sharing contract (PSC) for deepwater Block 14. Net production in 2013 averaged 27,000 barrels of liquids per day. Development and production rights for the various producing fields in Block 14 expire between 2023 and 2028.
Planning continues on the multireservoir, deepwater Lucapa Field in Block 14, located on the north rim of the Congo River Canyon. The project was recycled in 2013 to conduct additional subsurface studies over a 12-month period. During the year, development alternatives were evaluated for the Malange Field, and the project is expected to enter FEED in early 2014. At the end of 2013, 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 operates an onshore natural gas liquefaction plant in Soyo, Angola. The plant has a capacity 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. This is the world's first LNG
plant supplied with associated gas, where the natural gas is a by-product of crude oil production. Feedstock for the plant originates from multiple fields and operators. The first LNG shipment from the plant occurred in second quarter 2013. Commissioning and testing of the plant continued through the end of 2013. Due to the variability in the associated gas that supplies Angola LNG, the plant is expected to operate at approximately 50 percent of capacity until permanent plant modifications are completed in 2015, allowing Angola LNG to consistently produce at full capacity. Total daily production in 2013 averaged 83 million cubic feet of natural gas (30 million net) and 2,000 barrels of NGLs (1,000 net). The anticipated economic life of the project is in excess of 20 years.
The company also holds a 38.1 percent interest in the Congo River Canyon Crossing 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 2013, with project completion targeted for 2015.
Angola-Republic of the Congo Joint Development Area: Chevron operates and holds a 31.3 percent interest in the Lianzi Unitization Zone, located in an area shared equally by Angola and the Republic of the Congo. The project scope includes four producing wells and three water injection wells with a subsea tieback to an existing platform in Block 14. The project has a design capacity of 46,000 barrels of crude oil per day. First production is planned for 2015. Proved reserves have been recognized for this project.
Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2013 averaged 2,000 barrels of crude oil.
Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo). The licenses for Nsoko, Nkossa and Moho-Bilondo expire in 2018, 2027 and 2030, respectively. In September 2013, the company sold its nonoperated interest in the Kitina permit area. Net production averaged 13,000 barrels of liquids per day in 2013.
A final investment decision was reached in first quarter 2013 for the Moho Nord Project, located in the Moho-Bilondo development area. The $10 billion project includes a new facilities hub and a subsea tieback to the existing Moho-Bilondo FPU. First production is expected in 2015, and total daily production of 140,000 barrels of crude oil is expected in 2017. The initial recognition of proved reserves occurred in 2013.
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 crude oil production from the Chad fields in 2013 was 18,000 barrels. The Chad producing operations are conducted under a concession that expires in 2030.
Nigeria: Chevron holds a 40 percent interest in 13 operated concessions, predominantly in the onshore and near-offshore regions of the Niger Delta. The company also owns varying interests in three operated and six nonoperated deepwater blocks. In 2013, the company’s net oil-equivalent production in Nigeria averaged 268,000 barrels per day, composed of 233,000 barrels of crude oil, 182 million cubic feet of natural gas and 5,000 barrels of liquefied petroleum gas (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 2013, drilling continued on a 10-well, Phase 2 development program, Agbami 2, that is expected to offset field decline and maintain plateau production. Drilling is expected to continue through 2015. The third development phase, Agbami 3, is a five-well drilling program expected to offset field decline. The project entered FEED in early 2014, and a final investment decision is expected in second-half 2014. Drilling is scheduled to continue through 2017. The leases that contain the Agbami Field expire in 2023 and 2024.
Chevron holds a 30 percent nonoperated interest in the deepwater Usan Field in OML 138. Ramp-up continued during 2013, and additional development drilling is planned for 2014 through 2017.
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 proposed development plan involves subsea wells tied back to an FPSO with a planned design
capacity of 225,000 barrels of crude oil per day. The project achieved FEED in second quarter 2013, and a final investment decision is expected in late 2014. At the end of 2013, no proved reserves were recognized for this project.
In the Niger Delta region, the company reached a final investment decision in 2013 on the Dibi Long-Term Project that is designed to rebuild the Dibi facilities and replace the Early Production System facility. The facilities have a design capacity of 70,000 barrels of crude oil per day, and start-up is expected in 2016.
Also in the Niger Delta region, ramp-up activity continued at the Escravos Gas Plant (EGP). During 2013, 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 near-shore 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.
Construction activities progressed during 2013 on the 40 percent-owned and operated Sonam Field Development Project, which 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 is the operator of and has a 75 percent interest in this 33,000-barrel-per-day gas-to-liquids facility at Escravos. The facility is designed to process 325 million cubic feet per day of natural gas. Production is scheduled to commence in first-half 2014, and the first product shipment is expected to occur in second-half 2014. The estimated cost of the project is $10 billion.
In deepwater exploration, Chevron operates and holds a 100 percent interest in OML 132, where an exploration well at Aparo North is planned for 2014. In addition, Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery in OML 140, where additional exploration activities are planned for 2014.
Shallow-water exploration activities to identify and evaluate potential deep hydrocarbon targets are ongoing. Reprocessing of 3-D seismic data over OML 49 and regional mapping activities over OML 86 and OML 88 continued in 2013.
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 holds a 45 percent interest in and operates three deepwater blocks off the coast of Liberia. In 2014, the company plans additional drilling based on the evaluation of 3-D seismic data and 2012 drilling results.
Morocco: In early 2013, the company acquired a 75 percent-owned and 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. The acquisition of seismic data is planned for 2014.
Sierra Leone: The company holds a 55 percent interest in and operates a concession off the coast of Sierra Leone. The concession contains two deepwater blocks, with a combined area of approximately 1.4 million acres. Interpretation of 2-D seismic data is planned for 2014.
South Africa: In 2013, the company continued seeking shale gas exploration opportunities in the Karoo Basin in South Africa under an agreement that allows Chevron and its partner to work together 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 2013, net oil-equivalent production averaged 1,087,000 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) fields. The company’s daily net production averaged 28,000 barrels of oil-equivalent in 2013. AIOC operations are conducted under a PSC that expires in 2024.
In January 2014, production commenced on the next development phase of the ACG project, which further develops the Chirag and Deepwater Gunashli fields. The project has an incremental design capacity of 183,000 barrels of crude oil and 285 million cubic feet of natural gas per day.
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 million barrels per day and transports the majority of ACG production. Another production export route for crude oil is the Western Route Export Pipeline, which is 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 2013 from these fields averaged 321,000 barrels per day, composed of 243,000 barrels of crude oil, 347 million cubic feet of natural gas and 20,000 barrels of NGLs. During 2013, 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 of production was exported by rail to Black Sea ports and via the BTC pipeline to the Mediterranean.
In 2013, FEED continued for three projects. The Wellhead Pressure Management Project (WPMP) is designed to maintain production capacity and extend the production plateau from existing assets. The Capacity and Reliability (CAR) Project is designed to reduce facility bottlenecks and increase plant efficiency and reliability. The Future Growth Project (FGP) is designed to increase total daily production by 250,000 to 300,000 barrels of oil-equivalent and to increase ultimate recovery from the reservoir. The project plans to expand the utilization of sour gas injection technology proven in existing operations. During 2013, the company and the government of Kazakhstan signed a memorandum of understanding that establishes the framework and mutual commitments to progress the FGP and the WPMP. The final investment decision on the CAR Project was made in February 2014. The final investment decisions on the WPMP and the FGP are planned for second-half 2014. At the end of 2013, proved reserves have been recognized for the WPMP and the CAR Project.
The company holds an 18 percent nonoperated working interest in the Karachaganak Field under a PSC that expires in 2038. During 2013, Karachaganak net oil-equivalent production averaged 57,000 barrels per day, composed of 34,000 barrels of liquids and 135 million cubic feet of natural gas. Access to the CPC and Atyrau-Samara (Russia) pipelines enabled 32,000 net barrels per day of Karachaganak liquids to be exported and sold at world-market prices during 2013. The remaining liquids were sold into local and Russian markets. In 2013, work continued on identifying the optimal scope for future expansion of the field. At the end of 2013, proved reserves had not been recognized for a future expansion.
Kazakhstan/Russia: Chevron has a 15 percent interest in the CPC affiliate. During 2013, CPC transported an average of 706,000 barrels of crude oil per day, including 635,000 barrels per day from Kazakhstan and 71,000 barrels per day from Russia. In 2013, work continued on the 670,000-barrel-per-day expansion of the pipeline capacity with completion of the offshore loading system. The project is being implemented in phases, with capacity increasing progressively until reaching maximum capacity of 1.4 million barrels per day in 2016. The incremental capacity is expected to reach 400,000 barrels per day by year-end 2014, with the first increase expected to be realized by March 2014. The expansion is expected to provide additional transportation capacity that accommodates a portion of the future growth in TCO production.
Bangladesh: Chevron holds a 99 percent interest in two operated PSCs covering Block 12 (Bibiyana Field) 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 2013 averaged 113,000 barrels per day, composed of 663 million cubic feet of natural gas and 2,000 barrels of condensate.
The Bibiyana Expansion Project includes installation of two gas processing trains, additional development wells and an enhanced liquids recovery facility, and has an incremental design capacity of 300 million cubic feet of natural gas and 4,000 barrels of condensate per day. First production is expected in late 2014. Proved reserves have been recognized for this project.
Cambodia: Chevron owns a 30 percent interest in and operates the 1.2 million-acre Block A, located in the Gulf of Thailand. In 2013, the company continued discussions on the production permit and commercial terms 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 2013, 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 most of the natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. The company’s average net natural gas production in 2013 was 96 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 2013 averaged 229,000 barrels per day, composed of 62,000 barrels of crude oil and condensate and 1 billion cubic feet of natural gas. The company’s natural gas production is sold to the domestic market under long-term sales agreements.
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 also 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.
In the Pattani Basin, the Ubon Project entered FEED in second quarter 2013, and a final investment decision is expected in 2015. The facilities have a planned design capacity of 35,000 barrels of liquids and 115 million cubic feet of natural gas per day. At the end of 2013, proved reserves had not been recognized for this project.
During 2013, the company drilled five exploration wells in the Pattani Basin, and three 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 includes installation of wellhead and hub platforms, an FSO, a central processing platform and a pipeline to shore. The facilities have a design capacity of 640 million cubic feet of natural gas and 21,000 barrels of liquids per day. A final investment decision for the development is pending resolution of commercial terms. Concurrent with the commercial negotiations, the company is also evaluating these assets for possible divestment. At the end of 2013, proved reserves had not been recognized for the development project.
China: Chevron has operated and nonoperated working interests in several areas in China. The company’s net oil-equivalent production in 2013 averaged 20,000 barrels per day, composed of 19,000 barrels of crude oil and condensate and 6 million cubic feet of natural gas.
The company operates and holds a 49 percent interest in the Chuandongbei PSC, located onshore in the Sichuan Basin. The full development includes two sour gas processing plants connected by a natural gas gathering system to five fields.
During 2013, the company continued construction on both natural gas processing plants. The first plant's initial three trains have a design outlet capacity of 258 million cubic feet per day, with the first train targeted for mechanical completion in 2014. Start-up is scheduled for 2015. The total design outlet capacity for the project is 558 million cubic feet per day. 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 2038.
The company holds a 59.2 percent-owned and operated interest in deepwater Block 42/05 in the South China Sea. In late 2013 and early 2014, an exploratory well was drilled in Block 42/05 and was unsuccessful. Chevron also has a 100 percent-owned and operated interest in shallow-water Blocks 15/10 and 15/28. In 2013, the company acquired two 3-D seismic surveys in these blocks. Processing of this seismic data is ongoing.
During 2013, the company drilled two exploratory wells for shale gas in the Qiannan Basin and both were unsuccessful.
The company also has 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 and 32.7 percent in Block16/19 in the Pearl River Mouth Basin.
Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field. Net oil-equivalent production in 2013 averaged 23,000 barrels per day, composed of 119 million cubic feet of natural gas and 3,000 barrels of condensate. The Malampaya Phase 2 Project is designed to maintain capacity. During 2013, work progressed with two infill wells being completed. First production is expected to commence in first quarter 2014 with compression facilities to follow in 2015. Proved reserves have been recognized for this project.
Chevron holds a 40 percent interest in an affiliate that develops and produces geothermal resources in southern Luzon, which supplies steam to third-party power generation facilities with a combined operating capacity of 692 megawatts. During 2013, the affiliate secured a renewable energy service contract for an additional 25 years. Chevron also has a 90 percent-owned and operated interest in the Kalinga geothermal prospect area in northern Luzon. In 2013, Chevron held negotiations to sell down equity to comply with local law and to secure a 25-year term for a renewable energy service contract. Negotiations are planned to continue into 2014. The company continues to assess the prospect area.
Indonesia: Chevron holds operated and nonoperated working interests in Indonesia. In Sumatra, the company holds a 100 percent-owned and operated interest in the Rokan PSC. The Siak PSC expired in November 2013. Chevron also operates four PSCs in the Kutei Basin, located offshore eastern Kalimantan. These interests range from 62 percent to 92.5 percent. Chevron also has a 25 percent nonoperated working interest in a joint venture in Block B in the South Natuna Sea and a 51 percent operated working interest in two exploration blocks in western Papua, West Papua I and West Papua III.
The company’s net oil-equivalent production in 2013 from its interests in Indonesia averaged 193,000 barrels per day, composed of 156,000 barrels of liquids and 225 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 company continues to implement projects designed to sustain production from existing reservoirs. The company progressed construction on the Duri Area 13 expansion project during 2013. First production occurred in second-half 2013, and ramp-up of production is expected through 2016. The Rokan PSC expires in 2021.
During 2013, two deepwater natural gas development projects in the Kutei Basin progressed under a single plan of development. Collectively, these projects are referred to as the Indonesia Deepwater Development. One of these projects, Gendalo-Gehem, includes two separate hub developments, each with its own FPU, subsea drill centers, natural gas and condensate pipelines, and an onshore receiving facility. The
project has a planned design capacity of 1.1 billion cubic feet of natural gas and 47,000 barrels of condensate per day. During 2013, the company received bids for all major contracts. A final investment decision is planned for 2014, but is subject to the timing of government approvals. The company’s working interest is approximately 63 percent. At the end of 2013, proved reserves had not been recognized for this project.
The other project, Bangka, includes a subsea tieback to the West Seno FPU, with a planned design capacity of 115 million cubic feet of natural gas and 4,000 barrels of condensate per day. The company’s working interest is 62 percent. Bids were received on all major contracts during 2013. A final investment decision is planned for 2014, but is subject to the timing of government approvals. At year-end 2013, proved reserves had not been recognized for this project.
In Sumatra, three exploration wells were drilled with one discovery. Further exploration and appraisal drilling is planned for 2014. In the West Papua exploration blocks, which are in close proximity to a third-party LNG facility, 2-D seismic data acquisition and processing was completed 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 270 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 the Suoh-Sekincau prospect area of South 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: The company operates and holds an 80 percent interest in two PSCs covering the Rovi and Sarta blocks.In June 2013, the company acquired the operatorship and an 80 percent interest in the Qara Dagh Block. The blocks cover a combined area of 444,000 acres. In second-half 2013, Chevron commenced exploration drilling in the Rovi and Sarta blocks, and drilling on two wells is expected to be completed in first quarter 2014. Acquisition of seismic data and further exploration drilling is planned during 2014.
Partitioned Zone (PZ): Chevron holds a concession to operate the Kingdom of Saudi Arabia's 50 percent interest in the hydrocarbon resources in the onshore area of the PZ between Saudi Arabia and Kuwait. The concession expires in 2039.
During 2013, the company's average net oil-equivalent production was 87,000 barrels per day, composed of 84,000 barrels of crude oil and 19 million cubic feet of natural gas. During 2013, the company continued a steam injection pilot project in the First Eocene carbonate reservoir and achieved thermal maturity. A project to expand the steam injection pilot to the Second Eocene reservoir entered FEED in September 2013. Development planning also continued on a full-field steamflood application in the Wafra Field. The Wafra Steamflood Stage 1 Project has a planned design capacity of 80,000 barrels of crude oil per day and is expected to enter FEED in late 2014. At the end of 2013, proved reserves had not been recognized for any of these steamflood developments.
Also in 2013, 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 late 2014. At year-end 2013, proved reserves had not been recognized for this project.
In Australia, the company’s upstream efforts are concentrated off the northwest coast. During 2013, the average net oil-equivalent production from Australia was 96,000 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 includes the development of the Gorgon and nearby Jansz-Io natural gas fields. The development includes a three-train, 15.6 million-metric-ton-per-year LNG facility, a carbon dioxide injection facility and a domestic natural gas plant. The total production capacity for the project is expected to be approximately 2.6 billion cubic feet of natural gas and 20,000 barrels of condensate per day. Gorgon plant start-up and first cargo is planned for mid-2015. Total estimated project costs for the first phase of development are $54 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 2013 with approximately 75 percent of the project activities complete at year-end. Through early 2014, 20 of 21 Train 1 LNG plant modules had been delivered and installed at Barrow Island, with the final module expected to arrive by mid-year. In addition, installation activities were completed for the domestic gas pipeline from Barrow Island to the mainland, enabling delivery of commissioning gas. Progress continued on the construction of the LNG tanks and jetty, with completion of LNG Tank 1 expected in second-half 2014. Start-up of the first gas turbine generator, allowing first natural gas into the LNG plant, is planned for late 2014.
Construction of the upstream facilities also advanced with 14 of the 18 subsea wells drilled and completed. The offshore pipelines from both fields to Barrow Island were completed in 2013. Infield flow lines and subsea structures continue to be installed in 2014. Perforation of all eight development wells in the Gorgon Field and completion of the Jansz-Io drilling program are expected in late 2014.
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 65 percent of Chevron’s share of LNG from this project. Discussions continue with potential customers to increase long-term sales to around 80 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.
The evaluation of expansion options to increase the production capacity of Gorgon is planned to continue in 2014.
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, on the coast of Western Australia. The company plans to supply natural gas to the facilities from three company-operated licenses containing the Wheatstone and Iago fields. Chevron holds a 64.1 percent interest in the LNG facilities and an 80.2 percent interest in the offshore licenses. Total production capacity for the Wheatstone and Iago fields and nearby third-party fields is expected to be approximately 1.6 billion cubic feet of natural gas and 30,000 barrels of condensate per day. Start-up of the first train is expected in 2016. Total estimated costs for the foundation phase 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 2013, construction and fabrication activities progressed, with a focus on delivering site infrastructure to enable efficient plant construction. Offshore dredging, pipeline installation and drilling of development wells commenced during the year. Fabrication also progressed on key upstream components, including the offshore platform and subsea equipment. Delivery of the first Train 1 LNG plant modules is expected in second-half 2014, along with the installation of the offshore platform steel gravity-based structure, completion of the natural gas export trunkline and completion of the LNG Tank 1 foundation. The project was approximately 25 percent complete at year-end.
The company also executed binding long-term Sales and Purchase Agreements with two Asian customers for the delivery of additional LNG. As of year-end 2013, 85 percent of Chevron’s equity LNG offtake is committed under long-term agreements with customers in Asia. In addition, the company continues to market its equity share of natural gas to Western Australia consumers.
During 2013, the company announced two natural gas discoveries in the Carnarvon Basin. These include natural gas discoveries at the 50 percent-owned and operated Kentish Knock South prospect in Block WA-365-P and the 50 percent-owned and operated Elfin prospect in Block WA-268-P. These discoveries are expected to contribute to potential expansion opportunities at company-operated LNG projects.
Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. Daily net production in 2013 averaged 19,000 barrels of crude oil and condensate, 419 million cubic feet of natural gas, and 3,000 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.
Production commenced at the North Rankin 2 Project in fourth quarter 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 daily production of about 2 billion cubic feet of natural gas and 39,000 barrels of condensate. The project's estimated economic life exceeds 20 years from the time of start-up.
The company holds nonoperated working interests ranging from 24.8 percent to 50 percent in three blocks in the Browse Basin.
In 2013, the company acquired nonoperated working interests in two onshore blocks covering 810,000 total acres in the Nappamerri Trough, located in the Cooper Basin region in central Australia. The acquisition includes a 30 percent interest in PEL 218 in South Australia and an 18 percent interest in ATP 855 in Queensland. Pending favorable results of an exploration drilling program, Chevron could earn nonoperated working interests of 60 percent in PEL 218 and 36 percent in ATP 855.
In October 2013, the company acquired exploration interests in offshore Blocks EPP44 and EPP45, which span more than 8 million acres in the Bight Basin off the South Australian coast. Chevron is the operator and holds a 100 percent interest.
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 94,000 barrels per day during 2013.
Denmark: Chevron holds a 12 percent nonoperated working interest in the Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 fields in the Danish North Sea. Net oil-equivalent production in 2013 from DUC averaged 28,000 barrels per day, composed of 19,000 barrels of crude oil and 55 million cubic feet of natural gas. The concession expires in 2042.
Netherlands: Chevron operates and holds interests ranging from 23.5 percent to 80 percent in 11 blocks in the Dutch sector of the North Sea. In 2013, the company’s net oil-equivalent production was 9,000 barrels per day, composed of 2,000 barrels of crude oil and 41 million cubic feet of natural gas. The company is evaluating these assets for possible divestment.
Norway: The company holds a 7.6 percent nonoperated working interest in the Draugen Field. The company’s net production averaged 2,000 barrels of oil-equivalent per day during 2013. The company is evaluating this asset for possible divestment. 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 2013 from nine offshore fields was 55,000 barrels per day, composed of 40,000 barrels of liquids and 94 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.
At the 73.7 percent-owned and operated Alder Project, FEED activities were completed and a final investment decision was made in late 2013. The project is proceeding as a single subsea well tied back to the existing Britannia platform and has a design capacity of 14,000 barrels of condensate and 110 million cubic feet of natural gas per day. First production is scheduled for 2016. The initial recognition of proved reserves occurred in 2013 for this project.
Procurement and fabrication activities continued during 2013 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 design capacity is 120,000 barrels of crude oil and 100 million cubic feet of natural gas per day. 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 40 percent-owned and operated Rosebank Project northwest of the Shetland Islands, the company continues to assess alternatives for the optimum development of the Rosebank Field. At the end of 2013, proved reserves had not been recognized for this project.
An exploration well was drilled in License P1189, and the results of this well are under evaluation. In License P1191, 3-D seismic data was acquired to map the area southwest of the Rosebank Field. In the North Sea, an exploration well to further delineate the southern extension of the Jade Field was drilled in second-half 2013, and the results are under evaluation.
Bulgaria: In 2011, the Bulgarian government advised that Chevron had submitted a winning tender for an exploration permit in northeast Bulgaria. However, prior to execution of the license agreement, the government announced the withdrawal of the decision as the Bulgarian parliament imposed a ban on hydraulic fracturing. Chevron continues to work with the government of Bulgaria to provide the necessary assurances that shale hydrocarbons can be developed safely and responsibly.
Lithuania: Chevron holds a 50 percent interest in a Lithuanian exploration and production company. In 2013, two exploration wells were drilled in the 394,000-acre Rietavas Block, and the results of the wells are under evaluation. Drilling of a third exploration well commenced in January 2014 and is planned to be completed during second quarter 2014.
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. In 2013, the first exploration wells were drilled in the Zwierzyniec and Krasnik concessions. A 3-D seismic survey is under way on the Grabowiec concession and is planned to be completed in second quarter 2014. Exploration activities are planned to continue during 2014.
Romania: The company holds a 100 percent interest in and operates the 1.6 million-acre Barlad Shale concession in northeast Romania. Drilling of the first exploration well is planned to commence in second quarter 2014. In addition, Chevron holds a 100 percent interest in and operates three concessions covering 670,000 acres in southeast Romania. In October 2013, the company commenced acquisition of 2-D seismic data across two of the three concessions.
Ukraine: In November 2013, Chevron signed a PSC with the government of Ukraine for a 50 percent interest in and operatorship of the 1.6 million acre Oleska Shale block in western Ukraine. As of early 2014, the 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 2013, 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, Canada, Europe, Kazakhstan, Indonesia, Latin America, Myanmar, Nigeria, the Philippines and Thailand.
U.S. and international sales of natural gas liquids were 142,000 and 88,000 barrels per day, respectively, in 2013. 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 2013, the company had a refining network capable of processing nearly 2 million barrels of crude oil per day. Operable capacity at December 31, 2013, and daily refinery inputs for 2011 through 2013 for the company and affiliate refineries are summarized in the table below.
Average crude oil distillation capacity utilization during 2013 was 84 percent, compared with 88 percent in 2012. At the U.S. refineries, crude oil distillation capacity utilization averaged 81 percent in 2013, compared with 87 percent in 2012. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 76 percent and 77 percent of Chevron’s U.S. refinery inputs in 2013 and 2012, respectively.
At the Pascagoula Refinery, construction progressed during 2013 on a facility to produce approximately 25,000 barrels per day of premium base oil. Mechanical completion of the plant is expected in first quarter 2014, and ramp up to full production is planned during second quarter 2014.
During 2013, work continued on projects to improve refinery flexibility and enhance the capability to process lower
cost feedstocks. In early 2013, start-up was achieved on a project at the Pascagoula Refinery that provides additional flexibility to process a broader range of crudes. A project to improve flexibility at the Salt Lake City Refinery is scheduled to be completed by mid-2014.
Outside the United States, GS Caltex, a 50 percent-owned affiliate, started commercial operations of a 53,000-barrel-per-day gas oil fluid catalytic cracking unit at the Yeosu Refinery in South Korea in second quarter 2013. In 2013, Caltex Australia Ltd., a 50 percent-owned affiliate, progressed its plans to convert the Kurnell, Australia, refinery to an import terminal in 2014. In February 2014, Singapore Refining Company, Chevron's 50 percent-owned joint venture, reached a final investment decision to install a gasoline clean fuels facility and cogeneration plant. Addition of the facilities is expected to increase the refinery's capability to produce higher value gasoline and improve energy efficiency.
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, 2013
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 affiliates.
Chevron holds a controlling interest in the shares 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.
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, 2013.
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 affiliates’ sales:
In the United States, the company markets under the Chevron and Texaco brands. At year-end 2013, the company supplied directly or through retailers and marketers approximately 8,050 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 400 of these outlets are company-owned or -leased stations.
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 8,600 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 affiliate, GS Caltex, and in Australia through its 50 percent-owned affiliate, Caltex Australia Limited.
Chevron markets commercial aviation fuel at approximately 115 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the product lines Havoline, Delo, Ursa, Meropa, Rando, Clarity and
Taro in the United States and worldwide under the three brands: Chevron, Texaco and Caltex.
Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) affiliate. At the end of 2013, CPChem owned or had joint-venture interests in 35 manufacturing facilities and two research and development centers around the world.
During 2013, CPChem progressed 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 second quarter 2014. In October 2013, CPChem announced a final investment decision on its U.S. Gulf Coast Petrochemicals Project, which is expected to capitalize on advantaged feedstock sourced from shale gas development in North America. The $6 billion project includes 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 with refined base oil to produce finished lubricants, used primarily in engine applications such as passenger cars, heavy-duty diesel trucks, buses, ships, locomotives and motorcycles. Additives for fuels are blended to improve engine performance and extend engine life. In 2013, construction continued on a project to expand the capacity of the existing additives plant on Jurong Island in Singapore. Commercial operations are expected to begin by third quarter 2014. Upon start-up, the plant is expected to double its capacity since it was commissioned in 1999. In Gonfreville, France, a project to expand dispersant production by more than 25 percent was completed in third quarter 2013, and a project to effectively double detergent capacity began construction with expected completion in late 2014.
Pipelines: Chevron owns and operates an extensive network of crude oil, natural gas, natural gas liquid, refined product and chemical 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, 2013
Total United States
Includes company’s share of pipeline mileage owned by affiliates.
Excludes gathering pipelines relating to the crude oil and natural gas production function.
The company is leading the construction of a 136-mile, 24-inch crude oil pipeline from the planned Jack/St. Malo deepwater production 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. In early 2014, the company completed laying the pipe, which included the installation of two subsea connections for future tie-ins. All remaining work on the pipeline is expected to be completed by start-up of the production facility in late 2014.
In June 2013, the company completed the sale of the 100 percent-owned and operated Northwest Products System.
Refer to pages 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.
Shipping: All tankers in Chevron’s controlled seagoing fleet were utilized during 2013. During 2013, the company had 58 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, 20131
(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 2013, the company took delivery of two vessels that included one bareboat charter VLCC and a dynamically positioned shuttle tanker. Progress continued on contracts in place for bareboat charters and new builds, to modernize the fleet and increase LNG coverage. 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 owns and operates the Questa molybdenum mine in New Mexico. At year-end 2013, Chevron had 160 million pounds of proven molybdenum reserves at Questa. Production and underground development at Questa continued at reduced levels in 2013 in response to weak prices for molybdenum.
Power and Energy Services: In 2014, Chevron Energy Solutions is being combined with Chevron Global Power Company. As the company's power and energy services provider, this business delivers comprehensive commercial, engineering and operational support services to improve power reliability and energy efficiency of Chevron operations worldwide. The responsibilities also include developing and building sustainable energy projects for the production of renewable power and to reduce energy costs that benefit third parties and the environment.
This business also manages Chevron's interest in a variety of gas-fired and renewable power generation assets. The gas-fired cogeneration facilities produce electricity and steam and utilize recovered waste heat to support enhanced oil recovery operations. The renewable facilities consist of wind, geothermal, photovoltaic and solar-to-steam production assets.
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.
Research and Technology: The company’s energy technology organization supports Chevron’s upstream and downstream businesses by conducting research, developing and qualifying technology, providing technical services, and providing 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 technology ventures group manages investments in venture capital and projects in emerging energy technologies and their integration into Chevron’s core businesses. As of the end of 2013, the ventures group continued to explore technologies such as next-generation biofuels, advanced solar and enhanced pipeline inspection methods, and made investments in the primary carbon market.
Chevron’s research and development expenses were $750 million, $648 million and $627 million for the years 2013, 2012 and 2011, 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 through 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 page FS-15 for additional information on environmental matters and their impact on Chevron, and on the company's 2013 environmental expenditures. Refer to page FS-15 and Note 23 on page FS-55 for a discussion of environmental remediation provisions and year-end reserves. Refer also to Item 1A. Risk Factors on pages 27 through 29 for a discussion of greenhouse gas regulation and climate change.
Website Access to SEC Reports
The company’s website is www.chevron.com. Information contained on the company’s website 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 website 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 website 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. 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 14 to the Consolidated Financial Statements, beginning on page FS-39.
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, 2013, 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, 2013.
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-59 through FS-71. Note 13, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-39.
Item 3. Legal Proceedings
Ecuador: Information related to Ecuador matters is included in Note 14 to the Consolidated Financial Statements under the heading Ecuador, beginning on page FS-39.
Certain Governmental Proceedings:
As initially disclosed in the first quarter 2011 Form 10-Q, the Environmental Protection Agency (EPA) indicated that it would assess the company'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. On October 21, 2013, the U.S. District Court in Utah entered a Consent Decree resolving the NOV. Pursuant to the Consent Decree, Chevron paid a penalty of $384,000 and agreed to implement certain other measures.
On August 6, 2012, a piping failure and fire occurred at the Chevron U.S.A. Inc. refinery in Richmond, California. Various federal, state, and local agencies initiated investigations as a result of the incident. Based on its civil investigation, the United States EPA issued a Finding of Violations (FOV) to Chevron on December 17, 2013, which includes 62 findings of alleged noncompliance at the refinery. The majority of these findings relate to the August 2012 fire and alleged violations of chemical-accident-prevention laws, but the FOV also addresses a number of release-reporting issues, some of which are unrelated to the fire. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.
In July 2009, the Hawaii Department of Health (DOH) alleged that Chevron is obligated to pay stipulated civil penalties 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 EPA and the DOH. The company has disputed many of the allegations. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.
As initially disclosed in the 2012 Form 10-K, 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. In December 2012, a settlement agreement was finalized covering 28 of those NOVs for payment of $145,600 in civil penalties. The company reached a settlement agreement with BAAQMD and paid $190,000 in civil penalties to resolve 17 of the remaining NOVs, and the BAAQMD has informed the company that it will not seek penalties for the last two remaining NOVs.
On June 10, 2013, the company received correspondence from the California Air Resources Board regarding an alleged violation of California's Regulation for the Mandatory Reporting of Greenhouse Gas Emissions based on alleged delay in the reporting of emissions data for Chevron's San Joaquin Valley Business Unit. Chevron has reached an agreement-in-principle with the California Air Resources Board under which the company would pay a $328,500 civil penalty to resolve the alleged violations.
The California Air Resources Board (CARB) has alleged that greenhouse gas (GHG) emissions reported by Chevron’s El Segundo Refinery for the 2011 calendar year contained an error in violation of California’s GHG reporting regulation, and that the reporting error resulted in an over-allocation of GHG allowances. The company has reached an agreement-in-
principle with the CARB under which Chevron would pay a $364,500 civil penalty to resolve the alleged violations.
As initially disclosed in the third quarter 2013 Form 10-Q, in July 2013, Chevron Products Company, a division of Chevron U.S.A. Inc., received a NOV from the CARB for the Richmond and Montebello (California) terminals alleging the selling or offering for sale of gasoline containing more than the maximum allowable ethanol content. Resolution of the alleged violation may result in the payment of a civil penalty of $100,000 or more.
On October 18, 2013, the CARB issued a Notice of Violation alleging that Chevron’s San Diego terminal sold gasoline with less than the required detergent content for 34 months from 2010 to 2012. Resolution of the alleged violation may result in the payment of a civil penalty of $100,000 or more.
On December 18, 2013, EPA declared certain renewable fuel credits (also referred to as Renewable Identification Numbers or RINs) generated by E-Biofuel to be invalid. The company previously submitted RINs generated by E-Biofuel for 2012 compliance with federal renewable fuels requirements. Under current EPA policy, the company's earlier submittal of those now-invalid RINs generated by E-Biofuel may result in the payment of a civil penalty of $100,000 or more.
As previously disclosed in the third quarter 2013 Form 10-Q, Chevron U.S.A. Inc. has participated in settlement discussions and received a proposed settlement agreement from the South Coast Air Quality Management District to resolve alleged violations of the El Segundo Refinery's Clean Air Act Title V Operating Permit. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.
The State of New Mexico provided to Chevron a NOV on December 11, 2013, alleging that the flaring of fuel gas that occurred during periodic compressor purging events at the Chevron Buckeye CO2 plant resulted in hourly air emissions during these events in excess of the plant permit limits and alleging that the company had failed to timely report these excess emissions. The resolution of this NOV may result in the payment of a civil penalty of $100,000 or more.
As initially disclosed in the second quarter 2013 Form 10-Q, Chevron Pipe Line Company (CPL) received a NOV from the Utah Division of Water Quality (DWQ) in April 2013 alleging state law violations resulting from a pipeline spill near Willard Bay State Park, Utah. CPL has concluded a settlement agreement with the DWQ and the Utah Department of Natural Resources, State Parks and Recreation Division to resolve these alleged violations, which includes a monetary penalty of $350,000 as well as $5 million for environmentally beneficial mitigation projects and for lost use damages.
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-19.
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, 2013
Nov. 1 - Nov. 30, 2013
Dec. 1 - Dec. 31, 2013
Total Oct. 1 - Dec. 31, 2013
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 or in negotiated transactions at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. As of December 31, 2013, 139,340,805 shares had been acquired under this program (some pursuant to a Rule 10b5-1 plan and some pursuant to accelerated share repurchase plans) for $15 billion at an average price of approximately $108 per share.
Item 6. Selected Financial Data
The selected financial data for years 2009 through 2013 are presented on page FS-58.
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 Instrument Market Risk,” beginning on page FS-13 and in Note 10 to the
Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-34.
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, 2013.
(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 (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2013.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page FS-21.
(c) Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2013, 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.
On May 14, 2013, COSO published an updated Internal Control — Integrated Framework (2013) and related illustrative documents. As of December 31, 2013, the company is utilizing the original framework published in 1992. The transition period for adoption of the updated framework ends December 15, 2014.
Item 9B. Other Information
Item 10. Directors, Executive Officers and Corporate Governance
Executive Officers of the Registrant at February 21, 2014
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.
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 Chairman of the Board and Executive Vice President
Executive Vice President (2005 through 2009)
Vice Chairman of the Board and Executive Vice President
Executive Vice President (since 2006)
Worldwide Refining, Marketing and Lubricants; Chemicals
Executive Vice President (since 2011)
Vice President, Policy, Government and Public Affairs
(2007 through 2011)
Strategy and Planning; Health, Environment and Safety; Policy, Government and Public Affairs; Mining
Senior Vice President, Technology, Projects and Services
Corporate Vice President and President, Gas and Midstream
(2012 through 2013)
Managing Director, Asia South Business Unit (2008 through 2011)
Technology; Project Resources Company; Procurement
Senior Vice President, Upstream (since 2014)
President, Europe, Eurasia and Middle East Exploration and
Production (2011 through 2013)
Managing Director, Eurasia Business Unit
(2008 to 2011)
Worldwide Exploration and Production Activities
Corporate Vice President and President, Gas and Midstream
Managing Director, Asia South Business Unit (2012 through 2013)
Deputy Managing Director, Asia South Business Unit (2011)
Vice President and Treasurer (2009 to 2011)
Worldwide Natural Gas Commercialization; Supply and Trading Activities, including Natural Gas Trading; Shipping; Pipeline; and Power and Energy Services
Vice President and Chief Financial Officer (since 2009)
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 2014 Annual Meeting and 2014 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 2014 Annual Meeting of Stockholders (the “2014 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 2014 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 “Corporate Governance — Business Conduct and Ethics Code” in the 2014 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 “Corporate Governance — Board Committees” in the 2014 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 2014 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 “Corporate Governance — Board Committees” in the 2014 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 “Corporate Governance — Management Compensation Committee Report” in the 2014 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 2014 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 2014 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 2014 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 “Corporate Governance — Transactions with Related Parties” in the 2014 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 “Corporate Governance — Director Independence” in the 2014 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 “Board Proposal to Ratify the Appointment of the Independent Registered Public Accounting Firm” in the 2014 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
(Reductions) 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