UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

☑   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR    

o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-00368

(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code (925) 842-1000

Securities registered pursuant to Section 12 (b) of the Act:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes  ☑           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  ☑

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  ☑           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  ☑           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.   ☑

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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes  o        No  ☑

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 - $247,905,549,754 (As of June 30, 2014 )

Number of Shares of Common Stock outstanding as of February 9, 2015  - 1,880,180,422

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2015 Annual Meeting and 2015 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company's 2015 Annual Meeting of Stockholders (in Part III)

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TABLE OF CONTENTS

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," "may," "could," "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, other natural or human factors, 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 22 through 24 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, 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 plant. 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, 2014 , Chevron had approximately 64,700 employees (including about 3,300 service station employees). Approximately 31,800 employees (including about 3,100 service station employees), or 49 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. Production levels from the members of the Organization of Petroleum Exporting Countries (OPEC) 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.

Operating Environment

Refer to pages FS-2 through FS-9 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 in supply, trading and transportation to enable the success of the upstream and downstream strategies, and to utilize technology across all its businesses to differentiate performance.

Information about the company is available on the company's website at 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 U.S. Securities and Exchange Commission (SEC). The reports are also available on the SEC's website at www.sec.gov .

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, 2014 , and assets as of the end of 2014 and 2013  - for the United States and the company's international geographic areas - are in Note 12 to the Consolidated Financial Statements beginning on page FS-37. Similar comparative data for the company's investments in and income from equity affiliates and property, plant and equipment are in Notes 13 and 14 on pages FS-40 through FS-41. Refer to page FS-13 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 capital and exploratory expenditures.

Upstream

Reserves

Refer to Table V beginning on page FS-65 for a tabulation of the company's proved net liquids (including crude oil, condensate, natural gas liquids and synthetic oil) and natural gas reserves by geographic area, at the beginning of 2012 and each year-end from 2012 through 2014 . 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, 2014 , 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.

At December 31, 2014, 20 percent of the company's net proved reserves were located in Kazakhstan and 19 percent were located in the United States.

The net proved reserve balances at the end of each of the three years 2012 through 2014 are shown in the following table:

* Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of oil.

Net Production of Liquids and Natural Gas

The following table summarizes the net production of liquids and natural gas for 2014 and 2013 by the company and its affiliates. Worldwide oil-equivalent production of 2.571 million barrels per day in 2014 was down 1 percent from 2013 . Production increases in the Permian Basin in Texas and New Mexico and the Marcellus Shale in western Pennsylvania, and project ramp-ups in Nigeria, Argentina and Brazil, were more than offset by normal field declines, production entitlement effects in several locations and the effect of asset sales. Refer to the "Results of Operations" section beginning on page FS-7 for a detailed discussion of the factors explaining the 2012  through 2014 changes in production for crude oil and natural gas liquids, and natural gas, and refer to Table V on pages FS-68 and FS-69 for information on annual production by geographical region.

Production Outlook

The company estimates its average worldwide oil-equivalent production in 2015 will be flat to 3 percent growth compared to 2014. This estimate is subject to many factors and uncertainties, as described beginning on page FS-4. Refer to the "Review of Ongoing Exploration and Production Activities in Key Areas," beginning on page 8, for a discussion of the company's major crude oil and natural gas development projects.

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 2014 , 2013 and 2012 .

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end 2014 for the company and its affiliates:

Acreage

At December 31, 2014 , 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:

Delivery Commitments

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 239 billion cubic feet of natural gas to third parties through 2017 . 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 705 billion cubic feet of natural gas to third parties from 2015 through 2017 from operations in Australia, Colombia, Denmark and the Philippines. These sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The company believes it can satisfy these contracts from quantities available from production of the company's proved developed reserves in these countries.

Development Activities

Refer to Table I on page FS-61 for details associated with the company's development expenditures and costs of proved property acquisitions for 2014 , 2013 and 2012 .

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, 2014 . 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.

Exploration Activities

Refer to Table I on page FS-61 for detail on the company's exploration expenditures and costs of unproved property acquisitions for 2014 , 2013 and 2012 .

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, 2014 . "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.

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron has exploration and production activities in most of the world's major hydrocarbon basins. Chevron's 2014 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-3, 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 as well as 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.

United States

Upstream activities in the United States are primarily located 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 2014 was 664,000 barrels per day.

In California, the company has significant production in the San Joaquin Valley. In 2014, net daily production averaged 163,000 barrels of crude oil, 66 million cubic feet of natural gas and 3,000 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 2014, net daily production in the Gulf of Mexico averaged 133,000 barrels of crude oil, 320 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 2014.

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 is 40.6 percent. 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 as well as third-party tiebacks. First production was achieved in December 2014, and production from three of 10 planned wells ramped-up during first quarter 2015. In addition, front-end engineering and design (FEED) activities continued in 2014 on the second phase of the development plan for the Jack and St. Malo fields, and construction is expected to commence on Stage 2 in 2016. Proved reserves have been recognized for this 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 from the time of start-up.

Construction and commissioning activities for the 60 percent-owned and operated Big Foot Project progressed during 2014, reaching 93 percent complete by year end. The project facilities have a design capacity of 75,000 barrels of crude oil and 25 million cubic feet of natural gas per day. First production is anticipated in late 2015. The field has an estimated production life of 35 years from the time of start-up. Proved reserves have been recognized for this project.

At the 58 percent-owned and operated Tahiti Field, work continued during 2014 on Tahiti 2 – a project that is designed to increase recovery from the main producing interval. The last injection well is expected to be completed in first quarter 2015. Additional infill drilling is scheduled for the Tahiti Field through 2016, with production from the first well expected in second-half 2015. The initial recognition of proved reserves occurred in 2014 for the infill drilling. The Tahiti Field has an estimated remaining production life of at least 20 years.

The company has a 42.9 percent nonoperated working interest in the Tubular Bells Field. First production was achieved in November 2014. Total production is expected to average 58,000 to 67,000 barrels of oil-equivalent per day in 2015. The field has an estimated production life of 25 years from the time of start-up.

The company has a 15.6 percent nonoperated working interest in the Mad Dog Field. The next development phase, the Mad Dog 2 Project, is planned to develop the southern portion of the field. The development plan was re-evaluated in 2013, and FEED was re-entered on a new development concept in third quarter 2014. At the end of 2014, proved reserves had not been recognized for this project.

Chevron holds a 25 percent nonoperated working interest in the Stampede Project, which includes the joint development of the Knotty Head and Pony fields. The planned facilities have a design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas per day. A final investment decision was reached in third quarter 2014. Drilling is planned to commence in fourth quarter 2015 with first oil expected in 2018. The fields have an estimated production life of 30 years from the time of start-up. The initial recognition of proved reserves occurred in 2014 for this project.

FEED activities commenced in early 2015 on a project to jointly develop the 55 percent-owned and operated Buckskin Field and the 87.5 percent-owned and operated Moccasin Field, which are located 12 miles apart. The development plan includes a subsea tieback to a third-party production facility with 30,000 barrels of crude oil and 15 million cubic feet of natural gas per day of firm capacity and rights to additional available capacity. A final investment decision is expected in 2016. At the end of 2014, proved reserves had not been recognized for this project.

In early 2015, the company announced a joint venture to explore and appraise 24 jointly held offshore leases in the northwest portion of Keathley Canyon. Chevron will be the operator. The joint venture includes the Tiber and Gila discoveries and the Gibson exploratory prospect, located between Gila and Tiber. The company acquired a 36 percent interest in the Gila leases and a 31 percent interest in the Tiber leases and also holds a 36 percent interest in the Gibson prospect. The scope of the joint venture includes further exploration and appraisal of the leases and evaluation of the potential for a centralized production facility. Separately, during 2014, the company exchanged its interest in the Coronado prospect for interests in other prospective deepwater exploration opportunities.

During 2014 and early 2015, the company participated in four appraisal wells and eight exploration wells in the deepwater Gulf of Mexico. An appraisal well and a sidetrack were completed at the Buckskin Field in 2014, and results are under evaluation. In October 2014, the company completed drilling an exploration well at the 42.5 percent-owned and operated Guadalupe prospect, which resulted in a significant crude oil discovery in the Lower Tertiary Wilcox Sands, adjacent to Keathley Canyon. Drilling at the 55 percent-owned and operated Anchor prospect was completed in December 2014, resulting in a significant crude oil discovery, also in the Lower Tertiary Wilcox Sands. In late 2014, drilling commenced on an appraisal well of the Tiber discovery as well as on a sidetrack of the Gila discovery well, and drilling is expected to continue until mid-2015. In January 2015, drilling commenced at the 40 percent-owned and operated Sweetwater and the 50 percent-owned and operated Sicily exploration wells, and both wells are expected to be completed in second quarter 2015.

In addition, Chevron added eleven leases to its deepwater portfolio as a result of awards from Gulf of Mexico lease sales held in 2014.

The company produces crude oil and natural gas in the midcontinent region of the United States, primarily in Colorado, New Mexico, Oklahoma, Texas and Wyoming. During 2014, the company's net daily production in these areas averaged 110,000 barrels of crude oil, 595 million cubic feet of natural gas and 31,000 barrels of NGLs.

In the Permian Basin of West Texas and southeast New Mexico, the company continued to ramp-up development of shale and tight resources with drilling activities focused in the Midland and Delaware basins where the company holds approximately 500,000 and 1,000,000 net acres, respectively. The company drilled 550 wells in the Midland and Delaware basins in 2014.

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 2014, the company's net daily production in these areas averaged 269 million cubic feet of natural gas. In 2014, development of the Marcellus Shale continued at a measured pace, focused on improving execution capability and reservoir understanding. Activities in the Utica Shale during 2014 focused on exploration drilling to acquire data necessary for potential future development.

Other Americas

"Other Americas" includes Argentina, Brazil, Canada, Colombia, Greenland, Suriname, Trinidad and Tobago, and Venezuela. Net oil-equivalent production from these countries averaged 228,000 barrels per day during 2014.

Canada: Upstream activities in Canada are concentrated in Alberta, British Columbia and the offshore Atlantic region. The company also has exploration interests in the Beaufort Sea region of the Northwest Territories. Average net oil-equivalent production during 2014 was 69,000 barrels per day, composed of 24,000 barrels of crude oil, 10 million cubic feet of natural gas and 43,000 barrels of synthetic oil from oil sands.

Chevron holds a 26.9 percent nonoperated working interest in the Hibernia Field, which comprises the Hibernia and Ben Nevis Avalon (BNA) reservoirs, and a 23.6 nonoperated working interest in the unitized Hibernia Southern Extension (HSE) areas offshore Atlantic Canada. In 2014, work continued on HSE development, and full production start-up is planned for 2015. Proved reserves have been recognized for this project. In addition, FEED activities progressed on the Hibernia SW BNA project. At the end of 2014, proved reserves had not 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 platform with a design capacity of 150,000 barrels of crude oil per day. Construction activities progressed in 2014. The project has an expected economic life of 30 years from the time of start-up, and first oil is expected in 2017. Proved reserves have been recognized for this project.

The company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) in Alberta. 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 2014 on the Quest Project, which is designed to capture and store more than one million tons of carbon dioxide produced annually by AOSP bitumen processing. Project start-up is expected in 2016.

The company holds approximately 228,000 net acres in the Duvernay Shale in Alberta and approximately 200,000 overlying acres in the Montney tight rock formation. Chevron has a 70 percent-owned and operated interest in most of the Duvernay acreage after completing a 30 percent farm-down in 2014. Production from the initial multiwell program in the Duvernay continued during 2014, and drilling activities began on an expanded 16-well appraisal program. A total of twelve wells had been tied into production facilities by early 2015.

Chevron holds a 50 percent-owned and operated interest in the proposed Kitimat LNG and Pacific Trail Pipeline projects and a 50 percent interest in 322,000 net acres in the Horn River and Liard shale gas basins in British Colombia. The Kitimat LNG Project is planned to include a two-train LNG facility and has a 10.0 million-metric-ton-per-year export license. The total production capacity for the project is expected to be 1.6 billion cubic feet of natural gas per day. Spending is being paced until LNG market conditions and reductions in project costs are sufficient to support the development of this project. At the end of 2014, proved reserves had not been recognized for this project.

The company holds a 40 percent nonoperated working interest in exploration rights for two blocks in the Flemish Pass Basin offshore Newfoundland.

Greenland: Chevron holds a 29.2 percent-owned and operated interest in Blocks 9 and 14 located in the Kanumas Area, offshore the northeast coast of Greenland. The acquisition of 2-D seismic data commenced in third quarter 2014 and is expected to continue over the next few years.

Argentina: In the Vaca Muerta Shale formation, Chevron holds a 50 percent nonoperated interest in two concessions covering 73,000 net acres. Chevron also holds an 85 percent-owned and operated interest in one concession covering 94,000 net acres with both conventional production and Vaca Muerta Shale potential. In addition, the company holds operated interests in three concessions covering 73,000 net acres in the Neuquen Basin, with interests ranging from 18.8 percent to 100 percent. Net oil-equivalent production in 2014 averaged 25,000 barrels per day, composed of 21,000 barrels of crude oil and 23 million cubic feet of natural gas.

Development activities continued at the Loma Campana concession in the Vaca Muerta Shale where 166 wells were drilled in 2014, and the 2015 drilling plan includes approximately 150 wells. In 2014, the company also continued production testing of four previously completed exploratory wells in the El Trapial concession, targeting oil and gas in the Vaca Muerta Shale. The El Trapial concession expires in 2032.

During 2014, the company signed agreements for exploration of shale oil and gas resources in the Narambuena area in the Chihuido de la Sierra Negra concession, also in the Vaca Muerta Shale. The exploration plan for Narambuena includes nine wells to be drilled in two phases.

Brazil: Chevron holds 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). The concession that includes the Frade Field expires in 2025 and the concession that includes the Papa-Terra and Maromba fields expires in 2032. Net oil-equivalent production in 2014 averaged 21,000 barrels per day, composed of 20,000 barrels of crude oil and 6 million cubic feet of natural gas.

Following the resumption of production from four wells at the Frade Field during 2013, production resumed at the remaining six wells in second quarter 2014. At Papa-Terra, production is expected to ramp up through 2017 with additional development drilling until 2021.

Additionally, Chevron holds a 50 percent-owned and operated interest in Block CE-M715, located in the Ceara Basin offshore equatorial Brazil. Acquisition of 3-D seismic data is planned to commence in second quarter 2015.

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 186 million cubic feet of natural gas in 2014.

Suriname: Chevron holds a 50 percent nonoperated working interest in Blocks 42 and 45 offshore Suriname. In 2014, 2-D and 3-D seismic data for both blocks were processed. Farm-down opportunities are being pursued for the two blocks.

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 2014 averaged 112 million cubic feet of natural gas per day.

At the Starfish development, first gas was achieved in December 2014, and two additional wells are planned to be brought online in second quarter 2015. Natural gas from the project is planned to supply existing contractual commitments. Chevron also operates and holds a 50 percent 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. Work continued in 2014 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 under an agreement expiring in 2033. Chevron also holds 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, both of which are under agreements expiring in 2026. The company's share of net oil-equivalent production during 2014 from these operations averaged 63,000 barrels per day, composed of 59,000 barrels of liquids and 27 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. The company also 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. Work continued in 2014 on maturing commercial development concepts.

Africa

In Africa, the company is engaged in upstream activities in Angola, Democratic Republic of the Congo, Liberia, Mauritania, Morocco, Nigeria, Republic of the Congo, Sierra Leone and South Africa. Net oil-equivalent production in this region averaged 439 , 000 barrels per day during 2014.

Angola:  The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline, and a 31 percent interest in a production-sharing contract (PSC) for deepwater Block 14. The concession for Block 0 extends through 2030 and the development and production rights for the various producing fields in Block 14 expire between 2023 and 2028. The company also has a 16.3 percent nonoperated working interest in the onshore Fina Sonangol Texaco concession area. Chevron's interest in Block 2 expired in July 2014. In addition, Chevron has a 36.4 percent interest in Angola LNG Limited. During 2014, net production from these operations averaged 114,000 barrels of liquids and 78 million cubic feet of natural gas per day.

Construction activities on Mafumeira Sul, the second development stage for the Mafumeira Field in Block 0, progressed in 2014. 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 2016, and ramp-up to full production is expected to continue through 2017. Proved reserves have been recognized for this project.

Work continued in 2014 on the Nemba Enhanced Secondary Recovery Stage 1 & 2 Project in Block 0. Installation of the platform was completed in early 2014, and start-up of the project is expected in early 2015. Total daily production is expected to be 9,000 barrels of crude oil. Proved reserves have been recognized for this project.

Also in Block 0, the company drilled one post-salt appraisal well in Area B and one pre-salt exploration well in Area A, which completed drilling in early 2015. As of early 2015, the results of both wells were under evaluation. One additional exploration well in Area A is planned to commence drilling in fourth quarter 2015.

In addition to the exploration and production activities, Angola LNG Limited operates an onshore natural gas liquefaction plant in Soyo, Angola. The plant has the 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. In April 2014, the plant experienced a failure in the flare blowdown piping system, resulting in an extended plant shutdown. Following a thorough review, a number of design issues have been identified that require modifications. Capacity and reliability enhancements are also planned to be completed during the shutdown. The plant will be restarted following completion of these modifications and repairs, and LNG production is expected to resume in late 2015. The remaining economic life of the project is anticipated to be 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 2014, with commissioning and start-up targeted for second-half 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 Republic of the Congo. The Lianzi Project has a design capacity of 46,000 barrels of crude oil per day. Construction and drilling activities progressed during 2014, and first production is planned for fourth quarter 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 2014 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. Net production averaged 14,000 barrels of liquids per day in 2014.

During 2014, work continued on the Moho Nord Project, located in the Moho-Bilondo development area. First production to the existing Moho-Bilondo FPU is expected in 2015, and total daily production of 140,000 barrels of crude oil is expected in 2017. Proved reserves have been recognized for this project .

In 2014, the company acquired a 20.4 percent nonoperated working interest in the Haute Mer B permit area, which covers more than 20,000 net acres offshore Republic of the Congo.

Chad/Cameroon:  In June 2014, the company sold its 25 percent interest in seven crude oil fields in southern Chad and an approximate 21 percent interest in two affiliates that own the related crude oil export pipeline to the coast of Cameroon. Average daily net crude oil production from the Chad fields in 2014 was 8,000 barrels.

Liberia:  Chevron operates and holds a 45 percent interest in three deepwater blocks off the coast of Liberia. In 2014, Chevron requested, and the government of Liberia granted, a one-year extension of the LB-11 and LB-12 blocks.

Sierra Leone: The company is the operator of and holds a 55 percent interest in a concession off the coast of Sierra Leone that contains two deepwater blocks. In 2014, 2-D seismic processing was completed to identify drilling prospects.

Mauritania: In early 2015, the company reached an agreement to acquire a 30 percent nonoperated working interest in the C8, C12 and C13 contract areas offshore Mauritania. The blocks cover 2 million net acres and have a water depth between 5,000 and 10,000 feet. The acquisition is pending government approval.

Morocco: The company operates and holds a 75 percent interest in three deepwater areas offshore Morocco. The acquisition of 2-D seismic data was completed in 2014, and a 3-D seismic survey is planned for 2015. Chevron is pursuing a farm-down of its interest.

Nigeria:  Chevron holds a 40 percent interest in nine operated concessions, predominantly in the onshore and near-offshore regions of the Niger Delta. The company also holds acreage positions in three operated and six nonoperated deepwater blocks, with working interests ranging from 20 percent to 100 percent. The company is pursuing selected opportunities for divestment and farm-down in Nigeria. In 2014, the company's net oil-equivalent production in Nigeria averaged 286,000 barrels per day, composed of 240,000 barrels of crude oil, 236 million cubic feet of natural gas and 6,000 barrels of liquefied petroleum gas.

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 2014, drilling continued on a second phase development program, Agbami 2, that is expected to offset field declines and maintain a total daily liquids production rate of 250,000 barrels. The third development phase, Agbami 3, is also expected to offset field declines. The project entered FEED in early 2014, and drilling for this phase commenced in early 2015. The drilling programs for Agbami 2 and Agbami 3 are scheduled to end in 2015 and 2017, respectively. The first Phase 3 development well is scheduled to commence production in 2016. The leases that contain the Agbami Field expire in 2023 and 2024. Proved reserves have been recognized for the Agbami 3 Project.

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. Chevron holds a 19.6 percent nonoperated working interest in the unitized area. The planned facilities have a design capacity of 225,000 barrels of crude oil per day. A final investment decision is expected in 2015 or 2016 . At the end of 2014, no proved reserves were recognized for this project.

In the Niger Delta region, ramp-up activity continued at the Escravos Gas Plant (EGP). During 2014, 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 2014 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 2017. Proved reserves have been recognized for the project.

Chevron is the operator of a 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. The facility achieved initial production of product in mid-2014.

In deepwater exploration, Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery in OML 140, where drilling commenced on an exploration well at the Nsiko North prospect in fourth quarter 2014. Additional exploration activities are planned for 2015. In addition, Chevron holds a 30 percent nonoperated working interest in OML 138. In 2014, two exploration wells were drilled in the Usan area that resulted in crude oil discoveries. In 2015, the company plans to evaluate development options.

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 the western Niger Delta continued in 2014. Acquisition of 3-D seismic data over the Meren and Okan fields is planned for 2015.

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.

South Africa: In 2014, the company continued evaluating 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.

Asia

In Asia, the company is engaged in upstream activities in Azerbaijan, Bangladesh, 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 2014, net oil-equivalent production averaged 1,063,000 barrels per day.

Azerbaijan:  Chevron holds an 11.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC) and the crude oil production from the Azeri-Chirag-Gunashli (ACG) fields. The company's daily net production in 2014 averaged 28,000 barrels of oil-equivalent, composed of 26,000 barrels of crude oil and 12 million cubic feet of natural gas. AIOC operations are conducted under a PSC that expires in 2024.

The Chirag Oil Project is further developing the Chirag and 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. Production commenced in January 2014 and reached 84,000 barrels of crude oil and 87 million cubic feet of natural gas per day by year-end 2014.

Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) Pipeline affiliate, which transports the majority of ACG production 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. 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 has a 50 percent interest in the Tengizchevroil (TCO) affiliate and an 18 percent nonoperated working interest in the Karachaganak Field. Net oil-equivalent production in 2014 averaged 367,000 barrels per day, composed of 290,000 barrels of liquids and 460 million cubic feet of natural gas.

TCO is developing the Tengiz and Korolev crude oil fields in western Kazakhstan under a concession agreement that expires in 2033. Net daily production in 2014 from these fields averaged 239,000 barrels of crude oil, 334 million cubic feet of natural gas and 20,000 barrels of NGLs. 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 2014, work progressed on 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 FGP is planned to expand the utilization of sour gas injection technology proven in existing operations. The final investment decision for the CAR Project was reached in February 2014. The final investment decisions for the FGP and the WPMP are anticipated in 2015. Proved reserves have been recognized for the WPMP and the CAR Project .

The Karachaganak Field is located in northwest Kazakhstan, and operations are conducted under a PSC that expires in 2038. During 2014, net daily production averaged 31,000 barrels of liquids and 126 million cubic feet of natural gas. Access to the CPC and Atyrau-Samara (Russia) pipelines enabled most of the Karachaganak liquids to be exported and sold at world-market prices during 2014. The remaining liquids were sold into local and Russian markets.

Kazakhstan/Russia:  Chevron has a 15 percent interest in the CPC affiliate. During 2014, CPC transported an average of 865,000 barrels of crude oil per day, composed of 763,000 barrels per day from Kazakhstan and 102,000 barrels per day from Russia. In 2014, work continued on the 670,000-barrel-per-day expansion of the pipeline capacity. The project is being implemented in phases, with capacity increasing progressively until reaching a design capacity of 1.4 million barrels per day in 2016. By the end of 2014, capacity from Kazakhstan had been increased by a maximum of 230,000 barrels per day, and in December, nearly 90 percent of TCO's total production was exported via CPC. Additional capacity is expected to progressively come on line in 2015 and 2016. The expansion is expected to provide additional transportation capacity that accommodates a portion of the future growth in TCO production.

Bangladesh:  Chevron operates and holds a 100 percent interest in 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 2014 averaged 109,000 barrels per day, composed of 643 million cubic feet of natural gas and 2,000 barrels of condensate.

First production was achieved in late 2014 at the Bibiyana Expansion Project, which has an incremental design capacity of 300 million cubic feet of natural gas and 4,000 barrels of condensate per day. The expected economic life of the project is the duration of the PSC. FEED activities continued on the Bibiyana Compression Project during 2014. The project is expected to provide incremental production to offset field declines. A final investment decision is pending commercial negotiations. At the end of 2014, proved reserves had not been recognized for this project.

Cambodia:  In October 2014, Chevron completed the sale of its 30 percent interest in Block A, located in the Gulf of Thailand.

China:  Chevron has operated and nonoperated working interests in several areas in China. The company's net production in 2014 averaged 16,000 barrels of crude oil per day.

The company operates and holds a 49 percent interest in the Chuandongbei Project, 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. In 2014, the company continued construction on the first natural gas processing plant and development of the Luojiazhai and Gunziping natural gas fields. The first plant's initial three trains have a design outlet capacity of 258 million cubic feet per day. The first train reached mechanical completion in late 2014, and commissioning activities were initiated. Start-up is expected in 2015. The total design outlet capacity for the project is 558 million cubic feet per day. Proved reserves have been recognized for the natural gas fields supplying the first sour gas processing plant. The project's estimated economic life exceeds 20 years from start-up. The PSC for Chuandongbei expires in 2038.

Chevron has a 100 percent-owned and operated interest in shallow-water Blocks 15/10 and 15/28 in the South China Sea. In 2014, the company completed processing of two 3-D seismic surveys and plans to drill one exploration well in Block 15/10 in 2015. In May 2014, the company relinquished its interest in deepwater exploration Block 42/05.

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. The PSCs for these producing assets expire between 2022 and 2028.

Indonesia:  Chevron holds working interests through various PSCs in Indonesia. In Sumatra, the company holds a 100 percent-owned and operated interest in the Rokan PSC. Chevron also operates four PSCs in the Kutei Basin, located offshore eastern Kalimantan. These interests range from 62 percent to 92.5 percent. In addition, Chevron holds a 25 percent nonoperated working interest in Block B in the South Natuna Sea. The company's net oil-equivalent production in 2014 from its interests in Indonesia averaged 185,000 barrels per day, composed of 149,000 barrels of liquids and 214 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. Production ramp-up continued and first steam injection was achieved in 2014 at the steamflood expansion project in Area 13 of the Duri Field. The Rokan PSC expires in 2021.

There are two deepwater natural gas development projects in the Kutei Basin progressing under a single plan of development. Collectively, these projects are referred to as the Indonesia Deepwater Development. One of these projects, Bangka, has a design capacity of 115 million cubic feet of natural gas and 4,000 barrels of condensate per day. The company's interest is 62 percent. A final investment decision was reached in 2014, following government approvals. Project execution began with the drilling of two development wells in second-half 2014. First gas is planned for 2016. The initial recognition of proved reserves occurred in 2014 for this project.

The other project, Gendalo-Gehem, has a planned design capacity of 1.1 billion cubic feet of natural gas and 47,000 barrels of condensate per day. The company's interest is approximately 63 percent. The company continues to work toward a final investment decision, subject to the timing of government approvals, rebidding of the engineering and construction contracts, extension of the associated PSCs, and securing new LNG sales contracts. At the end of 2014, proved reserves had not been recognized for this project.

Chevron relinquished its 51 percent-owned and operated interest in the West Papua I and West Papua III PSCs. Government approval for the relinquishment is anticipated in 2015.

In West Java, the company operates the Darajat geothermal field and holds a 95 percent interest in two power plants. The field 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 six-unit power plant, three of which are company owned, with a total operating capacity of 377 megawatts. The company relinquished its 95 percent interest in the Suoh-Sekincau prospect area of South Sumatra. In 2014, Chevron secured the preliminary survey assignment for the adjacent South Sekincau prospect and is in the early phases of geological and geophysical assessment.

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 2014 was 99 million cubic feet per day.

In March 2014, Chevron was granted a 99 percent interest in and operatorship of Block A5. The exploration block covers 2.6 million net acres. As of early 2015, PSC terms were being finalized.

Philippines:  The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field, offshore Palawan. Net oil-equivalent production in 2014 averaged 23,000 barrels per day, composed of 118 million cubic feet of natural gas and 3,000 barrels of condensate. The Malampaya Phase 2 Project is designed to maintain capacity at the offshore platform. First production from the infill wells commenced in 2013, with first production from the compression facilities expected in second-half 2015. Proved reserves have been recognized for this project.

Chevron holds a 40 percent interest in an affiliate that develops and produces steam resources in southern Luzon, which supplies steam to third-party power generation facilities with a combined operating capacity of 692 megawatts. The renewable energy service contract expires in 2038. Chevron also has an interest in the Kalinga geothermal prospect area in northern Luzon. The company continues to assess the prospect area.

Thailand:  Chevron holds operated interests in the Pattani Basin, located in the Gulf of Thailand, with ownership 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. The company's net oil-equivalent production in 2014 averaged 238,000 barrels per day, composed of 63,000 barrels of crude oil and condensate and 1 billion cubic feet of natural gas.

In the Pattani Basin, FEED activities continued for the 35 percent-owned and operated Ubon Project in Block 12/27. The development concept includes facilities with a planned design capacity of 35,000 barrels of liquids and 115 million cubic feet of natural gas per day. At the end of 2014, proved reserves had not been recognized for this project.

During 2014, the company drilled six exploration wells in the Pattani Basin, and four were successful. The company also holds exploration interests in the Thailand-Cambodia overlapping claim area that are inactive, pending resolution of border issues between Thailand and Cambodia.

Vietnam: Chevron is the operator of two PSCs in the Malay Basin off the southwest coast of Vietnam. The company has a 42.4 percent interest in a PSC that includes Blocks B and 48/95 and a 43.4 percent interest in a PSC for Block 52/97.

The Block B Gas Development Project facilities have a planned 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 2014, proved reserves had not been recognized for the development project.

Kurdistan Region of Iraq: The company operates and holds 80 percent contractor interests in three PSCs covering the Rovi, Sarta and Qara Dagh blocks. Initial drilling operations in the Rovi and Sarta blocks continued to progress in 2014, and the results are under evaluation. The company also commenced 3-D and 2-D seismic acquisition programs in the Sarta and Qara Dagh blocks, respectively. In August 2014, all activities were temporarily suspended as a result of ongoing regional instability. In early 2015, mobilization of personnel back to the region commenced in preparation to restart operations in first quarter. Farm-down opportunities are being pursued for the three blocks.

Partitioned Zone:  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 Partitioned Zone between Saudi Arabia and Kuwait. The concession expires in 2039. During 2014, the company's average net oil-equivalent production was 81,000 barrels per day, composed of 78,000 barrels of crude oil and 18 million cubic feet of natural gas. Current difficulties in securing work and equipment permits may impact the company's ability to continue production at current levels.

During 2014, the company continued a steam injection pilot project in the First Eocene carbonate reservoir. Proved reserves have been recognized for this project.

FEED activities continued on a project to expand the steam injection pilot to the Second Eocene reservoir, and a final investment decision is planned for 2016. 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 third quarter 2015. At the end of 2014, proved reserves had not been recognized for these steamflood developments.

The Central Gas Utilization Project is intended to increase natural gas utilization and eliminate routine flaring at the Wafra Field. As of early, 2015, the development plan is being re-evaluated. At year-end 2014, proved reserves had not been recognized for this project.

In June 2014, the company began a 3-D seismic survey covering the entire onshore Partitioned Zone.

Australia/Oceania

In Australia/Oceania, the company is engaged in upstream activities in Australia and New Zealand. During 2014, net oil-equivalent production averaged 97,000 barrels per day, all from Australia.

Australia: Upstream activities in Australia are concentrated offshore Western Australia, where the company is the operator of two major LNG projects, Gorgon and Wheatstone, and has a nonoperated working interest in the North West Shelf (NWS) Venture and exploration acreage in the Browse Basin and the Carnarvon Basin. The company also holds exploration acreage in the Nappamerri Trough in central Australia and the Bight Basin offshore South Australia. During 2014, the company's production averaged 23,000 barrels of crude oil and 442 million cubic feet of natural gas per day. Most of this production was from the NWS Venture.

Chevron holds a 47.3 percent interest and is the operator of the Gorgon Project, which includes the development of the Gorgon and nearby Jansz-Io fields. The project includes a three-train, 15.6 million-metric-ton-per-year LNG facility, a carbon dioxide injection facility and a domestic natural gas plant, which are located on Barrow Island, off Western Australia. 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. Work continued during 2014 with 88 percent of the overall project complete at year-end. LNG Train 1 start-up is planned for third quarter 2015, with first cargo anticipated in fourth quarter 2015. Start-up of Trains 2 and 3 is expected in 2016. 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.

In January 2015, the company announced an additional binding sales agreement for delivery of LNG from the Gorgon Project for a five-year period starting in 2017. During the time of this agreement, more than 75 percent of Chevron's equity LNG offtake from the project is committed under binding sales agreements with customers in Asia. 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, and the company continues to market additional pipeline natural gas quantities from the project.

The evaluation of options to increase the production capacity of Gorgon is planned to continue in 2015.

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, both located at Ashburton North, on the coast of Western Australia. The company plans to supply natural gas to the facilities from the Wheatstone and Iago fields. Chevron holds an 80.2 percent interest in the offshore licenses and a 64.1 percent interest in the LNG facilities. The 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. The project was 53 percent complete at year-end. Start-up of the first train is expected in late 2016, with the second train start-up planned for 2017. 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.

As of year-end 2014, Chevron had binding, long-term sales agreements with four customers in Japan for 85 percent of the company's equity LNG offtake from this project. In addition, the company continues to market its equity share of pipeline natural gas to Western Australia customers.

During 2014, the company made five natural gas discoveries in the Carnarvon Basin. These discoveries contribute to the resources available to extend and expand Chevron's LNG projects in the region.

Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. Approximately 80 percent of the natural gas sales were 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.

T he company holds nonoperated working interests ranging from 24.8 percent to 50 percent in three blocks in the Browse Basin. Drilling in third quarter 2014 resulted in a natural gas discovery at the Lasseter prospect in Block WA-274-P.

In the Nappamerri Trough, the company holds a 30 percent nonoperated working interest in the Permian section of PRL 33-49 in South Australia and an 18 percent nonoperated working interest in ATP 855 in Queensland. During 2014, exploration drilling and flow testing continued in order to evaluate the commerciality of the resource base. Pending favorable results, Chevron could earn a 60 percent nonoperated working interest in PRL 33-49 and a 36 percent nonoperated working interest in ATP 855.

The company operates and holds a 100 percent working interest in offshore Blocks EPP44 and EPP45 in the Bight Basin off the South Australian coast. In 2014, the company completed the initial survey to acquire 3-D seismic data, and an additional survey and data processing are planned to continue through 2016.

New Zealand: In late 2014, Chevron was granted three exploration permits in the offshore Pegasus and East Coast basins. The deepwater permits cover 3.1 million net acres and are located approximately 100 miles east of Wellington. Chevron will be the operator with a 50 percent interest. The exploration permits are granted for a term of 15 years, commencing April 2015. Acquisition of 2-D and 3-D seismic data is scheduled to commence in 2016.

Europe

In Europe, the company is engaged in upstream activities in Denmark, Norway, Poland, Romania, and the United Kingdom. Net oil-equivalent production in the region averaged 80,000 barrels per day during 2014.

Denmark:  Chevron holds a 12 percent nonoperated working interest in the Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 North Sea fields. Net oil-equivalent production in 2014 from the DUC averaged 25,000 barrels per day, composed of 17,000 barrels of crude oil and 51 million cubic feet of natural gas. The concession expires in 2042.

Lithuania: Chevron divested its 50 percent interest in an exploration and production company in mid-2014.

Netherlands:  In November 2014, Chevron divested its upstream interests in the Dutch sector of the North Sea. Net oil-equivalent production in 2014 was 7,000 barrels per day, composed of 2,000 barrels of crude oil and 34 million cubic feet of natural gas.

Norway: In August 2014, the company completed the sale of its interest in the Draugen Field. Net production averaged 1,000 barrels of oil-equivalent per day during 2014. Chevron is the operator and has a 40 percent interest in exploration licenses PL 527 and PL 598. Both licenses are in the deepwater portion of the Norwegian Sea.

Poland:  In first-half 2014, Chevron completed a 3-D seismic survey on the Grabowiec concession. The company also entered into a joint exploration agreement covering Chevron's Grabowiec and Zwierzyniec licenses and two adjacent licenses in early 2014. In fourth quarter 2014, Chevron relinquished two shale concessions (Frampol and Krasnik) in southeastern Poland. In early 2015, Chevron announced the discontinuation of exploration activities in Poland.

Romania:  In 2014, drilling of the first exploration well in the Barlad Shale concession in northeast Romania was completed, as was a 2-D seismic survey across two of the three concessions in southeast Romania. Chevron intends to pursue relinquishment of its interest in these concessions in 2015.

Ukraine: In 2013, Chevron signed a PSC with the government of Ukraine for a 50 percent interest and operatorship of the Oleska Shale block in western Ukraine. In fourth quarter 2014, Chevron terminated the agreement.

United Kingdom:  The company's average net oil-equivalent production in 2014 from nine offshore fields was 47,000 barrels per day, composed of 32,000 barrels of liquids and 88 million cubic feet of natural gas. Most of the company's 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.

The 73.7 percent-owned and operated Alder Project is being developed as a tie-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. Fabrication of topside and subsea equipment progressed in 2014, and first production is expected in 2016. Proved reserves have been recognized for this project.

The Captain Enhanced Oil Recovery Project is the next development phase of the Captain Field and is designed to increase field recovery. The project entered FEED in fourth quarter 2014, and a final investment decision is scheduled for 2016. At the end of 2014, proved reserves had not been recognized for this project.

During 2014, procurement and fabrication activities continued 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. The design capacity of the project is 120,000 barrels of crude oil and 100 million cubic feet of natural gas per day. Production is scheduled to begin in 2017. The Clair Field has an estimated production life until 2050. 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 continued to assess alternatives for the optimum development of the Rosebank Field and made significant progress in optimizing the Rosebank development plan. The design capacity of the project is 100,000 barrels of crude oil and 80 million cubic feet of natural gas per day. At the end of 2014, proved reserves had not been recognized for this project.

West of the Shetland Islands, exploration activities included acquisition and interpretation of 3-D seismic data. In the central North Sea, an exploration well previously drilled to delineate the southern extension of the Jade Field was successfully tied back and first production was achieved.

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 supply and trading activities.

During 2014 , U.S. and international sales of natural gas were 4.0  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 141,000 and 86,000 barrels per day, respectively, in 2014 . Substantially all of the international sales of natural gas liquids from the company's producing interests are from operations in Africa, Canada, Indonesia and the United Kingdom.

Refer to "Selected Operating Data," on page FS-11 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" beginning on page 6 for information related to the company's delivery commitments for the sale of crude oil and natural gas.

Downstream

Refining Operations

At the end of 2014 , the company had a refining network capable of processing nearly 2 million barrels of crude oil per day. Operable capacity at December 31, 2014 , and daily refinery inputs for 2012 through 2014 for the company and affiliate refineries are summarized in the table below.

Average crude oil distillation capacity utilization during 2014 was 87 percent, compared with 84 percent in 2013 . At the U.S. refineries, crude oil distillation capacity utilization averaged 91 percent in 2014 , compared with 81 percent in 2013 . Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 73 percent and 76 percent of Chevron's U.S. refinery inputs in 2014 and 2013 , respectively.

At the Pascagoula Refinery, the 25,000 barrels-per-day premium base oil plant began commercial production in third quarter 2014. Elsewhere, work continued during 2014 on projects to improve refinery flexibility, reliability and capability to process lower cost feedstocks. A project to replace the atmospheric distillation column and other related equipment at the Salt Lake City Refinery was completed in mid-2014, resulting in improved plant reliability and feedstock flexibility. At the El Segundo Refinery, a project to replace six end-of-life coke drums was also completed during the year. At the Richmond, California refinery, a modernization project progressed, with certification of the Environmental Impact Report and approval of a conditional use permit by the Richmond City Council in July 2014. The company is now seeking to secure the further necessary approvals to resume construction. In addition, Chevron is evaluating the Hawaii refinery and related assets for possible divestment.

Outside the United States, Caltex Australia Ltd., a 50 percent-owned affiliate, completed the conversion of the Kurnell, Australia, refinery to an import terminal in fourth quarter 2014. During 2014, Singapore Refining Company, Chevron's 50 percent-owned joint venture, initiated construction of a gasoline desulfurization facility and a cogeneration plant. The investment is expected to increase the refinery's capability to produce higher value gasoline and to improve energy efficiency.

Petroleum Refineries: Locations, Capacities and Inputs

Marketing Operations

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, 2014 .

Refined Products Sales Volumes

In the United States, the company markets under the Chevron and Texaco brands. At year-end 2014 , the company supplied directly or through retailers and marketers approximately 7,930 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 380 of these outlets are company-owned or -leased stations.

Outside the United States, Chevron supplied directly or through retailers and marketers approximately 8,450 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 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 113 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the product names Havoline, Delo, Ursa, Meropa, Rando, Clarity and Taro in the United States and worldwide under the three brands: Chevron, Texaco and Caltex.

Chemicals Operations

Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) affiliate. CPChem produces olefins, polyolefins and alpha olefins and is a supplier of aromatics and polyethylene pipe, in addition to participating in the specialty chemical and specialty plastics markets. At the end of 2014 , CPChem owned or had joint-venture interests in 34 manufacturing facilities and two research and development centers around the world.

In second quarter 2014, CPChem completed commissioning and started commercial operation of a 1-hexene plant with a design capacity of 250,000 metric tons per year at the Cedar Bayou Plant in Baytown, Texas and, in fourth quarter 2014, CPChem began commercial operations of a 90,000 metric-ton-per-year expansion of ethylene production at its Sweeny complex located in Old Ocean, Texas. In early 2014, construction commenced on the U.S. Gulf Coast Petrochemicals Project, which is expected to capitalize on advantaged feedstock sourced from shale gas development in North America. The 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 facility and two polyethylene units to be located in Old Ocean, Texas, with a combined annual design capacity of one million metric tons. Start-up is expected in 2017.

Chevron Oronite Company develops, manufactures and markets performance additives for lubricating oils and fuels and conducts research and development for additive component and blended packages. At the end of 2014, the company manufactured, blended or conducted research at 10 locations around the world. In 2014, the company completed expansion projects at its manufacturing facilities in Singapore and Gonfreville, France. In addition, a final investment decision was reached in fourth quarter 2014 to build a carboxylate plant in Singapore, which is expected to be completed in 2017.

Chevron also maintains a role in the petrochemical business through the operations of GS Caltex, a 50 percent-owned affiliate. GS Caltex manufactures aromatics, including benzene, toluene and xylene. These are base chemicals used to produce a range of products, including adhesives, plastics and textile fibers. GS Caltex also produces polypropylene, which is used to make food packaging, laboratory equipment and textiles.

Transportation

Pipelines:  Chevron owns and operates a network of crude oil, natural gas, natural gas liquid, refined product and chemical pipelines and other infrastructure assets in the United States. In addition, Chevron operates pipelines for its 50 percent-owned CPChem affiliate. The company also has direct and indirect interests in other U.S. and international pipelines.

During 2014, the company continued to optimize its portfolio of pipeline and infrastructure assets. Net pipeline mileage at the end of 2014 was 5,548, a reduction of 4,524 miles from 2013, mainly due to asset sales. Also in 2014, Chevron completed construction of a 136-mile, 24-inch crude oil pipeline from the 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. Pipeline operations began with start-up of the production facilities in late 2014.

Refer to pages 13 and 14 in the Upstream section for information on the West African Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.

Shipping:  The company's marine fleet includes both U.S. and foreign-flagged vessels. The U.S.-flagged vessels are engaged primarily in transporting refined products, primarily 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, as well as refined products and feedstocks to and from various locations worldwide. In 2014, the company took delivery of three bareboat charter VLCCs and two Pacific Area Lightering vessels.

The company also owns a 16.7 percent interest in each of seven LNG carriers transporting cargoes for the North West Shelf Venture in Australia. In 2014, the company took delivery of two new LNG carriers in support of its developing LNG portfolio.

Other Businesses

Power and Energy Management: The company's power and energy management operation delivers comprehensive commercial, engineering and operational support services to improve power reliability and energy efficiency for Chevron's operations worldwide. The business operates a variety of power assets, including gas-fired cogeneration facilities within Chevron's San Joaquin Valley operations in California, and renewable power facilities in California, New Mexico and Wyoming. The business also manages Chevron's investments in six renewable power projects in California, Arizona and Texas.

Chevron also has major geothermal operations in Indonesia and the Philippines. For additional information on the company's geothermal operations refer to page 15 in the Upstream section.

Research and Technology: Chevron's energy technology organization supports upstream and downstream businesses. The company conducts research, develops and qualifies technology, and provides technical services and competency development. The disciplines cover earth sciences, reservoir and production engineering, drilling and completions, facilities engineering, manufacturing, process technology, catalysis, technical computing and health, environment and safety.

Chevron's information technology organization integrates computing, telecommunications, data management, security and network technology to provide a standardized digital infrastructure to enable Chevron's global operations and business processes.

Chevron's technology ventures company supports Chevron's upstream and downstream businesses by sourcing and demonstrating emerging technologies and championing their integration into Chevron's operations. As of the end of 2014 , the company continued to source technologies in emerging materials, power systems, production enhancements, renewables, water management, information technologies and advanced biofuels, and to develop options for efficient management of Chevron's carbon footprint. Additionally, in 2014, the company made investments in start-up companies with technologies for pipeline integrity, efficient carbon dioxide capture from flue gas and big data management.

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. Refer to Note 25 beginning on FS-59 for a summary of the company's research and development expenses.

Environmental Protection: The company designs, operates and maintains its facilities to avoid potential spills or leaks and to 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., 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-16 for additional information on environmental matters and their impact on Chevron, and on the company's 2014 environmental expenditures. Refer to page FS-16 and Note 23 on page FS-58 for a discussion of environmental remediation provisions and year-end reserves. Refer also to Item 1A. Risk Factors on pages 22 through 24 for a discussion of greenhouse gas regulation and climate change.

Item 1A. Risk Factors

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 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 or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and geopolitical risks. 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, cash flows, and capital and exploratory expenditure programs will be negatively affected, as will its production and proved reserves. 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.

Chevron utilizes comprehensive risk management systems to assess potential physical and other risks to its assets and to plan for their resiliency. While capital investment reviews and decisions involve uncertainty analysis, which incorporates potential ranges of physical risks such as storm severity and frequency, sea level rise, air and water temperature, precipitation, fresh water access, wind speed, and earthquake severity, among other factors, Chevron cannot predict the timing, frequency or severity of such events, any of which could have a material adverse effect on the company's results of operations or financial condition.

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 15 to the Consolidated Financial Statements, beginning on page FS-42.

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 proposed or imposed 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. In addition, changes in national or state environmental regulations, including those related to the use of hydraulic fracturing, could adversely affect the company's current or anticipated future operations and profitability.

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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and character of the company's crude oil and natural gas 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-61 through FS-71. Note 14, "Properties, Plant and Equipment," to the company's financial statements is on page FS-41.

Item 3. Legal Proceedings

Ecuador: Information related to Ecuador matters is included in Note 15 to the Consolidated Financial Statements under the heading Ecuador, beginning on page FS-42.

Certain Governmental Proceedings: As previously disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 21, 2014, 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 Environmental Protection Agency (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.

As previously disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 21, 2014, 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 Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 21, 2014, the State of New Mexico provided to Chevron a Notice of Violation 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 company has reached a settlement agreement with the State of New Mexico and paid a civil penalty of less than $100,000 to resolve the alleged violation .

As initially disclosed in the Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed May 2, 2014, a fire was reported on February 11, 2014, at Chevron Appalachia, LLC's Lanco 7H well located in Dunkard Township, Greene County, Pennsylvania. The Pennsylvania Department of Environmental Protection (PA DEP) and the Occupational Safety and Health Administration of the United States (OSHA) initiated investigations as a result of the incident. Based on its civil investigation to date, the PA DEP has issued Chevron a Notice of Violation alleging nine separate incidents of noncompliance. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.

Item 4. Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 C.F.R. § 229.104) is included in Exhibit 95 of this Annual Report on Form 10-K.

Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The information on Chevron's common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-20.

Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2014

Item 6. Selected Financial Data

The selected financial data for years 2010 through 2014 are presented on page FS-60.

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," on page FS-15 and in Note 10 to the Consolidated Financial Statements, "Financial and Derivative Instruments," beginning on page FS-35.

Item 8. Financial Statements and Supplementary Data

The index to Management's Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

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, 2014 .

(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 (2013) 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, 2014 .

The effectiveness of the company's internal control over financial reporting as of December 31, 2014 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page FS-22.

(c) Changes in Internal Control Over Financial Reporting: During the quarter ended December 31, 2014 , 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. The company adopted the new framework effective January 1, 2014.

Item 9B. Other Information

None.

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant at February 20, 2015

Members of the Corporation's Executive Committee are the Executive Officers of the Corporation:

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 2015 Annual Meeting and 2015 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 2015 Annual Meeting of Stockholders (the " 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 - Related Person Transactions" in the 2015 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 2015 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 2015 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 15. Exhibits, Financial Statement Schedules

(1) Financial Statements:

(2) Financial Statement Schedules:

Included below is Schedule II - Valuation and Qualifying Accounts.

(3) Exhibits:

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

* See also Note 16 to the Consolidated Financial Statements, beginning on page FS-45.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 20th day of February, 2015.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 20th day of February, 2015.

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