Chevron
Annual Report 2015

Plain-text annual report

C H E V R O N C O R P O R A T O N I 2 0 1 5 A N N U A L R E P O R T 2015 annual report Chevron Corporation 6001 Bollinger Canyon Road, San Ramon, CA 94583-2324 USA www.chevron.com © 2016 Chevron Corporation. All Rights Reserved. 10% Recycled 100% Recyclable 912-0975 136105_Chevron_Covers.indd 1 3/4/16 3:19 PM 2015 annual report 2015 supplement to the annual report 2015 corporate responsibility report highlights 2015 Annual Report 2015 Supplement to the Annual Report 2015 Corporate Responsibility Report Publications and other news sources The Annual Report, distributed in April, summarizes the company’s financial performance in the preced ing year and provides an overview of the company’s major activities. Chevron’s Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission and the Supplement to the Annual Report, containing additional financial and operating data, are available on the company’s website, Chevron.com, or copies may be requested by writing to: Comptroller’s Department Chevron Corporation 6001 Bollinger Canyon Road, A3140 San Ramon, CA 94583-2324 The 2015 Corporate Responsibility Report is available in May on the company’s website, Chevron.com/CR, or a copy may be requested by writing to: Policy, Government and Public Affairs Corporate Responsibility Communications Chevron Corporation 6001 Bollinger Canyon Road Building G San Ramon, CA 94583-2324 Additional information about the company’s corporate responsibility efforts can be found on Chevron’s website at Chevron.com/CR and Chevron.com/CreatingProsperity. Details of the company’s political contributions for 2015 are available on the company’s website, Chevron.com, or by writing to: Policy, Government and Public Affairs Chevron Corporation 6001 Bollinger Canyon Road Building G San Ramon, CA 94583-2324 For additional information about the company and the energy industry, visit Chevron’s website, Chevron.com. It includes articles, news releases, speeches, quarterly earnings information, the Proxy Statement and the complete text of this Annual Report. This Annual Report contains forward-looking statements — identified by words such as “expects,” “intends,” “projects,” etc. — that reflect management’s current estimates and beliefs, but are not guarantees of future results. Please see “Cautionary Statement Relevant to Forward-Looking Information for the Purpose of ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” on Page 9 for a discussion of some of the factors that could cause actual results to differ materially. PHOTOGRAPHY Cover: Darrell Brown; Page 2: Eric Myer PRODUCED BY Policy, Government and Public Affairs and Comptroller’s Departments, Chevron Corporation DESIGN Design One — San Francisco, California PRINTING ColorGraphics — Los Angeles, California Hold this QR code to your smartphone and learn more about Chevron. If you do not have a QR code reader on your phone, go to your app store and search “QR Reader.” Chevron.com/AnnualReport/2015 On the cover: The Chevron-operated Asia Excellence liquefied natural gas tanker docks at the Gorgon LNG plant on Barrow Island, Western Australia. The vessel delivered commissioning cargo to cool down LNG storage and loading facilities. This was a key piece of the cooling process prior to the start of LNG production. First deliveries of Gorgon LNG will begin in early 2016. This page: One of the largest land-based mobile crawler cranes in the world is used to replace the reactor and regenerator heads in our Richmond Refinery’s fluidized catalytic cracker. The Richmond Refinery produces a special clean blend of gasoline only available in California and fuels approximately 20 percent of the vehicles on Northern California roads. 136105_Chevron_Covers.indd 2 3/17/16 7:50 PM contents 2 letter to stockholders 4 chevron financial highlights 5 chevron operating highlights 6 chevron at a glance 8 glossary of energy and financial terms 9 financial review 68 five-year financial summary 69 five-year operating summary 81 chevron history 82 board of directors 83 corporate officers 84 s tockholder and investor information CVX_AR2015_v17.4_031716PRO.indd 1 3/17/16 7:41 PM 2015 brought a steep and dramatic drop in the price of crude oil, one of the largest declines our industry has experienced in years. Chevron’s response was to reduce capital spending and aggressively cut costs while moving forward on developments that will grow production and cash flow for the future. We are focused on improving project execution and delivering results safely, reliably, on time and within budget. We are optimizing our portfolio by divesting assets that no longer have a strategic fit or cannot compete for capital with other investment alternatives. And we are capturing the benefits of being a fully integrated energy company with Downstream and Chemicals delivering strong results. We are optimistic about the future and committed to being a top competitor in any economic environment. The online version of this report contains additional information about our company, as well as videos of our various projects. We invite you to visit our website at Chevron.com/AnnualReport2015.to our stockholders Low commodity prices made 2015 a challenging year for Chevron and the entire oil and natural gas industry, reducing earnings across the sector. Our full-year 2015 net income was $4.6 billion, down from $19.2 billion in 2014. Our sales and other operating revenue were $129.9 billion, down from $200.5 billion in 2014. We achieved a 2.5 percent return on capital employed versus the 10.9 percent achieved in 2014. In light of difficult market conditions, we took significant actions to reduce costs and improve net cash flow. We reduced capital and operating expenses by $9 billion through renegotiating contracts with vendors and suppliers, streamlining organizations to reduce our employee and contractor work- force, deferring and canceling projects not economic at low prices, and selling $6 billion in nonstrategic and other assets. We had a number of notable accomplish- ments during 2015. Our Upstream business, which is responsible for exploration and production, increased worldwide net oil-equivalent production by 2 percent, to 2.6 million barrels per day. We started up the Lianzi Field, located in a unitized offshore zone between the Republic of Congo and Angola; Moho Nord, our deepwater devel- opment offshore the Republic of Congo; Agbami 3, off the coast of the central Niger Delta region; and Chuandongbei, our natural gas field in southwest China, which initiated production in early 2016. In addition we ramped up Jack/St. Malo and Tubular Bells in the U.S. Gulf of Mexico. Also significant progress was achieved on our major capital projects, including Gorgon, our largest Australian liquefied natural gas (LNG) project, and Wheatstone LNG as they move toward start-up in 2016 and mid-2017, respectively. We added approximately 1 billion investments. We focused these invest- starting up projects under construction barrels of net oil-equivalent proved ments in three core areas — health, and realizing the cash flow from them, reserves in 2015. These additions equate education and economic development — lowering capital spending, reducing to approximately 107 percent of net to improve access to health care, develop operating expenses, completing our oil-equivalent production for the year. skilled workers, and boost local and divestment program for assets that Significant reserves were added from regional economies. These social invest- have greater value to others than to the Permian Basin in the United States ments complement our investments in us, and doing all this while continuing and the Wheatstone Project in Australia. projects and local goods and services, to operate safely and reliably. In our exploration program, we success- creating jobs and generating revenues fully drilled an appraisal well of our for the communities where we operate. Our company’s products provide the Anchor discovery in the deepwater More details are available in the 2015 energy that is critical for economic Gulf of Mexico. Corporate Responsibility Report. progress. We are well positioned to Our Downstream and Chemicals business, I am proud to note that 2015 marked the responsible manner. which is responsible for our refining, 28th consecutive year that we increased marketing and chemical manufacturing, the annual per-share dividend payout. In all we do, we are guided by The had an outstanding year. This business Our top financial priority remains Chevron Way. This roadmap underpins meet growing demand in a safe and “Our company’s products provide the energy that is critical for economic progress. We are well positioned to meet growing demand in a safe and responsible manner.” the character of our company and establishes the values by which we deliver our results. I am confident that our company and our employees have what it takes to meet the challenges of the current business environment and achieve our vision of being the global maintained reliable operations, benefited maintaining and growing the dividend energy company most admired for its from lower feedstock costs and realized as the pattern of earnings, cash flow people, partnership and performance. efficiencies gained by the reshaping of and balance sheet strength permits. our portfolio in recent years. Our year-end debt ratio was a comfort- Thank you for your confidence and able 20.2 percent. your investment in Chevron. 2015 was one of our best years in overall health, environment and safety Looking ahead, we announced a 2016 performance and our best year ever in capital and exploratory budget of preventing significant incidents. Our $26.6 billion, which is 22 percent lower Days Away From Work Rate and Motor than our expenditures for 2015 and Vehicle Crash Rate set new record lows, 34 percent lower than 2014. This capital and our Total Recordable Incident Rate budget will enable us to complete and John S. Watson and petroleum spill volume matched last ramp up projects under construction, Chairman of the Board and year’s record lows. fund high-return, short-cycle invest- Chief Executive Officer ments, preserve options for viable February 25, 2016 We also continued our support of the long-cycle projects, and ensure safe, communities in which we work. This reliable operations. past year we advanced our strategic programs and partnerships, with more The focus of the enterprise in 2016 will than $233 million in global social remain on our five key priorities — safely Chevron Corporation 2015 Annual Report 3 CVX_AR2015_v17.4_031716PRO.indd 3 3/17/16 7:44 PM chevron financial highlights Millions of dollars, except per-share amounts Net income attributable to Chevron Corporation Sales and other operating revenues Noncontrolling interests income Interest expense (after tax) Capital and exploratory expenditures* Total assets at year-end Total debt and capital lease obligations at year-end Noncontrolling interests Chevron Corporation stockholders’ equity at year-end Cash provided by operating activities Common shares outstanding at year-end (Thousands) Per-share data Net income attributable to Chevron Corporation — diluted Cash dividends Chevron Corporation stockholders’ equity Common stock price at year-end Total debt to total debt-plus-equity ratio Return on average Chevron Corporation stockholders’ equity Return on capital employed (ROCE) * Includes equity in affiliates $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2015 4,587 129,925 123 — 33,979 266,103 38,592 1,170 152,716 19,456 1,868,646 2.45 4.28 81.73 89.96 20.2% 3.0% 2.5% 2014 % Change (76.2)% (35.2)% 78.3 % 0.0 % (15.7)% 0.0 % 38.7 % 0.6 % (1.5)% (38.2)% 0.2 % (75.8)% 1.7 % (1.7)% (19.8)% $ $ $ $ $ $ $ $ $ $ $ $ $ $ 19,241 200,494 69 — 40,316 266,026 27,818 1,163 155,028 31,475 1,865,481 10.14 4.21 83.10 112.18 15.2% 12.7% 10.9% Net income attributable to Chevron Corporation Billions of dollars Annual cash dividends Dollars per share Chevron year-end common stock price Dollars per share Return on capital employed Percent $4.28 30.0 25.0 20.0 15.0 10.0 5.0 0.0 5.00 4.00 3.00 2.00 1.00 0.00 $4.6 150 120 90 60 30 0 $89.96 25 20 15 10 5 0 2.5% 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 The decrease in 2015 was due to lower earnings in upstream as a result of lower crude oil margins and higher depreciation expense, partially offset by higher earnings in downstream. The company’s annual dividend increased for the 28th consecutive year. The company’s stock price declined 19.8 percent in 2015. Chevron’s return on capital employed declined to 2.5 percent on lower earnings and higher capital employed. 4 Chevron Corporation 2015 Annual Report Chevron Corporation 2015 Annual Report 4 #002 – Net Income – v1 #004 – Cash Dividends – v1 #008 – Year End Common Stock – v1 #006 – Return on Avg. Cap. – v1 chevron financial highlights chevron operating highlights1 Millions of dollars, except per-share amounts Net income attributable to Chevron Corporation Sales and other operating revenues Noncontrolling interests income Interest expense (after tax) Capital and exploratory expenditures* Total assets at year-end Total debt and capital lease obligations at year-end Noncontrolling interests Chevron Corporation stockholders’ equity at year-end Cash provided by operating activities Common shares outstanding at year-end (Thousands) Per-share data Cash dividends Net income attributable to Chevron Corporation — diluted Chevron Corporation stockholders’ equity Common stock price at year-end Total debt to total debt-plus-equity ratio Return on average Chevron Corporation stockholders’ equity Return on capital employed (ROCE) * Includes equity in affiliates $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2015 4,587 129,925 123 — 33,979 266,103 38,592 1,170 152,716 19,456 2.45 4.28 81.73 89.96 20.2% 3.0% 2.5% 2014 % Change (76.2)% (35.2)% 78.3 % 0.0 % (15.7)% 0.0 % 38.7 % 0.6 % (1.5)% (38.2)% 0.2 % (75.8)% 1.7 % (1.7)% (19.8)% $ $ $ $ $ $ $ $ $ $ $ $ $ $ 19,241 200,494 69 — 40,316 266,026 27,818 1,163 155,028 31,475 10.14 4.21 83.10 112.18 15.2% 12.7% 10.9% 1,868,646 1,865,481 Net production of crude oil, condensate and natural gas liquids (Thousands of barrels per day) Net production of natural gas (Millions of cubic feet per day) Total net oil-equivalent production (Thousands of oil-equivalent barrels per day) Refinery input (Thousands of barrels per day) Sales of refined products (Thousands of barrels per day) Net proved reserves of crude oil, condensate and natural gas liquids2 (Millions of barrels) Consolidated companies Affiliated companies Net proved reserves of natural gas2 (Billions of cubic feet) Consolidated companies Affiliated companies Net proved oil-equivalent reserves2 (Millions of barrels) Consolidated companies Affiliated companies Number of employees at year-end3 1 Includes equity in affiliates, except number of employees 2 At the end of the year 3 Excludes service station personnel 2015 1,744 5,269 2,622 1,702 2,735 4,262 2,000 25,946 3,491 8,586 2,582 58,178 2014 % Change 1,709 5,167 2,571 1,690 2,711 4,285 1,964 25,707 3,409 8,570 2,532 61,456 2.0 % 2.0 % 2.0 % 0.7 % 0.9 % (0.5)% 1.8 % 0.9 % 2.4 % 0.2 % 2.0 % (5.3)% Net income attributable to Chevron Corporation Billions of dollars Annual cash dividends Dollars per share Chevron year-end common stock price Dollars per share Return on capital employed Percent 30.0 25.0 20.0 15.0 10.0 5.0 0.0 5.00 4.00 3.00 2.00 1.00 0.00 $4.6 $4.28 $89.96 150 120 90 60 30 0 25 20 15 10 5 0 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 The decrease in 2015 was due to lower earnings in upstream as a result of lower crude oil margins and higher depreciation expense, partially offset by higher earnings in downstream. The company’s annual dividend increased for the 28th consecutive year. The company’s stock price declined 19.8 percent in 2015. Chevron’s return on capital employed declined to 2.5 percent on lower earnings and higher capital employed. Chevron Corporation 2015 Annual Report 4 #002 – Net Income – v1 #004 – Cash Dividends – v1 #008 – Year End Common Stock – v1 #006 – Return on Avg. Cap. – v1 Performance graph Five-year cumulative total returns (Calendar years ended December 31) The stock performance graph at right shows how an initial investment of $100 in Chevron stock would have compared with an equal investment in the S&P 500 Index or the Competitor Peer Group. The comparison covers a five-year period begin ning December 31, 2010, and ending December 31, 2015, and for the peer group is weighted by market capitalization as of the beginning of each year. It includes the reinvestment of all dividends that an investor would be entitled to receive and is adjusted for stock splits. The interim measurement points show the value of $100 invested on December 31, 2010, as of the end of each year between 2011 and 2015. s r a l l o D 200 180 160 140 120 100 80 2010 2011 2012 2013 2014 2015 2.5% Chevron S&P 500 Peer group* Chevron S&P 500 Peer group* 2010 100.00 100.00 100.00 2011 120.27 102.12 112.01 2012 126.28 118.44 116.15 2013 150.58 156.83 137.36 2014 140.17 178.30 127.21 2015 117.78 180.81 108.23 *Peer Group: BP p.l.c.-ADS, ExxonMobil, Royal Dutch Shell p.l.c.-ADS, Total S.A.-ADS Five-Year Cum. Total Returns – v1 Chevron Corporation 2015 Annual Report 5 Chevron Corporation 2015 Annual Report 5 chevron at a glance Chevron is one of the world’s leading integrated energy companies. Our success is driven by our people and their commitment to getting results the right way — by operating responsibly, executing with excellence, applying innovative technologies and capturing new opportunities for profitable growth. We are involved in virtually every facet of the energy industry. We explore for, produce and transport crude oil and natural gas; refine, market and distribute transportation fuels and lubricants; manufacture and sell petrochemicals and additives; generate power and produce geothermal energy; and develop and deploy technologies that enhance business value in every aspect of the company’s operations. Photo: With the Jack/St. Malo development, Chevron continues to advance the boundaries of deepwater exploration and production. The Jack and St. Malo fields are among the largest in the U.S. Gulf of Mexico and are expected to have a producing life of more than 30 years. In 2015 Chevron ramped up production from Jack/St. Malo and announced two other important discoveries in the region: Anchor and Sicily. 6 Chevron Corporation 2015 Annual Report p01-08_81-84.indd 6 3/4/16 4:36 PM Upstream Strategy: Grow profitably in core Upstream explores for and produces crude oil and natural gas. At the end of 2015 worldwide net oil-equivalent proved reserves for consolidated and affiliated companies were 11.2 billion areas and build new legacy barrels. During 2015 net oil-equivalent production averaged 2.6 million barrels per day. positions. Top producing areas include the United States, Kazakhstan, Nigeria, Thailand, Indonesia, Bangladesh, Angola, Australia, Canada and Venezuela. Major conventional exploration areas include the deepwater U.S. Gulf of Mexico, offshore northwestern Australia and the deepwater regions of western Africa. Key exploration areas for unconventional shale and tight resources are the United States, Canada and Argentina. Downstream and Chemicals Strategy: Deliver competitive returns Downstream and Chemicals includes refining, fuels and lubricants marketing, and petro- chemicals and additives manufacturing and marketing. In 2015 we processed 1.7 million barrels and grow earnings across of crude oil per day and averaged 2.7 million barrels per day of refined product sales world- the value chain. wide. Our most significant areas of refinery operations are the west coast of North America, the U.S. Gulf Coast, Singapore, Thailand, South Korea and South Africa. We hold interests in 11 refineries, are a leader in the manufacturing and sale of premium base oils, and market transportation fuels and lubricants under the Chevron, Texaco and Caltex brands. Products are sold through a network of 13,946 retail stations, including those of affiliated companies. Our chemicals business includes Chevron Phillips Chemical Company LLC, a 50 percent-owned affiliate that is one of the world’s leading manufacturers of commodity petrochemicals, and Chevron Oronite Company LLC, which develops, manufactures and markets quality additives that improve the performance of fuels and lubricants. Midstream and Development Strategy: Apply commercial and Midstream and Development provides services that link Upstream and Downstream and Chemicals to the market. This includes commercializing our equity gas resource base; maxi- functional excellence to enable mizing the value of the company’s equity natural gas, crude oil, natural gas liquids and refined the success of Upstream and products; and transporting products worldwide. Midstream and Development has global Downstream and Chemicals. operations with major centers in Houston; London; Singapore; and San Ramon, California. Technology Strategy: Differentiate performance Our three technology companies — Chevron Energy Technology, Chevron Technology Ventures and Chevron Information Technology — are focused on enhancing business value through technology. in all aspects of our operations. We have established technology centers in Australia, the United Kingdom and the United States. Together they provide strategic research, technology development, technical and computing infrastructure services, and data protection to our global businesses. Renewable Energy and Energy Efficiency Operational Excellence Strategy: Invest in profitable We are one of the world’s leading producers of geothermal energy, supplying abundant, reliable energy to millions of people in Indonesia and the Philippines. We also are investing renewable energy and in energy efficiency technologies to improve the performance of our operations worldwide. energy efficiency solutions. We define operational excellence as the systematic management of process safety, personal safety and health, the environment, operational reliability, and energy efficiency. We are committed to attaining superior performance in operational excellence and believe our safety goal of zero incidents is attainable. Chevron Corporation 2015 Annual Report 7 CVX_AR2015_v17.4_031716PRO.indd 7 3/17/16 7:45 PM CYAN MAGENTA YELLOW BLACK PMS 2945 glossary of energy and financial terms energy terms Additives Specialty chemicals incorporated into fuels and lubricants that enhance the performance of the finished products. Barrels of oil-equivalent (BOE) A unit of measure to quantify crude oil, natural gas liquids and natural gas amounts using the same basis. Natural gas volumes are converted to barrels on the basis of energy content. See oil-equivalent gas and production. Condensate Hydrocarbons that are in a gaseous state at reservoir conditions but condense into liquid as they travel up the wellbore and reach surface conditions. Development Drilling, construction and related activities following discovery that are necessary to begin production and transportation of crude oil and natural gas. Enhanced recovery Techniques used to increase or prolong production from crude oil and natural gas reservoirs. Entitlement effects The impact on Chevron’s share of net production and net proved reserves due to changes in crude oil and natural gas prices, and spending levels, between periods. Under production-sharing contracts (PSCs) and variable-royalty provisions of certain agreements, price and spend variability can increase or decrease royalty burdens and/or volumes attributable to the company. For example, at higher prices, fewer volumes are required for Chevron to recover its costs under certain PSCs. Also under certain PSCs, Chevron’s share of future profit oil and/or gas is reduced once specified contractual thresholds are met, such as a cumulative return on investment. Exploration Searching for crude oil and/or natural gas by utilizing geologic and topographical studies, geophysical and seismic surveys, and drilling of wells. Gas-to-liquids (GTL) A process that converts natural gas into high-quality liquid transportation fuels and other products. Greenhouse gases Gases that trap heat in Earth’s atmosphere (e.g., water vapor, ozone, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluor- ocarbons and sulfur hexafluoride). Integrated energy company A company engaged in all aspects of the energy industry, including exploring for and producing crude oil and natural gas; refining, marketing and transporting crude oil, natural gas and refined products; manufacturing and distributing petrochemicals; and generating power. Liquefied natural gas (LNG) Natural gas that is liquefied under extremely cold temperatures to facilitate storage or transportation in specially designed vessels. Natural gas liquids (NGLs) Separated from natural gas, these include ethane, propane, butane and natural gasoline. Oil-equivalent gas (OEG) The volume of natural gas needed to generate the equivalent amount of heat as a barrel of crude oil. Approximately 6,000 cubic feet of natural gas is equivalent to one barrel of crude oil. Oil sands Naturally occurring mixture of bitumen (a heavy, viscous form of crude oil), water, sand and clay. Using hydroprocessing technology, bitumen can be refined to yield synthetic oil. 8 Chevron Corporation 2015 Annual Report Petrochemicals Compounds derived from petroleum. These include aromatics, which are used to make plastics, adhesives, synthetic fibers and household detergents; and olefins, which are used to make packaging, plastic pipes, tires, batteries, household detergents and synthetic motor oils. Production Total production refers to all the crude oil (including synthetic oil), NGLs and natural gas produced from a property. Net production is the company’s share of total production after deducting both royalties paid to landowners and a government’s agreed-upon share of production under a PSC. Liquids production refers to crude oil, condensate, NGLs and synthetic oil volumes. Oil-equivalent production is the sum of the barrels of liquids and the oil-equivalent barrels of natural gas produced. See barrels of oil-equivalent and oil-equivalent gas. Production-sharing contract (PSC) An agreement between a government and a contractor (generally an oil and gas company) whereby production is shared between the parties in a prearranged manner. The contractor typically incurs all exploration, development and production costs, which are subsequently recover- able out of an agreed-upon share of any future PSC production, referred to as cost recovery oil and/or gas. Any remaining production, referred to as profit oil and/ or gas, is shared between the parties on an agreed-upon basis as stipulated in the PSC. The government also may retain a share of PSC production as a royalty payment, and the contractor typically owes income tax on its portion of the profit oil and/or gas. The contractor’s share of PSC oil and/or gas production and reserves varies over time as it is dependent on prices, costs and specific PSC terms. Renewables Energy resources that are not depleted when consumed or converted into other forms of energy (e.g., solar, geothermal, ocean and tide, wind, hydroelectric power, biofuels and hydrogen). Reserves Crude oil and natural gas contained in underground rock formations called reservoirs and saleable hydrocarbons extracted from oil sands, shale, coalbeds and other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas. Net proved reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future from known reservoirs under existing eco- nomic conditions, operating methods and government regulations, and exclude royalties and interests owned by others. Estimates change as additional information becomes available. Oil-equivalent reserves are the sum of the liquids reserves and the oil-equivalent gas reserves. See barrels of oil-equivalent and oil-equivalent gas. The company discloses only net proved reserves in its filings with the U.S. Securities and Exchange Commission. Investors should refer to proved reserves disclosures in Chevron’s Annual Report on Form 10-K for the year ended December 31, 2015. Resources Estimated quantities of oil and gas resources are recorded under Chevron’s 6P system, which is mod- eled after the Society of Petroleum Engineers’ Petroleum Resource Management System, and include quantities classified as proved, probable and possible reserves, plus those that remain contingent on commerciality. Unrisked resources, unrisked resource base and similar terms represent the arithmetic sum of the amounts recorded under each of these classifications. Recoverable resources, potentially recoverable volumes and other similar terms represent estimated remaining quanti- ties that are expected to be ultimately recoverable and produced in the future, adjusted to reflect the relative uncertainty represented by the various classifications. These estimates may change significantly as develop- ment work provides additional information. At times, original oil in place and similar terms are used to describe total hydrocarbons contained in a reservoir without regard to the likelihood of their being produced. All of these measures are considered by management in making capital investment and operating decisions and may provide some indication to stockholders of the resource potential of oil and gas properties in which the company has an interest. Shale gas Natural gas produced from shale rock formations where the gas was sourced from within the shale itself. Shale is very fine-grained rock, characterized by low porosity and extremely low permeability. Production of shale gas normally requires formation stimulation such as the use of hydraulic fracturing (pumping a fluid-sand mixture into the formation under high pressure) to help produce the gas. Synthetic oil A marketable and transportable hydro- carbon liquid, resembling crude oil, that is produced by upgrading highly viscous or solid hydrocarbons, such as extra-heavy crude oil or oil sands. Tight oil Liquid hydrocarbons produced from shale (also referred to as shale oil) and other rock formations with extremely low permeability. As with shale gas, produc- tion from tight oil reservoirs normally requires formation stimulation such as hydraulic fracturing. financial terms Cash flow from operating activities Cash generated from the company’s businesses; an indicator of a company’s ability to fund capital programs and stock- holder distributions. Excludes cash flows related to the company’s financing and investing activities. Debt ratio Total debt, including capital lease obligations, divided by total debt plus Chevron Corporation stock- holders’ equity. Earnings Net income attributable to Chevron Corporation as presented on the Consolidated Statement of Income. Margin The difference between the cost of purchasing, producing and/or marketing a product and its sales price. Return on capital employed (ROCE) Ratio calculated by dividing earnings (adjusted for after-tax interest expense and noncontrolling interests) by the average of total debt, noncontrolling interests and Chevron Corporation stockholders’ equity for the year. Return on stockholders’ equity Ratio calculated by dividing earnings by average Chevron Corporation stockholders’ equity. Average Chevron Corporation stockholders’ equity is computed by averaging the sum of the beginning-of-year and end-of-year balances. Total stockholder return (TSR) The return to stock- holders as measured by stock price appreciation and reinvested dividends for a period of time. p01-08_81-84_r1.indd 8 3/12/16 3:44 PM Financial Table of Contents 10 Management’s Discussion and Analysis of Financial Condition and Results of Operations Key Financial Results 10 Earnings by Major Operating Area 10 Business Environment and Outlook 10 Operating Developments 13 Results of Operations 14 Consolidated Statement of Income 17 Selected Operating Data 19 Liquidity and Capital Resources 20 Financial Ratios 22 Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies 22 Financial and Derivative Instrument Market Risk 23 Transactions With Related Parties 23 Litigation and Other Contingencies 24 Environmental Matters 24 Critical Accounting Estimates and Assumptions 25 New Accounting Standards 28 Quarterly Results and Stock Market Data 28 29 Consolidated Financial Statements Reports of Management 29 Report of Independent Registered Public Accounting Firm 30 Consolidated Statement of Income 31 Consolidated Statement of Comprehensive Income 32 Consolidated Balance Sheet 33 Consolidated Statement of Cash Flows 34 Consolidated Statement of Equity 35 36 Notes to the Consolidated Financial Statements Summary of Significant Accounting Policies 36 Note 1 Changes in Accumulated Other Comprehensive Losses 38 Noncontrolling Interests 38 Information Relating to the Consolidated Note 3 Note 2 Note 4 Note 8 Note 7 Note 6 Note 5 Statement of Cash Flows 39 New Accounting Standards 40 Lease Commitments 40 Summarized Financial Data – Chevron U.S.A. Inc. 41 Summarized Financial Data – Tengizchevroil LLP 42 Note 9 Fair Value Measurements 42 Note 10 Financial and Derivative Instruments 43 Note 11 Assets Held for Sale 44 Note 12 Equity 45 Note 13 Earnings Per Share 45 Note 14 Operating Segments and Geographic Data 45 Note 15 Note 16 Properties, Plant and Equipment 49 Note 17 Note 18 Taxes 53 Note 19 Short-Term Debt 56 Note 20 Long-Term Debt 57 Note 21 Accounting for Suspended Exploratory Wells 57 Note 22 Stock Options and Other Share-Based Compensation 58 Note 23 Employee Benefit Plans 59 Note 24 Other Contingencies and Commitments 65 Note 25 Asset Retirement Obligations 67 Note 26 Restructuring and Reorganization Costs 67 Note 27 Other Financial Information 67 Investments and Advances 48 Litigation 50 Five-Year Financial Summary 68 Five-Year Operating Summary 69 Supplemental Information on Oil and Gas Producing Activities 70 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 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 or phrases such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “may,” “could,” “should,” “budgets,” “outlook,” “on schedule,” “on track” 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; the company’s ability to realize anticipated cost savings and expenditure reductions; 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 the company’s suppliers, vendors, partners and equity affiliates, particularly during extended periods of low prices for crude oil and natural gas; 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 operations due to war, accidents, political events, civil unrest, severe weather, cyber threats and terrorist acts, crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries, or other natural or human causes beyond its control; changing economic, regulatory and political environments in the various countries in which the company operates; general domestic and international economic and political conditions; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant operational, investment or product changes required by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce greenhouse gas emissions; 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; material reductions in corporate liquidity and access to debt markets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; the company’s ability to identify and mitigate the risks and hazards inherent in operating in the global energy industry; and the factors set forth under the heading “Risk Factors” on pages 21 through 23 of the company’s Annual Report on Form 10-K. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Chevron Corporation 2015 Annual Report 9 Management’s Discussion and Analysis of Financial Condition and Results of Operations Key Financial Results Millions of dollars, except per-share amounts Net Income Attributable to Chevron Corporation Per Share Amounts: Net Income Attributable to Chevron Corporation – Basic – Diluted Dividends Sales and Other Operating Revenues Return on: Capital Employed Stockholders’ Equity Earnings by Major Operating Area Millions of dollars Upstream United States International Total Upstream Downstream United States International Total Downstream All Other Net Income Attributable to Chevron Corporation1,2 1 Includes foreign currency effects: 2 Income net of tax, also referred to as “earnings” in the discussions that follow. 2015 $ 4,587 2.46 $ 2.45 $ $ 4.28 $ 129,925 2.5% 3.0% 2015 (4,055) 2,094 (1,961) 3,182 4,419 7,601 (1,053) 4,587 769 $ $ $ $ $ $ $ $ $ $ $ 2014 2013 19,241 $ 21,423 10.21 10.14 4.21 200,494 11.18 $ 11.09 $ $ 3.90 $ 220,156 10.9% 12.7% 13.5% 15.0% 2014 2013 3,327 13,566 16,893 $ 4,044 16,765 20,809 2,637 1,699 4,336 787 1,450 2,237 (1,988) 19,241 487 $ $ (1,623) 21,423 474 Refer to the “Results of Operations” section beginning on page 14 for a discussion of financial results by major operating area for the three years ended December 31, 2015. Business Environment and Outlook Chevron is a global energy company with substantial business activities in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Canada, China, Colombia, Democratic Republic of the Congo, Denmark, Indonesia, Kazakhstan, Myanmar, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, and Venezuela. Earnings of the company depend mostly on the profitability of its upstream business segment. The biggest factor affecting the results of operations for the upstream segment is the price of crude oil. The price of crude oil has fallen significantly since mid-year 2014, reflecting persistently high global crude oil inventories and production. The downturn in the price of crude oil has impacted, and, depending upon its duration, will continue to significantly impact the company’s results of operations, cash flows, leverage, capital and exploratory investment program and production outlook. The company is responding with reductions in operating expenses, including employee reductions, reductions in capital and exploratory expenditures in 2016 and future periods, and increased asset sales. The company anticipates that crude oil prices will increase in the future, as continued growth in demand and a slowing in supply growth should bring global markets into balance; however, the timing of any such increase is unknown. In the company’s downstream business, crude oil is the largest cost component of refined products. Refer to the “Cautionary Statement Relevant to Forward-Looking Information” on page 9 and to “Risk Factors” in Part I, Item 1A, on pages 21 through 23 of the company’s Annual Report on Form 10-K for a discussion of some of the inherent risks that could materially impact the company’s results of operations or financial condition. The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and growth. Refer to the “Results of Operations” section beginning on page 14 for discussions of net gains on asset sales during 2015. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses. The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning. 10 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations Comments related to earnings trends for the company’s major business areas are as follows: Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, technology advancements, production quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC), actions of regulators, weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company closely monitors developments in the countries in which it operates and holds investments, and seeks to manage risks in operating its facilities and businesses. The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, and changes in tax laws and regulations. The company continues to actively manage its schedule of work, contracting, procurement and supply-chain activities to effectively manage costs. However, price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and natural gas can be subject to external factors beyond the company’s control including, among other things, the general level of inflation, commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. In recent years, Chevron and the oil and gas industry generally experienced an increase in certain costs that exceeded the general trend of inflation in many areas of the world. As a result of the decline in prices of crude oil and other commodities since mid-2014, these cost pressures have softened. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest, delays in construction, or other factors. WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Spot Prices - Quarterly Average WTI/Brent $/bbl 120 Brent WTI HH 90 60 30 0 HH $/mcf 20 15 10 5 0 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 2013 2014 2015 The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The Brent price averaged $52 per barrel for the full-year 2015, compared to $99 in 2014. As of mid- February 2016, the Brent price was $31 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. Prices firmed in the first half of 2015, but declined in the remainder of the year amid persistently high global crude oil inventories and production. The WTI price averaged $49 per barrel for the full-year 2015, compared to $93 in 2014. As of mid-February 2016, the WTI price was $29 per barrel. WTI traded at a discount to Brent throughout 2015 due to high inventories and excess crude supply in the U.S. market. With the lifting of the U.S. crude oil export ban in December 2015, the spread between WTI and Brent narrowed substantially and WTI traded around parity into February 2016. A differential in crude oil prices exists between high-quality (high-gravity, low-sulfur) crudes and those of lower quality (low- gravity, high-sulfur). The amount of the differential in any period is associated with the relative supply/demand balances for each crude type, which are functions of the capacity of refineries that are able to process each as feedstock into high-value light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). In second-half 2015, the differential expanded in North America as Canadian heavy crude production recovered from earlier planned and unplanned outages, while light sweet crude prices in the U.S. were supported by reductions in the rig count and slowing domestic production growth. Outside of North Chevron Corporation 2015 Annual Report 11 Management’s Discussion and Analysis of Financial Condition and Results of Operations America, high refinery runs in Europe and Asia supported pricing for light sweet crude from the Atlantic Basin, while increased output from Iraq and other Middle East producers pressured values of heavier, more sour crudes. Chevron produces or shares in the production of heavy crude oil in California, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page 19 for the company’s average U.S. and international crude oil realizations.) In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply-and-demand conditions in those markets. Fluctuations in the price of natural gas in the United States are closely associated with customer demand relative to the volumes produced and stored in North America. In the United States, prices at Henry Hub averaged $2.62 per thousand cubic feet (MCF) during 2015, compared with $4.28 during 2014. As of mid-February 2016, the Henry Hub spot price was $1.92 per MCF. Outside the United States, price changes for natural gas depend on a wide range of supply, demand and regulatory circumstances. Chevron sells natural gas into the domestic pipeline market in most locations. In some locations, Chevron is investing in long-term projects to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets. The company’s long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. Approximately 85 percent of the equity LNG offtake from the operated Australian LNG projects is targeted to be sold into binding long-term contracts, with the remainder to be sold in the Asian spot LNG market. The Asian spot market reflects the supply and demand for LNG in the Pacific Basin and is not directly linked to crude oil prices. International natural gas realizations averaged $4.53 per MCF during 2015, compared with $5.78 per MCF during 2014. (See page 19 for the company’s average natural gas realizations for the U.S. and international regions.) Net Liquids Production* Thousands of barrels per day Net Natural Gas Production* Millions of cubic feet per day Net Proved Reserves Billions of BOE Net Proved Reserves Liquids vs. Natural Gas Billions of BOE 2000 1600 1200 800 400 0 1,744 5500 5,269 4400 3300 2200 1100 0 11.2 12.5 10.0 7.5 5.0 2.5 0.0 11.2 12.5 10.0 7.5 5.0 2.5 0.0 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 United States International United States International * Includes equity in affiliates. * Includes equity in affiliates. United States Other Americas Africa Asia Australia Europe Affiliates Natural Gas Liquids The company’s worldwide net oil-equivalent production in 2015 averaged 2.622 million barrels per day. About one-fifth of the company’s net oil-equivalent production in 2015 occurred in the OPEC-member countries of Angola, Nigeria, Venezuela and the Partitioned Zone between Saudi Arabia and Kuwait. OPEC quotas had no effect on the company’s net crude oil production in 2015 or 2014. At their December 2015 meeting, members of OPEC did not agree on a target production level, and in January 2016 western sanctions on Iran were lifted. As such, OPEC output is now considered likely to increase from recent levels of approximately 31.5 million barrels per day as Iranian production and exports recover. The company estimates that net oil-equivalent production in 2016 will be flat to 4 percent growth compared to 2015. This estimate is subject to many factors and uncertainties, including the duration of the low price environment that began in second- half 2014; quotas or other actions that may be imposed by OPEC; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction, start-up or ramp-up of projects; fluctuations in demand for natural gas in various markets; weather conditions that may shut in production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; greater-than-expected declines in production from mature fields; or other disruptions 12 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and, for new, large-scale projects, the time lag between initial exploration and the beginning of production. Investments in upstream projects generally begin well in advance of the start of the associated crude oil and natural gas production. A significant majority of Chevron’s upstream investment is made outside the United States. In the Partitioned Zone between Saudi Arabia and Kuwait, production was shut-in beginning in May 2015 as a result of difficulties in securing work and equipment permits. Net oil-equivalent production in the Partitioned Zone in 2014 was 81,000 barrels per day. During 2015, net oil-equivalent production averaged 28,000 barrels per day. As of early 2016, production remains shut-in and the exact timing of a production restart is uncertain and dependent on dispute resolution between Saudi Arabia and Kuwait. The financial effects from the loss of production in 2015 were not significant and are not expected to be significant in 2016. Net proved reserves for consolidated companies and affiliated companies totaled 11.2 billion barrels of oil-equivalent at year-end 2015, an increase of 1 percent from year-end 2014. The reserve replacement ratio in 2015 was 107 percent. Refer to Table V beginning on page 74 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2013 and each year-end from 2013 through 2015, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2015. Refer to the “Results of Operations” section on pages 14 through 16 for additional discussion of the company’s upstream business. Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, and petrochemicals. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals, and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, costs of materials and services, refinery or chemical plant capacity utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events. Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of its crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets. The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Asia and southern Africa. Chevron operates or has significant ownership interests in refineries in each of these areas. Refer to the “Results of Operations” section on pages 14 through 16 for additional discussion of the company’s downstream operations. All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies. Operating Developments Key operating developments and other events during 2015 and early 2016 included the following: Upstream Angola-Republic of Congo Joint Development Area Achieved first production from the Lianzi Project. Australia Progressed LNG Train 1 commissioning and start-up activities for the Gorgon Project, with first cargo lifting expected in March 2016. All Train 2 modules are installed, and all remaining Train 3 modules were delivered as of January 2016. Progressed construction of the Wheatstone Project. Major milestones reached include the installation of the offshore platform and topsides, and all of the subsea pipelines and structures, along with the delivery of all LNG Train 1 and common modules. Announced a natural gas discovery, Isosceles, in the Carnarvon Basin in 50 percent-owned Block WA-392-P. Bangladesh Achieved first liquids from the Bibiyana Expansion Liquid Recovery Unit. China Achieved first production from the Chuandongbei Project in early 2016. Chevron Corporation 2015 Annual Report 13 Management’s Discussion and Analysis of Financial Condition and Results of Operations Republic of Congo Announced start of production from the first phase of the Moho Nord Project. United States Announced a successful appraisal well at the Anchor prospect in the deepwater Gulf of Mexico. Downstream Australia Completed the sale of the company’s 50 percent interest in Caltex Australia Limited. New Zealand Completed the sale of the company’s interest in The New Zealand Refining Company Limited and reached agreement to sell the company’s marketing operations. Other Common Stock Dividends The 2015 annual dividend was $4.28 per share, making 2015 the 28th consecutive year that the company increased its annual dividend payout. Results of Operations The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 14, beginning on page 45, for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages 10 through 13. Worldwide Upstream Earnings Billions of dollars Exploration Expenses Millions of dollars (before-tax) Worldwide Downstream Earnings* Billions of dollars Worldwide Gasoline & Other Refined Product Sales Thousands of barrels per day 28.0 21.0 14.0 7.0 0.0 -7.0 $(2.0) $3,340 4000 3000 2000 1000 0 $7.6 8.0 6.0 4.0 2.0 0.0 2,735 3600 2700 1800 900 0 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 United States International United States International United States International *Includes equity in affiliates. Gasoline Jet Fuel Gas Oils Residual Fuel Oil Other U.S. Upstream Millions of dollars Earnings 2015 2014 $ (4,055) $ 3,327 $ 2013 4,044 U.S. upstream operations incurred a loss of $4.06 billion in 2015 compared to earnings of $3.33 billion from 2014. The decrease was primarily due to lower crude oil and natural gas realizations of $4.86 billion and $570 million, respectively, higher depreciation expenses of $2.19 billion and higher exploration expenses of $650 million. The increase in depreciation and exploration expenses was primarily due to impairments and project cancellations. Lower gains on asset sales also contributed to the decrease with current year gains of $110 million compared with $700 million in 2014. Partially offsetting these effects were higher crude oil production of $900 million and lower operating expenses of $450 million. U.S. upstream earnings of $3.33 billion in 2014 decreased $717 million from 2013, primarily due to lower crude oil prices of $950 million. Higher depreciation expenses of $440 million and higher operating expenses of $210 million also contributed to the decline. Partially offsetting the decrease were gains on asset sales of $700 million in 2014 compared with $60 million in 2013, higher natural gas realizations of $150 million and higher crude oil production of $100 million. 14 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations The company’s average realization for U.S. crude oil and natural gas liquids in 2015 was $42.70 per barrel, compared with $84.13 in 2014 and $93.46 in 2013. The average natural gas realization was $1.92 per thousand cubic feet in 2015, compared with $3.90 in 2014 and $3.37 in 2013. Net oil-equivalent production in 2015 averaged 720,000 barrels per day, up 8 percent from 2014 and 10 percent from 2013. Between 2015 and 2014, production increases due to project ramp-ups in the Gulf of Mexico and the Permian Basin in Texas and New Mexico were partially offset by the effect of asset sales and normal field declines. Between 2014 and 2013, production increases in the Permian Basin in Texas and New Mexico and the Marcellus Shale in western Pennsylvania were partially offset by normal field declines. The net liquids component of oil-equivalent production for 2015 averaged 501,000 barrels per day, up 10 percent from 2014 and 12 percent from 2013. Net natural gas production averaged about 1.3 billion cubic feet per day in 2015, up 5 percent from 2014 and 2013. Refer to the “Selected Operating Data” table on page 19 for a three-year comparison of production volumes in the United States. International Upstream Millions of dollars Earnings* *Includes foreign currency effects: 2015 2,094 725 $ $ 2014 13,566 597 $ $ 2013 16,765 559 $ $ International upstream earnings were $2.09 billion in 2015 compared with $13.57 billion in 2014. The decrease between periods was primarily due to lower crude oil and natural gas realizations of $10.57 billion and $880 million, respectively, and higher depreciation expenses of $1.11 billion, primarily reflecting impairments. Lower gains on asset sales also contributed to the decrease with current year gains of $370 million compared with $1.10 billion in 2014. Partially offsetting the decrease were higher crude oil sales volumes of $590 million and lower operating expenses of $510 million. Foreign currency effects increased earnings by $725 million in 2015, compared with an increase of $597 million a year earlier. International upstream earnings were $13.57 billion in 2014 compared with $16.77 billion in 2013. The decrease between periods was primarily due to lower crude oil prices and sales volumes of $1.97 billion and $400 million, respectively. Also contributing to the decrease were higher depreciation expenses of $1.02 billion, mainly related to impairments and other asset write-offs, and higher operating and tax expenses of $340 million and $310 million, respectively. Partially offsetting these items were gains on asset sales of $1.10 billion in 2014, compared with $140 million in 2013. Foreign currency effects increased earnings by $597 million in 2014, compared with a decrease of $559 million a year earlier. The company’s average realization for international crude oil and natural gas liquids in 2015 was $46.52 per barrel, compared with $90.42 in 2014 and $100.26 in 2013. The average natural gas realization was $4.53 per thousand cubic feet in 2015, compared with $5.78 and $5.91 in 2014 and 2013, respectively. International net oil-equivalent production was 1.90 million barrels per day in 2015, essentially unchanged from 2014 and down 2 percent from 2013. Between 2015 and 2014, production increases from entitlement effects in several locations and project ramp-ups in Bangladesh and other areas were offset by the Partitioned Zone shut-in, normal field declines and the effect of asset sales. Between 2014 and 2013, production increases due to 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. The net liquids component of international oil-equivalent production was 1.24 million barrels per day in 2015, a decrease of approximately 1 percent from 2014 and a decrease of approximately 3 percent from 2013. International net natural gas production of 4.0 billion cubic feet per day in 2015 was up 1 percent from 2014 and unchanged from 2013. Refer to the “Selected Operating Data” table, on page 19, for a three-year comparison of international production volumes. Chevron Corporation 2015 Annual Report 15 Management’s Discussion and Analysis of Financial Condition and Results of Operations U.S. Downstream Millions of dollars Earnings 2015 2014 $ 3,182 $ 2,637 $ 2013 787 U.S. downstream operations earned $3.18 billion in 2015, compared with $2.64 billion in 2014. The increase was due to higher margins on refined product sales of $1.51 billion, partially offset by the absence of 2014 asset sale gains of $960 million. U.S. downstream operations earned $2.64 billion in 2014, compared with $787 million in 2013. The increase in earnings was mainly due to higher margins on refined product sales of $830 million. Gains from asset sales were $960 million in 2014, compared with $250 million in 2013. Higher earnings from 50 percent-owned Chevron Phillips Chemical Company, LLC (CPChem) of $160 million and lower operating expenses of $80 million also contributed to the earnings increase. Refined product sales of 1.23 million barrels per day in 2015 increased 1 percent, mainly reflecting higher sales of jet fuel. Sales volumes of refined products were 1.21 million barrels per day in 2014, an increase of 2 percent from 2013, mainly reflecting higher gas oil sales. U.S. branded gasoline sales of 522,000 barrels per day in 2015 increased 1 percent from 2014 and 2013. Refer to the “Selected Operating Data” table on page 19 for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes. International Downstream Millions of dollars Earnings* *Includes foreign currency effects: 2015 4,419 47 $ $ $ $ 2014 1,699 (112) $ $ 2013 1,450 (76) International downstream earned $4.42 billion in 2015, compared with $1.70 billion in 2014. The increase was primarily due to a $1.6 billion gain from the sale of the company’s interest in Caltex Australia Limited in second quarter 2015 and higher margins on refined product sales of $690 million. Foreign currency effects increased earnings by $47 million in 2015, compared to a decrease of $112 million a year earlier. International downstream earned $1.70 billion in 2014, compared with $1.45 billion in 2013. The increase was mainly due to a favorable change in the effects on derivative instruments of $640 million. The increase was partially offset by the economic buyout of a legacy pension obligation of $160 million in the 2014 period, lower margins on refined product sales of $130 million and higher tax expenses of $110 million. Foreign currency effects decreased earnings by $112 million in 2014, compared with a decrease of $76 million a year earlier. Total refined product sales of 1.51 million barrels per day in 2015 were essentially unchanged from 2014. Excluding the effects of the Caltex Australia Limited divestment, refined product sales were up 107,000 barrels per day, primarily reflecting higher sales of jet fuel, gasoline and gas oil. Sales of 1.50 million barrels per day in 2014 declined 2 percent from 2013, mainly reflecting lower gas oil sales. Refer to the “Selected Operating Data” table, on page 19, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes. All Other Millions of dollars Net charges* *Includes foreign currency effects: 2015 (1,053) (3) $ $ $ $ 2014 2013 (1,988) $ (1,623) 2 $ (9) All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies. Net charges in 2015 decreased $935 million from 2014, mainly due to lower corporate tax items and the absence of 2014 charges related to mining assets, partially offset by higher charges related to reductions in corporate staffs. Net charges in 2014 increased $365 million from 2013, mainly due to higher environmental reserve additions, asset impairments and additional asset retirement obligations for mining assets, as well as higher corporate tax items. These increases were partially offset by the absence of 2013 impairments of power-related affiliates and lower other corporate charges. 16 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations Consolidated Statement of Income Comparative amounts for certain income statement categories are shown below: Millions of dollars Sales and other operating revenues 2015 2014 2013 $ 129,925 $ 200,494 $ 220,156 Sales and other operating revenues decreased in 2015 primarily due to lower refined product and crude oil prices, partially offset by an increase in refined product and crude oil volumes. The decrease between 2014 and 2013 was mainly due to lower crude oil volumes, and lower refined product and crude oil prices. Millions of dollars Income from equity affiliates 2015 2014 $ 4,684 $ 7,098 $ 2013 7,527 Income from equity affiliates decreased in 2015 from 2014 mainly due to lower earnings from Tengizchevroil in Kazakhstan, CPChem, Angola LNG and the effect of the sale of Caltex Australia Limited in second quarter 2015. Partially offsetting these effects were higher earnings from GS Caltex in South Korea and Petropiar in Venezuela. Income from equity affiliates decreased in 2014 from 2013 mainly due to lower upstream-related earnings from Tengizchevroil in Kazakhstan, Petropiar and Petroboscan in Venezuela, and Angola LNG. Partially offsetting these effects were higher downstream-related earnings from GS Caltex in South Korea, higher earnings from CPChem and the absence of 2013 impairments of power-related affiliates. Refer to Note 15, beginning on page 48, for a discussion of Chevron’s investments in affiliated companies. Millions of dollars Other income 2015 2014 $ 3,868 $ 4,378 $ 2013 1,165 Other income of $3.9 billion in 2015 included net gains from asset sales of $3.2 billion before-tax. Other income in 2014 and 2013 included net gains from asset sales of $3.6 billion and $710 million before-tax, respectively. Interest income was approximately $119 million in 2015, $145 million in 2014 and $136 million in 2013. Foreign currency effects increased other income by $82 million in 2015, $277 million in 2014 and $103 million in 2013. Millions of dollars Purchased crude oil and products 2015 2014 2013 $ 69,751 $ 119,671 $ 134,696 Crude oil and product purchases of $69.8 billion were down in 2015 mainly due to lower crude oil and refined product prices, partially offset by an increase in crude oil volumes. Crude oil and product purchases in 2014 decreased by $15.0 billion from the prior year, mainly due to lower crude oil and refined product prices, along with lower crude oil volumes. Millions of dollars Operating, selling, general and administrative expenses 2015 2014 2013 $ 27,477 $ 29,779 $ 29,137 Operating, selling, general and administrative expenses decreased $2.3 billion between 2015 and 2014. The decrease included lower fuel costs of $920 million. Also contributing to the decrease were lower expenses for construction, repair and maintenance of $300 million, contract labor of $270 million, and research, technical and professional services of $200 million. Operating, selling, general and administrative expenses increased $642 million between 2014 and 2013. The increase included higher employee compensation and benefit costs of $360 million, primarily related to a buyout of a legacy pension obligation. Also contributing to the increase was higher transportation costs of $350 million, primarily reflecting the economic buyout of a long-term contractual obligation, and higher environmental expenses related to a mining asset of $300 million. Partially offsetting the increase were lower fuel expenses of $360 million. Millions of dollars Exploration expense 2015 2014 $ 3,340 $ 1,985 $ 2013 1,861 Exploration expenses in 2015 increased from 2014 mainly due to higher charges for well write-offs largely related to project cancellations. Exploration expenses in 2014 increased from 2013 mainly due to higher charges for well write-offs, partially offset by lower geological and geophysical expenses. Chevron Corporation 2015 Annual Report 17 Management’s Discussion and Analysis of Financial Condition and Results of Operations Millions of dollars Depreciation, depletion and amortization 2015 2014 2013 $ 21,037 $ 16,793 $ 14,186 Depreciation, depletion and amortization expenses increased in 2015 from 2014 mainly due to impairments of oil and gas producing fields of about $3.5 billion in 2015 compared with $900 million in 2014. Also contributing to the increase were higher depreciation rates and higher production levels for certain oil and gas producing fields. The increase in 2014 from 2013 was mainly due to higher depreciation rates and impairments for certain oil and gas producing fields, and the impairment of a mining asset. Millions of dollars Taxes other than on income 2015 2014 2013 $ 12,030 $ 12,540 $ 13,063 Taxes other than on income decreased in 2015 from 2014 mainly due to lower crude oil and refined product prices. Taxes other than on income decreased in 2014 from 2013 primarily due to a decrease in duty expense in South Africa along with lower consumer excise taxes in Thailand, reflecting lower sales volumes at both locations. Millions of dollars Income tax expense 2015 2014 2013 $ 132 $ 11,892 $ 14,308 Effective income tax rates were 3 percent in 2015, 38 percent in 2014 and 40 percent in 2013. The decrease in the effective tax rate between 2015 and 2014 primarily resulted from the impacts of jurisdictional mix, one-time tax benefits, foreign currency remeasurement, equity earnings and a reduction in statutory tax rates in the United Kingdom, partially offset by the effects of valuation allowances recognized on deferred tax assets and the sale of the company’s interest in Caltex Australia Limited. The rate decreased between 2014 and 2013 primarily due to the impact of changes in jurisdictional mix and equity earnings, and the tax effects related to the 2014 sale of interests in Chad and Cameroon, partially offset by other one-time and ongoing tax charges. 18 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations Selected Operating Data1,2 U.S. Upstream Net Crude Oil and Natural Gas Liquids Production (MBPD) Net Natural Gas Production (MMCFPD)3 Net Oil-Equivalent Production (MBOEPD) Sales of Natural Gas (MMCFPD) Sales of Natural Gas Liquids (MBPD) Revenues From Net Production Liquids ($/Bbl) Natural Gas ($/MCF) International Upstream Net Crude Oil and Natural Gas Liquids Production (MBPD)4 Net Natural Gas Production (MMCFPD)3 Net Oil-Equivalent Production (MBOEPD)4 Sales of Natural Gas (MMCFPD) Sales of Natural Gas Liquids (MBPD) Revenues From Liftings Liquids ($/Bbl) Natural Gas ($/MCF) Worldwide Upstream Net Oil-Equivalent Production (MBOEPD)4 United States International Total U.S. Downstream Gasoline Sales (MBPD)5 Other Refined Product Sales (MBPD) Total Refined Product Sales (MBPD) Sales of Natural Gas Liquids (MBPD) Refinery Input (MBPD) International Downstream Gasoline Sales (MBPD)5 Other Refined Product Sales (MBPD) Total Refined Product Sales (MBPD)6 Sales of Natural Gas Liquids (MBPD) Refinery Input (MBPD)7 1 Includes company share of equity affiliates. $ $ $ $ 2015 501 1,310 720 3,913 26 42.70 1.92 1,243 3,959 1,902 4,299 24 46.52 4.53 720 1,902 2,622 621 607 1,228 127 924 389 1,118 1,507 65 778 2014 2013 456 1,250 664 3,995 20 84.13 3.90 $ $ 1,253 3,917 1,907 4,304 28 449 1,246 657 5,483 17 93.46 3.37 1,282 3,946 1,940 4,251 26 90.42 5.78 $ $ 100.26 5.91 $ $ $ $ 664 1,907 2,571 615 595 1,210 121 871 403 1,098 1,501 58 819 657 1,940 2,597 613 569 1,182 125 774 398 1,131 1,529 62 864 2 MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day; MBOEPD – thousands of barrels of oil-equivalents per day; Bbl – Barrel; MCF - Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of oil. Includes natural gas consumed in operations (MMCFPD): United States International Includes net production of synthetic oil: Canada Venezuela affiliate 66 430 47 29 71 452 43 31 Includes branded and unbranded gasoline. Includes sales of affiliates (MBPD): In 2015, the company sold its interests in affiliates in Australia and New Zealand, which included operable capacities of 55,000 and 12,000 barrels per day, respectively. 420 475 3 4 5 6 7 72 458 43 25 471 Chevron Corporation 2015 Annual Report 19 Management’s Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources Cash, Cash Equivalents, Time Deposits and Marketable Securities Total balances were $11.3 billion and $13.2 billion at December 31, 2015 and 2014, respectively. Cash provided by operating activities in 2015 was $19.5 billion, compared with $31.5 billion in 2014 and $35.0 billion in 2013. Cash provided by operating activities was net of contributions to employee pension plans of approximately $0.9 billion, $0.4 billion and $1.2 billion in 2015, 2014 and 2013, respectively. Cash provided by investing activities included proceeds and deposits related to asset sales of $5.7 billion in 2015, $5.7 billion in 2014, and $1.1 billion in 2013. Restricted cash of $1.1 billion and $1.5 billion at December 31, 2015 and 2014, respectively, was held in cash and short-term marketable securities and recorded as “Deferred charges and other assets” on the Consolidated Balance Sheet. These amounts are generally associated with upstream abandonment activities, tax payments, and funds held in escrow for tax-deferred exchanges and asset acquisitions and divestitures. Dividends Dividends paid to common stockholders were $8.0 billion in 2015, $7.9 billion in 2014 and $7.5 billion in 2013. Debt and Capital Lease Obligations Total debt and capital lease obligations were $38.6 billion at December 31, 2015, up from $27.8 billion at year-end 2014. The $10.8 billion increase in total debt and capital lease obligations during 2015 was primarily due to funding the company’s capital investment program, which included several large projects in the construction phase. The company completed bond issuances of $6 billion and $5 billion in March and November 2015, respectively. The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper, redeemable long-term obligations and the current portion of long-term debt, totaled $12.9 billion at December 31, 2015, compared with $11.8 billion at year-end 2014. Of these amounts, $8.0 billion was reclassified to long-term at the end of both periods. At year-end 2015, settlement of these obligations was not expected to require the use of working capital in 2016, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. Chevron has an automatic shelf registration statement nonconvertible debt securities issued or guaranteed by the company. that expires in August 2018 for an unspecified amount of Cash Provided by Operating Activities Billions of dollars Total Debt at Year-End Billions of dollars Total Capital & Exploratory Expenditures* Billions of dollars Ratio of Total Debt to Total Debt-Plus-Chevron Corporation Stockholders’ Equity Percent $38.6 45.0 36.0 27.0 18.0 9.0 0.0 $19.5 40.0 32.0 24.0 16.0 8.0 0.0 44.0 33.0 22.0 11.0 0.0 $34.0 24.0 18.0 12.0 6.0 0.0 20.2% 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 11 12 13 14 15 All Other Downstream Upstream *Includes equity in affiliates. Excludes the acquisition of Atlas Energy, Inc. in 2011. The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation and Texaco Capital Inc. All of these securities are the obligations of, or guaranteed by, Chevron Corporation. In February 2016, Standard & Poor’s Corporation changed its rating for these securities from AA to AA-. These securities are rated Aa1 by Moody’s Investors 20 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations Service. The company’s U.S. commercial paper is rated A-1+ by Standard & Poor’s and P-l by Moody’s. All of these ratings denote high-quality, investment-grade securities. The company’s future debt level is dependent primarily on results of operations, the capital program and cash that may be generated from asset dispositions. Based on its high-quality debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash requirements. During extended periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company can also modify capital spending plans to provide flexibility to continue paying the common stock dividend and also remain committed to retaining the company’s high-quality debt ratings. Committed Credit Facilities Information related to committed credit facilities is included in Note 19 to the Consolidated Financial Statements, Short-Term Debt, on page 56. Common Stock Repurchase Program In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits. The company did not acquire any shares under the program in 2015. From the inception of the program through 2014, the company had purchased 180.9 million shares for $20.0 billion. Capital and Exploratory Expenditures Capital and exploratory expenditures by business segment for 2015, 2014 and 2013 are as follows: Millions of dollars Upstream Downstream All Other Total Total, Excluding Equity in Affiliates 2015 Total Int’l. $ 23,535 513 8 $31,117 2,436 426 $ U.S. 8,799 1,649 584 U.S. 7,582 1,923 418 2014 Total Int’l. $ 28,316 941 27 $37,115 2,590 611 $ 2013 Total Int’l. $ 29,378 1,189 23 $ 37,858 3,175 844 U.S. 8,480 1,986 821 9,923 $ 24,056 $33,979 $ 11,032 $ 29,284 $40,316 $ 11,287 $ 30,590 $ 41,877 8,579 $ 22,003 $30,582 $ 10,011 $ 26,838 $36,849 $ 10,562 $ 28,617 $ 39,179 $ $ $ Total expenditures for 2015 were $34.0 billion, including $3.4 billion for the company’s share of equity-affiliate expenditures, which did not require cash outlays by the company. In 2014 and 2013, expenditures were $40.3 billion and $41.9 billion, expenditures of $3.5 billion and $2.7 billion, respectively. including the respectively, company’s share of affiliates’ Of the $34.0 billion of expenditures in 2015, 92 percent, or $31.1 billion, was related to upstream activities. Approximately 92 percent and 90 percent was expended for upstream operations in 2014 and 2013, respectively. International upstream accounted for 76 percent of the worldwide upstream investment in 2015, 76 percent in 2014 and 78 percent in 2013. The company estimates that 2016 capital and exploratory expenditures will be $26.6 billion, including $4.5 billion of spending by affiliates. This planned reduction, compared to 2015 expenditures, is in response to current crude oil market conditions. Approximately 90 percent of the total, or $24.0 billion, is budgeted for exploration and production activities. Approximately $9 billion of planned upstream capital spending is for existing base producing assets, which include shale and tight resource investments. Approximately $11 billion is related to major capital projects currently underway, and approximately $3 billion relates to projects yet to be sanctioned. Global exploration funding accounts for approximately $1 billion. The company will continue to monitor crude oil market conditions, and will further restrict capital outlays should current oil price conditions persist. Worldwide downstream spending in 2016 is estimated at $2.2 billion, with $1.6 billion for projects in the United States. Investments in technology companies and other corporate businesses in 2016 are budgeted at $0.4 billion. Noncontrolling Interests The company had noncontrolling interests of $1.2 billion at both December 31, 2015, and December 31, 2014. Distributions to noncontrolling interests totaled $128 million and $47 million in 2015 and 2014, respectively. Pension Obligations Information related to pension plan contributions is included on page 64 in Note 23 to the Consolidated Financial Statements under the heading “Cash Contributions and Benefit Payments.” Chevron Corporation 2015 Annual Report 21 Management’s Discussion and Analysis of Financial Condition and Results of Operations Financial Ratios Current Ratio Interest Coverage Ratio Debt Ratio 2015 1.3 9.9 20.2 % At December 31 2014 2013 1.3 87.2 15.2 % 12.1 % 1.5 126.2 Current Ratio Current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 2015, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $3.7 billion. Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt. The company’s interest coverage ratio in 2015 was lower than 2014 and 2013 due to lower income. Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage. The company’s debt ratio in 2015 was higher than 2014 and 2013 as the company took on more debt to finance its ongoing investment program. Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2016 – $2.1 billion; 2017 – $1.9 billion; 2018 – $1.7 billion; 2019 – $1.5 billion; 2020 – $1.1 billion; 2020 and after – $3.1 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $1.9 billion in 2015, $3.7 billion in 2014 and $3.6 billion in 2013. The following table summarizes the company’s significant contractual obligations: Millions of dollars On Balance Sheet:2 Short-Term Debt3 Long-Term Debt3 Noncancelable Capital Lease Obligations Interest Off Balance Sheet: Noncancelable Operating Lease Obligations Throughput and Take-or-Pay Agreements4 Other Unconditional Purchase Obligations4 Total1 2016 2017-2018 2019-2020 After 2020 Payments Due by Period $ 4,928 33,584 150 3,052 3,348 6,042 5,293 $ 4,928 $ — $ — $ — — 23 563 846 634 1,480 20,023 40 994 1,243 1,352 2,228 6,704 25 615 731 1,294 1,276 6,857 62 880 528 2,762 309 1 Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 23 beginning on page 59. 2 Does not include amounts related to the company’s income tax liabilities associated with uncertain tax positions. The company is unable to make reasonable estimates of the periods in which such liabilities may become payable. The company does not expect settlement of such liabilities to have a material effect on its consolidated financial position or liquidity in any single period. $8.0 billion of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule above reflects the projected repayment of the entire amounts in the 2017–2018 period. 3 4 Does not include commodity purchase obligations that are not fixed or determinable. These obligations are generally monetized in a relatively short period of time through sales transactions or similar agreements with third parties. Examples include obligations to purchase LNG, regasified natural gas and refinery products at indexed prices. 22 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations Direct Guarantees Millions of dollars Guarantee of nonconsolidated affiliate or joint-venture obligations Commitment Expiration by Period Total $447 2016 2017-2018 2019-2020 After 2020 $38 $76 $76 $257 The company’s guarantee of $447 million is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 12-year remaining term of the guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee. Indemnifications Information related to indemnifications is included on page 65 in Note 24 to the Consolidated Financial Statements under the heading “Indemnifications.” Financial and Derivative Instrument Market Risk The market risk associated with the company’s portfolio of financial and derivative instruments is discussed below. The estimates of financial exposure to market risk do not represent the company’s projection of future market changes. The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading “Risk Factors” in Part I, Item 1A, of the company’s 2015 Annual Report on Form 10-K. Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks. The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company refineries. The company also uses derivative commodity instruments for limited trading purposes. The results of these activities were not material to the company’s financial position, results of operations or cash flows in 2015. The company’s market exposure positions are monitored on a daily basis by an internal Risk Control group in accordance with the company’s risk management policies, which are reviewed by the Audit Committee of the company’s Board of Directors. Derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value of Chevron’s derivative commodity instruments in 2015 was not material to the company’s results of operations. The company uses the Monte Carlo simulation method with a 95 percent confidence level as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. A one-day holding period is used on the assumption that market-risk positions can be liquidated or hedged within one day. Based on these inputs, the VaR for the company’s primary risk exposures in the area of derivative commodity instruments at December 31, 2015 and 2014 was not material to the company’s cash flows or results of operations. Foreign Currency The company may enter into foreign currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The foreign currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open foreign currency derivative contracts at December 31, 2015. Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2015, the company had no interest rate swaps. Transactions With Related Parties Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” in Note 15 of the Consolidated Financial Statements, page 49, for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party. Chevron Corporation 2015 Annual Report 23 Management’s Discussion and Analysis of Financial Condition and Results of Operations Litigation and Other Contingencies MTBE Information related to methyl tertiary butyl ether (MTBE) matters is included on page 50 in Note 17 to the Consolidated Financial Statements under the heading “MTBE.” Ecuador Information related to Ecuador matters is included in Note 17 to the Consolidated Financial Statements under the heading “Ecuador,” beginning on page 50. Environmental The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for federal Superfund sites and analogous sites under state laws. Millions of dollars Balance at January 1 Net Additions Expenditures Balance at December 31 2015 1,683 365 (470) $ 2014 1,456 636 (409) $ 2013 1,403 488 (435) 1,578 $ 1,683 $ 1,456 $ $ The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to environmental issues. The liability balance of approximately $15.6 billion for asset retirement obligations at year-end 2015 related primarily to upstream properties. For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise abandon the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation. Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company’s 2015 environmental expenditures. Refer to Note 24 on page 66 for additional discussion of environmental remediation provisions and year-end reserves. Refer also to Note 25 on page 67 for additional discussion of the company’s asset retirement obligations. Suspended Wells Information related to suspended wells is included in Note 21 to the Consolidated Financial Statements, Accounting for Suspended Exploratory Wells, beginning on page 57. Income Taxes Information related to income tax contingencies is included on pages 53 through 56 in Note 18 and page 65 in Note 24 to the Consolidated Financial Statements under the heading “Income Taxes.” Other Contingencies Information related to other contingencies is included on page 66 in Note 24 to the Consolidated Financial Statements under the heading “Other Contingencies.” Environmental Matters The company is subject to various international, federal, state and local environmental, health and safety laws, regulations and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. For example, international agreements (e.g., the Paris Accord and the Kyoto Protocol) and national (e.g., carbon tax, cap-and-trade, or efficiency standards), regional, and state legislation (e.g., California’s AB32 or other low carbon fuel standards) and regulatory measures (e.g., the U.S. Environmental Protection Agency’s methane performance standards) to limit or reduce greenhouse gas (GHG) emissions are currently in various stages of discussion or implementation. Consideration of GHG issues and the responses to those issues through international agreements and national, regional or state legislation or regulation are integrated into the company’s strategy, planning and capital investment reviews, where applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect long-range effects from renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve at the international, national and state levels. Refer to “Risk Factors” in Part I, Item 1A, on pages 21 through 23 of the company’s Annual Report on Form 10-K for a discussion of some of the inherent risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of operations or financial condition. 24 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations Most of the costs of complying with existing laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business. However, it is not possible to predict with certainty the amount of additional investments in new or existing technology or facilities or the amounts of increased operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the environment; remediate and restore areas damaged by prior releases of nitrogen oxide, sulfur oxide, or other hazardous materials; or comply with new environmental laws or regulations. Although these costs may be significant to the results of operations in any single period, the company does not presently expect them to have a material adverse effect on the company’s liquidity or financial position. Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. The company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards. Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2015 at approximately $2.7 billion for its consolidated companies. Included in these expenditures were approximately $0.9 billion of environmental capital expenditures and $1.8 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the abandonment and restoration of sites. For 2016, total worldwide environmental capital expenditures are estimated at $0.6 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites. Critical Accounting Estimates and Assumptions Management makes many estimates and assumptions in the application of generally accepted accounting principles (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. Such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known. The discussion in this section of “critical” accounting estimates and assumptions is according to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein: 1. 2. the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and the impact of the estimates and assumptions on the company’s financial condition or operating performance is material. The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows: Oil and Gas Reserves Crude oil and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the Consolidated Financial Statements. Proved reserves are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future under existing economic conditions, operating methods and government regulations. Proved reserves include both developed and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion. Variables impacting Chevron’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development and production costs. The estimates of crude oil and natural gas reserves are important to the timing of expense recognition for costs incurred and to the valuation of certain oil and gas producing assets. Impacts of oil and gas reserves on Chevron’s Consolidated Financial Statements, using the successful efforts method of accounting, include the following: 1. Amortization - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves. During 2015, Chevron’s UOP Depreciation, Depletion and Amortization (DD&A) for Chevron Corporation 2015 Annual Report 25 Management’s Discussion and Analysis of Financial Condition and Results of Operations oil and gas properties was $13.9 billion, and proved developed reserves at the beginning of 2015 were 4.7 billion barrels for consolidated companies. If the estimates of proved reserves used in the UOP calculations for consolidated operations had been lower by 5 percent across all oil and gas properties, UOP DD&A in 2015 would have increased by approximately $730 million. 2. Impairment - Oil and gas reserves are used in assessing oil and gas producing properties for impairment. A significant reduction in the estimated reserves of a property would trigger an impairment review. Proved reserves (and, in some cases, a portion of unproved resources) are used to estimate future production volumes in the cash flow model. For a further discussion of estimates and assumptions used in impairment assessments, see Impairment of Properties, Plant and Equipment and Investments in Affiliates below. Refer to Table V, “Reserve Quantity Information,” beginning on page 74, for the changes in proved reserve estimates for the three years ending December 31, 2015, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page 80 for estimates of proved reserve values for each of the three years ended December 31, 2015. This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of Note 1 to the Consolidated Financial Statements, beginning on page 36, which includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities. Impairment of Properties, Plant and Equipment and Investments in Affiliates The company assesses its properties, plant and equipment (PP&E) for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters, such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are generally consistent with the company’s business plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in Note 16 beginning on page 49 and to the section on Properties, Plant and Equipment in Note 1, “Summary of Significant Accounting Policies,” beginning on page 36. The company routinely performs impairment reviews when triggering events arise to determine whether any write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable. Similarly, a significant downward revision in the company’s crude oil or natural gas price outlook would trigger impairment reviews for impacted upstream assets. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed of. Assets that are not impaired on a held-and- used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values. Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When this occurs, a determination must be made as to whether this loss is other-than-temporary, in which case the investment is impaired. Because of the number of differing assumptions potentially affecting whether an investment is impaired in any period or the amount of the impairment, a sensitivity analysis is not practicable. The company reported impairments for certain oil and gas properties during 2015 primarily as a result of downward revisions in the company’s longer-term crude oil price outlook. The impairments were primarily in Brazil and the United States. No material individual impairments of PP&E or Investments were recorded for the years 2014 and 2013. A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired, or resulted in larger impacts on impaired assets. 26 Chevron Corporation 2015 Annual Report Management’s Discussion and Analysis of Financial Condition and Results of Operations Asset Retirement Obligations In the determination of fair value for an asset retirement obligation (ARO), the company uses various assumptions and judgments, including such factors as the existence of a legal obligation, estimated amounts and timing of settlements, discount and inflation rates, and the expected impact of advances in technology and process improvements. A sensitivity analysis of the ARO impact on earnings for 2015 is not practicable, given the broad range of the company’s long-lived assets and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions would have reduced estimated future obligations, thereby lowering accretion expense and amortization costs, whereas unfavorable changes would have the opposite effect. Refer to Note 25 on page 67 for additional discussions on asset retirement obligations. Pension and Other Postretirement Benefit Plans Note 23, beginning on page 59, includes information on the funded status of the company’s pension and other postretirement benefit (OPEB) plans reflected on the Consolidated Balance Sheet; the components of pension and OPEB expense reflected on the Consolidated Statement of Income; and the related underlying assumptions. The determination of pension plan expense and obligations is based on a number of actuarial assumptions. Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations. Critical assumptions in determining expense and obligations for OPEB plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, are the discount rate and the assumed health care cost-trend rates. Information related to the Company’s processes to develop these assumptions is included on page 62 in Note 23 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes in the world’s financial markets. For 2015, the company used an expected long-term rate of return of 7.5 percent and a discount rate of 3.7 percent for U.S. pension plans. The actual return for 2015 was slightly negative due to a broad decline in financial markets in the second half of the year. For the 10 years ending December 31, 2015, actual asset returns averaged 5.0 percent for the plan. Additionally, with the exception of three years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.5 percent during each year. Total pension expense for 2015 was $1.2 billion. An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in this assumption for the company’s primary U.S. pension plan, which accounted for about 61 percent of companywide pension expense, would have reduced total pension plan expense for 2015 by approximately $95 million. A 1 percent increase in the discount rate for this same plan would have reduced pension expense for 2015 by approximately $221 million. The aggregate funded status recognized at December 31, 2015, was a net liability of approximately $4.5 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2015, the company used a discount rate of 4.0 percent to measure the obligations for the U.S. pension plans. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S. pension plan, which accounted for about 63 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $384 million, which would have decreased the plan’s underfunded status from approximately $1.7 billion to $1.3 billion. For the company’s OPEB plans, expense for 2015 was $271 million, and the total liability, which reflected the unfunded status of the plans at the end of 2015, was $3.3 billion. For the main U.S. OPEB plan, the company used a 4.1 percent discount rate to measure expense in 2015, and a 4.5 percent discount rate to measure the benefit obligations at December 31, 2015. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2015 OPEB expense and OPEB liabilities at the end of 2015. For information on the sensitivity of the health care cost-trend rate, refer to page 62 in Note 23 under the heading “Other Benefit Assumptions.” Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are included in actuarial gain/loss. Refer to page 61 in Note 23 for a description of the method used to amortize the $6.3 billion of before-tax actuarial losses recorded by the company as of December 31, 2015, and an estimate of the costs to be recognized in expense during 2016. In addition, information related to company contributions is included on page 64 in Note 23 under the heading “Cash Contributions and Benefit Payments.” Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability Chevron Corporation 2015 Annual Report 27 Management’s Discussion and Analysis of Financial Condition and Results of Operations and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology. Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally reports these losses as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is “more likely than not” (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 24 beginning on page 65. Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2015. An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss. New Accounting Standards Refer to Note 5 on page 40 for information regarding new accounting standards. Quarterly Results and Stock Market Data Unaudited Millions of dollars, except per-share amounts 4th Q 3rd Q 2nd Q 2015 1st Q 4th Q 3rd Q 2nd Q 2014 1st Q Revenues and Other Income Sales and other operating revenues1 Income from equity affiliates Other income Total Revenues and Other Income Costs and Other Deductions Purchased crude oil and products Operating expenses Selling, general and administrative expenses Exploration expenses Depreciation, depletion and amortization Taxes other than on income1 $28,014 $32,767 $36,829 $32,315 $42,111 $51,822 $55,583 $50,978 919 314 1,195 353 1,169 2,359 1,401 842 1,555 2,422 1,912 945 1,709 646 1,922 365 29,247 34,315 40,357 34,558 46,088 54,679 57,938 53,265 14,570 17,447 20,541 17,193 24,263 30,741 33,844 30,823 5,970 1,303 1,358 5,400 2,856 5,592 1,026 315 4,268 2,883 6,077 1,170 1,075 6,958 3,173 5,395 944 592 4,411 3,118 6,572 1,368 510 4,873 3,118 6,403 1,122 366 3,948 3,236 6,287 1,077 694 3,842 3,167 6,023 927 415 4,130 3,019 Total Costs and Other Deductions 31,457 31,531 38,994 31,653 40,704 45,816 48,911 45,337 Income (Loss) Before Income Tax Expense Income Tax Expense (Benefit) Net Income (Loss) (2,210) (1,655) 2,784 727 $ (555) $ 2,057 $ Less: Net income attributable to noncontrolling interests 33 20 1,363 755 608 37 2,905 305 5,384 1,912 8,863 3,236 9,027 3,337 7,928 3,407 $ 2,600 $ 3,472 $ 5,627 $ 5,690 $ 4,521 33 1 34 25 9 Net Income (Loss) Attributable to Chevron Corporation $ (588) $ 2,037 $ 571 $ 2,567 $ 3,471 $ 5,593 $ 5,665 $ 4,512 Per Share of Common Stock Net Income (Loss) Attributable to Chevron Corporation – Basic – Diluted Dividends Common Stock Price Range – High2 – Low2 1 Includes excise, value-added and similar taxes: 2 Intraday price. $ (0.31) $ $ (0.31) $ 1.09 1.09 1.07 $ $ 98.64 $ 77.31 1.07 $ $ 96.67 $ 69.58 $ $ 0.30 0.30 1.07 $ $112.20 $ 96.22 $ $ 1.38 1.37 1.07 $ $113.00 $ 98.88 $ $ 1.86 1.85 1.07 $ $120.17 $100.15 $ $ 2.97 2.95 1.07 $ $135.10 $118.66 $ $ 3.00 2.98 1.07 $ $133.57 $116.50 $ $ 2.38 2.36 1.00 $ $125.32 $109.27 $ 1,717 $ 1,800 $ 1,965 $ 1,877 $ 2,004 $ 2,116 $ 2,120 $ 1,946 The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 15, 2016, stockholders of record numbered approximately 145,000. There are no restrictions on the company’s ability to pay dividends. 28 Chevron Corporation 2015 Annual Report Management’s Responsibility for Financial Statements To the Stockholders of Chevron Corporation Management of Chevron Corporation is responsible for preparing the accompanying consolidated financial statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgments. As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management. The company’s management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in the Exchange Act Rules 13a- 15(e) and 15d-15(e)) as of December 31, 2015. Based on that evaluation, management concluded that the company’s disclosure controls are effective in ensuring that information required to be recorded, processed, summarized and reported, are done within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms. 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 defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and 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, 2015. The effectiveness of the company’s internal control over financial reporting as of December 31, 2015, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein. John S. Watson Chairman of the Board and Chief Executive Officer February 25, 2016 Patricia E. Yarrington Vice President and Chief Financial Officer Jeanette L. Ourada Vice President and Comptroller Chevron Corporation 2015 Annual Report 29 Report of Independent Registered Public Accounting Firm To the Stockholders and the Board of Directors of Chevron Corporation: In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity and of cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2015, and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. San Francisco, California February 25, 2016 30 Chevron Corporation 2015 Annual Report Consolidated Statement of Income Millions of dollars, except per-share amounts Revenues and Other Income Sales and other operating revenues* Income from equity affiliates Other income Total Revenues and Other Income Costs and Other Deductions Purchased crude oil and products Operating expenses Selling, general and administrative expenses Exploration expenses Depreciation, depletion and amortization Taxes other than on income* Total Costs and Other Deductions Income Before Income Tax Expense Income Tax Expense Net Income Less: Net income attributable to noncontrolling interests Net Income Attributable to Chevron Corporation Per Share of Common Stock Net Income Attributable to Chevron Corporation – Basic – Diluted * Includes excise, value-added and similar taxes. See accompanying Notes to the Consolidated Financial Statements. Year ended December 31 2015 2014 2013 $ 129,925 4,684 3,868 $ 200,494 7,098 4,378 $ 220,156 7,527 1,165 138,477 211,970 228,848 69,751 23,034 4,443 3,340 21,037 12,030 133,635 4,842 132 4,710 123 4,587 119,671 25,285 4,494 1,985 16,793 12,540 180,768 31,202 11,892 19,310 69 134,696 24,627 4,510 1,861 14,186 13,063 192,943 35,905 14,308 21,597 174 $ 19,241 $ 21,423 2.46 2.45 7,359 $ $ $ 10.21 10.14 8,186 $ $ $ 11.18 11.09 8,492 $ $ $ $ Chevron Corporation 2015 Annual Report 31 Consolidated Statement of Comprehensive Income Millions of dollars Net Income Currency translation adjustment Unrealized net change arising during period Unrealized holding loss on securities Net loss arising during period Derivatives Net derivatives loss on hedge transactions Reclassification to net income of net realized gain Income taxes on derivatives transactions Total Defined benefit plans Actuarial gain (loss) Amortization to net income of net actuarial loss and settlements Actuarial gain (loss) arising during period Prior service credits (cost) Amortization to net income of net prior service costs (credits) and curtailments Prior service credits (costs) arising during period Defined benefit plans sponsored by equity affiliates Income taxes on defined benefit plans Total Other Comprehensive Gain (Loss), Net of Tax Comprehensive Income Comprehensive income attributable to noncontrolling interests Year ended December 31 2015 2014 2013 $ 4,710 $ 19,310 $ 21,597 (44) (21) — — —2 — 794 109 30 6 30 (336) 633 568 5,278 (123) (73) (2) (66) (17) 9 (54) 757 (2,730) 26 (6) (99) 901 (1,151) (1,280) 18,030 (69) 42 (7) (111) (1) 39 (73) 866 3,379 (27) 60 164 (1,614) 2,828 2,790 24,387 (174) Comprehensive Income Attributable to Chevron Corporation $ 5,155 $ 17,961 $ 24,213 See accompanying Notes to the Consolidated Financial Statements. 32 Chevron Corporation 2015 Annual Report Consolidated Balance Sheet Millions of dollars, except per-share amount Assets Cash and cash equivalents Time deposits Marketable securities Accounts and notes receivable (less allowance: 2015 - $313; 2014 - $59) Inventories: Crude oil and petroleum products Chemicals Materials, supplies and other Total inventories Prepaid expenses and other current assets Total Current Assets Long-term receivables, net Investments and advances Properties, plant and equipment, at cost Less: Accumulated depreciation, depletion and amortization Properties, plant and equipment, net Deferred charges and other assets Goodwill Assets held for sale Total Assets Liabilities and Equity Short-term debt Accounts payable Accrued liabilities Federal and other taxes on income Other taxes payable Total Current Liabilities Long-term debt Capital lease obligations Deferred credits and other noncurrent obligations Noncurrent deferred income taxes Noncurrent employee benefit plans Total Liabilities Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued) Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares issued at December 31, 2015 and 2014) Capital in excess of par value Retained earnings Accumulated other comprehensive loss Deferred compensation and benefit plan trust Treasury stock, at cost (2015 - 559,862,580 shares; 2014 - 563,027,772 shares) Total Chevron Corporation Stockholders’ Equity Noncontrolling interests Total Equity Total Liabilities and Equity See accompanying Notes to the Consolidated Financial Statements. At December 31 2015 2014 $ $ $ 11,022 — 310 12,860 3,535 490 2,309 6,334 4,821 35,347 2,412 27,110 340,277 151,881 188,396 6,801 4,588 1,449 266,103 4,928 13,516 4,833 2,069 1,118 26,464 33,584 80 23,465 20,689 7,935 112,217 — 1,832 16,330 181,578 (4,291) (240) (42,493) 152,716 1,170 153,886 $ $ $ 12,785 8 422 16,736 3,854 467 2,184 6,505 5,776 42,232 2,817 26,912 327,289 144,116 183,173 6,299 4,593 — 266,026 3,790 19,000 5,328 2,575 1,233 31,926 23,960 68 23,549 21,920 8,412 109,835 — 1,832 16,041 184,987 (4,859) (240) (42,733) 155,028 1,163 156,191 $ 266,103 $ 266,026 Chevron Corporation 2015 Annual Report 33 Consolidated Statement of Cash Flows Millions of dollars Operating Activities Net Income Adjustments Depreciation, depletion and amortization Dry hole expense Distributions less than income from equity affiliates Net before-tax gains on asset retirements and sales Net foreign currency effects Deferred income tax provision Net increase in operating working capital (Increase) decrease in long-term receivables Decrease (increase) in other deferred charges Cash contributions to employee pension plans Other Net Cash Provided by Operating Activities Investing Activities Capital expenditures Proceeds and deposits related to asset sales Net maturities of time deposits Net sales (purchases) of marketable securities Net (borrowing) repayment of loans by equity affiliates Net sales (purchases) of other short-term investments Net Cash Used for Investing Activities Financing Activities Net (repayments) borrowings of short-term obligations Proceeds from issuances of long-term debt Repayments of long-term debt and other financing obligations Cash dividends - common stock Distributions to noncontrolling interests Net sales (purchases) of treasury shares Net Cash Provided by (Used for) Financing Activities Effect of Exchange Rate Changes on Cash and Cash Equivalents Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at January 1 Cash and Cash Equivalents at December 31 See accompanying Notes to the Consolidated Financial Statements. Year ended December 31 2015 2014 2013 $ 4,710 $ 19,310 $ 21,597 21,037 2,309 (760) (3,215) (82) (1,861) (1,979) (59) 25 (868) 199 19,456 (29,504) 5,739 8 122 (217) 44 (23,808) (335) 11,091 (32) (7,992) (128) 211 2,815 (226) (1,763) 12,785 16,793 875 (2,202) (3,540) (277) 1,572 (540) (9) 263 (392) (378) 31,475 (35,407) 5,729 — (148) 140 (207) (29,893) 3,431 4,000 (43) (7,928) (47) (4,412) (4,999) (43) (3,460) 16,245 14,186 683 (1,178) (639) (103) 1,876 (1,331) 183 (321) (1,194) 1,243 35,002 (37,985) 1,143 700 3 314 216 (35,609) 2,378 6,000 (132) (7,474) (99) (4,494) (3,821) (266) (4,694) 20,939 $ 11,022 $ 12,785 $ 16,245 34 Chevron Corporation 2015 Annual Report Consolidated Statement of Equity Shares in thousands; amounts in millions of dollars Preferred Stock Common Stock Capital in Excess of Par Balance at January 1 Treasury stock transactions Balance at December 31 Retained Earnings Balance at January 1 Net income attributable to Chevron Corporation Cash dividends on common stock Stock dividends Tax (charge) benefit from dividends paid on unallocated ESOP shares and other Balance at December 31 Accumulated Other Comprehensive Loss Currency translation adjustment Balance at January 1 Change during year Balance at December 31 Unrealized net holding (loss) gain on securities Balance at January 1 Change during year Balance at December 31 Net derivatives (loss) gain on hedge transactions Balance at January 1 Change during year Balance at December 31 Pension and other postretirement benefit plans Balance at January 1 Change during year Balance at December 31 Balance at December 31 Deferred Compensation and Benefit Plan Trust Deferred Compensation Balance at January 1 Net reduction of ESOP debt and other Balance at December 31 Benefit Plan Trust (Common Stock) Balance at December 31 Treasury Stock at Cost Balance at January 1 Purchases Issuances - mainly employee benefit plans 2015 2014 2013 Shares Amount Shares Amount Shares Amount — $ — — $ — — $ — 2,442,677 $ 1,832 2,442,677 $ 1,832 2,442,677 $ 1,832 $ $ $ 16,041 289 16,330 184,987 4,587 (7,992) (3) (1) $ 181,578 $ $ $ $ $ $ $ $ $ $ $ 14,168 14,168 $ (96) (44) (140) (8) (21) (29) (2) — (2) (4,753) 633 (4,120) (4,291) — — — (240) (240) $ $ 15,713 328 16,041 $ 173,677 19,241 (7,928) (3) — $ 184,987 $ $ $ $ $ $ $ $ $ $ $ (23) (73) (96) (6) (2) (8) 52 (54) (2) (3,602) (1,151) (4,753) (4,859) — — — $ $ 15,497 216 15,713 $ 159,730 21,423 (7,474) (3) 1 $ 173,677 $ $ $ $ $ $ $ $ $ $ $ (65) 42 (23) 1 (7) (6) 125 (73) 52 (6,430) 2,828 (3,602) (3,579) (42) 42 — (240) (240) 14,168 14,168 $ (240) (240) 14,168 14,168 $ 563,028 $ 15 (3,180) (42,733) (2) 242 529,074 $ (38,290) (5,006) 41,592 563 (7,638) 495,979 $ (33,884) (5,004) 41,676 598 (8,581) Balance at December 31 559,863 $ (42,493) 563,028 $ (42,733) 529,074 $ (38,290) Total Chevron Corporation Stockholders’ Equity at December 31 Noncontrolling Interests Total Equity See accompanying Notes to the Consolidated Financial Statements. $ $ $ 152,716 1,170 153,886 $ 155,028 $ 1,163 $ 156,191 $ 149,113 $ 1,314 $ 150,427 Chevron Corporation 2015 Annual Report 35 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 1 Summary of Significant Accounting Policies General The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur. Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable-interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method. As part of that accounting, the company recognizes gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company’s proportionate share of the dollar amount of the affiliate’s equity currently in income. Investments in affiliates are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value. Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values. Fair Value Measurements The three levels of the fair value hierarchy of inputs the company uses to measure the fair value of an asset or a liability are as follows. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market. Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from derivative instruments are reported in current income. The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet. Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt securities. Those investments that are part of the company’s cash management portfolio and have original maturities of three months or less are reported as “Cash equivalents.” Bank time deposits with maturities greater than 90 days are reported as “Time deposits.” The balance of short-term investments is reported as “Marketable securities” and is marked-to-market, with any unrealized gains or losses included in “Other comprehensive income.” Inventories Crude oil, petroleum products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories generally are stated at average cost. Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending 36 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 21, beginning on page 57, for additional discussion of accounting for suspended exploratory well costs. Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net before-tax cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast), significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net before-tax cash flows. For proved crude oil and natural gas properties, the company performs impairment reviews on a country, concession, PSC, development area or field basis, as appropriate. In Downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9, beginning on page 42, relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25, on page 67, relating to AROs. Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of- production method by individual field as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method is generally used to depreciate international plant and equipment and to amortize all capitalized leased assets. Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses, and from sales as “Other income.” Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized. Goodwill Goodwill resulting from a business combination is not subject to amortization. The company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized. Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 25, on page 67, for a discussion of the company’s AROs. For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs, and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured. Chevron Corporation 2015 Annual Report 37 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency remeasurement are included in current period income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity. Revenue Recognition Revenues associated with sales of crude oil, natural gas, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are generally recognized using the entitlement method. Excise, value-added and similar taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer are presented on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income, on page 31. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income. Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to certain employees. For equity awards, such as stock options, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period an employee becomes eligible to retain the award at retirement. Stock options and stock appreciation rights granted under the company’s Long-Term Incentive Plan have graded vesting provisions by which one-third of each award vests on the first, second and third anniversaries of the date of grant. The company amortizes these graded awards on a straight-line basis. Note 2 Changes in Accumulated Other Comprehensive Losses The change in Accumulated Other Comprehensive Losses (AOCL) presented on the Consolidated Balance Sheet and the impact of significant amounts reclassified from AOCL on information presented in the Consolidated Statement of Income for the year ending December 31, 2015, are reflected in the table below. Balance at January 1 Components of Other Comprehensive Income (Loss): Before Reclassifications Reclassifications2 Net Other Comprehensive Income (Loss) Balance at December 31 Year Ended December 31, 20151 Currency Translation Adjustment Unrealized Holding Gains (Losses) on Securities Derivatives Defined Benefit Plans Total $ (96) $ (8) $ (2) $ (4,753) $ (4,859) (44) — (44) (21) — (21) — — — 126 507 633 61 507 568 $ (140) $ (29) $ (2) $ (4,120) $ (4,291) 1 All amounts are net of tax. 2 Refer to Note 23 beginning on page 59, for reclassified components totaling $824 that are included in employee benefit costs for the year ending December 31, 2015. Related income taxes for the same period, totaling $317, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant. Note 3 Noncontrolling Interests Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income. The term “earnings” is defined as “Net Income Attributable to Chevron Corporation.” 38 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Activity for the equity attributable to noncontrolling interests for 2015, 2014 and 2013 is as follows: Balance at January 1 Net income Distributions to noncontrolling interests Other changes, net Balance at December 31 Note 4 Information Relating to the Consolidated Statement of Cash Flows $ 2015 1,163 123 (128) 12 $ 2014 1,314 69 (47) (173) 1,170 $ 1,163 $ 2013 1,308 174 (99) (69) 1,314 $ $ Year ended December 31 2015 2014 2013 Net increase in operating working capital was composed of the following: Decrease (increase) in accounts and notes receivable Decrease (increase) in inventories Decrease (increase) in prepaid expenses and other current assets (Decrease) increase in accounts payable and accrued liabilities Decrease in income and other taxes payable Net increase in operating working capital Net cash provided by operating activities includes the following cash payments for income taxes: Income taxes Net sales (purchases) of marketable securities consisted of the following gross amounts: Marketable securities purchased Marketable securities sold Net sales (purchases) of marketable securities Net maturities of time deposits consisted of the following gross amounts: Investments in time deposits Maturities of time deposits Net maturities of time deposits Net (repayments) borrowings of short-term obligations consisted of the following gross and net amounts: Proceeds from issuances of short-term obligations Repayments of short-term obligations Net borrowings (repayments) of short-term obligations with three months or less maturity Net (repayments) borrowings of short-term obligations $ $ $ $ $ $ $ $ $ 3,631 85 713 (5,769) (639) (1,979) 4,645 (6) 128 122 $ $ $ $ $ — $ 8 8 $ $ 4,491 (146) (407) (3,737) (741) (540) $ (1,101) (237) 834 160 (987) (1,331) 10,562 $ 12,898 (162) $ 14 (148) $ (317) $ 317 — $ (7) 10 3 (2,317) 3,017 700 1,551 (375) 1,202 2,378 $ 13,805 (16,379) 2,239 $ 9,070 (4,612) (1,027) (335) $ 3,431 $ The “Net increase in operating working capital” includes reductions of $17, $58 and $79 for excess income tax benefits associated with stock options exercised during 2015, 2014 and 2013, respectively. These amounts are offset by an equal amount in “Net sales (purchases) of treasury shares.” “Other” includes changes in postretirement benefits obligations and other long-term liabilities. The “Net sales (purchases) of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $2, $5,006 and $5,004 in 2015, 2014 and 2013, respectively. No purchases were made under the company’s share repurchase program in 2015. In 2014 and 2013, the company purchased 41.5 million and 41.6 million common shares for $5,000 and $5,000 under its share repurchase program, respectively. In 2015, 2014 and 2013, “Net sales (purchases) of other short-term investments” generally consisted of restricted cash associated with upstream abandonment activities, tax payments, and funds held in escrow for tax-deferred exchanges and asset acquisitions and divestitures that was invested in cash and short-term securities and reclassified from “Cash and cash equivalents” to “Deferred charges and other assets” on the Consolidated Balance Sheet. The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. “Depreciation, depletion and amortization,” “Dry hole expense” and “Deferred income tax provision” collectively include approximately $3,700 in non-cash reductions to properties, plant and equipment recorded in 2015 relating to impairments and project suspensions and associated adverse tax effects, primarily as a result of downward revisions in the company’s longer-term crude oil price outlook. Chevron Corporation 2015 Annual Report 39 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Refer also to Note 25, on page 67, for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2015. The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, are presented in the following table: Year ended December 31 Additions to properties, plant and equipment * Additions to investments Current-year dry hole expenditures Payments for other liabilities and assets, net Capital expenditures Expensed exploration expenditures Assets acquired through capital lease obligations and other financing obligations Capital and exploratory expenditures, excluding equity affiliates Company’s share of expenditures by equity affiliates $ $ 2015 28,213 555 736 — 29,504 1,031 47 30,582 3,397 $ 2014 34,393 526 504 (16) 35,407 1,110 332 36,849 3,467 Capital and exploratory expenditures, including equity affiliates $ 33,979 $ 40,316 $ * Excludes noncash additions of $1,362 in 2015, $2,310 in 2014 and $1,661 in 2013. 2013 36,550 934 594 (93) 37,985 1,178 16 39,179 2,698 41,877 Note 5 New Accounting Standards Revenue Recognition (Topic 606), Revenue from Contracts with Customers (ASU 2014-09) In July 2015, the FASB approved a one-year deferral of the effective date of ASU 2014-09, which becomes effective for the company January 1, 2018. Early adoption is permitted at the original effective date of January 1, 2017. The standard provides a single industry-specific revenue comprehensive revenue recognition model for contracts with customers, eliminates most recognition guidance, and expands disclosure requirements. The company is evaluating the effect of the standard on its consolidated financial statements. The company does not intend to proceed with early adoption. Income Taxes (Topic 740), Balance Sheet Classification of Deferred Taxes (ASU 2015-17) In November 2015, FASB issued ASU 2015-17, which becomes effective for the company January 1, 2017. Early adoption is permitted. The standard provides that all deferred income taxes be classified as noncurrent on the balance sheet. The current requirement is to classify most deferred tax assets and liabilities based on the classification of the underlying asset or liability. Adoption of the standard will not have an impact on the company’s results of operations or liquidity. Note 6 Lease Commitments Certain noncancelable leases are classified as capital leases, and the leased assets are included as part of “Properties, plant and equipment, at cost” on the Consolidated Balance Sheet. Such leasing arrangements involve crude oil production and processing equipment, service stations, bareboat charters, office buildings, and other facilities. Other leases are classified as operating leases and are not capitalized. The payments on operating leases are recorded as expense. Details of the capitalized leased assets are as follows: Upstream Downstream All Other Total Less: Accumulated amortization Net capitalized leased assets 40 Chevron Corporation 2015 Annual Report At December 31 2015 800 98 — 898 448 450 $ $ $ $ 2014 765 97 — 862 381 481 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Rental expenses incurred for operating leases during 2015, 2014 and 2013 were as follows: Minimum rentals Contingent rentals Total Less: Sublease rental income Net rental expense Year ended December 31 2015 1,041 2 1,043 9 1,034 $ $ $ $ $ 2014 1,080 1 1,081 14 1,067 $ 2013 1,049 1 1,050 25 1,025 Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging up to 25 years, and options to purchase the leased property during or at the end of the initial or renewal lease period for the fair market value or other specified amount at that time. At December 31, 2015, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a noncancelable term of more than one year, were as follows: Year 2016 2017 2018 2019 2020 Thereafter Total Less: Amounts representing interest and executory costs Net present values Less: Capital lease obligations included in short-term debt Long-term capital lease obligations At December 31 Operating Leases Capital Leases $ $ 846 689 554 420 311 528 3,348 $ $ $ $ 23 21 19 19 6 62 150 (53) 97 (17) 80 Note 7 Summarized Financial Data – Chevron U.S.A. Inc. Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. The summarized financial information for CUSA and its consolidated subsidiaries is as follows: Sales and other operating revenues Total costs and other deductions Net income (loss) attributable to CUSA Current assets Other assets Current liabilities Other liabilities Total CUSA net equity Memo: Total debt $ 2015 97,766 101,565 (1,054) $ Year ended December 31 2014 157,198 153,139 3,849 2015 9,732 59,170 13,664 29,100 26,138 14,462 $ $ $ $ $ $ $ 2013 174,318 169,984 3,714 2014 13,724 62,195 16,191 30,175 29,553 14,473 Chevron Corporation 2015 Annual Report 41 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 8 Summarized Financial Data – Tengizchevroil LLP Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 15, beginning on page 48, for a discussion of TCO operations. Summarized financial information for 100 percent of TCO is presented in the table below: Sales and other operating revenues Costs and other deductions Net income attributable to TCO Current assets Other assets Current liabilities Other liabilities Total TCO net equity $ 2015 12,811 7,257 3,897 Year ended December 31 2014 22,813 10,275 8,772 $ 2013 25,239 11,173 9,855 At December 31 2015 2,098 17,094 1,063 2,266 15,863 $ $ 2014 3,425 14,810 1,531 2,375 14,329 $ $ $ Note 9 Fair Value Measurements The tables below and on the next page show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2015, and December 31, 2014. Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets. The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2015. Derivatives The company records its derivative instruments – other than any commodity derivative contracts that are designated as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options and forward contracts principally with financial institutions and other oil and gas companies, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information. Properties, Plant and Equipment The company reported impairments for certain oil and gas properties during 2015 primarily as a result of downward revisions in the company’s longer-term crude oil price outlook. The impairments were primarily in Brazil and the United States. The company reported impairments for certain oil and gas properties and a mining asset in 2014. Investments and Advances The company did not have any material investments and advances measured at fair value on a nonrecurring basis to report in 2015 or 2014. Assets and Liabilities Measured at Fair Value on a Recurring Basis Marketable securities Derivatives Total Assets at Fair Value Derivatives Total Liabilities at Fair Value At December 31, 2015 At December 31, 2014 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 $ $ $ 310 $ 205 515 $ 53 53 $ 310 $ 189 499 $ 47 47 $ — $ 16 16 $ 6 6 $ — $ — — $ — — $ 422 $ 413 835 $ 84 84 $ 422 $ 394 816 $ 83 83 $ — $ 19 19 $ 1 1 $ — — — — — 42 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Total Level 1 Level 2 Level 3 At December 31 Before-Tax Loss Year 2015 Total Level 1 Level 2 Level 3 At December 31 Before-Tax Loss Year 2014 Properties, plant and equipment, net (held and used) $ 3,051 $ — $ 239 $ 2,812 $ 3,222 $ 947 $ — $ 213 $ 734 $ 1,249 Properties, plant and equipment, net (held for sale) Investments and advances Total Nonrecurring Assets at Fair 937 75 — — 937 75 — — 844 28 — 11 — — — — — 11 25 41 Value $ 4,063 $ — $ 1,251 $ 2,812 $ 4,094 $ 958 $ — $ 213 $ 745 $ 1,315 Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents and time deposits in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $11,022 and $12,785 at December 31, 2015, and December 31, 2014, respectively. The instruments held in “Time deposits” are bank time deposits with maturities greater than 90 days, and had carrying/fair values of zero and $8 at December 31, 2015, and December 31, 2014, respectively. The fair values of cash, cash equivalents and bank time deposits are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2015. “Cash and cash equivalents” do not include investments with a carrying/fair value of $1,100 and $1,474 at December 31, 2015, and December 31, 2014, respectively. At December 31, 2015, these investments are classified as Level 1 and include restricted funds related to upstream abandonment activities, tax payments, and funds held in escrow for tax- deferred exchanges and asset acquisitions and divestitures, which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $25,584 and $15,960 at December 31, 2015, and December 31, 2014, had estimated fair values of $25,884 and $16,450, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $25,117 and classified as Level 1. The fair value of the other bonds is $767 and classified as Level 2. The carrying values of short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values. Fair value remeasurements of other financial instruments at December 31, 2015 and 2014, were not material. Note 10 Financial and Derivative Instruments Derivative Commodity Instruments The company’s derivative commodity instruments principally include crude oil, natural gas and refined product futures, swaps, options, and forward contracts. None of the company’s derivative instruments is designated as a hedging instrument, although certain of the company’s affiliates make such designation. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodity derivative activities. The company uses derivative commodity instruments traded on the New York Mercantile Exchange and on electronic platforms of the Inter-Continental Exchange and Chicago Mercantile Exchange. In addition, the company enters into swap contracts and option contracts principally with major financial institutions and other oil and gas companies in the “over-the-counter” markets, which are governed by International Swaps and Derivatives Association agreements and other master netting arrangements. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required. Derivative instruments measured at fair value at December 31, 2015, December 31, 2014, and December 31, 2013, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are on the next page: Chevron Corporation 2015 Annual Report 43 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Consolidated Balance Sheet: Fair Value of Derivatives Not Designated as Hedging Instruments Type of Contract Balance Sheet Classification Commodity Commodity Accounts and notes receivable, net Long-term receivables, net Total Assets at Fair Value Commodity Commodity Total Liabilities at Fair Value Accounts payable Deferred credits and other noncurrent obligations At December 31 2015 2014 $ $ $ $ 200 5 205 51 2 53 $ $ $ $ 401 12 413 57 27 84 Consolidated Statement of Income: The Effect of Derivatives Not Designated as Hedging Instruments Type of Derivative Contract Commodity Commodity Commodity Statement of Income Classification Sales and other operating revenues Purchased crude oil and products Other income Gain/(Loss) Year ended December 31 2015 277 30 (3) $ 2014 553 (17) (32) $ 304 $ 504 $ 2013 (108) (77) (9) (194) $ $ The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2015 and December 31, 2014. Consolidated Balance Sheet: The Effect of Netting Derivative Assets and Liabilities At December 31, 2015 Derivative Assets Derivative Liabilities At December 31, 2014 Derivative Assets Derivative Liabilities Gross Amount Recognized Gross Amounts Offset Net Amounts Presented Gross Amounts Not Offset Net Amount $ $ $ $ 2,459 2,307 4,004 3,675 $ $ $ $ 2,254 2,254 3,591 3,591 $ $ $ $ 205 53 413 84 $ $ $ $ — $ — $ 7 $ — $ 205 53 406 84 Derivative assets and liabilities are classified on the Consolidated Balance Sheet as accounts and notes receivable, long-term receivables, accounts payable, and deferred credits and other noncurrent obligations. Amounts not offset on the Consolidated Balance Sheet represent positions that do not meet all the conditions for “a right of offset.” Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, time deposits, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. Company investment policies limit the company’s exposure both to credit risk and to concentrations of credit risk. Similar policies on diversification and creditworthiness are applied to the company’s counterparties in derivative instruments. The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a result, the company believes concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, alternative risk mitigation measures may be deployed, including requiring pre-payments, letters of credit or other acceptable collateral instruments to support sales to customers. Note 11 Assets Held for Sale At December 31, 2015, the company classified $1,449 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream and downstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2015 were not material. 44 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 12 Equity Retained earnings at December 31, 2015 and 2014, included approximately $15,010 and $14,512, respectively, for the company’s share of undistributed earnings of equity affiliates. At December 31, 2015, about 114 million shares of Chevron’s common stock remained available for issuance from the 260 million shares that were reserved for issuance under the Chevron Long-Term Incentive Plan. In addition, approximately 120,753 shares remain available for issuance from the 800,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan. Note 13 Earnings Per Share Basic earnings per share (EPS) is based upon “Net Income Attributable to Chevron Corporation” (“earnings”) and includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note 22, “Stock Options and Other Share-Based Compensation,” beginning on page 58). The table below sets forth the computation of basic and diluted EPS: Basic EPS Calculation Earnings available to common stockholders - Basic* Weighted-average number of common shares outstanding Add: Deferred awards held as stock units Total weighted-average number of common shares outstanding Earnings per share of common stock - Basic Diluted EPS Calculation Earnings available to common stockholders - Diluted* Weighted-average number of common shares outstanding Add: Deferred awards held as stock units Add: Dilutive effect of employee stock-based awards Total weighted-average number of common shares outstanding Earnings per share of common stock - Diluted Year ended December 31 2015 2014 2013 4,587 $ 19,241 $ 21,423 1,867 1 1,868 1,883 1 1,884 2.46 $ 10.21 $ 1,916 1 1,917 11.18 4,587 $ 19,241 $ 21,423 1,867 1 71 1,875 1,883 1 4 1,898 2.45 $ 10.14 $ 1,916 1 15 1,932 11.09 $ $ $ $ * There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings. Note 14 Operating Segments and Geographic Data Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments.” Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids plant. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of 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. All Other activities of the company include worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies. The company’s segments are managed by “segment managers” who report to the “chief operating decision maker” (CODM). The segments represent components of the company that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available. The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States). Chevron Corporation 2015 Annual Report 45 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” Earnings by major operating area are presented in the following table: Year ended December 31 2015 2014 2013 Upstream United States International Total Upstream Downstream United States International Total Downstream Total Segment Earnings All Other Interest income Other $ (4,055) $ 2,094 (1,961) 3,182 4,419 7,601 5,640 65 (1,118) $ 3,327 13,566 16,893 2,637 1,699 4,336 21,229 77 (2,065) Net Income Attributable to Chevron Corporation $ 4,587 $ 19,241 $ 4,044 16,765 20,809 787 1,450 2,237 23,046 80 (1,703) 21,423 Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2015 and 2014 are as follows: Upstream United States International Goodwill Total Upstream Downstream United States International Total Downstream Total Segment Assets All Other United States International Total All Other Total Assets – United States Total Assets – International Goodwill Total Assets 1 2014 conformed to 2015 presentation. At December 31 2015 20141 $ $ 46,407 163,217 4,588 214,212 21,408 14,982 36,390 250,602 5,076 10,425 15,501 72,891 188,624 4,588 $ 266,103 $ 49,343 152,736 4,593 206,672 23,068 17,723 40,791 247,463 6,603 11,960 18,563 79,014 182,419 4,593 266,026 Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2015, 2014 and 2013, are presented in the table on the next page. Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from insurance operations, real estate activities and technology companies. 46 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Year ended December 31 Upstream United States Intersegment Total United States International Intersegment Total International Total Upstream* Downstream United States Excise and similar taxes Intersegment Total United States International Excise and similar taxes Intersegment Total International Total Downstream* All Other United States Intersegment Total United States International Intersegment Total International Total All Other Segment Sales and Other Operating Revenues United States International Total Segment Sales and Other Operating Revenues Elimination of intersegment sales $ $ 2015 4,117 8,631 12,748 15,587 11,492 27,079 39,827 48,420 4,426 26 52,872 54,296 2,933 1,528 58,757 $ 2014 7,455 15,455 22,910 23,808 23,107 46,915 69,825 73,942 4,633 31 78,606 86,848 3,553 8,839 99,240 111,629 177,846 141 1,372 1,513 5 37 42 1,555 67,133 85,878 153,011 (23,086) 252 1,475 1,727 3 28 31 1,758 103,243 146,186 249,429 (48,935) Total Sales and Other Operating Revenues $ 129,925 $ 200,494 $ 2013 8,052 16,865 24,917 17,607 33,034 50,641 75,558 80,272 4,792 39 85,103 105,373 3,699 859 109,931 195,034 358 1,524 1,882 3 31 34 1,916 111,902 160,606 272,508 (52,352) 220,156 * Effective January 1, 2014, International Upstream prospectively includes selected amounts previously recognized in International Downstream, which are not material to the segments. Segment Income Taxes Segment income tax expense for the years 2015, 2014 and 2013 is as follows: Upstream United States International Total Upstream Downstream United States International Total Downstream All Other $ 2015 (2,041) 1,214 (827) 1,320 1,313 2,633 (1,674) $ $ 2,043 9,217 11,260 1,302 467 1,769 (1,137) Total Income Tax Expense $ 132 $ 11,892 $ 2,333 12,470 14,803 364 389 753 (1,248) 14,308 Year ended December 31 2013 2014 Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 15, on page 48. Information related to properties, plant and equipment by segment is contained in Note 16, on page 49. Chevron Corporation 2015 Annual Report 47 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 15 Investments and Advances Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.” Upstream Tengizchevroil Petropiar Caspian Pipeline Consortium Petroboscan Angola LNG Limited Other Total Upstream Downstream GS Caltex Corporation Chevron Phillips Chemical Company LLC Caltex Australia Ltd. Other Total Downstream All Other Other Total equity method Other at or below cost Total investments and advances Total United States Total International *2014 conformed to 2015 presentation. Investments and Advances At December 31* Equity in Earnings Year ended December 31 2015 8,077 679 1,342 1,163 3,284 2,158 16,703 3,620 5,196 — 1,077 9,893 (18) 26,578 532 27,110 6,863 20,247 $ $ $ $ $ 2014 7,319 794 1,487 917 3,277 2,316 16,110 2,867 5,116 1,161 1,048 10,192 33 26,335 577 26,912 6,787 20,125 $ $ $ $ 2015 1,939 180 162 219 (417) 135 2,218 824 1,367 92 186 2,469 (3) 4,684 1,342 3,342 $ $ $ $ 2014 4,392 26 191 186 (311) 229 4,713 420 1,606 183 180 2,389 (4) 7,098 1,623 5,475 $ $ $ $ 2013 4,957 339 113 300 (111) 214 5,812 132 1,371 224 199 1,926 (211) 7,527 1,294 6,233 $ $ $ $ $ Descriptions of major affiliates, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows: Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), which operates the Tengiz and Korolev crude oil fields in Kazakhstan. At December 31, 2015, the company’s carrying value of its investment in TCO was about $150 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. See Note 8, on page 42, for summarized financial information for 100 percent of TCO. Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company which operates the Hamaca heavy-oil production and upgrading project in Venezuela’s Orinoco Belt. At December 31, 2015, the company’s carrying value of its investment in Petropiar was approximately $160 less than the amount of underlying equity in Petropiar’s net assets. The difference represents the excess of Chevron’s underlying equity in Petropiar’s net assets over the net book value of the assets contributed to the venture. Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, a variable interest entity, which provides the critical export route for crude oil from both TCO and Karachaganak. The company has investments and advances totaling $1,342, which includes long-term loans of $1,098 at year-end 2015. The loans were provided to fund 30 percent of the initial pipeline construction. The company is not the primary beneficiary of the consortium because it does not direct activities of the consortium and only receives its proportionate share of the financial returns. Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in Venezuela. At December 31, 2015, the company’s carrying value of its investment in Petroboscan was approximately $140 higher than the amount of underlying equity in Petroboscan’s net assets. The difference reflects the excess of the net book value of the assets contributed by Chevron over its underlying equity in Petroboscan’s net assets. Angola LNG Limited Chevron has a 36.4 percent interest in Angola LNG Limited, which processes and liquefies natural gas produced in Angola for delivery to international markets. 48 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Energy. The joint venture imports, refines and markets petroleum products, petrochemicals and lubricants, predominantly in South Korea. Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. The other half is owned by Phillips 66. Caltex Australia Ltd. Chevron sold its 50 percent equity ownership interest in Caltex Australia Ltd. (CAL) in second quarter 2015. Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $4,850, $10,404 and $14,635 with affiliated companies for 2015, 2014 and 2013, respectively. “Purchased crude oil and products” includes $4,240, $6,735 and $7,063 with affiliated companies for 2015, 2014 and 2013, respectively. “Accounts and notes receivable” on the Consolidated Balance Sheet includes $399 and $924 due from affiliated companies at December 31, 2015 and 2014, respectively. “Accounts payable” includes $286 and $345 due to affiliated companies at December 31, 2015 and 2014, respectively. The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron’s net loans to affiliates of $410, $874 and $1,129 at December 31, 2015, 2014 and 2013, respectively. Year ended December 31 Total revenues Income before income tax expense Net income attributable to affiliates At December 31 Current assets Noncurrent assets Current liabilities Noncurrent liabilities $ $ $ $ 2015 71,389 13,129 10,649 27,162 71,650 20,559 18,560 2014 123,003 20,609 14,758 35,662 70,817 25,308 17,983 $ $ Affiliates 2013 131,875 24,075 15,594 39,713 68,593 29,642 19,442 $ $ Chevron Share $ $ 2015 33,492 6,279 4,691 10,657 26,607 7,351 3,909 2014 58,937 9,968 7,237 13,465 26,053 9,588 4,211 $ $ 2013 63,101 11,108 7,845 15,156 25,059 11,587 4,559 Total affiliates’ net equity $ 59,693 $ 63,188 $ 59,222 $ 26,004 $ 25,719 $ 24,069 Note 16 Properties, Plant and Equipment1 Gross Investment at Cost At December 31 Net Investment Additions at Cost2 Depreciation Expense3 Year ended December 31 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 2014 2013 Upstream United States International $ 93,848 $ 208,395 96,850 $ 192,637 89,555 $ 169,623 43,125 $ 127,459 45,864 $ 118,926 41,831 $ 104,100 6,586 $ 19,993 9,688 $ 24,920 8,188 $ 27,383 8,545 $ 10,803 5,127 $ 9,688 4,412 8,336 Total Upstream 302,243 289,487 259,178 170,584 164,790 145,931 26,579 34,608 35,571 19,348 14,815 12,748 Downstream United States International 23,202 9,177 22,640 9,334 22,407 9,303 10,807 4,090 11,019 4,219 11,481 4,139 696 365 588 530 Total Downstream 32,379 31,974 31,710 14,897 15,238 15,620 1,061 1,118 All Other United States International Total All Other 5,500 155 5,655 5,673 155 5,828 5,402 143 5,545 2,859 56 2,915 3,077 68 3,145 3,194 84 3,278 357 5 362 581 25 606 1,154 653 1,807 721 23 744 878 355 886 396 780 360 1,233 1,282 1,140 439 17 456 680 16 696 286 12 298 Total United States Total International 122,550 217,727 125,163 202,126 117,364 179,069 56,791 131,605 59,960 123,213 56,506 108,323 7,639 20,363 10,857 25,475 10,063 28,059 9,862 11,175 6,693 10,100 5,478 8,708 Total $ 340,277 $ 327,289 $ 296,433 $ 188,396 $ 183,173 $ 164,829 $ 28,002 $ 36,332 $ 38,122 $ 21,037 $ 16,793 $ 14,186 1 Other than the United States, Australia and Nigeria, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2015. Australia had $49,205, $41,012 and $31,464 in 2015, 2014, and 2013, respectively. Nigeria had PP&E of $18,773, $19,214 and $18,429 for 2015, 2014 and 2013, respectively. 2 Net of dry hole expense related to prior years’ expenditures of $1,573, $371 and $89 in 2015, 2014 and 2013, respectively. 3 Depreciation expense includes accretion expense of $715, $882 and $627 in 2015, 2014 and 2013, respectively, and impairments of $4,066, $1,274 and $382 in 2015, 2014 and 2013, respectively. Chevron Corporation 2015 Annual Report 49 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 17 Litigation MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to seven pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not determinable. The company no longer uses MTBE in the manufacture of gasoline in the United States. Ecuador Background Chevron is a defendant in a civil lawsuit initiated in the Superior Court of Nueva Loja in Lago Agrio, Ecuador, in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations. Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador and by the pertinent provincial and municipal governments. With regard to the facts, the company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations. Lago Agrio Judgment In 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $18,900, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems and additional infrastructure for Petroecuador. The engineer’s report also asserted that an additional $8,400 could be assessed against Chevron for unjust enrichment. In 2009, following the disclosure by Chevron of evidence that the judge participated in meetings in which businesspeople and individuals holding themselves out as government officials discussed the case and its likely outcome, the judge presiding over the case was recused. In 2010, Chevron moved to strike the mining engineer’s report and to dismiss the case based on evidence obtained through discovery in the United States indicating that the report was prepared by consultants for the plaintiffs before being presented as the mining engineer’s independent and impartial work and showing further evidence of misconduct. In August 2010, the judge issued an order stating that he was not bound by the mining engineer’s report and requiring the parties to provide their positions on damages within 45 days. Chevron subsequently petitioned for recusal of the judge, claiming that he had disregarded evidence of fraud and misconduct and that he had failed to rule on a number of motions within the statutory time requirement. In September 2010, Chevron submitted its position on damages, asserting that no amount should be assessed against it. The plaintiffs’ submission, which relied in part on the mining engineer’s report, took the position that damages are between approximately $16,000 and $76,000 and that unjust enrichment should be assessed in an amount between approximately $5,000 and $38,000. The next day, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment. Chevron petitioned to have that order declared a nullity in light of Chevron’s prior recusal petition, and because procedural and evidentiary matters remained unresolved. In October 2010, Chevron’s motion to recuse the judge was granted. A new judge took charge of the case and revoked the prior judge’s order closing the evidentiary phase of the case. On December 17, 2010, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment. 50 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts On February 14, 2011, the provincial court in Lago Agrio rendered an adverse judgment in the case. The court rejected Chevron’s defenses to the extent the court addressed them in its opinion. The judgment assessed approximately $8,600 in damages and approximately $900 as an award for the plaintiffs’ representatives. It also assessed an additional amount of approximately $8,600 in punitive damages unless the company issued a public apology within 15 days of the judgment, which Chevron did not do. On February 17, 2011, the plaintiffs appealed the judgment, seeking increased damages, and on March 11, 2011, Chevron appealed the judgment seeking to have the judgment nullified. On January 3, 2012, an appellate panel in the provincial court affirmed the February 14, 2011 decision and ordered that Chevron pay additional attorneys’ fees in the amount of “0.10% of the values that are derived from the decisional act of this judgment.” The plaintiffs filed a petition to clarify and amplify the appellate decision on January 6, 2012, and the court issued a ruling in response on January 13, 2012, purporting to clarify and amplify its January 3, 2012 ruling, which included clarification that the deadline for the company to issue a public apology to avoid the additional amount of approximately $8,600 in punitive damages was within 15 days of the clarification ruling, or February 3, 2012. Chevron did not issue an apology because doing so might be mischaracterized as an admission of liability and would be contrary to facts and evidence submitted at trial. On January 20, 2012, Chevron appealed (called a petition for cassation) the appellate panel’s decision to Ecuador’s National Court of Justice. As part of the appeal, Chevron requested the suspension of any requirement that Chevron post a bond to prevent enforcement under Ecuadorian law of the judgment during the cassation appeal. On February 17, 2012, the appellate panel of the provincial court admitted Chevron’s cassation appeal in a procedural step necessary for the National Court of Justice to hear the appeal. The provincial court appellate panel denied Chevron’s request for suspension of the requirement that Chevron post a bond and stated that it would not comply with the First and Second Interim Awards of the international arbitration tribunal discussed below. On March 29, 2012, the matter was transferred from the provincial court to the National Court of Justice, and on November 22, 2012, the National Court agreed to hear Chevron’s cassation appeal. On August 3, 2012, the provincial court in Lago Agrio approved a court-appointed liquidator’s report on damages that calculated the total judgment in the case to be $19,100. On November 13, 2013, the National Court ratified the judgment but nullified the $8,600 punitive damage assessment, resulting in a judgment of $9,500. On December 23, 2013, Chevron appealed the decision to the Ecuador Constitutional Court, Ecuador’s highest court. The reporting justice of the Constitutional Court heard oral arguments on the appeal on July 16, 2015. On July 2, 2013, the provincial court in Lago Agrio issued an embargo order in Ecuador ordering that any funds to be paid by the Government of Ecuador to Chevron to satisfy a $96 award issued in an unrelated action by an arbitral tribunal presiding in the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law must be paid to the Lago Agrio plaintiffs. The award was issued by the tribunal under the United States-Ecuador Bilateral Investment Treaty in an action filed in 2006 in connection with seven breach of contract cases that Texpet filed against the Government of Ecuador between 1991 and 1993. The Government of Ecuador has moved to set aside the tribunal’s award. On September 26, 2014, the Supreme Court of the Netherlands issued an opinion denying Ecuador’s set aside request. A Federal District Court for the District of Columbia confirmed the tribunal’s award, and on August 4, 2015, a panel of the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court’s decision. On September 9, 2015, the Court of Appeals denied the Government of Ecuador’s request for full appellate court review of the Federal District Court’s decision. Lago Agrio Plaintiffs’ Enforcement Actions Chevron has no assets in Ecuador and the Lago Agrio plaintiffs’ lawyers have stated in press releases and through other media that they will seek to enforce the Ecuadorian judgment in various countries and otherwise disrupt Chevron’s operations. On May 30, 2012, the Lago Agrio plaintiffs filed an action against Chevron Corporation, Chevron Canada Limited, and Chevron Canada Finance Limited in the Ontario Superior Court of Justice in Ontario, Canada, seeking to recognize and enforce the Ecuadorian judgment. On May 1, 2013, the Ontario Superior Court of Justice held that the Court has jurisdiction over Chevron and Chevron Canada Limited for purposes of the action, but stayed the action due to the absence of evidence that Chevron Corporation has assets in Ontario. The Lago Agrio plaintiffs appealed that decision and on December 17, 2013, the Court of Appeals for Ontario affirmed the lower court’s decision on jurisdiction and set aside the stay, allowing the recognition and enforcement action to be heard in the Ontario Superior Court of Justice. Chevron appealed the decision to the Supreme Court of Canada and, on September 4, 2015, the Supreme Court dismissed the appeal and affirmed that the Ontario Superior Court of Justice has jurisdiction over Chevron and Chevron Canada Limited for purposes of the action. The recognition and enforcement proceeding and related preliminary motions are proceeding in the Ontario Superior Court of Justice. On June 27, 2012, the Lago Agrio plaintiffs filed a complaint against Chevron Corporation in the Superior Court of Justice in Brasilia, Brazil, seeking to recognize and enforce the Ecuadorian judgment. Chevron has answered the complaint. In accordance with Brazilian procedure, the matter was referred to the public prosecutor for a nonbinding opinion of the issues raised in the complaint. On May 13, 2015, the public prosecutor issued its nonbinding opinion and recommended that the Superior Court of Justice reject the plaintiffs’ recognition and enforcement request, finding, among other things, that the Lago Agrio judgment was Chevron Corporation 2015 Annual Report 51 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts procured through fraud and corruption and cannot be recognized in Brazil because it violates Brazilian and international public order. On October 15, 2012, the provincial court in Lago Agrio issued an ex parte embargo order that purports to order the seizure of assets belonging to separate Chevron subsidiaries in Ecuador, Argentina and Colombia. On November 6, 2012, at the request of the Lago Agrio plaintiffs, a court in Argentina issued a Freeze Order against Chevron Argentina S.R.L. and another Chevron subsidiary, Ingeniero Norberto Priu, requiring shares of both companies to be “embargoed,” requiring third parties to withhold 40 percent of any payments due to Chevron Argentina S.R.L. and ordering banks to withhold 40 percent of the funds in Chevron Argentina S.R.L. bank accounts. On December 14, 2012, the Argentinean court rejected a motion to revoke the Freeze Order but modified it by ordering that third parties are not required to withhold funds but must report their payments. The court also clarified that the Freeze Order relating to bank accounts excludes taxes. On January 30, 2013, an appellate court upheld the Freeze Order, but on June 4, 2013 the Supreme Court of Argentina revoked the Freeze Order in its entirety. On December 12, 2013, the Lago Agrio plaintiffs served Chevron with notice of their filing of an enforcement proceeding in the National Court, First Instance, of Argentina. Chevron filed its answer on February 27, 2014, to which the Lago Agrio plaintiffs responded on December 29, 2015. Chevron continues to believe the provincial court’s judgment is illegitimate and unenforceable in Ecuador, the United States and other countries. The company also believes the judgment is the product of fraud, and contrary to the legitimate scientific evidence. Chevron cannot predict the timing or ultimate outcome of the appeals process in Ecuador or any enforcement action. Chevron expects to continue a vigorous defense of any imposition of liability in the Ecuadorian courts and to contest and defend any and all enforcement actions. filed an arbitration claim in Company’s Bilateral Investment Treaty Arbitration Claims Chevron and Texpet September 2009 against the Republic of Ecuador before an arbitral tribunal presiding in the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law. The claim alleges violations of the Republic of Ecuador’s obligations under the United States–Ecuador Bilateral Investment Treaty (BIT) and breaches of the settlement and release agreements between the Republic of Ecuador and Texpet (described above), which are investment agreements protected by the BIT. Through the arbitration, Chevron and Texpet are seeking relief against the Republic of Ecuador, including a declaration that any judgment against Chevron in the Lago Agrio litigation constitutes a violation of Ecuador’s obligations under the BIT. On February 9, 2011, the Tribunal issued an Order for Interim Measures requiring the Republic of Ecuador to take all measures at its disposal to suspend or cause to be suspended the enforcement or recognition within and without Ecuador of any judgment against Chevron in the Lago Agrio case pending further order of the Tribunal. On January 25, 2012, the Tribunal converted the Order for Interim Measures into an Interim Award. Chevron filed a renewed application for further interim measures on January 4, 2012, and the Republic of Ecuador opposed Chevron’s application and requested that the existing Order for Interim Measures be vacated on January 9, 2012. On February 16, 2012, the Tribunal issued a Second Interim Award mandating that the Republic of Ecuador take all measures necessary (whether by its judicial, legislative or executive branches) to suspend or cause to be suspended the enforcement and recognition within and without Ecuador of the judgment against Chevron and, in particular, to preclude any certification by the Republic of Ecuador that would cause the judgment to be enforceable against Chevron. On February 27, 2012, the Tribunal issued a Third Interim Award confirming its jurisdiction to hear Chevron’s arbitration claims. On February 7, 2013, the Tribunal issued its Fourth Interim Award in which it declared that the Republic of Ecuador “has violated the First and Second Interim Awards under the [BIT], the UNCITRAL Rules and international law in regard to the finalization and enforcement subject to execution of the Lago Agrio Judgment within and outside Ecuador, including (but not limited to) Canada, Brazil and Argentina.” The Republic of Ecuador subsequently filed in the District Court of the Hague a request to set aside the Tribunal’s Interim Awards and the First Partial Award (described below), and on January 20, 2016, the District Court denied the Republic’s request. The Tribunal has divided the merits phase of the proceeding into three phases. On September 17, 2013, the Tribunal issued its First Partial Award from Phase One, finding that the settlement agreements between the Republic of Ecuador and Texpet applied to Texpet and Chevron, released Texpet and Chevron from claims based on “collective” or “diffuse” rights arising from Texpet’s operations in the former concession area and precluded third parties from asserting collective/diffuse rights environmental claims relating to Texpet’s operations in the former concession area but did not preclude individual claims for personal harm. The Tribunal held a hearing on April 29-30, 2014, to address remaining issues relating to Phase One, and on March 12, 2015, it issued a nonbinding decision that the Lago Agrio plaintiffs’ complaint, on its face, includes claims not barred by the settlement agreement between the Republic of Ecuador and Texpet. In the same decision, the Tribunal deferred to Phase Two remaining issues from the Republic of Ecuador breached the 1995 settlement agreement and the remedies Phase One, including whether 52 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts that are available to Chevron and Texpet as a result of that breach. Phase Two issues were addressed at a hearing held in April and May 2015. The Tribunal has not set a date for Phase Three, the damages phase of the arbitration. Company’s RICO Action Through a series of U.S. court proceedings initiated by Chevron to obtain discovery relating to the Lago Agrio litigation and the BIT arbitration, Chevron obtained evidence that it believes shows a pattern of fraud, collusion, corruption, and other misconduct on the part of several lawyers, consultants and others acting for the Lago Agrio plaintiffs. In February 2011, Chevron filed a civil lawsuit in the Federal District Court for the Southern District of New York against the Lago Agrio plaintiffs and several of their lawyers, consultants and supporters, alleging violations of the Racketeer Influenced and Corrupt Organizations Act and other state laws. Through the civil lawsuit, Chevron is seeking relief that includes a declaration that any judgment against Chevron in the Lago Agrio litigation is the result of fraud and other unlawful conduct and is therefore unenforceable. On March 7, 2011, the Federal District Court issued a preliminary injunction prohibiting the Lago Agrio plaintiffs and persons acting in concert with them from taking any action in furtherance of recognition or enforcement of any judgment against Chevron in the Lago Agrio case pending resolution of Chevron’s civil lawsuit by the Federal District Court. On May 31, 2011, the Federal District Court severed claims one through eight of Chevron’s complaint from the ninth claim for declaratory relief and imposed a discovery stay on claims one through eight pending a trial on the ninth claim for declaratory relief. On September 19, 2011, the U.S. Court of Appeals for the Second Circuit vacated the preliminary injunction, stayed the trial on Chevron’s ninth claim, a claim for declaratory relief, that had been set for November 14, 2011, and denied the defendants’ mandamus petition to recuse the judge hearing the lawsuit. The Second Circuit issued its opinion on January 26, 2012 ordering the dismissal of Chevron’s ninth claim for declaratory relief. On February 16, 2012, the Federal District Court lifted the stay on claims one through eight, and on October 18, 2012, the Federal District Court set a trial date of October 15, 2013. On March 22, 2013, Chevron settled its claims against Stratus Consulting, and on April 12, 2013 sworn declarations by representatives of Stratus Consulting were filed with the Court admitting their role and that of the plaintiffs’ attorneys in drafting the environmental report of the mining engineer appointed by the provincial court in Lago Agrio. On September 26, 2013, the Second Circuit denied the defendants’ Petition for Writ of Mandamus to recuse the judge hearing the case and to collaterally estop Chevron from seeking a declaration that the Lago Agrio judgment was obtained through fraud and other unlawful conduct. The trial commenced on October 15, 2013 and concluded on November 22, 2013. On March 4, 2014, the Federal District Court entered a judgment in favor of Chevron, prohibiting the defendants from seeking to enforce the Lago Agrio judgment in the United States and further prohibiting them from profiting from their illegal acts. The defendants appealed the Federal District Court’s decision, and, on April 20, 2015, a panel of the U.S. Court of Appeals for the Second Circuit heard oral arguments. Management’s Assessment The ultimate outcome of the foregoing matters, including any financial effect on Chevron, remains uncertain. Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the Ecuadorian judgment, the 2008 engineer’s report on alleged damages and the September 2010 plaintiffs’ submission on alleged damages, management does not believe these documents have any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss). Note 18 Taxes Income Taxes Income tax expense (benefit) U.S. federal Current Deferred State and local Current Deferred Total United States International Current Deferred Total International $ $ 2015 (817) (580) (187) (109) (1,693) 2,997 (1,172) 1,825 Year ended December 31 2014 2013 $ 748 1,330 336 36 2,450 9,235 207 9,442 15 1,128 120 74 1,337 12,296 675 12,971 14,308 Total income tax expense (benefit) $ 132 $ 11,892 $ Chevron Corporation 2015 Annual Report 53 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts In 2015, before-tax loss for U.S. operations, including related corporate and other charges, was $(2,877), compared with before-tax income of $6,296 and $4,672 in 2014 and 2013, respectively. For international operations, before-tax income was $7,719, $24,906 and $31,233 in 2015, 2014 and 2013, respectively. U.S. federal income tax expense was reduced by $35, $68 and $175 in 2015, 2014 and 2013, respectively, for business tax credits. The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table: U.S. statutory federal income tax rate Effect of income taxes from international operations1 State and local taxes on income, net of U.S. federal income tax benefit Tax credits Other1,2 Effective tax rate 2015 35.0 % (25.1) (1.5) (0.7) (5.0) 2.7 % Year ended December 31 2014 2013 35.0 % 2.1 0.7 (0.2) 0.5 38.1 % 35.0 % 4.4 0.6 (0.5) 0.4 39.9 % 1 2 2013 and 2014 conformed to 2015 presentation. 2015 includes one-time tax benefits associated with changes in uncertain tax positions and provision-to-return adjustments. The company’s effective tax rate decreased from 38.1 percent in 2014 to 2.7 percent in 2015. The decrease primarily resulted from the impacts of jurisdictional mix, one-time tax benefits, foreign currency remeasurement, equity earnings and a reduction in statutory tax rates in the United Kingdom, partially offset by the effects of valuation allowances recognized on deferred tax assets and the sale of the company’s interest in Caltex Australia Limited. The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities. The reported deferred tax balances are composed of the following: Deferred tax liabilities Properties, plant and equipment Investments and other Total deferred tax liabilities Deferred tax assets Foreign tax credits Abandonment/environmental reserves Employee benefits Deferred credits Tax loss carryforwards Other accrued liabilities Inventory Miscellaneous Total deferred tax assets Deferred tax assets valuation allowance Total deferred taxes, net At December 31 2015 27,044 3,743 30,787 (10,534) (6,880) (4,801) (1,810) (2,748) (525) (120) (2,525) (29,943) 15,412 16,256 $ $ 2014 28,452 3,059 31,511 (11,867) (6,686) (4,831) (1,828) (1,747) (498) (153) (2,128) (29,738) 16,292 18,065 $ $ Deferred tax liabilities at the end of 2015 decreased by approximately $700 from year-end 2014. The decrease was primarily related to decreased temporary differences related to property, plant and equipment. Deferred tax assets were essentially unchanged between periods. A reduction in U.S. foreign tax credits was substantially offset by an increase in foreign tax loss carryforwards. The overall valuation allowance relates to deferred tax assets for U.S. foreign tax credit carryforwards, tax loss carryforwards and temporary differences. It reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2015, the company had tax loss carryforwards of approximately $7,615 and tax credit carryforwards of approximately $1,249, primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2016 through 2025. U.S. foreign tax credit carryforwards of $10,534 will expire between 2017 and 2024. 54 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts At December 31, 2015 and 2014, deferred taxes were classified on the Consolidated Balance Sheet as follows: Prepaid expenses and other current assets Deferred charges and other assets Federal and other taxes on income Noncurrent deferred income taxes Total deferred income taxes, net $ At December 31 2015 (917) (4,512) 996 20,689 16,256 $ $ 2014 (1,071) (3,597) 813 21,920 18,065 Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely. Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $45,400 at December 31, 2015. This amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. At the end of 2015, deferred income taxes were recorded for the undistributed earnings of certain international operations where indefinite reinvestment of the earnings is not planned. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested. Uncertain Income Tax Positions The company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2015, 2014 and 2013. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included. Balance at January 1 Foreign currency effects Additions based on tax positions taken in current year Additions/reductions resulting from current-year asset acquisitions/sales Additions for tax positions taken in prior years Reductions for tax positions taken in prior years Settlements with taxing authorities in current year Reductions as a result of a lapse of the applicable statute of limitations Balance at December 31 2015 3,552 (27) 154 — 218 (678) (5) (172) 3,042 $ $ 2014 3,848 (25) 354 (22) 37 (561) (50) (29) 3,552 $ $ 2013 3,071 (58) 276 — 1,164 (176) (320) (109) 3,848 $ $ The decrease in unrecognized tax benefits between December 31, 2014, and December 31, 2015 was primarily due to the resolution of numerous audit issues with various tax jurisdictions during the year. Approximately 71 percent of the $3,042 of unrecognized tax benefits at December 31, 2015, would have an impact on the effective tax rate if subsequently recognized. Certain of these unrecognized tax benefits relate to tax carryforwards that may require a full valuation allowance at the time of any such recognition. Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of December 31, 2015. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – 2011, Nigeria – 2000, Angola – 2009, Saudi Arabia – 2012 and Kazakhstan – 2007. The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions. Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain. However, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in significant increases or decreases in the company’s total unrecognized tax benefits within the next 12 months. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits. Chevron Corporation 2015 Annual Report 55 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2015, accruals of $399 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $233 as of year-end 2014. Income tax expense (benefit) associated with interest and penalties was $195, $4 and $(42) in 2015, 2014 and 2013, respectively. Taxes Other Than on Income United States Excise and similar taxes on products and merchandise Import duties and other levies Property and other miscellaneous taxes Payroll taxes Taxes on production Total United States International Excise and similar taxes on products and merchandise Import duties and other levies Property and other miscellaneous taxes Payroll taxes Taxes on production Total International Total taxes other than on income Note 19 Short-Term Debt Commercial paper* Notes payable to banks and others with originating terms of one year or less Current maturities of long-term debt Current maturities of long-term capital leases Redeemable long-term obligations Long-term debt Capital leases Subtotal Reclassified to long-term debt Total short-term debt $ $ 2015 4,426 4 1,367 270 157 6,224 2,933 40 2,548 161 124 5,806 Year ended December 31 $ 2014 4,633 6 1,002 273 349 6,263 3,553 45 2,277 172 230 6,277 2013 4,792 4 1,036 255 333 6,420 3,700 41 2,486 168 248 6,643 $ 12,030 $ 12,540 $ 13,063 $ At December 31 2015 8,252 20 1,487 17 3,152 — $ 2014 8,506 104 — 22 3,152 6 12,928 (8,000) 11,790 (8,000) $ 4,928 $ 3,790 * Weighted-average interest rates at December 31, 2015 and 2014, were 0.26 percent and 0.12 percent, respectively. Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date. The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2015, the company had no interest rate swaps on short-term debt. At December 31, 2015, the company had $8,000 in committed credit facilities with various major banks that enable the refinancing of short-term obligations on a long-term basis. The credit facilities consist of a 364-day facility which enables borrowing of up to $6,000 and can be renewed for an additional 364-day period or the company can convert any amounts outstanding into a term loan for a period of up to one year, and a $2,000 five-year facility expiring in December 2020. These facilities support commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2015. At both December 31, 2015 and 2014, the company classified $8,000 of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. 56 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 20 Long-Term Debt Total long-term debt, excluding capital leases, at December 31, 2015, was $33,584. The company’s long-term debt outstanding at year-end 2015 and 2014 was as follows: 3.191% notes due 2023 Floating rate notes due 2017 (0.555%)1 1.104% notes due 2017 1.718% notes due 2018 2.355% notes due 2022 1.365% notes due 2018 1.961% notes due 2020 4.95% notes due 2019 1.790% notes due 2018 2.419% notes due 2020 1.345% notes due 2017 1.344% notes due 2017 2.427% notes due 2020 Floating rate notes due 2018 (0.676%)1 0.889% notes due 2016 2.193% notes due 2019 3.326% notes due 2025 2.411% notes due 2022 Floating rate notes due 2016 (0.444%)2 Floating rate notes due 2019 (0.772%)2 Floating rate notes due 2021 (0.892%)2 Floating rate notes due 2022 (0.952%)2 8.625% debentures due 2032 Amortizing Bank Loan due 2018 (1.172%)2 8.625% debentures due 2031 8.0% debentures due 2032 9.75% debentures due 2020 8.875% debentures due 2021 Medium-term notes, maturing from 2021 to 2038 (5.975%)1 Total including debt due within one year Debt due within one year Reclassified from short-term debt Total long-term debt 1 Weighted-average interest rate at December 31, 2015. 2 Interest rate at December 31, 2015. $ At December 31 $ 2015 2,250 2,050 2,000 2,000 2,000 1,750 1,750 1,500 1,250 1,250 1,100 1,000 1,000 800 750 750 750 700 700 400 400 350 147 110 108 74 54 40 38 2014 2,250 650 2,000 2,000 2,000 — — 1,500 — — 1,100 — 1,000 — 750 750 — — 700 400 400 — 147 — 107 74 54 40 38 27,071 (1,487) 8,000 15,960 — 8,000 $ 33,584 $ 23,960 Chevron has an automatic shelf registration statement that expires in August 2018. This registration statement is for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company. Long-term debt of $27,071 matures as follows: 2016 – $1,487; 2017 – $6,187; 2018 – $5,836; 2019 – $2,650; 2020 – $4,054; and after 2020 – $6,857. The company completed bond issuances of $6,000 and $5,000 in March and November 2015, respectively. See Note 9, beginning on page 42, for information concerning the fair value of the company’s long-term debt. Note 21 Accounting for Suspended Exploratory Wells The company continues to capitalize exploratory well costs after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the business unit is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if the company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. Chevron Corporation 2015 Annual Report 57 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2015: Beginning balance at January 1 Additions to capitalized exploratory well costs pending the determination of proved reserves Reclassifications to wells, facilities and equipment based on the determination of proved reserves Capitalized exploratory well costs charged to expense Other reductions* Ending balance at December 31 * Represents property sales. $ 2015 4,195 869 (164) (1,397) (191) $ $ 2014 3,245 1,591 (298) (312) (31) 2013 2,681 885 (290) (31) — $ 3,312 $ 4,195 $ 3,245 The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. Exploratory well costs capitalized for a period of one year or less Exploratory well costs capitalized for a period greater than one year Balance at December 31 Number of projects with exploratory well costs that have been capitalized for a period greater than one year* * Certain projects have multiple wells or fields or both. $ $ 2015 489 2,823 3,312 39 At December 31 $ $ 2014 1,522 2,673 4,195 51 $ $ 2013 641 2,604 3,245 51 Of the $2,823 of exploratory well costs capitalized for more than one year at December 31, 2015, $1,662 (20 projects) is related to projects that had drilling activities under way or firmly planned for the near future. The $1,161 balance is related to 19 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development. The projects for the $1,161 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $190 (two projects) – undergoing front-end engineering and design with final investment decision expected within four years; (b) $99 (one project) – development concept under review by government; (c) $814 (seven projects) – development alternatives under review; (d) $58 (nine projects) – miscellaneous activities for projects with smaller amounts suspended. While progress was being made on all 39 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects. Approximately half of these decisions are expected to occur in the next five years. The $2,823 of suspended well costs capitalized for a period greater than one year as of December 31, 2015, represents 165 exploratory wells in 39 projects. The tables below contain the aging of these costs on a well and project basis: Aging based on drilling completion date of individual wells: Amount Number of wells 1998–2004 2005–2009 2010–2014 Total Aging based on drilling completion date of last suspended well in project: 2003–2007 2008–2011 2012–2015 Total $ $ $ $ 285 395 2,143 2,823 26 33 106 165 Amount Number of projects 200 393 2,230 2,823 4 6 29 39 Note 22 Stock Options and Other Share-Based Compensation Compensation expense for stock options for 2015, 2014 and 2013 was $312 ($203 after tax), $287 ($186 after tax) and $292 ($190 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance units and restricted stock units was $32 ($21 after tax), $71 ($46 after tax) and $223 ($145 after tax) for 2015, 2014 and 2013, respectively. No significant stock-based compensation cost was capitalized at December 31, 2015, or December 31, 2014. 58 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Cash received in payment for option exercises under all share-based payment arrangements for 2015, 2014 and 2013 was $195, $527 and $553, respectively. Actual tax benefits realized for the tax deductions from option exercises were $17, $54 and $73 for 2015, 2014 and 2013, respectively. Cash paid to settle performance units and stock appreciation rights was $104, $204 and $186 for 2015, 2014 and 2013, respectively. Awards under the Chevron Long-Term Incentive Plan (LTIP) may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance units and nonstock grants. From April 2004 through May 2023, no more than 260 million shares may be issued under the LTIP. For awards issued on or after May 29, 2013, no more than 50 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient. For the major types of awards outstanding as of December 31, 2015, the contractual terms vary between three years for the performance units and restricted stock units, and 10 years for the stock options and stock appreciation rights. Remaining awards under the Unocal Share-Based Plans expired in early 2015. The fair market values of stock options and stock appreciation rights granted in 2015, 2014 and 2013 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions: Expected term in years1 Volatility2 Risk-free interest rate based on zero coupon U.S. treasury note Dividend yield Weighted-average fair value per option granted 2015 6.1 21.9 % 1.4 % 3.6 % Year ended December 31 2014 6.0 30.3 % 1.9 % 3.3 % 2013 6.0 31.3 % 1.2 % 3.3 % $ 13.89 $ 25.86 $ 24.48 1 Expected term is based on historical exercise and postvesting cancellation data. 2 Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term. A summary of option activity during 2015 is presented below: Shares (Thousands) Weighted-Average Exercise Price Averaged Remaining Contractual Term (Years) Aggregate Intrinsic Value Outstanding at January 1, 2015 Granted Exercised Forfeited Outstanding at December 31, 2015 Exercisable at December 31, 2015 78,341 22,126 (3,104) (3,071) 94,292 65,657 $ $ $ $ $ $ 93.59 103.71 62.06 103.70 96.67 91.85 5.83 4.61 $ $ 467 467 The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2015, 2014 and 2013 was $120, $398 and $445, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards. As of December 31, 2015, there was $190 of total unrecognized before-tax compensation cost related to nonvested share- based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 1.7 years. At January 1, 2015, the number of LTIP performance units outstanding was equivalent to 2,265,952 shares. During 2015, 890,000 units were granted, 828,868 units vested with cash proceeds distributed to recipients and 134,147 units were forfeited. At December 31, 2015, units outstanding were 2,192,937. The fair value of the liability recorded for these instruments was $166, and was measured using the Monte Carlo simulation method. In addition, outstanding stock appreciation rights and other awards that were granted under various LTIP programs totaled approximately 4.5 million equivalent shares as of December 31, 2015. A liability of $51 was recorded for these awards. Note 23 Employee Benefit Plans The company has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations Chevron Corporation 2015 Annual Report 59 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives. The company also sponsors other postretirement benefit (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and retirees share the costs. Medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D) and the increase to the company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company. The company recognizes the overfunded or underfunded status of each of its defined benefit pension and OPEB plans as an asset or liability on the Consolidated Balance Sheet. The funded status of the company’s pension and OPEB plans for 2015 and 2014 follows: $ Change in Benefit Obligation Benefit obligation at January 1 Service cost Interest cost Plan participants’ contributions Plan amendments Actuarial (gain) loss Foreign currency exchange rate changes Benefits paid Divestitures Curtailment Benefit obligation at December 31 Change in Plan Assets Fair value of plan assets at January 1 Actual return on plan assets Foreign currency exchange rate changes Employer contributions Plan participants’ contributions Benefits paid Divestitures Fair value of plan assets at December 31 $ $ U.S. 14,250 538 502 — — (345) — (1,382) — — 13,563 11,090 (75) — 641 — (1,382) — 10,274 2015 Int’l. 5,767 185 277 6 (6) (309) (326) (241) — (17) 5,336 4,244 112 (239) 227 6 (241) — 4,109 Pension Benefits $ U.S. 12,080 450 494 — — 2,299 — (1,073) — — 14,250 11,210 854 — 99 — (1,073) — 11,090 2014 Int’l. 6,095 190 340 8 3 336 (348) (293) (564) — 5,767 4,543 571 (279) 276 8 (293) (582) 4,244 Other Benefits 2015 2014 $ 3,660 72 151 148 — (326) (37) (344) — — 3,324 — — — 196 148 (344) — — $ 3,138 50 148 150 2 544 (22) (350) — — 3,660 — — — 200 150 (350) — — Funded Status at December 31 $ (3,289) $ (1,227) $ (3,160) $ (1,523) $ (3,324) $ (3,660) Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2015 and 2014, include: Deferred charges and other assets Accrued liabilities Noncurrent employee benefit plans Net amount recognized at December 31 $ $ U.S. 13 (153) (3,149) $ 2015 Int’l. 333 (77) (1,483) (3,289) $ (1,227) $ $ Pension Benefits U.S. 13 (123) (3,050) $ 2014 Int’l. 244 (68) (1,699) (3,160) $ (1,523) 2015 — (191) (3,133) (3,324) $ $ Other Benefits 2014 — (198) (3,462) (3,660) $ $ Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $6,478 and $7,417 at the end of 2015 and 2014, respectively. These amounts consisted of: U.S. 4,809 (5) 4,804 $ $ $ $ 2015 Int’l. 1,143 120 1,263 Pension Benefits U.S. 4,972 (13) 4,959 $ $ $ $ 2014 Int’l. 1,487 150 1,637 2015 367 44 411 $ $ Other Benefits 2014 763 58 821 $ $ Net actuarial loss Prior service (credit) costs Total recognized at December 31 60 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts The accumulated benefit obligations for all U.S. and international pension plans were $12,032 and $4,684, respectively, at December 31, 2015, and $12,833 and $4,995, respectively, at December 31, 2014. Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2015 and 2014, was: Projected benefit obligations Accumulated benefit obligations Fair value of plan assets $ U.S. 13,500 11,969 10,198 $ Pension Benefits 2015 Int’l. 1,623 1,357 207 $ U.S. 14,182 12,765 11,009 $ 2014 Int’l. 1,938 1,525 262 The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2015, 2014 and 2013 are shown in the table below: Net Periodic Benefit Cost Service cost Interest cost Expected return on plan assets Amortization of prior service costs (credits) Recognized actuarial losses Settlement losses Curtailment losses (gains) 2015 Int’l. $ 185 277 (262) 22 78 6 (14) U.S. $ 538 502 (783) (8) 356 320 — $ U.S. $ 450 494 (788) (9) 209 237 — Total net periodic benefit cost 925 292 593 Changes Recognized in Comprehensive Income Net actuarial (gain) loss during period Amortization of actuarial loss Prior service (credits) costs during period Amortization of prior service (costs) credits Total changes recognized in other comprehensive income Recognized in Net Periodic Benefit Cost and Other 513 (676) — 8 (260) (84) (6) (24) 2,233 (446) — 9 Pension Benefits 2014 Int’l. 190 340 (298) 21 96 208 — 557 (17) (304) 4 (21) $ U.S. 495 471 (701) 2 485 173 — 925 (2,244) (658) (78) (2) $ 2013 Int’l. 197 314 (274) 21 143 12 — 413 (476) (155) 18 (21) Other Benefits 2015 2014 2013 $ 72 151 — 14 34 — — 271 (362) (34) — (14) $ 50 148 — 14 7 — — 219 514 (7) 2 (14) $ 66 149 — (50) 53 — — 218 (659) (53) — 50 (155) (374) 1,796 (338) (2,982) (634) (410) 495 (662) Comprehensive Income $ 770 $ (82) $2,389 $ 219 $(2,057) $ (221) $ (139) $ 714 $ (444) Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2015, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 10, 10 and 16 years, respectively. These amortization periods represent the estimated average remaining service of employees expected to receive benefits under the plans. These losses are amortized to the extent they exceed 10 percent of the higher of the projected benefit obligation or market-related value of plan assets. The amount subject to amortization is determined on a plan-by-plan basis. During 2016, the company estimates actuarial losses of $335, $56 and $19 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively. In addition, the company estimates an additional $324 will be recognized from “Accumulated other comprehensive loss” during 2016 related to lump-sum settlement costs from the main U.S. pension plan. The weighted average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, 2015, was approximately 4 and 11 years for U.S. and international pension plans, respectively, and 7 years for OPEB plans. During 2016, the company estimates prior service (credits) costs of $(9), $15 and $14 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively. Chevron Corporation 2015 Annual Report 61 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31: Assumptions used to determine benefit obligations: Discount rate Rate of compensation increase Assumptions used to determine net periodic benefit cost: Discount rate Expected return on plan assets Rate of compensation increase 2015 Int’l. U.S. 4.0% 5.3% 4.5% 4.8% 3.7% 5.0% 7.5% 6.3% 4.5% 5.1% Pension Benefits 2014 Int’l. 5.0% 5.1% 5.8% 6.6% 5.5% U.S. 4.3% 4.5% 3.6% 7.5% 4.5% 2013 Int’l. 5.8% 5.5% 5.2% 6.8% 5.5% U.S. 3.7% 4.5% 4.3% 7.5% 4.5% Other Benefits 2015 2014 2013 4.6% N/A 4.3% N/A N/A 4.3% N/A 4.9% N/A N/A 4.9% N/A 4.1% N/A N/A Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/ liability studies, and the company’s estimated long-term rates of return are consistent with these studies. For 2015, the company used an expected long-term rate of return of 7.5 percent for U.S. pension plan assets, which account for 71 percent of the company’s pension plan assets. In both 2014 and 2013, the company used a long-term rate of return of 7.5 percent for this plan. The market-related value of assets of the main U.S. pension plan used in the determination of pension expense was based on the market values in the three months preceding the year-end measurement date. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense. Discount Rate The discount rate assumptions used to determine the U.S. and international pension and OPEB plan obligations and expense reflect the rate at which benefits could be effectively settled, and are equal to the equivalent single rate resulting from yield curve analysis. This analysis considered the projected benefit payments specific to the company’s plans and the yields on high-quality bonds. At December 31, 2015, the projected cash flows were discounted to the valuation date using the yield curve for the main U.S. pension and OPEB plans. The effective discount rates derived from this analysis were 4.0 percent for the main U.S. pension plan and 4.5 percent for the main U.S. OPEB plan. The discount rates for these plans at the end of 2014 were 3.7 and 4.1 percent, respectively, while in 2013 they were 4.3 and 4.7 percent for these plans, respectively. The company changed the method used to estimate the service and interest costs associated with the company’s main U.S. pension and OPEB plans. In prior years, the service and interest costs were estimated utilizing a single weighted-average discount rate derived from the yield curve used to measure the defined benefit obligations at the beginning of the year. Under the new method, these costs are estimated by applying spot rates along the yield curve to the relevant projected cash flows. The change was made to provide a more precise measurement of the service and interest costs by improving the correlation between projected benefit cash flows and the corresponding spot yield curve rates. This change in accounting estimate is accounted for prospectively beginning with the year ending December 31, 2016. The company does not expect the change to have a material effect on its consolidated financial position or liquidity. Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2015, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 7.1 percent in 2016 and gradually decline to 4.5 percent for 2025 and beyond. For this measurement at December 31, 2014, the assumed health care cost-trend rates started with 7 percent in 2015 and gradually declined to 4.5 percent for 2025 and beyond. In both measurements, the annual increase to company contributions was capped at 4 percent. Assumed health care cost-trend rates can have a significant effect on the amounts reported for retiree health care costs. The impact is mitigated by the 4 percent cap on the company’s medical contributions for the main U.S. plan. A 1-percentage- point change in the assumed health care cost-trend rates would have the following effects on worldwide plans: Effect on total service and interest cost components Effect on postretirement benefit obligation 62 Chevron Corporation 2015 Annual Report 1 Percent Increase 1 Percent Decrease $ $ 20 192 $ $ (17) (164) Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Plan Assets and Investment Strategy The fair value measurements of the company’s pension plans for 2015 and 2014 are below: Total Fair Value Level 1 Level 2 Level 3 Total Fair Value Level 1 Level 2 Level 3 U.S. Int’l. $ $ $ At December 31, 2014 Equities U.S.1 International Collective Trusts/Mutual Funds2 Fixed Income Government Corporate Mortgage-Backed Securities Other Asset Backed Collective Trusts/Mutual Funds2 Mixed Funds3 Real Estate4 Cash and Cash Equivalents Other5 Total at December 31, 2014 At December 31, 2015 Equities U.S.1 International Collective Trusts/Mutual Funds2 Fixed Income Government Corporate Bank Loans Mortgage-Backed Securities Other Asset Backed Collective Trusts/Mutual Funds2 Mixed Funds3 Real Estate4 Cash and Cash Equivalents Other5 $ $ $ 2,087 1,297 3,240 84 1,502 1 — 1,174 — 1,364 270 71 $ $ 2,087 1,297 22 — $ — 3,218 47 — — — — — — 270 (3) 37 1,502 1 — 1,174 — — — 20 — — — — — — — — — 1,364 — 54 11,090 $ 3,720 $ 5,952 $ 1,418 1,699 1,302 2,460 257 1,654 148 1 1 933 — 1,494 253 72 $ $ 1,699 1,296 18 — $ 6 2,442 46 — — — — — — — 253 (6) 211 1,654 148 1 1 933 — — — 26 — — — — — — — — — — 1,494 — 52 $ 241 313 979 1,066 585 1 — 394 122 329 190 24 241 313 173 53 26 — — 16 3 — 189 — $ — $ — — — — 806 1,013 537 1 — 378 119 — 1 21 — 22 — — — — 329 — 3 4,244 $ 1,014 $ 2,876 $ 354 $ 392 457 572 1,089 615 — 1 — 269 85 378 232 19 $ 382 435 7 93 33 — — — 12 4 — 232 (2) 10 22 565 996 557 — 1 — 257 81 — — 19 $ — — — — 25 — — — — — 378 — 2 Total at December 31, 2015 $ 10,274 $ 3,306 $ 5,422 $ 1,546 $ 4,109 $ 1,196 $ 2,508 $ 405 1 U.S. equities include investments in the company’s common stock in the amount of $9 at December 31, 2015, and $24 at December 31, 2014. 2 Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly index funds. For these index funds, the Level 2 designation is partially based on the restriction that advance notification of redemptions, typically two business days, is required. 3 Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk. 4 The year-end valuations of the U.S. real estate assets are based on internal appraisals by the real estate managers, which are updates of third-party appraisals that occur at least once a year for each property in the portfolio. 5 The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts and investments in private-equity limited partnerships (Level 3). Chevron Corporation 2015 Annual Report 63 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below: Total at December 31, 2013 Actual Return on Plan Assets: Assets held at the reporting date Assets sold during the period Purchases, Sales and Settlements Transfers in and/or out of Level 3 Total at December 31, 2014 Actual Return on Plan Assets: Assets held at the reporting date Assets sold during the period Purchases, Sales and Settlements Transfers in and/or out of Level 3 Total at December 31, 2015 $ $ $ Corporate Mortgage-Backed Securities Real Estate Other Fixed Income 23 $ 2 $ 1,559 $ — — (1) — 22 (3) — 6 — 25 $ $ — — (2) — — — — — — — 115 20 (1) — $ 1,693 $ 149 23 7 — $ 1,872 $ 57 — — — — 57 (1) — (2) — 54 $ Total 1,641 115 20 (4) — $ 1,772 145 23 11 — $ 1,951 The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate liquidity for benefit payments and portfolio management. The company’s U.S. and U.K. pension plans comprise 91 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established. For the primary U.S. pension plan, the company’s Benefit Plan Investment Committee has established the following approved asset allocation ranges: Equities 40–70 percent, Fixed Income and Cash 20–60 percent, Real Estate 0–15 percent, and Other 0–5 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 30–50 percent, Fixed Income and Cash 35–65 percent, and Real Estate 5–15 percent. The other significant international pension plans also have established maximum and minimum asset allocation ranges that vary by plan. Actual asset allocation within approved ranges is based on a variety of current economic and market conditions and consideration of specific asset class risk. To mitigate concentration and other risks, assets are invested across multiple asset classes with active investment managers and passive index funds. The company does not prefund its OPEB obligations. Cash Contributions and Benefit Payments In 2015, the company contributed $641 and $227 to its U.S. and international pension plans, respectively. In 2016, the company expects contributions to be approximately $650 to its U.S. plans and $250 to its international pension plans. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations. The company anticipates paying OPEB benefits of approximately $191 in 2016; $196 was paid in 2015. The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years: 2016 2017 2018 2019 2020 2021-2025 64 Chevron Corporation 2015 Annual Report Pension Benefits U.S. 1,462 1,384 1,360 1,329 1,287 5,804 $ $ $ $ $ $ Int’l. 284 297 467 339 346 1,822 Other Benefits 191 195 199 203 207 1,053 $ $ $ $ $ $ $ $ $ $ $ $ Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP). Compensation expense for the ESIP totaled $316, $316 and $163 in 2015, 2014 and 2013, respectively. The amount for ESIP expense in 2013 is net of $140, which reflects the value of common stock released from the former leveraged employee stock ownership plan (LESOP). LESOP debt was retired in 2013, and all remaining shares were released. Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2015, the trust contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The company intends to continue to pay its obligations under the benefit plans. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings- per-share purposes until distributed or sold by the trust in payment of benefit obligations. Prior to its acquisition by Chevron, Unocal established various grantor trusts to fund obligations under some of its benefit plans, including the deferred compensation and supplemental retirement plans. At December 31, 2015 and 2014, trust assets of $36 and $38, respectively, were invested primarily in interest-earning accounts. Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate, business unit and individual performance in the prior year. Charges to expense for cash bonuses were $690, $965 and $871 in 2015, 2014 and 2013, respectively. Chevron also has the LTIP for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 22, beginning on page 58. Note 24 Other Contingencies and Commitments Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 18, beginning on page 53, for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. Settlement of open tax years, as well as other tax issues in countries where the company conducts its businesses, are not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination. Guarantees The company’s guarantee of $447 is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 12-year remaining term of the guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee. Indemnifications In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $200, which had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200 obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997. Although the company has provided for known obligations under this indemnity that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum Chevron Corporation 2015 Annual Report 65 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2016 – $2,100; 2017 – $1,900; 2018 – $1,700; 2019 – $1,500; 2020 – $1,100; 2020 and after – $3,100. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $1,900 in 2015, $3,700 in 2014 and $3,600 in 2013. Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, chemical plants, marketing facilities, crude oil fields, and mining sites. Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities. The amount of additional future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of operations in the period in which they are recognized, but the company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Chevron’s environmental reserve as of December 31, 2015, was $1,578. Included in this balance were $348 related to remediation activities at approximately 163 sites for which the company had been identified as a potentially responsible party under the provisions of the federal Superfund law or analogous state laws which provide for joint and several liability for all responsible parties. Any future actions by regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity. Of the remaining year-end 2015 environmental reserves balance of $1,230, $845 is related to the company’s U.S. downstream operations, $58 to its international downstream operations, $323 to upstream operations and $4 to other businesses. Liabilities at all sites were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both. The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2015 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity. Refer to Note 25 on page 67 for a discussion of the company’s asset retirement obligations. Other Contingencies On November 7, 2011, while drilling a development well in the deepwater Frade Field about 75 miles offshore Brazil, an unanticipated pressure spike caused oil to migrate from the well bore through a series of fissures to the sea floor, emitting approximately 2,400 barrels of oil. The source of the seep was substantially contained within four days and the well was plugged and abandoned. On March 14, 2012, the company identified a small, second seep in a different part of the field. No evidence of any coastal or wildlife impacts related to either of these seeps emerged. As reported in the company’s previously filed periodic reports, it has resolved civil claims relating to these incidents brought by a Brazilian federal district prosecutor. As also reported previously, the federal district prosecutor also filed criminal charges against Chevron and 11 Chevron employees. These charges were dismissed by the trial court on February 19, 2013, reinstated by an appellate court on October 9, 2013, and then, upon Chevron’s motion for reconsideration, dismissed by the appellate court on August 27, 2015. The federal district prosecutor has appealed the appellate court’s decision. Chevron receives claims from and submits claims to customers; trading partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; suppliers; and individuals. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve, and may result in gains or losses in future periods. The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in significant gains or losses in future periods. 66 Chevron Corporation 2015 Annual Report Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 25 Asset Retirement Obligations The company records the fair value of a liability for an asset retirement obligation (ARO) as an asset and liability when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional, even though uncertainty may exist about the timing and/or method of settlement that may be beyond the company’s control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate fair value. Recognition of the ARO includes: (1) the present value of a liability and offsetting asset, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates. AROs are primarily recorded for the company’s crude oil and natural gas producing assets. No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO. The company performs periodic reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation. The following table indicates the changes to the company’s before-tax asset retirement obligations in 2015, 2014 and 2013: Balance at January 1 Liabilities incurred Liabilities settled Accretion expense Revisions in estimated cash flows Balance at December 31 $ 2015 15,053 51 (981) 715 804 $ $ 2014 14,298 133 (1,291) 882 1,031 2013 13,271 59 (907) 627 1,248 $ 15,642 $ 15,053 $ 14,298 In the table above, the amounts associated with “Revisions in estimated cash flows” generally reflect increased cost estimates to abandon wells, equipment and facilities and accelerated timing of abandonment. The long-term portion of the $15,642 balance at the end of 2015 was $14,892. Note 26 Restructuring and Reorganization Costs In 2015, the company recorded accruals and adjustments for employee reduction programs related to the restructuring and reorganization of its corporate staffs and certain upstream operations. The employee reductions are expected to be substantially completed by the end of 2016. A before-tax charge of $353 ($223 after-tax) was recorded in 2015, with $219 reported as “Operating Expenses” and $134 reported as “Selling, general and administrative expense” on the Consolidated Statement of Income. The accrued liability, covering severance benefits, is classified as current on the Consolidated Balance Sheet. Approximately $134 ($87 after-tax) is associated with employee reductions in All Other, $113 ($73 after-tax) in U.S. Upstream and $106 ($63 after-tax) in International Upstream. During 2015, the company made payments of $60 associated with these liabilities. The following table summarizes the accrued severance liability, which is classified as current on the Consolidated Balance Sheet: Balance at January 1, 2015 Accruals/Adjustments Payments Balance at December 31, 2015 Amounts Before Tax $ $ — 353 (60) 293 Note 27 Other Financial Information Earnings in 2015 included after-tax gains of approximately $2,300 relating to the sale of nonstrategic properties. Of this amount, approximately $1,800 and $500 related to downstream and upstream, respectively. Earnings in 2014 included after- tax gains of approximately $3,000 relating to the sale of nonstrategic properties, of which approximately $1,800 and $1,000 related to upstream and downstream assets, respectively. Earnings in 2015 included after-tax charges of approximately $3,000 for impairments and other asset write-offs related to upstream. Earnings in 2014 included after-tax charges of approximately $1,000 for impairments and other asset write-offs, of which $800 was related to upstream and $200 to a mining asset. Chevron Corporation 2015 Annual Report 67 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Other financial information is as follows: Total financing interest and debt costs Less: Capitalized interest Interest and debt expense Research and development expenses Excess of replacement cost over the carrying value of inventories (LIFO method) LIFO (losses) / profits on inventory drawdowns included in earnings Foreign currency effects* 2015 495 495 — 601 3,745 (65) 769 $ $ $ $ Year ended December 31 2014 358 358 $ — $ 707 $ 8,135 13 487 $ 2013 284 284 — 750 9,150 14 474 $ $ $ $ * Includes $344, $118 and $244 in 2015, 2014 and 2013, respectively, for the company’s share of equity affiliates’ foreign currency effects. The company has $4,588 in goodwill on the Consolidated Balance Sheet related to the 2005 acquisition of Unocal and to the 2011 acquisition of Atlas Energy, Inc. The company tested this goodwill for impairment during 2015 and concluded no impairment was necessary. Five-Year Financial Summary Unaudited Millions of dollars, except per-share amounts 2015 2014 2013 2012 2011 Statement of Income Data Revenues and Other Income Total sales and other operating revenues* Income from equity affiliates and other income Total Revenues and Other Income Total Costs and Other Deductions Income Before Income Tax Expense Income Tax Expense Net Income Less: Net income attributable to noncontrolling interests Net Income Attributable to Chevron Corporation Per Share of Common Stock Net Income Attributable to Chevron – Basic – Diluted Cash Dividends Per Share Balance Sheet Data (at December 31) Current assets Noncurrent assets Total Assets Short-term debt Other current liabilities Long-term debt and capital lease obligations Other noncurrent liabilities Total Liabilities Total Chevron Corporation Stockholders’ Equity Noncontrolling interests Total Equity * Includes excise, value-added and similar taxes: $ $ $ $ $ $ $ $ $ 68 Chevron Corporation 2015 Annual Report $ 129,925 8,552 138,477 133,635 4,842 132 4,710 123 4,587 2.46 2.45 4.28 35,347 230,756 266,103 4,928 21,536 33,664 52,089 112,217 152,716 1,170 153,886 7,359 200,494 11,476 211,970 180,768 31,202 11,892 19,310 69 $ 220,156 8,692 $ 228,848 192,943 35,905 14,308 21,597 174 230,590 11,319 241,909 195,577 46,332 19,996 26,336 157 $ 244,371 9,335 253,706 206,072 47,634 20,626 27,008 113 $ 19,241 $ 21,423 $ 26,179 $ 26,895 $ $ $ $ $ $ $ 10.21 10.14 4.21 42,232 223,794 266,026 3,790 28,136 24,028 53,881 109,835 155,028 1,163 $ $ $ $ 11.18 11.09 3.90 50,250 203,503 253,753 374 32,644 20,057 50,251 103,326 $ 149,113 1,314 156,191 $ 150,427 8,186 $ 8,492 $ $ $ $ $ $ $ 13.42 13.32 3.51 55,720 177,262 232,982 127 34,085 12,065 48,873 95,150 136,524 1,308 137,832 8,010 $ $ $ $ $ $ $ 13.54 13.44 3.09 53,234 156,240 209,474 340 33,260 9,812 43,881 87,293 121,382 799 122,181 8,085 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Five-Year Operating Summary Unaudited Worldwide – Includes Equity in Affiliates Thousands of barrels per day, except natural gas data, which is millions of cubic feet per day United States Net production of crude oil and natural gas liquids Net production of natural gas1 Net oil-equivalent production Refinery input Sales of refined products Sales of natural gas liquids Total sales of petroleum products Sales of natural gas International Net production of crude oil and natural gas liquids2 Net production of natural gas1 Net oil-equivalent production Refinery input3 Sales of refined products4 Sales of natural gas liquids Total sales of petroleum products Sales of natural gas Total Worldwide Net production of crude oil and natural gas liquids Net production of natural gas Net oil-equivalent production Refinery input Sales of refined products Sales of natural gas liquids Total sales of petroleum products Sales of natural gas Worldwide – Excludes Equity in Affiliates Number of completed wells (net)5, 6 Oil and gas Dry Productive oil and gas wells (net)5, 6 1 Includes natural gas consumed in operations: United States International 2 Includes net production of synthetic oil: Canada Venezuela affiliate 3 As of June 2012, Star Petroleum Refining Public Company Limited crude-input volumes are reported on a 100 percent consolidated basis. Prior to June 2012, crude- input volumes reflect a 64 percent equity interest. 4 Includes sales of affiliates (MBPD): 5 Net wells include wholly owned and the sum of fractional interests in partially owned wells 6 2014 conformed to 2015 presentation 2015 2014 2013 2012 2011 501 1,310 720 924 1,228 153 1,381 3,913 1,243 3,959 1,902 778 1,507 89 1,596 4,299 1,744 5,269 2,622 1,702 2,735 242 2,977 8,212 456 1,250 664 871 1,210 141 1,351 3,995 1,253 3,917 1,907 819 1,501 86 1,587 4,304 1,709 5,167 2,571 1,690 2,711 227 2,938 8,299 449 1,246 657 774 1,182 142 1,324 5,483 1,282 3,946 1,940 864 1,529 88 1,617 4,251 1,731 5,192 2,597 1,638 2,711 230 2,941 9,734 455 1,203 655 833 1,211 157 1,368 5,470 1,309 3,871 1,955 869 1,554 88 1,642 4,315 1,764 5,074 2,610 1,702 2,765 245 3,010 9,785 1,848 18 57,454 2,248 28 56,204 1,833 20 56,635 1,618 19 55,812 465 1,279 678 854 1,257 161 1,418 5,836 1,384 3,662 1,995 933 1,692 87 1,779 4,361 1,849 4,941 2,673 1,787 2,949 248 3,197 10,197 1,551 19 55,049 69 447 40 32 66 430 47 29 420 71 452 43 31 72 458 43 25 65 457 43 17 475 471 522 556 Chevron Corporation 2015 Annual Report 69 Supplemental Information on Oil and Gas Producing Activities - Unaudited In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V through VII present information on the company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved Table I - Costs Incurred in Exploration, Property Acquisitions and Development1 U.S. Other Americas Africa Asia Australia/ Oceania Europe Total TCO Other Consolidated Companies Affiliated Companies Millions of dollars Year Ended December 31, 2015 Exploration Wells Geological and geophysical Rentals and other Total exploration Property acquisitions2 Proved Unproved Total property acquisitions $ $ 857 69 218 1,144 23 554 577 $ 66 6 56 128 21 3 24 $ 172 77 121 370 — 30 30 $ 218 86 109 413 54 — 54 $ 81 107 71 259 — — — $ 14 26 68 108 — — — 1,408 371 643 2,422 98 587 685 $ — $ — — — — — — Development3 6,275 2,048 3,701 3,924 6,715 995 23,658 1,641 Total Costs Incurred4 $ 7,996 $ 2,200 $ 4,101 $ 4,391 $ 6,974 $ 1,103 $ 26,765 $ 1,641 $ Year Ended December 31, 2014 Exploration Wells Geological and geophysical Rentals and other Total exploration Property acquisitions2 Proved Unproved Total property acquisitions $ $ 965 107 150 1,222 33 196 229 $ 87 72 37 196 1 2 3 $ 436 32 198 666 521 39 560 $ $ 381 64 98 543 60 — 60 207 88 101 396 — — — $ 101 41 103 245 — — — 2,177 404 687 3,268 615 237 852 $ — $ — — — — — — Development3 8,207 3,226 3,771 4,363 7,182 887 27,636 1,598 Total Costs Incurred4 $ 9,658 $ 3,425 $ 4,997 $ 4,966 $ 7,578 $ 1,132 $ 31,756 $ 1,598 $ Year Ended December 31, 2013 Exploration Wells Geological and geophysical Rentals and other $ Total exploration Property acquisitions2 Proved Unproved Total property acquisitions Development3 $ 594 134 166 894 71 331 402 7,457 $ 495 70 62 627 — 2,068 2,068 2,306 $ 88 105 147 340 26 — 26 $ 405 116 80 601 64 203 267 $ 262 29 124 415 — 105 105 $ 123 55 131 309 1 3 4 1,967 509 710 3,186 162 2,710 2,872 $ — $ — — — — — — 3,549 4,907 6,611 1,046 25,876 1,027 Total Costs Incurred4 $ 8,753 $ 5,001 $ 3,915 $ 5,775 $ 7,131 $ 1,359 $ 31,934 $ 1,027 $ — — — — — — — 225 225 — — — — — — — 393 393 — — — — — — — 544 544 1 Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 25, “Asset Retirement Obligations,” on page 67. 2 Does not include properties acquired in nonmonetary transactions. 3 Includes $325, $349 and $661 costs incurred prior to assignment of proved reserves for consolidated companies in 2015, 2014, and 2013, respectively. 4 Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions: 2015 2014 2013 Total cost incurred $ Non-oil and gas activities ARO 28.6 3.5 (1.0) $ 33.7 4.6 (1.2) $ 33.5 5.8 (1.4) (Primarily includes LNG, gas-to-liquids and transportation activities) Upstream C&E $ 31.1 $ 37.1 $ 37.9 Reference page 21 Upstream total 70 Chevron Corporation 2015 Annual Report Supplemental Information on Oil and Gas Producing Activities - Unaudited reserves and changes in estimated discounted future net cash flows. The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia/Oceania and Europe. Amounts for affiliated companies include Chevron’s equity interests in Tengizchevroil (TCO) in the Republic of Kazakhstan and in other affiliates, principally in Venezuela and Angola. Refer to Note 15, beginning on page 48, for a discussion of the company’s major equity affiliates. Table II - Capitalized Costs Related to Oil and Gas Producing Activities Millions of dollars At December 31, 2015 Unproved properties Proved properties and related producing assets Support equipment Deferred exploratory wells Other uncompleted projects Gross Capitalized Costs Unproved properties valuation Proved producing properties – Depreciation and depletion Support equipment depreciation Accumulated provisions Net Capitalized Costs At December 31, 2014 Unproved properties Proved properties and related producing assets Support equipment Deferred exploratory wells Other uncompleted projects Gross Capitalized Costs Unproved properties valuation Proved producing properties – Depreciation and depletion Support equipment depreciation Accumulated provisions Net Capitalized Costs At December 31, 2013 Unproved properties Proved properties and related producing assets Support equipment Deferred exploratory wells Other uncompleted projects Gross Capitalized Costs Unproved properties valuation Proved producing properties – Depreciation and depletion Support equipment depreciation Accumulated provisions U.S. Other Americas Africa Asia Australia/ Oceania Europe Total TCO Other Consolidated Companies Affiliated Companies $ 9,880 $ 3,216 $ 271 $ 1,487 $ 1,990 $ 23 $ 16,867 $ 108 $ — $ $ $ $ 79,891 1,970 438 7,700 99,879 1,667 53,718 800 56,185 16,810 363 237 5,566 26,192 873 8,950 208 10,031 36,563 1,229 443 6,517 45,023 209 21,904 740 22,853 51,509 1,967 612 5,070 60,645 438 35,004 1,420 36,862 3,012 1,195 1,321 29,843 9,664 176 261 2,332 197,449 6,900 3,312 57,028 7,803 1,452 — 3,732 37,361 12,456 281,556 13,095 107 23 3,317 51 1,950 480 2,537 8,074 161 8,258 129,600 3,809 136,726 3,714 661 4,426 3,857 — — 425 4,282 — 984 — 984 43,694 $ 16,161 $ 22,170 $ 23,783 $ 34,824 $ 4,198 $ 144,830 $ 8,669 $ 3,298 10,095 $ 3,207 $ 286 $ 1,933 $ 1,990 $ 33 $ 17,544 $ 108 $ — 75,511 1,670 1,012 7,714 96,002 1,332 48,315 711 50,358 14,697 361 220 5,566 24,051 796 6,516 203 7,515 33,117 1,193 647 6,691 41,934 213 19,729 694 20,636 47,007 1,791 734 5,997 57,462 634 31,207 1,276 33,117 3,303 796 1,330 23,487 9,172 186 252 1,841 182,807 5,997 4,195 51,296 7,370 1,331 — 2,679 30,906 11,484 261,839 11,488 46 33 3,054 48 2,259 202 2,507 7,540 159 7,732 115,566 3,245 121,865 3,295 611 3,954 3,713 — — 458 4,171 — 845 — 845 45,644 $ 16,536 $ 21,298 $ 24,345 $ 28,399 $ 3,752 $ 139,974 $ 7,534 $ 3,326 10,228 $ 3,697 $ 267 $ 2,064 $ 1,990 $ 36 $ 18,282 $ 109 $ 29 67,837 1,314 670 9,149 89,198 1,243 45,756 656 47,655 12,868 344 297 4,175 21,381 707 5,695 189 6,591 32,936 1,180 536 4,424 39,343 203 18,051 647 18,901 42,780 1,678 335 5,998 52,855 389 27,356 1,177 28,922 3,274 1,608 1,134 16,000 9,592 177 273 1,390 24,006 11,468 6 31 2,083 384 2,473 7,825 149 8,005 169,287 6,301 3,245 41,136 238,251 2,579 106,766 3,202 112,547 6,977 1,166 — 1,638 9,890 45 2,672 538 3,255 3,408 — — 404 3,841 10 696 — 706 Net Capitalized Costs $ 41,543 $ 14,790 $ 20,442 $ 23,933 $ 21,533 $ 3,463 $ 125,704 $ 6,635 $ 3,135 Chevron Corporation 2015 Annual Report 71 Supplemental Information on Oil and Gas Producing Activities - Unaudited Table III - Results of Operations for Oil and Gas Producing Activities1 The company’s results of operations from oil and gas producing activities for the years 2015, 2014 and 2013 are shown in the following table. Net income from exploration and production activities as reported on page 46 reflects income taxes computed on an effective rate basis. Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page 46. Millions of dollars Year Ended December 31, 2015 Revenues from net production Sales Transfers Total Production expenses excluding taxes Taxes other than on income Proved producing properties: Depreciation and depletion Accretion expense2 Exploration expenses Unproved properties valuation Other income (expense)3 Results before income taxes Income tax expense Results of Producing Operations Year Ended December 31, 2014 Revenues from net production Sales Transfers Total Production expenses excluding taxes Taxes other than on income Proved producing properties: Depreciation and depletion Accretion expense2 Exploration expenses Unproved properties valuation Other income (expense)3 Results before income taxes Income tax expense Other Americas U.S. Africa Australia/ Oceania Asia Europe Total TCO Other Consolidated Companies Affiliated Companies $ 1,475 $ 7,195 1,155 $ 1,089 8,670 (4,293) (430) (7,640) (265) (1,614) (583) 220 (5,935) 2,133 2,244 (1,162) (123) (2,519) (23) (137) (55) (291) (2,066) 550 279 $ 6,182 6,461 (1,758) (124) (2,506) (127) (667) (24) 638 1,893 (986) 6,254 $ 3,779 889 $ 408 403 $ 829 10,455 19,482 $ 4,097 $ — 10,033 (3,601) (15) (3,887) (158) (492) (79) 21 1,822 (679) 1,297 (162) (172) (217) (37) (289) (61) 73 432 (178) 1,232 (505) (2) (556) (69) (106) — 237 231 (62) 29,937 (11,481) (866) (17,325) (679) (3,305) (802) 898 (3,623) 778 4,097 (510) (279) (501) (3) — — (25) 2,779 (835) 729 — 729 (365) (31) (169) (14) (1) — 373 522 (291) $ $ (3,802) $ (1,516) $ 907 $ 1,143 $ 254 $ 169 $ (2,845) $ 1,944 $ 231 2,660 $ 13,023 1,338 $ 2,285 15,683 (4,786) (654) 3,623 (1,328) (122) (4,605) (334) (581) (140) 654 5,237 (1,955) (793) (22) (119) (219) 674 1,694 (471) 707 $ 12,546 13,253 (2,084) (140) (3,092) (130) (383) (12) 221 7,633 (4,924) 8,290 $ 1,466 $ 8,153 888 1,037 $ 1,277 15,498 38,172 $ 7,717 $ — 16,443 (4,527) (82) (3,977) (142) (309) (289) 115 7,232 (3,604) 2,354 (191) (329) (208) (32) (269) (40) 102 1,387 (392) 2,314 (773) (4) (351) (84) (281) (3) 358 1,176 (579) 53,670 (13,689) (1,331) (13,026) (744) (1,942) (703) 2,124 24,359 (11,925) 7,717 (493) (344) (567) (9) — — (28) 6,276 (1,883) 1,733 — 1,733 (670) (418) (175) (4) (5) (38) (85) 338 (284) Results of Producing Operations $ 3,282 $ 1,223 $ 2,709 $ 3,628 $ 995 $ 597 $ 12,434 $ 4,393 $ 54 1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. 2 Represents accretion of ARO liability. Refer to Note 25, “Asset Retirement Obligations,” on page 67. 3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses. 72 Chevron Corporation 2015 Annual Report Supplemental Information on Oil and Gas Producing Activities - Unaudited Table III - Results of Operations for Oil and Gas Producing Activities1, continued Millions of dollars Year Ended December 31, 2013 Revenues from net production Sales Transfers Total Production expenses excluding taxes Taxes other than on income Proved producing properties: Depreciation and depletion Accretion expense2 Exploration expenses Unproved properties valuation Other income (expense)3 Results before income taxes Income tax expense Other Americas U.S. Africa Asia Australia/ Oceania Europe Total TCO Other Consolidated Companies Affiliated Companies $ 2,303 $ 14,471 1,351 $ 1,973 16,774 (4,606) (648) 3,324 (1,218) (90) (4,039) (223) (555) (129) 242 6,816 (2,471) (440) (22) (372) (84) (5) 1,093 (289) 702 $ 14,804 15,506 (2,099) (149) (2,747) (125) (203) (13) 145 10,315 (6,545) 9,220 $ 9,521 1,431 $ 984 1,345 $ 1,701 16,352 43,454 $ 8,522 $ — 18,741 (4,429) (140) (3,602) (114) (272) (141) (275) 9,768 (4,824) 2,415 (193) (378) (342) (28) (161) (4) 89 1,398 (411) 3,046 (759) (3) (416) (79) (258) (5) 13 1,539 (1,058) 59,806 (13,304) (1,408) (11,586) (591) (1,821) (376) 209 30,929 (15,598) 8,522 (401) (439) (518) (9) — — (81) 7,074 (2,122) 2,100 — 2,100 (444) (704) (179) (14) — (10) 462 1,211 (624) Results of Producing Operations $ 4,345 $ 804 $ 3,770 $ 4,944 $ 987 $ 481 $ 15,331 $ 4,952 $ 587 1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. 2 Represents accretion of ARO liability. Refer to Note 25, “Asset Retirement Obligations,” on page 67. 3 Includes foreign currency gains and losses, gains and losses on property dispositions, and other miscellaneous income and expenses. Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs1 Other Americas3 U.S. Africa Asia Australia/ Oceania Europe Total TCO Other Consolidated Companies Affiliated Companies Year Ended December 31, 2015 Average sales prices Liquids, per barrel Natural gas, per thousand cubic feet Average production costs, per barrel2 Year Ended December 31, 2014 Average sales prices Liquids, per barrel Natural gas, per thousand cubic feet Average production costs, per barrel2 Year Ended December 31, 2013 Average sales prices Liquids, per barrel Natural gas, per thousand cubic feet Average production costs, per barrel2 $ $ $ 42.70 $ 1.89 16.60 49.66 $ 3.24 20.45 49.88 $ 1.84 12.23 46.19 $ 4.94 13.55 49.96 $ 6.17 5.03 48.53 $ 5.28 17.14 46.26 3.96 14.60 84.13 $ 3.90 20.09 86.23 $ 3.25 22.77 96.43 $ 1.53 13.77 89.44 $ 5.86 17.21 95.17 $ 10.42 5.53 95.05 $ 9.29 27.14 89.44 5.44 17.69 93.46 $ 3.38 19.57 91.44 $ 3.03 21.29 107.22 $ 1.76 13.93 98.37 $ 6.02 16.49 103.28 $ 10.61 5.90 105.78 $ 11.04 22.87 99.05 5.45 17.10 $ $ $ 38.71 $ 1.57 4.32 34.92 2.51 17.44 81.07 $ 1.53 4.47 76.07 6.38 29.30 88.06 $ 1.50 4.37 78.87 4.00 22.69 1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. 2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel. 3 2013 and 2014 conformed to 2015 presentation. Chevron Corporation 2015 Annual Report 73 Supplemental Information on Oil and Gas Producing Activities - Unaudited Table V Reserve Quantity Information Summary of Net Oil and Gas Reserves Liquids in Millions of Barrels Natural Gas in Billions of Cubic Feet 2015 2014 2013 Crude Oil Condensate NGLs Synthetic Oil Natural Gas Crude Oil Condensate NGLs Synthetic Oil Natural Gas Crude Oil Condensate NGLs Synthetic Oil Natural Gas Proved Developed Consolidated Companies U.S. Other Americas Africa Asia Australia/Oceania Europe Total Consolidated Affiliated Companies TCO Other Total Consolidated and Affiliated Companies Proved Undeveloped Consolidated Companies U.S. Other Americas Africa Asia Australia/Oceania Europe Total Consolidated Affiliated Companies TCO Other Total Consolidated and Affiliated Companies Total Proved Reserves 933 109 702 660 60 76 — 2,683 597 594 — 1,100 — 4,933 — 4,330 166 — 955 103 701 584 38 87 — 2,743 739 531 — 1,112 — 4,607 — 1,117 167 — 976 109 763 601 44 94 — 2,632 943 403 — 1,161 — 4,620 — 1,251 200 — 2,540 594 13,809 2,468 531 10,485 2,587 403 10,807 1,020 91 3,651 453 127 255 130 93 67 — 1,504 288 58 961 100 — 1,431 317 51 884 105 — 1,188 330 44 652 15,601 3,529 582 12,233 3,576 447 12,325 — 1,559 117 3 — 1,837 — 1,023 — 7,543 58 — 477 135 320 168 104 79 — 1,431 384 3 — 1,856 — 1,659 — 9,824 68 — 354 134 341 191 87 72 — 1,358 357 134 — 1,884 — 2,125 — 9,076 63 — 1,125 3 12,137 1,283 3 15,222 1,179 134 14,863 656 40 1,821 5,472 — 135 764 935 138 13,836 790 29,437 654 45 1,982 5,511 — 153 746 915 156 16,883 738 29,116 784 49 2,012 5,588 — 1,102 856 176 310 16,821 757 29,146 Reserves Governance The company has adopted a comprehensive reserves and resource classification system modeled after a system developed and approved by the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The system classifies recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three potentially recoverable. Within the commercial classification are proved reserves and two categories of unproved: probable and possible. The potentially recoverable categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC and company standards. Proved oil and gas reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate. Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available. 74 Chevron Corporation 2015 Annual Report Supplemental Information on Oil and Gas Producing Activities - Unaudited Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Corporate Reserves, a corporate department that is separate from the Upstream operating organization. The Manager of Corporate Reserves has more than 30 years’ experience working in the oil and gas industry and a Master of Science in Petroleum Engineering degree from Stanford University. His experience includes more than 15 years of managing oil and gas reserves processes. He was chairman of the Society of Petroleum Engineers Oil and Gas Reserves Committee, served on the United Nations Expert Group on Resources Classification, and is a past member of the Joint Committee on Reserves Evaluator Training and the California Conservation Committee. He is an active member of the Society of Petroleum Evaluation Engineers and serves on the Society of Petroleum Engineers Oil and Gas Reserves Committee. All RAC members are degreed professionals, each with more than 10 years of experience in various aspects of reserves estimation relating to reservoir engineering, petroleum engineering, earth science or finance. The members are knowledgeable in SEC guidelines for proved reserves classification and receive annual training on the preparation of reserves estimates. The RAC has the following primary responsibilities: establish the policies and processes used within the operating units to estimate reserves; provide independent reviews and oversight of the business units’ recommended reserves estimates and changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology; and maintain the Corporate Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves. During the year, the RAC is represented in meetings with each of the company’s upstream business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s Strategy and Planning Committee, whose members include the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserve activity is also reviewed with the Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board. RAC subteams also conduct in-depth reviews during the year of many of the fields that have large proved reserves quantities. These reviews include an examination of the proved-reserve records and documentation of their compliance with the Corporate Reserves Manual. Technologies Used in Establishing Proved Reserves Additions In 2015, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies. Information generated from wells, such as well logs, wire line sampling, production and pressure testing, fluid analysis, and core analysis, was integrated with seismic data, regional geologic studies, and information from analogous reservoirs to provide “reasonably certain” proved reserves estimates. Both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates. Proved Undeveloped Reserves At the end of 2015, proved undeveloped reserves totaled 4.3 billion barrels of oil-equivalent (BOE), a decrease of 687 million BOE from year-end 2014. The decrease was due to the transfer of 1,027 million BOE to proved developed and 2 million BOE in sales, partially offset by increases of 273 million BOE in extensions and discoveries, 65 million BOE in revisions, and 4 million BOE in improved recovery. During 2015, investments totaling approximately $14.3 billion in oil and gas producing activities and about $2.3 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. Australia accounted for about $6.4 billion of the total, mainly for development and construction activities at the Gorgon and Wheatstone LNG projects. Expenditures of about $2.7 billion in the United States related primarily to various development activities in the Gulf of Mexico and the midcontinent region. In Asia, expenditures during the year totaled approximately $3.2 billion, primarily related to development projects of the TCO affiliate in Kazakhstan, and in Thailand. In Africa, about $2.8 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of the Congo. Development activities in Canada were primarily responsible for about $1.5 billion of expenditures in Other Americas. Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels. Chevron Corporation 2015 Annual Report 75 Supplemental Information on Oil and Gas Producing Activities - Unaudited At year-end 2015, the company held approximately 2.2 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in three locations where the company has a proven track record of developing major projects. In Australia, approximately 500 million BOE have remained undeveloped for five years or more related to the Gorgon Project. The company is currently constructing liquefaction and other facilities in Australia to develop this natural gas. In Africa, approximately 400 million BOE have remained undeveloped for five years or more, primarily due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria. Affiliates account for about 1.1 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more, with the majority related to the TCO affiliate in Kazakhstan. At TCO, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion. Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations or government policies, that would warrant a revision to reserve estimates. In 2015, significant reductions in commodity prices negatively impacted the economic limits of oil and gas properties, resulting in proved reserve decreases, and positively impacted proved reserves due to entitlement effects. The year-end reserves volumes have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections. For 2015, this assessment did not result in any material changes in reserves classified as proved undeveloped. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 38 percent and 46 percent. The consistent completion of major capital projects has kept the ratio in a narrow range over this time period. Proved Reserve Quantities For the three years ending December 31, 2015, the pattern of net reserve changes shown in the following tables are not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest. At December 31, 2015, proved reserves for the company were 11.2 billion BOE. The company’s estimated net proved reserves of liquids including crude oil, condensate, natural gas liquids and synthetic oil for the years 2013, 2014 and 2015 are shown in the table on page 77. The company’s estimated net proved reserves of natural gas are shown on page 78. Noteworthy changes in liquids proved reserves for 2013 through 2015 are discussed below and shown in the table on the following page: Revisions In 2013, improved field performance from various Nigeria and Angola producing assets was primarily responsible for the 94 million barrel increase in Africa. In Asia, drilling performance across numerous assets resulted in an 84 million barrel increase. Improved field performance and drilling associated with Gulf of Mexico projects and drilling in the Midland and Delaware basins accounted for the majority of the 55 million barrel increase in the United States. Synthetic oil reserves in Canada increased by 40 million barrels, primarily due to improved field performance. In 2014, drilling in the Midland and Delaware basins and improved field performance and drilling in California accounted for the majority of the 90 million barrel increase in the United States. Improved field performance at various Nigeria fields was primarily responsible for the 74 million barrel increase in Africa. In Asia, drilling performance across numerous assets, primarily in Indonesia, resulted in the 80 million barrel increase. In 2015, entitlement effects and improved performance were responsible for the 163 million barrel increase in the TCO affiliate in Kazakhstan. In Asia, entitlement effects and drilling performance across numerous assets resulted in the 164 million barrel increase. Improved field performance at various Nigerian fields, including Agbami, was primarily responsible for the 60 million barrel increase in Africa. Synthetic oil reserves in Canada increased by 80 million barrels, primarily due to entitlement effects. Improved Recovery In 2013, improved recovery increased reserves by 57 million barrels due to numerous small projects, including expansions of existing projects in the United States, Europe, Asia, and Africa. In 2014, improved recovery increased reserves by 34 million barrels, primarily due to secondary recovery projects in the United States, mostly related to steamflood expansions in California. Extensions and Discoveries In 2013, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 55 million barrel increase in the United States. 76 Chevron Corporation 2015 Annual Report Supplemental Information on Oil and Gas Producing Activities - Unaudited In 2014, extensions and discoveries in the Midland and Delaware basins and the Gulf of Mexico were primarily responsible for the 164 million barrel increase in the United States. In 2015, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 137 million barrel increase in the United States. Purchases In 2014, the purchase of additional reserves in Canada was responsible for the 26 million barrel increase in synthetic oil. Sales In 2014, the sale of the company’s interests in Chad was responsible for the 20 million barrel decrease in Africa. Net Proved Reserves of Crude Oil, Condensate, Natural Gas Liquids and Synthetic Oil Millions of barrels U.S. Americas1 Africa Asia Oceania Europe Oil2 Total TCO Oil Other3 Other Australia/ Consolidated Companies Synthetic Affiliated Companies Synthetic Total Consolidated and Affiliated Companies Reserves at January 1, 2013 Changes attributable to: Revisions Improved recovery Extensions and discoveries Purchases Sales Production Reserves at December 31, 20134 Changes attributable to: Revisions Improved recovery Extensions and discoveries Purchases Sales Production Reserves at December 31, 20144 Changes attributable to: Revisions Improved recovery Extensions and discoveries Purchases Sales Production 1,359 223 1,130 837 134 157 513 4,353 1,732 232 164 6,481 55 26 55 2 (3) (164) 25 — 4 9 — (18) 84 94 10 10 13 2 — — (1) — (142) (141) 7 — — — — (10) 17 11 4 — — (23) 40 — — — — (16) 322 57 78 11 (4) (514) 32 — — — — (96) (3) — — — — (9) 3 — — — — (13) 354 57 78 11 (4) (632) 1,330 243 1,104 792 131 166 537 4,303 1,668 220 154 6,345 90 19 164 1 (6) (166) 80 74 — 8 1 1 7 2 18 — — — — (20) — (140) (135) (24) 19 — — — — (8) 9 5 8 — (3) (19) 240 (32) 34 — 218 19 26 27 — (29) (508) (16) 41 — — — — (94) (4) — — — — (12) — — 1 — — (10) 277 34 219 27 (29) (624) 1,432 238 1,021 752 142 166 534 4,285 1,615 204 145 6,249 (1) 7 137 — (6) (183) (9) — 28 — — (21) 60 11 4 164 2 5 — — (7) — (132) (133) 14 — 5 — — (8) (3) — — — — (20) 305 80 — 20 — 179 — — — (13) (514) (17) 163 — — — — (102) — — — — — (11) (4) — — — (10) 464 20 179 — (13) (637) Reserves at December 31, 20154 1,386 236 957 790 153 143 597 4,262 1,676 193 131 6,262 1 Ending reserve balances in North America were 155, 142 and 141 and in South America were 81, 96 and 102 in 2015, 2014 and 2013, respectively. 2 Reserves associated with Canada. 3 Ending reserve balances in Africa were 34, 37 and 37 and in South America were 97, 108 and 117 in 2015, 2014 and 2013, respectively. 4 Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page 8 for the definition of a PSC). PSC-related reserve quantities are 20 percent, 19 percent and 20 percent for consolidated companies for 2015, 2014 and 2013, respectively. Chevron Corporation 2015 Annual Report 77 Supplemental Information on Oil and Gas Producing Activities - Unaudited Net Proved Reserves of Natural Gas Billions of cubic feet (BCF) U.S. Americas1 Africa Asia Other Consolidated Companies Affiliated Companies Australia/ Oceania Europe Total TCO Other2 Total Consolidated and Affiliated Companies Reserves at January 1, 2013 Changes attributable to: Revisions Improved recovery Extensions and discoveries Purchases Sales Production3 Reserves at December 31, 2013 Changes attributable to: Revisions Improved recovery Extensions and discoveries Purchases Sales Production3 Reserves at December 31, 2014 Changes attributable to: Revisions Improved recovery Extensions and discoveries Purchases Sales Production3 3,722 1,475 3,081 6,867 10,252 257 25,654 2,299 1,242 (234) 3 951 12 (10) (454) (59) — — 32 — (148) 27 2 27 — (1) (91) 627 6 16 60 — (831) 229 — — — — (154) 46 4 27 — (1) (70) 636 15 1,021 104 (12) (1,748) 117 — — — — (126) (35) — — — — (21) 3,990 1,300 3,045 6,745 10,327 263 25,670 2,290 1,186 76 2 614 1 (53) (456) (110) 1 56 — (1) (123) 35 1 — — (3) (110) 252 — 79 21 — (831) 775 — — — — (161) 36 1 3 — (5) (63) 1,064 5 752 22 (62) (1,744) 9 — — — — (122) 34 — 32 — — (20) 4,174 1,123 2,968 6,266 10,941 235 25,707 2,177 1,232 (66) 1 659 — (48) (478) (435) — 147 — — (121) 27 — 61 — (5) (114) 480 — 61 — — (851) 974 — 118 — — (160) 1,029 49 1 — — 1,046 — — — (53) (1,784) (60) 218 — — — — (127) 2 — — — — (11) Reserves at December 31, 2015 4,242 714 2,937 5,956 11,873 224 25,946 2,268 1,223 29,195 718 15 1,021 104 (12) (1,895) 29,146 1,107 5 784 22 (62) (1,886) 29,116 1,249 1 1,046 — (53) (1,922) 29,437 1 Ending reserve balances in North America and South America were 174, 59, 54 and 540, 1,064, 1,246 in 2015, 2014 and 2013, respectively. 2 Ending reserve balances in Africa and South America were 1,044, 1,043, 1,009 and 179, 189, 177 in 2015, 2014 and 2013, respectively. 3 Total “as sold” volumes are 1,742 BCF, 1,695 BCF and 1,702 BCF for 2015, 2014 and 2013, respectively; 2013 conformed to 2014 presentation. 4 Includes reserve quantities related to production-sharing contracts (PSC) (refer to page 8 for the definition of a PSC). PSC-related reserve quantities are 16 percent, 19 percent and 20 percent for consolidated companies for 2015, 2014 and 2013, respectively. Noteworthy changes in natural gas proved reserves for 2013 through 2015 are discussed below and shown in the table above: Revisions In 2013, net revisions of 627 BCF in Asia were primarily due to development drilling and improved field performance in Bangladesh and Thailand. In Australia, drilling performance drove the 229 BCF increase. The majority of the net decrease of 234 BCF in the United States was due to a change in development plans in the Appalachian region. In 2014, net revisions of 775 BCF in Australia were primarily due to development drilling at Gorgon. In 2015, positive drilling performance at Wheatstone and Gorgon was responsible for the 974 BCF increase in Australia. Net revisions of 480 BCF in Asia were primarily due to improved field performance in Thailand and to entitlement effects and improved performance in Kazakhstan. The majority of the net decrease of 435 BCF in Other Americas was due to the deferral of the infill drilling and compression projects as well as drilling results in Trinidad and Tobago. The 218 BCF increase for the TCO affiliate was due to entitlement effects and improved performance. Extensions and Discoveries In 2013, extensions and discoveries of 951 BCF in the United States were primarily in the Appalachian region. In 2014, extensions and discoveries of 614 BCF in the United States were primarily in the Appalachian region and the Delaware Basin. In 2015, extensions and discoveries of 659 BCF in the United States were primarily in the Appalachian region and the Midland and Delaware basins. 78 Chevron Corporation 2015 Annual Report Supplemental information on Oil and Gas Producing Activities - Unaudited Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves The standardized measure of discounted future net cash flows is calculated in accordance with SEC and FASB requirements. This includes using the average of first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount factors. Estimates of proved-reserve quantities are imprecise and change over time as new information becomes available. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves. In the following table, the caption “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows. Millions of dollars At December 31, 2015 Future cash inflows from production $ Future production costs Future development costs Future income taxes Undiscounted future net cash flows 10 percent midyear annual discount for timing of estimated cash flows Other Americas U.S. Consolidated Companies Australia/ Affiliated Companies Africa Asia Oceania Europe Total TCO Other Total Consolidated and Affiliated Companies 67,536 $ 39,363 $ 52,128 $ (33,895) (12,625) (4,161) (22,963) (6,562) (14,681) (26,477) (5,485) (2,316) 58,645 $ (27,499) (8,924) (9,229) 93,550 $ 8,561 $ 319,783 $ (10,814) (11,612) (21,337) (128,642) (46,959) (51,654) (6,994) (1,751) 70 75,378 $ 17,519 $ (17,959) (17,232) (12,056) (6,546) (3,226) (3,460) 412,680 (153,147) (67,417) (67,170) 16,855 5,085 7,922 12,993 49,787 (114) 92,528 28,131 4,287 124,946 (5,871) (2,830) (2,230) (3,673) (26,179) 292 (40,491) (15,249) (2,239) (57,979) Standardized Measure Net Cash Flows $ 10,984 $ 2,255 $ 5,692 $ 9,320 $ 23,608 $ 178 $ 52,037 $ 12,882 $ 2,048 $ 66,967 At December 31, 2014 Future cash inflows from production $ 138,385 $ 67,102 $ 103,304 $ Future production costs Future development costs Future income taxes (26,992) (9,486) (47,884) (30,899) (8,283) (8,445) (42,817) (13,616) (27,129) 99,741 $ 142,541 $ 18,168 $ 569,241 (158,625) (34,359) (62,726) (12,629) (144,610) (24,225) (10,814) (3,031) (2,692) (12,744) (15,681) (34,235) $ 144,721 $ 37,511 $ (30,015) (19,349) (28,607) (17,061) (4,454) (6,634) 751,473 (205,701) (86,529) (179,851) Undiscounted future net cash flows 10 percent midyear annual discount for timing of estimated cash flows Standardized Measure Net Cash Flows 54,823 19,475 18,942 28,528 79,881 1,631 203,280 66,750 9,362 279,392 (23,257) (12,082) (6,145) (8,570) (43,325) (380) (93,759) (34,987) (5,294) (134,040) $ 31,566 $ 7,393 $ 12,797 $ 19,958 $ 36,556 $ 1,251 $ 109,521 $ 31,763 $ 4,068 $ 145,352 At December 31, 20131 Future cash inflows from production $ 136,942 $ 73,468 $ 117,119 $ 111,970 $ 130,620 $ 20,232 $ 590,351 (154,590) Future production costs (71,344) Future development costs (152,696) Future income taxes (10,099) (2,644) (4,727) (35,716) (17,290) (26,162) (12,593) (18,220) (29,942) (27,800) (10,983) (53,953) (29,373) (10,149) (9,454) (39,009) (12,058) (28,458) $ 157,108 $ 43,380 $ (32,245) (12,852) (33,603) (18,027) (3,879) (9,418) 790,839 (204,862) (88,075) (195,717) Undiscounted future net cash flows 10 percent midyear annual discount for timing of estimated cash flows Standardized Measure Net Cash Flows 57,417 24,492 24,383 32,802 69,865 2,762 211,721 78,408 12,056 302,185 (23,055) (15,217) (8,165) (10,901) (39,117) (888) (97,343) (41,444) (6,482) (145,269) $ 34,362 $ 9,275 $ 16,218 $ 21,901 $ 30,748 $ 1,874 $ 114,378 $ 36,964 $ 5,574 $ 156,916 1 2013 conformed to 2014 and 2015 presentation. Chevron Corporation 2015 Annual Report 79 Supplemental information on Oil and Gas Producing Activities - Unaudited Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves The changes in present values between years, which can be significant, reflect changes in estimated proved-reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.” Millions of dollars Consolidated Companies1 Affiliated Companies Total Consolidated and Affiliated Companies Present Value at January 1, 2013 Sales and transfers of oil and gas produced net of production costs Development costs incurred Purchases of reserves Sales of reserves Extensions, discoveries and improved recovery less related costs Revisions of previous quantity estimates Net changes in prices, development and production costs Accretion of discount Net change in income tax Net change for 2013 Present Value at December 31, 2013 Sales and transfers of oil and gas produced net of production costs Development costs incurred Purchases of reserves Sales of reserves Extensions, discoveries and improved recovery less related costs Revisions of previous quantity estimates Net changes in prices, development and production costs Accretion of discount Net change in income tax Net change for 2014 Present Value at December 31, 2014 Sales and transfers of oil and gas produced net of production costs Development costs incurred Purchases of reserves Sales of reserves Extensions, discoveries and improved recovery less related costs Revisions of previous quantity estimates Net changes in prices, development and production costs Accretion of discount Net change in income tax Net change for 2015 Present Value at December 31, 2015 1 2013 conformed to 2014 and 2015 presentation. $ $ $ 110,626 (43,760) 22,907 184 243 3,135 22,796 (22,591) 18,510 2,328 3,752 114,378 (38,935) 25,687 255 (1,178) 3,956 17,462 (34,953) 18,884 3,965 (4,857) 109,521 (17,145) 21,703 2 (109) 1,415 9,171 (143,055) 18,179 52,355 (57,484) $ $ $ 45,214 (8,692) 1,411 — — — 1,306 (5,925) 6,406 2,818 (2,676) 42,538 (7,578) 1,963 — — 215 1,573 (12,496) 5,926 3,690 (6,707) 35,831 (3,637) 1,863 — — — 3,607 (37,056) 4,965 9,357 (20,901) $ $ $ 155,840 (52,452) 24,318 184 243 3,135 24,102 (28,516) 24,916 5,146 1,076 156,916 (46,513) 27,650 255 (1,178) 4,171 19,035 (47,449) 24,810 7,655 (11,564) 145,352 (20,782) 23,566 2 (109) 1,415 12,778 (180,111) 23,144 61,712 (78,385) $ 52,037 $ 14,930 $ 66,967 80 Chevron Corporation 2015 Annual Report chevron history 1984 Acquired Gulf Corporation — nearly doubling the company’s crude oil and natural gas activities — and gained significant presence in industrial chemicals, natural gas liquids and coal. Changed name to Chevron Corporation to identify with the name under which most products were marketed. 1988 Purchased Tenneco Inc.’s U.S. Gulf of Mexico crude oil and natural gas properties, becoming one of the largest U.S. natural gas producers. 1993 Formed Tengizchevroil, a joint venture with the Republic of Kazakhstan, to develop and produce the giant Tengiz Field, becoming the first major Western oil company to enter newly independent Kazakhstan. 1999 Acquired Rutherford-Moran Oil Corporation. This acquisition provided inroads to Asian natural gas markets. 2001 Merged with Texaco Inc. and changed name to ChevronTexaco Corporation. Became the second-largest U.S.-based energy company. 2002 Relocated corporate headquarters from San Francisco, California, to San Ramon, California. 2005 Acquired Unocal Corporation, an independent crude oil and natural gas exploration and production company. Unocal’s upstream assets bolstered Chevron’s already-strong position in the Asia-Pacific, U.S. Gulf of Mexico and Caspian regions. Changed name to Chevron Corporation to convey a clearer, stronger and more unified presence in the global marketplace. 2011 Acquired Atlas Energy, Inc., an indepen- dent U.S. developer and producer of shale gas resources. The acquired assets provide a targeted, high-quality core acreage position primarily in the Marcellus Shale. 1879 Incorporated in San Francisco, California, as the Pacific Coast Oil Company. 1900 Acquired by the West Coast operations of John D. Rockefeller’s original Standard Oil Company. 1911 Emerged as an autonomous entity — Standard Oil Company (California) — following U.S. Supreme Court decision to divide the Standard Oil conglomerate into 34 independent companies. 1926 Acquired Pacific Oil Company to become Standard Oil Company of California (Socal). 1936 Formed the Caltex Group of Companies, jointly owned by Socal and The Texas Company (later became Texaco), to combine Socal’s exploration and production interests in the Middle East and Indonesia and provide an outlet for crude oil through The Texas Company’s marketing network in Africa and Asia. 1947 Acquired Signal Oil Company, obtaining the Signal brand name and adding 2,000 retail stations in the western United States. 1961 Acquired Standard Oil Company (Kentucky), a major petroleum products marketer in five southeastern states, to provide outlets for crude oil from southern Louisiana and the U.S. Gulf of Mexico, where the company was a major producer. CYAN BLACK PMS 2945 board of directors John S. Watson, 59 Chairman of the Board and Chief Executive Officer since 2010. Previously he was elected a Director and Vice Chairman in 2009; Executive Vice President, Strategy and Development; Corporate Vice President and President, Chevron International Exploration and Production Company; Vice President and Chief Financial Officer; and Corporate Vice President, Strategic Planning. He serves on the Board of Directors and the Executive Committee of the American Petroleum Institute. Joined Chevron in 1980. Alexander B. Cummings Jr., 59 Director since 2014. He is a retired Executive Vice President and Chief Administrative Officer of The Coca-Cola Company, the world’s largest beverage manufacturer. Previously he was President and Chief Operating Officer of Coca-Cola’s Africa Group. He is a Director of Coca-Cola Bottling Co. Consolidated. (1) Linnet F. Deily, 70 Director since 2006. She served as a Deputy U.S. Trade Representative and U.S. Ambassador to the World Trade Organization. Previously she was Vice Chairman of Charles Schwab Corporation. She is a Director of Honeywell International Inc. (2, 3) Robert E. Denham, 70 Director since 2004. He is a Partner in the law firm of Munger, Tolles & Olson LLP. Previously he was Chairman and Chief Executive Officer of Salomon Inc. He is a Director of The New York Times Company; Oaktree Capital Group, LLC; and Fomento Económico Mexicano, S.A. de C.V. (1, 4) Alice P. Gast, 57 Director since 2012. She is President of Imperial College London, a public research university specializing in science, engineering, medicine and business. Previously she was President of Lehigh University in Pennsylvania. Prior to that she was Vice President for Research, Associate Provost and Robert T. Haslam Chair in Chemical Engineering at the Massachusetts Institute of Technology. (1) Enrique Hernandez Jr., 60 Director since 2008. He is Chairman, Chief Executive Officer and President of Inter-Con Security Systems, Inc., a global provider of security services to local, state, federal and foreign governments, utilities, and corporations. He is a Director of McDonald’s Corporation; Nordstrom, Inc.; and Wells Fargo & Company. (2, 4) Jon M. Huntsman Jr., 56 Director since 2014. He served as U.S. Ambassador to China and was Governor of Utah for two consecutive terms. He is Chairman of the Board of the Atlantic Council, a nonprofit that promotes leadership and engagement in international affairs, and Chairman of the Board of the Huntsman Cancer Foundation, a nonprofit that financially supports research, education and patient care initiatives at the Huntsman Cancer Institute at the University of Utah. In 2011 he was a candidate for the Republican nomination for President of the United States. He is a Director of Caterpillar Inc., Ford Motor Company and Hilton Worldwide. (2, 3) Charles W. Moorman IV, 64 Director since 2012. He is a retired Chairman of the Board and Chief Executive Officer of Norfolk Southern Corporation, a freight and transportation company. He served as President at Norfolk Southern from 2004 to 2013. (1) John G. Stumpf, 62 Director since 2010. He is Chairman of the Board, Chief Executive Officer and President of Wells Fargo & Company, a diversified financial services company. He served as President of Wells Fargo from 2005 to 2015. He is a Director of Target Corporation. (3, 4) Ronald D. Sugar, 67 Lead Director since 2015 and a Director since 2005. He is a retired Chairman of the Board and Chief Executive Officer of Northrop Grumman Corporation. He is a Senior Advisor to various businesses and organizations, including Ares Management LLC, a leading private investment firm; Bain & Company, a global consulting firm; Temasek Americas Advisory Panel, a private investment company based in Singapore; and the G100 Network and the World 50, peer- to-peer exchanges for current and former senior executives from some of the world’s largest companies. He is a Director of Amgen Inc., Air Lease Corporation and Apple Inc. (3, 4) Inge G. Thulin, 62 Director since 2015. He is Chairman of the Board, President and Chief Executive Office of 3M Company, a diversified technology company. Previously he was Executive Vice President and Chief Operating Officer of 3M. Prior to that he was the company’s Executive Vice President of International Operations. (3, 4) Retiring Director , 72, a Director since 2001, Carl Ware reached the mandatory retirement age and will not stand for re-election at the Annual Meeting in May. He is a retired Executive Vice President of The Coca-Cola Company. (2, 4) has Committees of the Board  1 ) Audit: Charles W. Moorman IV, Chair 2) Public Policy: Linnet F. Deily, Chair 3) Board Nominating and Governance: Ronald D. Sugar, Chair 4) Management Compensation: Enrique Hernandez Jr., Chair 82 Chevron Corporation 2015 Annual Report CVX_AR2015_v17.4_031716PRO.indd 82 3/17/16 7:48 PM corporate officers Paul V. Bennett, 62 Vice President and Treasurer since 2011. Responsible for banking, financing, cash management, insurance, pension investments, and credit and receivables activities across the corporation. Previously Vice President, Finance, Downstream and Chemicals. Joined the company in 1980. Pierre R. Breber, 51 Executive Vice President, Downstream and Chemicals, since January 2016. Responsible for directing the company’s worldwide manufacturing, marketing, lubricants, chemicals and Oronite additives businesses, and Chevron’s joint-venture Chevron Phillips Chemical Company. Previously Executive Vice President, Gas and Midstream, and Managing Director, Asia South Business Unit. Joined the company in 1989. Mary A. Francis, 51 Corporate Secretary and Chief Governance Officer since 2015. Responsible for providing advice and counsel to the Board of Directors and senior management on corporate governance matters, managing the company’s corporate governance function, and serving on the Law Function Executive Committee. Previously Deputy Corporate Secretary; Chief Corporate Counsel, Corporation Law Department; General Counsel, Chevron Asia Pacific Exploration and Production Company; Managing Counsel, Chevron Pipe Line Company and Chevron Shipping Company; and Lead Senior Counsel, Chevron Shipping Company. Joined the company in 2002. Joseph C. Geagea, 56 Executive Vice President, Technology, Projects and Services, since 2015. Responsible for energy technology; delivery of major capital projects; procurement; information technology; health, environment and safety; upstream production services; and talent selection and development in support of Chevron’s upstream, downstream and midstream businesses. Previously Senior Vice President, Technology, Projects and Services, and Corporate Vice President and President, Chevron Gas and Midstream. Joined the company in 1982. James W. Johnson, 57 Executive Vice President, Upstream, since 2015. Responsible for Chevron’s global exploration and production activities for crude oil and natural gas. Previously Senior Vice President, Upstream; President, Chevron Europe, Eurasia and Middle East Exploration and Production Company; Managing Director, Eurasia Business Unit; and Managing Director, Australasia Business Unit. Joined the company in 1981. Joe W. Laymon, 63 Vice President, Human Resources and Corporate Services, since 2008. Responsible for human resources, medical services, security, aviation, diversity, ombuds, and business and real estate services. Previously Group Vice President, Corporate Human Resources and Labor Affairs, Ford Motor Company. Joined the company in 2008. Wesley E. Lohec, 56 Vice President, Health, Environment and Safety (HES), since 2011. Responsible for HES strategic planning and issues management, compliance assurance, emergency response, and Chevron’s Environmental Management Company. Previously Managing Director, Latin America, Chevron Africa and Latin America Exploration and Production Company. Joined the company in 1981. Charles N. Macfarlane, 61 Vice President since 2013 and General Tax Counsel since 2010. Responsible for directing Chevron’s worldwide tax activities. Previously the company’s Assistant General Tax Counsel. Joined Chevron in 1984 upon the merger with Gulf Oil Corporation. Joseph M. Naylor, 55 Vice President, Policy, Government and Public Affairs, since April 2016. Responsible for U.S. and international government relations, all aspects of communications, and the company’s worldwide efforts to protect and enhance its reputation. Previously Vice President, Strategic Planning. Joined Chevron in 1982. R. Hewitt Pate, 53 Vice President and General Counsel since 2009. Responsible for directing the company’s worldwide legal affairs. Previously Chair, Competition Practice, Hunton & Williams LLP, Washington, D.C., and Assistant Attorney General, Antitrust Division, U.S. Department of Justice. Joined Chevron in 2009. Mark A. Nelson, 52 Vice President, Strategic Planning, since April 2016. Responsible for advising senior corporate executives in setting strategic direction for the company, allocating capital and other resources, and determining operating unit performance measures and targets. Previously President, International Products. Joined Chevron in 1985. Jeanette L. Ourada, 50 Vice President and Comptroller since 2015. Responsible for corporatewide accounting, financial reporting and analysis, internal controls, and Finance Shared Services. Previously General Manager, Finance Shared Services. Joined Chevron in 2005 upon the merger with Unocal Corporation. Jay R. Pryor, 58 Vice President, Business Development, since 2006. Responsible for identifying and developing new, large-scale upstream and downstream business opportunities, including mergers and acquisitions. Previously Managing Director, Chevron Nigeria Ltd., and Managing Director, Asia South Business Unit and Chevron Offshore (Thailand) Ltd. Joined Chevron in 1979. Michael K. Wirth, 55 Executive Vice President, Midstream and Development, since January 2016. Responsible for supply and trading, gas commercialization, and the company’s midstream operating units engaged in transportation and power, as well as corporate strategy and business development. Previously Executive Vice President, Downstream and Chemicals; President, Global Supply and Trading; and President, Marketing, Asia/Middle East/Africa Strategic Business Unit. Joined Chevron in 1982. Patricia E. Yarrington, 60 Vice President and Chief Financial Officer since 2009. Responsible for comptroller, tax, treasury, audit and investor relations activities. Served as Chairman of the San Francisco Federal Reserve’s Board of Directors in 2013 and 2014. Previously Corporate Vice President and Treasurer; Corporate Vice President, Policy, Government and Public Affairs; Corporate Vice President, Strategic Planning; and President, Chevron Canada Limited. Joined Chevron in 1980. Executive Committee John S. Watson, Pierre R. Breber, Joseph C. Geagea, James W. Johnson, R. Hewitt Pate, Michael K. Wirth and Patricia E. Yarrington. Mary A. Francis, Secretary. Chevron Corporation 2015 Annual Report 83 CVX_AR2015_v17.4_031716PRO.indd 83 3/17/16 7:48 PM CYAN MAGENTA YELLOW BLACK PMS 2945 stockholder and investor information Stock exchange listing Chevron common stock is listed on the New York Stock Exchange. The symbol is “CVX.” Stockholder information Questions about stock ownership, changes of address, dividend payments or direct deposit of dividends should be directed to Chevron ’s transfer agent and registrar: Computershare P.O. Box 30170 College Station, TX 77842-3170 800 368 8357 www.computershare.com/investor Overnight correspondence should be sent to: Computershare 211 Quality Circle, Suite 210 College Station, TX 77845-4470 The Computershare Investment Plan features dividend reinvestment, optional cash investments of $50 to $100,000 a year and automatic stock purchase. Investor information Securities analysts, portfolio managers and representatives of financial institutions may contact: Investor Relations Chevron Corporation 6001 Bollinger Canyon Road, A3064 San Ramon, CA 94583-2324 925 842 5690 Email: invest@chevron.com Notice As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we” and “us” may refer to one or more of its consolidated subsidia ries or to all of them taken as a whole. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs. Corporate headquarters 6001 Bollinger Canyon Road San Ramon, CA 94583-2324 925 842 1000 Dividend payment dates Quarterly dividends on common stock are paid, generally, following declaration by the Board of Directors, on or about the 10th day of March, June, September and December. Direct deposit of dividends is available to stockholders. For information, contact Computershare. (See Stockholder information.) Annual meeting The Annual Meeting of stockholders will be held at 8:00 a.m. PDT, Wednesday, May 25, 2016, at: Chevron Park Auditorium 6001 Bollinger Canyon Road San Ramon, CA 94583-2324 Electronic access In an effort to conserve natural resources and reduce the cost of printing and mailing proxy materials, we encourage stock holders to register to receive these documents via email and vote their shares on the Internet. Stock holders of record may sign up on our website, www.icsdelivery.com/ cvx/, for electronic access. Enrollment is revocable until each year’s Annual Meeting record date. Bene ficial stockholders may be able to request electronic access by contacting their broker or bank, or Broadridge Financial Solutions at: www.icsdelivery.com/cvx/. 84 Chevron Corporation 2015 Annual Report p01-08_81-84_r1.indd 84 3/12/16 3:47 PM 2015 annual report 2015 supplement to the annual report 2015 corporate responsibility report highlights 2015 Annual Report 2015 Supplement to the Annual Report 2015 Corporate Responsibility Report Publications and other news sources The Annual Report, distributed in April, summarizes the company’s financial performance in the precedi ng year and provides an overview of the company’s major activities. Chevron’s Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission and the Supplement to the Annual Report, containing additional financial and operating data, are available on the company’s website, Chevron.com, or copies may be requested by writing to: Comptroller’s Department Chevron Corporation 6001 Bollinger Canyon Road, A3140 San Ramon, CA 94583-2324 The 2015 Corporate Responsibility Report is available in May on the company’s website, Chevron.com/CR, or a copy may be requested by writing to: Policy, Government and Public Affairs Corporate Responsibility Communications Chevron Corporation 6001 Bollinger Canyon Road Building G San Ramon, CA 94583-2324 Additional information about the company’s corporate responsibility efforts can be found on Chevron’s website at Chevron.com/CR and Chevron.com/CreatingProsperity. Details of the company’s political contributions for 2015 are available on the company’s website, Chevron.com, or by writing to: Policy, Government and Public Affairs Chevron Corporation 6001 Bollinger Canyon Road Building G San Ramon, CA 94583-2324 For additional information about the company and the energy industry, visit Chevron’s website, Chevron.com. It includes articles, news releases, speeches, quarterly earnings information, the Proxy Statement and the complete text of this Annual Report. This Annual Report contains forward-looking statements — identified by words such as “expects,” “intends,” “projects,” etc. — that reflect management’s current estimates and beliefs, but are not guarantees of future results. Please see “Cautionary Statement Relevant to Forward-Looking Information for the Purpose of ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” on Page 9 for a discussion of some of the factors that could cause actual results to differ materially. PHOTOGRAPHY Cover: Darrell Brown; Page 2: Eric Myer PRODUCED BY Policy, Government and Public Affairs and Comptroller’s Departments, Chevron Corporation DESIGN Design One — San Francisco, California PRINTING ColorGraphics — Los Angeles, California Hold this QR code to your smartphone and learn more about Chevron. If you do not have a QR code reader on your phone, go to your app store and search “QR Reader.” Chevron.com/AnnualReport/2015 On the cover: The Chevron-operated Asia Excellence liquefied natural gas tanker docks at the Gorgon LNG plant on Barrow Island, Western Australia. The vessel delivered commissioning cargo to cool down LNG storage and loading facilities. This was a key piece of the cooling process prior to the start of LNG production. First deliveries of Gorgon LNG will begin in early 2016. This page: One of the largest land-based mobile crawler cranes in the world is used to replace the reactor and regenerator heads in our Richmond Refinery’s fluidized catalytic cracker. The Richmond Refinery produces a special clean blend of gasoline only available in California and fuels approximately 20 percent of the vehicles on Northern California roads. 136105_Chevron_Covers.indd 2 3/17/16 7:50 PM contents 2 letter to stockholders 4 chevron financial highlights 5 chevron operating highlights 6 chevron at a glance 8 glossary of energy and financial terms 9 financial review 68 five-year financial summary 69 five-year operating summary 81 chevron history 82 board of directors 83 corporate officers 84 s tockholder and investor information C H E V R O N C O R P O R A T O N I 2 0 1 5 A N N U A L R E P O R T 2015 annual report Chevron Corporation 6001 Bollinger Canyon Road, San Ramon, CA 94583-2324 USA www.chevron.com © 2016 Chevron Corporation. All Rights Reserved. 10% Recycled 100% Recyclable 912-0975 136105_Chevron_Covers.indd 1 3/4/16 3:19 PM 

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