Chevron Corporation (CVX, NYSE)
Industry: Oil & Gas Integrated
Annual report, fiscal year 2016


## 2016
annual report

human energy \( ^{®} \) 






## positioned for the future

As the average annual crude oil price hit a 10-year low, 2016 presented significant challenges for the oil and gas industry. In response, Chevron took action to improve our free cash flow with tighter spending and with additional revenue from expected production growth. We are committed to becoming cash balanced in 2017, and today we stand well positioned to meet that objective.

Chevron’s portfolio is built upon a strong and diverse set of assets around the globe. In the Upstream sector, our asset classes comprise conventional and unconventional crude oil and natural gas, heavy oil, liquefied natural gas (LNG), and deepwater assets. Our Upstream portfolio includes premier LNG assets in Australia; legacy crude oil assets in Kazakhstan; strong unconventional assets in the United States, Canada and Argentina; and excellent deepwater assets in Nigeria, Angola and the U.S. Gulf of Mexico. In addition, our world-class Downstream and Chemicals business is focused on growing higher-return segments, including petrochemicals, lubricants and additives.

Chevron’s employees take great pride in safely developing and delivering affordable, reliable energy that improves lives and powers the world forward while creating value for our stockholders, our business partners and the communities where we operate.

A digital version of this report is available on our website at chevron.com/annualreport2016.

On the cover: Chevron has a strong shale and tight resource position in the Permian Basin of West Texas and southeastern New Mexico. The Permian Basin is one of the oldest and most important producing areas in the United States.

On this page: Building on a record of strong performance at the Tengiz oil field in Kazakhstan, Chevron's 50 percent-owned affiliate, Tengizchevroil, is proceeding with the development of its Future Growth Project—Wellhead Pressure Management Project.



future growth
project-wellhead pressure
management project

production
2.9 billion
barrels

Tengiz crude oil production since Tengizchevroil (TCO) was founded in 1993

production growth
260,000
barrels

Approximate daily crude oil production increase expected when the Tengiz expansion project is complete and operating at full capacity

goods and services
$20 billion

Invested by TCO in
Kazakhstani goods and
services since 1993

## contents

2 letter to stockholders

4 2016 priorities

5 chevron at a glance

6 chevron stock performance

7 financial and operating highlights

8 2017 strategies

9 financial review

72 five-year financial summary

73 five-year operating summary

85 glossary of energy and financial terms

86 board of directors

87 corporate officers

88 stockholder and investor information




# to our stockholders

Low commodity prices in 2016 reduced earnings across the industry and reinforced the need for structural reform. With Brent averaging $44 per barrel, Chevron reported a loss of $497 million compared with earnings of $4.6 billion in 2015. It was a year of transition, and Chevron took significant actions to reduce costs and improve net cash flow to ensure our competitiveness in any operating environment.

Our 2016 priorities were to finish projects under construction; reduce capital spending; reduce operating expenses; complete asset sales; and operate safely and reliably. We made substantial progress (see graphic, Page 4) on these priorities as we worked toward our goal of becoming cash balanced and able to pay the dividend from free cash flow in 2017.

The actions we took included thousands of initiatives across the enterprise to prioritize investments, negotiate better rates from vendors and suppliers, and improve drilling and other efficiencies. All of these actions enabled us to increase our annual per-share dividend payout for the 29th consecutive year. Our total stockholder returns outpaced our major competitors by a wide margin last year. In fact, we’re No. 1 in total stockholder return relative to our peers for any cumulative holding period going back 25 years. Our year-end debt ratio was 24 percent.

Operationally, we met a number of milestones, including startup at our Gorgon liquefied natural gas (LNG) project. Gorgon is one of the world’s largest LNG projects, and we expect it to be a significant revenue source for decades. We also achieved startup at Alder in the U.K. North Sea. We brought on line all three trains at the Chuandongbei Project in China. We restarted the Angola LNG project. We achieved natural gas production from the Bangka Field Development Project in Indonesia. And finally, we ramped up our Jack/St. Malo deepwater project in the U.S. Gulf of Mexico.

Our Upstream business, responsible for exploration and production, reported worldwide net production of 2.6 million barrels of oil-equivalent per day. Production increases were offset by asset sales, normal field declines and



# 29th consecutive year

2016 marked the 29th consecutive year we increased the annual per-share dividend payout.

maintenance-related downtime. We added approximately 1 billion barrels of oil-equivalent (BBOE) of proved reserves in 2016 before asset sales. These equate to approximately 108 percent of net oil-equivalent production for the year. After asset sales, we replaced approximately 95 percent of production. In our exploration program, we added approximately 1.4 BBOE to our resource base.

Our Downstream and Chemicals business, which is responsible for our refining, marketing and chemical manufacturing, achieved its highest refinery utilization in more than 10 years. We also progressed a number of strategic initiatives. For example, we closed the sale of our Hawaii refining and marketing business. We sanctioned the Salt Lake refinery’s alkylation retrofit project using technology we developed to improve the efficiency and safety of this process – technology that we will license to others. We also progressed work on our $6 billion joint-venture U.S. Gulf Coast Petrochemicals Project, which includes a world-scale ethane cracker and polyethylene units, targeted for initial production in 2017.

Midstream and Development secured additional LNG sales commitments for delivery from Australia, despite the challenging market environment. In addition, we made good progress toward scheduled delivery of the fifth and sixth LNG carriers in 2017, to complete the largest shipbuilding program in our history.

Our 2016 health, environment and safety performance set or matched record lows in many of our core safety metrics. We continue to focus on eliminating high-consequence personal and process safety incidents. We also continued our social investments. In 2016, we invested $186 million in global partnerships and programs, complementing our investments in projects and local goods and services that created jobs and generated revenues for the communities where we operate. More details are available in the 2016 Corporate Responsibility Report.

Going forward, we’re committed to continuing to improve free cash flow and returns by focusing on investments that are economic with lower prices and by controlling our capital program. We announced a 2017 capital and exploratory budget of $19.8 billion – 42 percent less than what we spent in 2015 and approximately 12 percent lower than 2016 capital and exploratory investments.

In 2017, we expect Wheatstone, our next major Australian LNG project, to start up and the Mafumeira Sul project in Angola to achieve first oil. In Kazakhstan, our 50 percent-owned affiliate, Tengizchevroil, will be working on a project expected to increase its total production to approximately 1 million barrels of oil-equivalent per day. First oil is planned for 2022. In the Permian Basin, we will continue to focus on shale and tight resource development, capitalizing on efficiencies we’ve already demonstrated in our drilling program there.

I am optimistic about the future.
Our products are responsible for
the greatest advancements in living
standards in recorded history. Energy
demand remains strong, and we expect
the need for oil and natural gas to
continue to grow over the next 20-plus
years as the developing world reaches
for a better quality of life.

As we work to provide the energy the world needs, we will continue to be guided by The Chevron Way (www.chevron.com/thechevronway), our roadmap for enabling human progress as the global energy company most admired for its people, partnership and performance. In 2016, we refined our business strategies to address the changing operating environment. We are focused on improving returns on all our assets. We maintained our workforce development programs and university hiring to ensure we have the talented workforce we need in order to deliver these strategies.

I am confident Chevron will remain competitive and at the forefront of an industry that provides the reliable and affordable energy necessary for global economic growth. Thank you for your interest and investment in the company.



John S. Watson
Chairman of the Board and
Chief Executive Officer
February 23, 2017



# 2016 priorities

Responding to low commodity prices in 2016, we took significant actions to ensure our competitiveness in any operating environment.



## finish projects under
construction

We completed several capital projects, including Gorgon Trains 1–2, Chuandongbei Trains 1–3, Bangka and Alder, thereby reducing capital spending and bringing in new revenue for the company.



## reduce capital spending

We reduced capital spending by 34 percent, to $22.4 billion – more than $4 billion under budget and $11 billion lower than 2015.



## reduce operating expenses

Through aggressive cost management and simplification of processes, we reduced operating expenses nearly 10 percent, to the lowest level in six years.



## complete
asset sales

Select assets were divested, including
Downstream sites in New Zealand and Hawaii.
In sum, asset sales proceeds totaled
$2.8 billion for the corporation.



## operate safely and reliably

With the fewest spills, injuries and days away from work, we led the industry in these operational categories. Our most important Operational Excellence objective is the prevention of fatalities and high-consequence process safety events. Zero incidents or injuries is the only acceptable outcome.



## 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 delivering industry-leading results and superior stockholder value in any business environment. We do this by operating responsibly, applying advanced technologies, capturing new high-return opportunities, and executing with excellence in a socially and environmentally responsible manner. 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; and develop and deploy technologies that enhance business value in every aspect of the company’s operations. We take great pride in enabling human progress by developing the energy that improves lives and powers the world forward.

net oil-equivalent
daily production \( ^{*} $ 

2.6 million barrels

sales and other
operating revenues \( ^{*} \) 

$110.2 billion
net oil-equivalent
proved reserves \( ^{**} $ 

11.1 billion barrels

total assets \( ^{**} \) 
$260.1 billion

Photo: Chevron's Asia Excellence liquefied natural gas carrier approaches Japan to deliver the first cargo from Gorgon, an LNG project in Western Australia. Gorgon achieved start-up and first delivery in 2016.

 \( ^{*} \) Year ended December 31, 2016.  \( ^{**} \) At December 31, 2016.



## chevron stock performance

## 25 years

Chevron is No. 1 in total stockholder return (TSR) \( ^{*} \)  relative to peers for any annualized holding period from year-end 2016 going back 25 years.





■ Peer group: BP p.l.c. (ADS), ExxonMobil, Royal Dutch Shell p.l.c. (ADS), Total S.A. (ADR)

* Annualized total stockholder return as of 12/31/2016. Includes stock price appreciation and reinvested dividends when paid. For TSR comparison purposes, ADR / ADS prices and dividends are used for non-U.S.-based companies. Dividends include both cash and scrip share distributions.

Dividend growth
Basis 2006 = 100



Performance graph

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 beginning December 30, 2011, and ending December 31, 2016, 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 30, 2011, as of the end of each year between 2012 and 2016.

Dividend yield \( ^{**} \) 



**Represents the annual dividend per share divided by the closing stock price on the last trading day of the year.

Five-year cumulative total returns (Calendar years ended December 31)






## financial and operating highlights

<table><tr><td>Financial highlights \( ^{1} \)</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Net income (loss) attributable to Chevron Corporation</td><td>$ (497)</td><td>$ 4,587</td><td>$ 19,241</td></tr><tr><td>Sales and other operating revenues</td><td>$ 110,215</td><td>$ 129,925</td><td>$ 200,494</td></tr><tr><td>Cash provided by operating activities</td><td>$ 12,846</td><td>$ 19,456</td><td>$ 31,475</td></tr><tr><td>Capital and exploratory expenditures \( ^{2} \)</td><td>$ 22,428</td><td>$ 33,979</td><td>$ 40,316</td></tr><tr><td>Total assets at year-end</td><td>$ 260,078</td><td>$ 264,540*</td><td>$ 264,884*</td></tr><tr><td>Total debt and capital lease obligations at year-end</td><td>$ 46,126</td><td>$ 38,549*</td><td>$ 27,784*</td></tr><tr><td>Chevron Corporation stockholders&#x27; equity at year-end</td><td>$ 145,556</td><td>$ 152,716</td><td>$ 155,028</td></tr><tr><td>Common shares outstanding at year-end (Thousands)</td><td>1,877,338</td><td>1,868,646</td><td>1,865,481</td></tr><tr><td>Per-share data</td><td></td><td></td><td></td></tr><tr><td>Net income (loss) attributable to Chevron Corporation — diluted</td><td>$ (0.27)</td><td>$ 2.45</td><td>$ 10.14</td></tr><tr><td>Cash dividends</td><td>$ 4.29</td><td>$ 4.28</td><td>$ 4.21</td></tr><tr><td>Chevron Corporation stockholders&#x27; equity</td><td>$ 77.53</td><td>$ 81.73</td><td>$ 83.10</td></tr><tr><td>Common stock price at year-end</td><td>$ 117.70</td><td>$ 89.96</td><td>$ 112.18</td></tr><tr><td>Debt ratio</td><td>24.1%</td><td>20.2%</td><td>15.2%</td></tr><tr><td>Return on stockholders&#x27; equity</td><td>(0.3)%</td><td>3.0%</td><td>12.7%</td></tr><tr><td>Return on capital employed (ROCE)</td><td>(0.1)%</td><td>2.5%</td><td>10.9%</td></tr></table>

 \( ^{1} \)  Millions of dollars, except per-share amounts

 \( ^{2} \)  Includes equity in affiliates

* 2015 and 2014 presentation were adjusted to conform to ASU 2015-17 “Income Taxes – Balance Sheet Classification of Deferred Taxes” and ASU 2015-03 “Imputation of Interest – Simplifying the Presentation of Debt Issuance Costs”

Total capital and exploratory expenditures \( ^{3} \) 
(Billion US$)



 \( ^{3} \)  Includes equity in affiliates

Operating expense and SG&A expense \( ^{4,5} \) 
(Billion US$)



 \( ^{4} \)  Excludes affiliate spending
 \( ^{5} \)  Selling, general and administrative expense

<table><tr><td>Operating highlights \( ^{6} \)</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Net production of crude oil, condensate, NGLs and synthetic oil (Thousands of barrels per day)</td><td>1,719</td><td>1,744</td><td>1,709</td></tr><tr><td>Net production of natural gas (Millions of cubic feet per day)</td><td>5,252</td><td>5,269</td><td>5,167</td></tr><tr><td>Total net oil-equivalent production (Thousands of oil-equivalent barrels per day)</td><td>2,594</td><td>2,622</td><td>2,571</td></tr><tr><td>Net proved reserves of crude oil, condensate, NGLs and synthetic oil \( ^{7} \)  (Millions of barrels)</td><td>6,328</td><td>6,262</td><td>6,249</td></tr><tr><td>Net proved reserves of natural gas \( ^{7} \)  (Billions of cubic feet)</td><td>28,760</td><td>29,437</td><td>29,116</td></tr><tr><td>Net proved oil-equivalent reserves \( ^{7} \)  (Millions of barrels)</td><td>11,122</td><td>11,168</td><td>11,102</td></tr><tr><td>Refinery input (Thousands of barrels per day)</td><td>1,688</td><td>1,702</td><td>1,690</td></tr><tr><td>Sales of refined products (Thousands of barrels per day)</td><td>2,675</td><td>2,735</td><td>2,711</td></tr><tr><td>Number of employees at year-end \( ^{8} \)</td><td>51,953</td><td>58,178</td><td>61,456</td></tr></table>

 \( ^{6} \)  Includes equity in affiliates, except number of employees

 \( ^{7} \)  At the end of the year

 \( ^{8} \)  Excludes service station personnel



## 2017 strategies

Our strategies guide our actions to deliver industry-leading results and superior stockholder value in any business environment.

## major business strategies



## Upstream

Deliver industry-leading returns while developing high-value resource opportunities



## Downstream and Chemicals

Grow earnings across the value chain and make targeted investments to lead the industry in returns



## Midstream

Deliver operational, commercial and technical expertise to enhance results in Upstream and Downstream and Chemicals

## enterprise strategies



## People

Invest in people to develop and empower a highly competent workforce that delivers results the right way



## Execution

Deliver results through disciplined operational excellence, capital stewardship and cost efficiency



## Growth

Grow profits and returns by using our competitive advantages



Technology and functional excellence
Differentiate performance through
technology and functional expertise

Photo: Wheatstone, one of Australia’s largest resource projects, is expected to contribute more than 10 percent of Australia’s total future liquefied natural gas production and generate substantial earnings for decades to come.






## 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 14
Results of Operations 14
Consolidated Statement of Income 17
Selected Operating Data 20
Liquidity and Capital Resources 21
Financial Ratios 23
Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies 23
Financial and Derivative Instrument Market Risk 24
Transactions With Related Parties 25
Litigation and Other Contingencies 25
Environmental Matters 26
Critical Accounting Estimates and Assumptions 26
New Accounting Standards 29
Quarterly Results and Stock Market Data 30

## 31

## Consolidated Financial Statements

Reports of Management 31
Report of Independent Registered Public Accounting Firm 32
Consolidated Statement of Income 33
Consolidated Statement of Comprehensive Income 34
Consolidated Balance Sheet 35
Consolidated Statement of Cash Flows 36
Consolidated Statement of Equity 37

## 38

## Notes to the Consolidated Financial Statements

Note 1 Summary of Significant Accounting Policies 38
Note 2 Changes in Accumulated Other Comprehensive Losses 40
Note 3 Noncontrolling Interests 41
Note 4 Information Relating to the Consolidated Statement of Cash Flows 41
Note 5 New Accounting Standards 42
Note 6 Lease Commitments 43
Note 7 Summarized Financial Data – Chevron U.S.A. Inc. 44
Note 8 Summarized Financial Data – Tengizchevroil LLP 44
Note 9 Summarized Financial Data – Chevron Phillips Chemical Company LLC 44
Note 10 Fair Value Measurements 45
Note 11 Financial and Derivative Instruments 46
Note 12 Assets Held for Sale 47
Note 13 Equity 47
Note 14 Earnings Per Share 47
Note 15 Operating Segments and Geographic Data 48
Note 16 Investments and Advances 51
Note 17 Properties, Plant and Equipment 52
Note 18 Litigation 53
Note 19 Taxes 57
Note 20 Short-Term Debt 60
Note 21 Long-Term Debt 61
Note 22 Accounting for Suspended Exploratory Wells 62
Note 23 Stock Options and Other Share-Based Compensation 63
Note 24 Employee Benefit Plans 64
Note 25 Other Contingencies and Commitments 69
Note 26 Asset Retirement Obligations 70
Note 27 Restructuring and Reorganization Costs 71
Note 28 Other Financial Information 71

Five-Year Financial Summary 72
Five-Year Operating Summary 73
Supplemental Information on Oil and Gas Producing Activities 74

## 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,” “positions,” “pursues,” “may,” “could,” “should,” “budgets,” “outlook,” “focus,” “on schedule,” “on track,” “goals,” “objectives,” “strategies” 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 or the delay or failure of such transactions to close based on required closing conditions set forth in the applicable transaction agreements; the potential for 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 20 through 22 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.



## Key Financial Results

<table><tr><td>Millions of dollars, except per-share amounts</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation</td><td>$ (497)</td><td>$ 4,587</td><td>$ 19,241</td></tr><tr><td>Per Share Amounts:</td><td></td><td></td><td></td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation</td><td></td><td></td><td></td></tr><tr><td>- Basic</td><td>$ (0.27)</td><td>$ 2.46</td><td>$ 10.21</td></tr><tr><td>- Diluted</td><td>$ (0.27)</td><td>$ 2.45</td><td>$ 10.14</td></tr><tr><td>Dividends</td><td>$ 4.29</td><td>$ 4.28</td><td>$ 4.21</td></tr><tr><td>Sales and Other Operating Revenues</td><td>$ 110,215</td><td>$ 129,925</td><td>$ 200,494</td></tr><tr><td>Return on:</td><td></td><td></td><td></td></tr><tr><td>Capital Employed</td><td>(0.1)%</td><td>2.5%</td><td>10.9%</td></tr><tr><td>Stockholders’ Equity</td><td>(0.3)%</td><td>3.0%</td><td>12.7%</td></tr></table>

## Earnings by Major Operating Area

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Upstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ (2,054)</td><td>$ (4,055)</td><td>$ 3,327</td></tr><tr><td>International</td><td>(483)</td><td>2,094</td><td>13,566</td></tr><tr><td>Total Upstream</td><td>(2,537)</td><td>(1,961)</td><td>16,893</td></tr><tr><td>Downstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>1,307</td><td>3,182</td><td>2,637</td></tr><tr><td>International</td><td>2,128</td><td>4,419</td><td>1,699</td></tr><tr><td>Total Downstream</td><td>3,435</td><td>7,601</td><td>4,336</td></tr><tr><td>All Other</td><td>(1,395)</td><td>(1,053)</td><td>(1,988)</td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation \( ^{1,2} \)</td><td>$ (497)</td><td>$ 4,587</td><td>$ 19,241</td></tr><tr><td>1 Includes foreign currency effects:</td><td></td><td></td><td></td></tr><tr><td>2 Income net of tax, also referred to as “earnings” in the discussions that follow.</td><td>$ 58</td><td>$ 769</td><td>$ 487</td></tr></table>

 \( ^{1} \)  Income net of tax, also referred to as “earnings” in the discussions that follow.

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, 2016.

## 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, pacing and re-focusing of capital and exploratory expenditures, 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. It is the company's objective to deliver competitive results and shareholder value in any business environment.

The effective tax rate for the company can change substantially during periods of significant earnings volatility. This is due to the mix effects that are impacted both by the absolute level of earnings or losses and whether they arise in higher or lower tax rate jurisdictions. As a result, a decline or increase in the effective income tax rate in one period may not be indicative of expected results in future periods. Note 19 provides the company’s effective income tax rate for the last three years.

Refer to the “Cautionary Statement Relevant to Forward-Looking Information” on page 9 and to “Risk Factors” in Part I, Item 1A, on pages 20 through 22 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



value growth. Refer to the “Results of Operations” section beginning on page 14 for discussions of net gains on asset sales during 2016. 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.

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. As a result of the decline in prices of crude oil and other commodities since mid-2014, these costs have declined. 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.



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 $44 per barrel for the full-year 2016, compared to $52 in 2015. As of mid-February 2017, the Brent price was $55 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. Crude oil prices remained low through much of 2016, but increased modestly late in the year after OPEC announced production cuts. On November 30, 2016, OPEC agreed to cap production at 32.5 million barrels per day starting in January 2017.

The WTI price averaged $43 per barrel for the full-year 2016, compared to $49 in 2015. As of mid-February 2017, the WTI price was $53 per barrel. WTI traded at a discount to Brent for much of 2016 due to high inventories and excess crude supply in the U.S. market.



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 2016, the differential held generally steady in North America as robust refinery demand supported heavy crude values, while light sweet crude prices in the U.S. were supported by slowing domestic production. Outside of North America, differentials were steady to slightly wider amid well-supplied light sweet crude markets in the Atlantic Basin, while continued robust Middle East exports and rising Iranian production kept pressure on heavier, more sour crudes. Differentials widened in December as light sweet crude values benefited more from the announced OPEC deal.

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 20 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 $2.46 per thousand cubic feet (MCF) during 2016, compared with $2.62 during 2015. As of mid-February 2017, the Henry Hub spot price was $2.86 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 continues to invest 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. Most of the equity LNG offtake from the operated Australian LNG projects is committed under 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 $4.02 per MCF during 2016, compared with $4.53 per MCF during 2015. (See page 20 for the company’s average natural gas realizations for the U.S. and international regions.)

The company’s worldwide net oil-equivalent production in 2016 averaged 2.594 million barrels per day. About one-sixth of the company’s net oil-equivalent production in 2016 occurred in the OPEC-member countries of Angola, Nigeria and Venezuela. OPEC quotas had no effect on the company’s net crude oil production in 2016 or 2015.

The company estimates that net oil-equivalent production in 2017 will grow 4 to 9 percent compared to 2016, assuming a Brent crude oil price of $50 per barrel and before the effect of anticipated asset sales. The impact of 2017 asset sales on full-year production is expected to be in the range of 50,000 to 100,000 barrels of oil-equivalent per day, depending on the timing of the close of individual transactions. 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 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.




 \( ^{*} \) Includes equity in affiliates.



 \( ^{*} \) Includes equity in affiliates.





■ Affiliates
■ Europe
■ Australia/Oceania
■ Asia
■ Africa
■ Other Americas
■ 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 2017, 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 2016 were not significant and are not expected to be significant in 2017.

Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil-equivalent at year-end 2016, down slightly from year-end 2015. The reserve replacement ratio in 2016 was 95 percent. Refer to Table V beginning on page 78 for a tabulation of the company's proved net oil and gas reserves by geographic area, at the beginning of 2014 and each year-end from 2014 through 2016, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2016.

Refer to the “Results of Operations” section on pages 14 through 17 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 17 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 2016 and early 2017 included the following:

## Upstream

Angola Restarted LNG production and cargo shipments at the Angola LNG plant.

Australia Achieved start-up of Trains 1 and 2 at the Gorgon Project and progressed commissioning of Train 3.

Progressed commissioning and testing of subsea and platform facilities and production wells at the Wheatstone Project. Progressed commissioning of LNG Train 1 and common facilities, and received and installed all Train 2 modules at the site.

Indonesia Commenced production at the Bangka Field, the first stage of the Indonesia Deepwater Development.

Reached agreement to sell the company’s geothermal assets.

Kazakhstan Announced final investment decision on the Future Growth and Wellhead Pressure Management Project at the company’s 50 percent-owned affiliate, Tengizchevroil, which is expected to increase crude oil production at the Tengiz Field by about 260,000 barrels per day and maintain production levels as reservoir pressure declines.

Philippines Reached agreement to sell the company’s geothermal assets.

United Kingdom Announced first gas from the Alder Field in the Central North Sea.

## Downstream

Completed the sales of the company’s marketing and lubricants assets in New Zealand, and its refining and marketing assets in Hawaii.

## Other

Common Stock Dividends The quarterly common stock dividend was increased by $0.01 per share in October 2016, making 2016 the 29th 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 15, beginning on page 48, 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 14.










## U.S. Upstream

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Earnings</td><td>(2,054)</td><td>(4,055)</td><td>3,327</td></tr></table>

U.S. upstream operations incurred a loss of $2.05 billion in 2016 compared to a loss of $4.06 billion in 2015. The improvement was due to lower depreciation expense of $1.2 billion and lower exploration expense of $780 million primarily reflecting a decrease in impairments and project cancellations. Also contributing to the improvement were lower operating expenses of $600 million and lower tax items of $190 million. Partially offsetting these effects were lower crude oil and natural gas realizations of $920 million.

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 2015 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.

The company’s average realization for U.S. crude oil and natural gas liquids in 2016 was $35.00 per barrel, compared with $42.70 in 2015 and $84.13 in 2014. The average natural gas realization was $1.59 per thousand cubic feet in 2016, compared with $1.92 in 2015 and $3.90 in 2014.

Net oil-equivalent production in 2016 averaged 691,000 barrels per day, down 4 percent from 2015 and up 4 percent from 2014. Between 2016 and 2015, production increases from shale and tight properties in the Permian Basin in Texas and New Mexico, and base business were more than offset by the effect of asset sales and normal field declines. 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.

The net liquids component of oil-equivalent production for 2016 averaged 504,000 barrels per day, up 1 percent from 2015 and 11 percent from 2014. Net natural gas production averaged about 1.1 billion cubic feet per day in 2016, down 15 percent from 2015 and 10 percent from 2014, primarily as a result of asset sales. Refer to the “Selected Operating Data” table on page 20 for a three-year comparison of production volumes in the United States.



## International Upstream

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Earnings \( ^{*} \)</td><td>(483)</td><td>2,094</td><td>13,566</td></tr><tr><td>*Includes foreign currency effects:</td><td>122</td><td>725</td><td>597</td></tr></table>

International upstream incurred a loss of $483 million in 2016 compared with earnings of $2.09 billion in 2015. The decrease in earnings was primarily due to lower crude oil realizations of $1.89 billion, lower natural gas realizations of $600 million, lower gains on asset sales of $450 million and higher tax items of $330 million. Partially offsetting the decrease were lower exploration and operating expenses of $640 million and $520 million, respectively, and higher natural gas sales volumes of $330 million. Foreign currency effects increased earnings by $122 million in 2016 compared with an increase of $725 million a year earlier.

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 gains of $370 million in 2015 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.

The company’s average realization for international crude oil and natural gas liquids in 2016 was $38.61 per barrel, compared with $46.52 in 2015 and $90.42 in 2014. The average natural gas realization was $4.02 per thousand cubic feet in 2016, compared with $4.53 and $5.78 in 2015 and 2014, respectively.

International net oil-equivalent production was 1.90 million barrels per day in 2016, essentially unchanged from 2015 and 2014. Between 2016 and 2015, production increases from major capital projects, base business, and shale and tight properties were largely offset by normal field declines, the Partitioned Zone shut-in, the impact of civil unrest in Nigeria and planned turnaround activity. 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.

The net liquids component of international oil-equivalent production was 1.22 million barrels per day in 2016, down 2 percent from 2015 and 3 percent from 2014. International net natural gas production of 4.1 billion cubic feet per day in 2016 was up 4 percent from 2015 and 5 percent from 2014.

Refer to the “Selected Operating Data” table, on page 20, for a three-year comparison of international production volumes.

## U.S. Downstream

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Earnings</td><td>1,307</td><td>3,182</td><td>2,637</td></tr></table>

U.S. downstream operations earned $1.31 billion in 2016, compared with $3.18 billion in 2015. The decrease was due to lower margins on refined product sales of $1.45 billion, lower earnings from the 50 percent-owned Chevron Phillips Chemicals Company LLC of $400 million and asset impairments of $110 million. Partially offsetting this decrease were lower operating expenses of $80 million and higher gains on asset sales of $110 million.

U.S. downstream operations earned $3.18 billion in 2015, compared with $2.64 billion in 2014. The increase in earnings 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.

Refined product sales of 1.21 million barrels per day in 2016 were down 1 percent, primarily due to lower gas oil sales. Sales volumes of refined products were 1.23 million barrels per day in 2015, an increase of 1 percent from 2014, mainly reflecting higher sales of jet fuel. U.S. branded gasoline sales of 532,000 barrels per day in 2016 increased 2 percent from 2015 and 3 percent from 2014.

Refer to the “Selected Operating Data” table on page 20 for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.



## International Downstream

<table><tr><td>Millions of dollars</td><td></td><td>2016</td><td></td><td>2015</td><td></td><td>2014</td></tr><tr><td>Earnings \( ^{*} \)</td><td></td><td>2,128</td><td></td><td>4,419</td><td></td><td>1,699</td></tr><tr><td>*Includes foreign currency effects:</td><td></td><td>(25)</td><td></td><td>47</td><td></td><td>(112)</td></tr></table>

International downstream earned $2.13 billion in 2016, compared with $4.42 billion in 2015. The decrease in earnings was primarily due to the absence of a $1.6 billion gain from the sale of the company’s interest in Caltex Australia Limited in 2015, partially offset by 2016 asset sales gains of $420 million. Lower margins on refined product sales of $1.14 billion also contributed to the decline. Partially offsetting these decreases were lower operating expenses of $240 million. Foreign currency effects decreased earnings by $25 million in 2016, compared to an increase of $47 million a year earlier.

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 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.

Total refined product sales of 1.46 million barrels per day in 2016 were down 3 percent from 2015. Excluding the effects of the Caltex Australia Limited divestment, refined product sales were down 1 percent, primarily reflecting lower fuel oil sales. Sales of 1.51 million barrels per day in 2015 were essentially unchanged from 2014.

Refer to the “Selected Operating Data” table, on page 20, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

## All Other

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Net charges \( ^{*} \)</td><td>$ (1,395)</td><td>$ (1,053)</td><td>$ (1,988)</td></tr><tr><td>*Includes foreign currency effects:</td><td>$ (39)</td><td>$ (3)</td><td>$ 2</td></tr></table>

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 2016 increased $342 million from 2015, mainly due to higher corporate charges, interest expense and corporate tax items, partially offset by lower environmental reserve additions and lower charges related to reductions in corporate staffs. 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.

## Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Sales and other operating revenues</td><td>$ 110,215</td><td>$ 129,925</td><td>$ 200,494</td></tr></table>

Sales and other operating revenues decreased in 2016 primarily due to lower refined product and crude oil prices, partially offset by higher crude oil volumes. The decrease between 2015 and 2014 was primarily due to lower refined product and crude oil prices, partially offset by higher refined product and crude oil volumes.

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Income from equity affiliates</td><td>$ 2,661</td><td>$ 4,684</td><td>$ 7,098</td></tr></table>

Income from equity affiliates decreased in 2016 from 2015 primarily due to lower upstream-related earnings from Tengizchevroil in Kazakhstan and Petrocosan in Venezuela, and lower downstream-related earnings from CPChem and GS Caltex in South Korea.

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 Petropar in Venezuela.

Refer to Note 16, beginning on page 51, for a discussion of Chevron’s investments in affiliated companies.



<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Other income</td><td>$ 1,596</td><td>$ 3,868</td><td>$ 4,378</td></tr></table>

Other income of $1.6 billion in 2016 included net gains from asset sales of $1.1 billion before-tax. Other income in 2015 and 2014 included net gains from asset sales of $3.2 billion and $3.6 billion before-tax, respectively. Interest income was approximately $145 million in 2016, $119 million in 2015 and $145 million in 2014. Foreign currency effects decreased other income by $186 million in 2016, and increased other income $82 million in 2015 and $277 million in 2014.

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Purchased crude oil and products</td><td>$ 59,321</td><td>$ 69,751</td><td>$ 119,671</td></tr></table>

Crude oil and product purchases in 2016 and 2015 decreased from prior year periods by $10.4 billion and $49.9 billion, respectively, primarily due to lower crude oil and refined product prices, partially offset by an increase in crude oil volumes.

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Operating, selling, general and administrative expenses</td><td>$ 24,952</td><td>$ 27,477</td><td>$ 29,779</td></tr></table>

Operating, selling, general and administrative expenses decreased $2.5 billion between 2016 and 2015. The decrease included lower employee expenses of $800 million, transportation expenses of $680 million, contract labor expenses of $370 million, materials and supplies expenses of $310 million, and fuel expenses of $310 million.

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.

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Exploration expense</td><td>$ 1,033</td><td>$ 3,340</td><td>$ 1,985</td></tr></table>

Exploration expenses in 2016 decreased from 2015 primarily due to significantly higher 2015 charges for well write-offs largely related to project cancellations, and lower 2016 geological and geophysical expenses.

Exploration expenses in 2015 increased from 2014 primarily due to higher charges for well write-offs largely related to project cancellations.

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Depreciation, depletion and amortization</td><td>$ 19,457</td><td>$ 21,037</td><td>$ 16,793</td></tr></table>

Depreciation, depletion and amortization expenses decreased in 2016 from 2015 primarily due to lower impairments of certain oil and gas producing fields of about $3.0 billion in 2016 compared with about $3.5 billion in 2015. Also contributing to the decrease were lower production levels and accretion expenses for certain oil and gas producing fields.

The increase in 2015 from 2014 was primarily 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.

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Taxes other than on income</td><td>$ 11,668</td><td>$ 12,030</td><td>$ 12,540</td></tr></table>

Taxes other than on income decreased in 2016 from 2015 primarily due to lower refined product and crude oil prices, and the divestment of the Pakistan fuels business at the end of June 2015. Taxes other than on income decreased in 2015 from 2014 primarily due to lower crude oil and refined product prices.

<table><tr><td>Millions of dollars</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Income tax expense (benefit)</td><td>$ (1,729)</td><td>$ 132</td><td>$ 11,892</td></tr></table>

The decline in income tax expense in 2016 of $1.86 billion is consistent with the decline in total income before-tax for the company of $7.00 billion. U.S. losses before tax increased from a loss of $2.88 billion in 2015 to a loss of $4.32 billion in 2016. This $1.44 billion increase in losses was primarily driven by the effect of lower crude oil prices. The increase in losses had a direct impact on the company’s U.S. income tax benefit, resulting in an increase of $624 million between year-over-year periods, from a tax benefit of $1.69 billion in 2015 to a tax benefit of $2.32 billion in 2016. International income before tax was reduced between calendar years from $7.72 billion in 2015 to $2.16 billion in 2016. This $5.56 billion decline was



also primarily driven by the effect of lower crude oil prices. This effect drove the $1.24 billion reduction in international income tax expense between year-over-year periods, from $1.83 billion in 2015 to $588 million in 2016. Refer also to the discussion of the effective income tax rate in Note 19 on Page 57.

The decline in income tax expense in 2015 of $11.76 billion is consistent with the decline in total income before tax for the company of $26.36 billion. U.S. income before tax was reduced from $6.29 billion in 2014 to a loss of $2.88 billion in 2015. This $9.17 billion reduction was primarily driven by the effect of lower crude oil prices. The lower earnings had a direct impact on the company’s U.S. income tax expense, resulting in a reduction of $4.14 billion between year-over-year periods, from a tax expense of $2.45 billion in 2014 to a tax benefit of $1.69 billion in 2015. International income before tax was reduced between calendar years from $24.91 billion in 2014 to $7.72 billion in 2015. This $17.19 billion decline was also primarily driven by the effect of lower crude oil prices and the shut in of production in the Partitioned Zone. These effects drove the $7.62 billion reduction in international income tax expense between year-over-year periods, from $9.44 billion in 2014 to $1.82 billion in 2015. In addition, there was an income tax benefit from the decrease in statutory tax rates in the United Kingdom in 2015. Refer also to the discussion of the effective income tax rate in Note 19 on Page 57.



## Selected Operating Data \( ^{1,2} \) 

<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>U.S. Upstream</td><td></td><td></td><td></td></tr><tr><td>Net Crude Oil and Natural Gas Liquids Production (MBPD)</td><td>504</td><td>501</td><td>456</td></tr><tr><td>Net Natural Gas Production (MMCFPD) \( ^{3} \)</td><td>1,120</td><td>1,310</td><td>1,250</td></tr><tr><td>Net Oil-Equivalent Production (MBOEPD)</td><td>691</td><td>720</td><td>664</td></tr><tr><td>Sales of Natural Gas (MMCFPD)</td><td>3,317</td><td>3,913</td><td>3,995</td></tr><tr><td>Sales of Natural Gas Liquids (MBPD)</td><td>30</td><td>26</td><td>20</td></tr><tr><td>Revenues from Net Production</td><td></td><td></td><td></td></tr><tr><td>Liquids (S/Bbl)</td><td>35.00</td><td>42.70</td><td>84.13</td></tr><tr><td>Natural Gas (S/MCF)</td><td>1.59</td><td>1.92</td><td>3.90</td></tr><tr><td>International Upstream</td><td></td><td></td><td></td></tr><tr><td>Net Crude Oil and Natural Gas Liquids Production (MBPD) \( ^{4} \)</td><td>1,215</td><td>1,243</td><td>1,253</td></tr><tr><td>Net Natural Gas Production (MMCFPD) \( ^{3} \)</td><td>4,132</td><td>3,959</td><td>3,917</td></tr><tr><td>Net Oil-Equivalent Production (MBOEPD) \( ^{4} \)</td><td>1,903</td><td>1,902</td><td>1,907</td></tr><tr><td>Sales of Natural Gas (MMCFPD)</td><td>4,491</td><td>4,299</td><td>4,304</td></tr><tr><td>Sales of Natural Gas Liquids (MBPD)</td><td>24</td><td>24</td><td>28</td></tr><tr><td>Revenues from Liftings</td><td></td><td></td><td></td></tr><tr><td>Liquids (S/Bbl)</td><td>38.61</td><td>46.52</td><td>90.42</td></tr><tr><td>Natural Gas (S/MCF)</td><td>4.02</td><td>4.53</td><td>5.78</td></tr><tr><td>Worldwide Upstream</td><td></td><td></td><td></td></tr><tr><td>Net Oil-Equivalent Production (MBOEPD) \( ^{4} \)</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>691</td><td>720</td><td>664</td></tr><tr><td>International</td><td>1,903</td><td>1,902</td><td>1,907</td></tr><tr><td>Total</td><td>2,594</td><td>2,622</td><td>2,571</td></tr><tr><td>U.S. Downstream</td><td></td><td></td><td></td></tr><tr><td>Gasoline Sales (MBPD) \( ^{5} \)</td><td>631</td><td>621</td><td>615</td></tr><tr><td>Other Refined Product Sales (MBPD)</td><td>582</td><td>607</td><td>595</td></tr><tr><td>Total Refined Product Sales (MBPD)</td><td>1,213</td><td>1,228</td><td>1,210</td></tr><tr><td>Sales of Natural Gas Liquids (MBPD)</td><td>115</td><td>127</td><td>121</td></tr><tr><td>Refinery Input (MBPD) \( ^{6} \)</td><td>900</td><td>924</td><td>871</td></tr><tr><td>International Downstream</td><td></td><td></td><td></td></tr><tr><td>Gasoline Sales (MBPD) \( ^{5} \)</td><td>382</td><td>389</td><td>403</td></tr><tr><td>Other Refined Product Sales (MBPD)</td><td>1,080</td><td>1,118</td><td>1,098</td></tr><tr><td>Total Refined Product Sales (MBPD) \( ^{7} \)</td><td>1,462</td><td>1,507</td><td>1,501</td></tr><tr><td>Sales of Natural Gas Liquids (MBPD)</td><td>61</td><td>65</td><td>58</td></tr><tr><td>Refinery Input (MBPD) \( ^{8} \)</td><td>788</td><td>778</td><td>819</td></tr></table>

 \( ^{1} \)  Includes company share of equity affiliates.

 \( ^{2} \)  MBPD – thousands of barrels per day; MCMFPD – 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 crude oil.

 \( ^{3} \)  Includes natural gas consumed in operations (MMCFPD):

United States

International

 \( ^{4} \)  Includes net production of synthetic oil:

Canada

Venezuela affiliate

 \( ^{5} \)  Includes branded and unbranded gasoline.

 \( ^{6} \)  In November 2016, the company sold its interests in the Hawaii Refinery which included operable capacity of 54,000 barrels per day.

 \( ^{7} \)  Includes sales of affiliates (MBPD):

 \( ^{8} \)  In 2015, the company sold its interests in affiliates in Australia and New Zealand, which included operable refinery capacities of 55,000 and 12,000 barrels per day, respectively.



## Liquidity and Capital Resources

## Sources and uses of cash



The lower crude oil price environment that began in second-half 2014 and continued through 2016 significantly reduced the company’s cash flows from operations. The company responded with reductions in capital and exploratory expenditures, reductions in its cost structure, and increased asset sales. Progress on these actions during 2016 included:

• Reducing capital expenditures to $18.1 billion, a 39 percent decrease compared to 2015,

• Reducing operating and administrative expenses by $2.5 billion, a 9 percent decrease compared to 2015, and

• Realizing net proceeds from asset sales of $2.8 billion during 2016, with additional transactions expected to close in 2017.

The strength of the company’s balance sheet enabled it to meet the remaining cash outflows through additional borrowing.

Cash, Cash Equivalents and Marketable Securities Total balances were $7.0 billion and $11.3 billion at December 31, 2016 and 2015, respectively. Cash provided by operating activities in 2016 was $12.8 billion, compared with $19.5 billion in 2015 and $31.5 billion in 2014, reflecting lower crude oil prices. Cash provided by operating activities was net of contributions to employee pension plans of approximately $0.9 billion in 2016 and 2015 and $0.4 billion in 2014. Cash provided by investing activities included proceeds and deposits related to asset sales of $2.8 billion in 2016, $5.7 billion in 2015, and $5.7 billion in 2014.

Restricted cash of $1.4 billion and $1.1 billion at December 31, 2016 and 2015, 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, funds held in escrow for tax-deferred exchanges and refundable deposits related to pending asset sales.

Dividends Dividends paid to common stockholders were $8.0 billion in 2016, $8.0 billion in 2015 and $7.9 billion in 2014. In October 2016, the company increased its quarterly dividend by $0.01 per common share.

Debt and Capital Lease Obligations Total debt and capital lease obligations were $46.1 billion at December 31, 2016, up from $38.5 billion at year-end 2015.

The $7.6 billion increase in total debt and capital lease obligations during 2016 was primarily due to funding the company’s capital investment program, which included several large projects in the construction phase. The company completed a bond issuance of $6.8 billion in May 2016. 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 $19.8 billion at December 31, 2016, compared with $12.9 billion at year-end 2015. Of these amounts, $9.0 billion and $8.0 billion were reclassified to long-term debt at the end of 2016 and 2015, respectively. At year-end 2016, settlement of these obligations was not expected to require the use of working capital in 2017, 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 that expires in August 2018 for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company.







 \( ^{*} \) Includes equity in affiliates.



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 and are rated AA-by Standard and Poor’s Corporation and Aa2 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 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 20, Short-Term Debt, on page 60.

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 2016 or 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 2016, 2015 and 2014 are as follows:

<table><tr><td rowspan="2">Millions of dollars</td><td colspan="6">2016</td><td colspan="3">2015</td><td colspan="2">2014</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>Total</td><td>U.S.</td><td>Int&#x27;l.</td><td>Total</td><td>U. S.</td><td>Int&#x27;l.</td><td>Total</td><td></td><td></td></tr><tr><td>Upstream</td><td>$ 4,713</td><td>$ 15,403</td><td>$20,116</td><td>$ 7,582</td><td>$ 23,535</td><td>$31,117</td><td>$ 8,799</td><td>$ 28,316</td><td>$37,115</td><td></td><td></td></tr><tr><td>Downstream</td><td>1,545</td><td>527</td><td>2,072</td><td>1,923</td><td>513</td><td>2,436</td><td>1,649</td><td>941</td><td>2,590</td><td></td><td></td></tr><tr><td>All Other</td><td>235</td><td>5</td><td>240</td><td>418</td><td>8</td><td>426</td><td>584</td><td>27</td><td>611</td><td></td><td></td></tr><tr><td>Total</td><td>$ 6,493</td><td>$ 15,935</td><td>$22,428</td><td>$ 9,923</td><td>$ 24,056</td><td>$33,979</td><td>$ 11,032</td><td>$ 29,284</td><td>$40,316</td><td></td><td></td></tr><tr><td>Total, Excluding Equity in Affiliates</td><td>$ 5,456</td><td>$ 13,202</td><td>$18,658</td><td>$ 8,579</td><td>$ 22,003</td><td>$30,582</td><td>$ 10,011</td><td>$ 26,838</td><td>$36,849</td><td></td><td></td></tr></table>

Total expenditures for 2016 were $22.4 billion, including $3.8 billion for the company’s share of equity-affiliate expenditures, which did not require cash outlays by the company. In 2015 and 2014, expenditures were $34.0 billion and $40.3 billion, respectively, including the company’s share of affiliates’ expenditures of $3.4 billion and $3.5 billion, respectively.



Of the $22.4 billion of expenditures in 2016, 90 percent, or $20.1 billion, related to upstream activities. Approximately 92 percent was expended for upstream operations in both 2015 and 2014. International upstream accounted for 77 percent of the worldwide upstream investment in 2016 and 76 percent in 2015 and 2014.

The company estimates that 2017 capital and exploratory expenditures will be $19.8 billion, including $4.7 billion of spending by affiliates. This planned reduction, compared to 2016 expenditures, reflects current crude oil market conditions, major capital projects nearing completion and the targeting of shorter-cycle projects. Approximately 87 percent of the total, or $17.3 billion, is budgeted for exploration and production activities. Approximately $8.5 billion of planned upstream capital spending relates to base producing assets, including about $2.5 billion for shale and tight resource investments, the majority of which is slated for Permian Basin developments in Texas and New Mexico. Another $7 billion is related to major capital projects already underway, including approximately $2 billion for completion of the Gorgon and Wheatstone LNG projects in Australia and $3 billion of affiliate expenditures associated with the Future Growth and Wellhead Pressure Management Project at the Tengiz Field in Kazakhstan. Global exploration funding accounts for approximately $1 billion, and the remainder is primarily related to early stage projects supporting potential future development opportunities. The company will continue to monitor crude oil market conditions, and will further restrict capital outlays should oil price conditions deteriorate.

Worldwide downstream spending in 2017 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 2017 are budgeted at $0.3 billion.

Noncontrolling Interests The company had noncontrolling interests of $1.2 billion at December 31, 2016 and December 31, 2015. Distributions to noncontrolling interests totaled $63 million and $128 million in 2016 and 2015, respectively.

Pension Obligations Information related to pension plan contributions is included on page 64 in Note 24, Employee Benefit Plans, under the heading “Cash Contributions and Benefit Payments.”

## Financial Ratios

<table><tr><td rowspan="2"></td><td colspan="3">At December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Current Ratio</td><td>0.9</td><td>1.3</td><td>1.3</td></tr><tr><td>Interest Coverage Ratio</td><td>(2.6)</td><td>9.9</td><td>87.2</td></tr><tr><td>Debt Ratio</td><td>24.1 %</td><td>20.2 %</td><td>15.2 %</td></tr></table>

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 2016, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $2.9 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 2016 was lower than 2015 and 2014 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 2016 was higher than 2015 and 2014 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: 2017 – $1.5 billion; 2018 – $1.6 billion; 2019 – $1.4 billion; 2020 – $1.1 billion; 2021 – $0.9 billion; 2022 and after – $2.6 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $1.3 billion in 2016, $1.9 billion in 2015 and $3.7 billion in 2014.



The following table summarizes the company’s significant contractual obligations:

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">Total \( ^{1} \)</td><td rowspan="2">2017</td><td rowspan="2">2018-2019</td><td colspan="3">Payments Due by Period</td></tr><tr><td>2020-2021</td><td>After 2021</td><td></td></tr><tr><td>On Balance Sheet: \( ^{2} \)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Short-Term Debt \( ^{3} \)</td><td>$ 10,840</td><td>$ 10,840</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Long-Term Debt \( ^{3} \)</td><td>35,234</td><td>—</td><td>19,722</td><td>6,108</td><td>9,404</td><td></td></tr><tr><td>Noncancelable Capital Lease Obligations</td><td>232</td><td>22</td><td>41</td><td>24</td><td>145</td><td></td></tr><tr><td>Interest</td><td>4,344</td><td>796</td><td>1,237</td><td>877</td><td>1,434</td><td></td></tr><tr><td>Off Balance Sheet:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Noncancelable Operating Lease Obligations</td><td>2,481</td><td>615</td><td>941</td><td>533</td><td>392</td><td></td></tr><tr><td>Throughput and Take-or-Pay Agreements \( ^{4} \)</td><td>5,455</td><td>625</td><td>1,327</td><td>1,106</td><td>2,397</td><td></td></tr><tr><td>Other Unconditional Purchase Obligations \( ^{4} \)</td><td>3,638</td><td>902</td><td>1,628</td><td>933</td><td>175</td><td></td></tr></table>

Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 24 beginning on page 64.

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.

3 $9.0 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 2018–2019 period. The amounts represent only the principal balance.

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.

## Direct Guarantees

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">Total</td><td colspan="6">Commitment Expiration by Period</td></tr><tr><td>2017</td><td>2018-2019</td><td>2020-2021</td><td>After 2021</td><td></td><td></td></tr><tr><td>Guarantee of nonconsolidated affiliate or joint-venture obligations</td><td>$ 1,157</td><td>$ 57</td><td>$ 326</td><td>$ 556</td><td>$ 218</td><td></td><td></td></tr></table>

The company has two guarantees of equity affiliates totaling $1.16 billion. Of this amount, $749 million is associated with a financing arrangement with an equity affiliate. Over the approximate 5-year remaining term of this guarantee, the maximum amount will be reduced as payments are made by the affiliate. The remaining amount of $408 million is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 11-year remaining term of this 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 either guarantee.

Indemnifications Information related to indemnifications is included on page 69 in Note 25, Other Contingencies and Commitments, 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 2016 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 2016.

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. The company’s risk management practices and its compliance with policies 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 2016 was not material to the company’s results of operations.

The company uses the Monte Carlo simulation method as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value, at the 95% confidence level with a one-day holding period, from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. Based on these inputs, the VaR for the company’s primary risk exposures in the area of derivative commodity instruments at December 31, 2016 and 2015 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, 2016.

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 2016, 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” on page 52, in Note 16, Investments and Advances, for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

## Litigation and Other Contingencies

MTBE Information related to methyl tertiary butyl ether (MTBE) matters is included on page 53 in Note 18 under the heading “MTBE.”

Ecuador Information related to Ecuador matters is included in Note 18 under the heading “Ecuador,” beginning on page 53.

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.

<table><tr><td>Millions of dollars</td><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Balance at January 1</td><td>$ 1,578</td><td>$ 1,683</td><td>$ 1,456</td><td></td></tr><tr><td>Net Additions</td><td>260</td><td>365</td><td>636</td><td></td></tr><tr><td>Expenditures</td><td>(371)</td><td>(470)</td><td>(409)</td><td></td></tr><tr><td>Balance at December 31</td><td>$ 1,467</td><td>$ 1,578</td><td>$ 1,683</td><td></td></tr></table>

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 $14.2 billion for asset retirement obligations at year-end 2016 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 2016 environmental expenditures. Refer to Note 25 on page 69 for additional discussion of environmental remediation provisions and year-end reserves. Refer also to Note 26 on page 70 for additional discussion of the company’s asset retirement obligations.

Suspended Wells Information related to suspended wells is included in Note 22, Accounting for Suspended Exploratory Wells, beginning on page 62.



Income Taxes Information related to income tax contingencies is included on pages 57 through 59 in Note 19 and page 69 in Note 25 under the heading “Income Taxes.”

Other Contingencies Information related to other contingencies is included on page 70 in Note 25 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 Agreement 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 and SB32; other low carbon fuel standards) and regulatory measures (e.g., the U.S. Environmental Protection Agency’s methane performance standards) that aim to limit or reduce greenhouse gas (GHG) emissions are currently in various stages of 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 20 through 22 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.

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 2016 at approximately $2.1 billion for its consolidated companies. Included in these expenditures were approximately $0.5 billion of environmental capital expenditures and $1.6 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 2017, total worldwide environmental capital expenditures are estimated at $0.4 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. 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

2. 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 2016, Chevron’s UOP Depreciation, Depletion and Amortization (DD&A) for oil and gas properties was $13.3 billion, and proved developed reserves at the beginning of 2016 were 5.4 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 2016 would have increased by approximately $700 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 78, for the changes in proved reserve estimates for the three years ending December 31, 2016, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page 84 for estimates of proved reserve values for each of the three years ended December 31, 2016.

This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of Note 1, beginning on page 38, 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 17 on page 52 and to the section on Properties, Plant and Equipment in Note 1, “Summary of Significant Accounting Policies,” beginning on page 38.



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. In addition, impairments could occur due to changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas. 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 2016 due to reservoir performance and lower crude oil prices. 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 for the years 2016 and 2015 were primarily in Brazil and the United States. No material individual impairments of PP&E or Investments were recorded for the year 2014. 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.

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 2016 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 26 on page 70 for additional discussions on asset retirement obligations.

Pension and Other Postretirement Benefit Plans Note 24, beginning on page 64, 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 66 in Note 24 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes in the world’s financial markets.

For 2016, the company used an expected long-term rate of return of 7.25 percent and a discount rate for service costs of 4.4 percent and a discount rate for interest cost of 3.0 percent for U.S. pension plans. The actual return for 2016 was 9.5 percent. For the 10 years ending December 31, 2016, actual asset returns averaged 4.5 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 7.25 percent during each year.



Total pension expense for 2016 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 67 percent of companywide pension expense, would have reduced total pension plan expense for 2016 by approximately $86 million. A 1 percent increase in the discount rates for this same plan would have reduced pension expense for 2016 by approximately $297 million.

The aggregate funded status recognized at December 31, 2016, was a net liability of approximately $4.7 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2016, the company used a discount rate of 3.9 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 62 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $390 million, and would have decreased the plan’s underfunded status from approximately $2.0 billion to $1.6 billion.

For the company’s OPEB plans, expense for 2016 was $221 million, and the total liability, all unfunded at the end of 2016, was $2.5 billion. For the main U.S. OPEB plan, the company used a discount rate for service cost of 4.9 percent and a discount rate for interest cost of 3.6 percent to measure expense in 2016, and a 4.1 percent discount rate to measure the benefit obligations at December 31, 2016. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2016 OPEB expense and OPEB liabilities at the end of 2016. For information on the sensitivity of the health care cost-trend rate, refer to page 67 in Note 24 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 65 in Note 24 for a description of the method used to amortize the $5.7 billion of before-tax actuarial losses recorded by the company as of December 31, 2016, and an estimate of the costs to be recognized in expense during 2017. In addition, information related to company contributions is included on page 68 in Note 24 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 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 25 beginning on page 69. 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, 2016.

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 beginning on page 42 for information regarding new accounting standards.



<table><tr><td rowspan="2">Millions of dollars, except per-share amounts</td><td colspan="8">2016</td><td>2015</td></tr><tr><td>4th Q</td><td>3rd Q</td><td>2nd Q</td><td>1st Q</td><td>4th Q</td><td>3rd Q</td><td>2nd Q</td><td>1st Q</td><td></td></tr><tr><td>Revenues and Other Income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Sales and other operating revenues \( ^{1} \)</td><td>30,142</td><td>29,159</td><td>27,844</td><td>23,070</td><td>28,014</td><td>32,767</td><td>36,829</td><td>32,315</td><td></td></tr><tr><td>Income from equity affiliates</td><td>778</td><td>555</td><td>752</td><td>576</td><td>919</td><td>1,195</td><td>1,169</td><td>1,401</td><td></td></tr><tr><td>Other income</td><td>577</td><td>426</td><td>686</td><td>(93)</td><td>314</td><td>353</td><td>2,359</td><td>842</td><td></td></tr><tr><td>Total Revenues and Other Income</td><td>31,497</td><td>30,140</td><td>29,282</td><td>23,553</td><td>29,247</td><td>34,315</td><td>40,357</td><td>34,558</td><td></td></tr><tr><td>Costs and Other Deductions</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased crude oil and products</td><td>16,976</td><td>15,842</td><td>15,278</td><td>11,225</td><td>14,570</td><td>17,447</td><td>20,541</td><td>17,193</td><td></td></tr><tr><td>Operating expenses</td><td>5,144</td><td>4,666</td><td>5,054</td><td>5,404</td><td>5,970</td><td>5,592</td><td>6,077</td><td>5,395</td><td></td></tr><tr><td>Selling, general and administrative expenses</td><td>1,544</td><td>1,109</td><td>1,033</td><td>998</td><td>1,303</td><td>1,026</td><td>1,170</td><td>944</td><td></td></tr><tr><td>Exploration expenses</td><td>191</td><td>258</td><td>214</td><td>370</td><td>1,358</td><td>315</td><td>1,075</td><td>592</td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>4,203</td><td>4,130</td><td>6,721</td><td>4,403</td><td>5,400</td><td>4,268</td><td>6,958</td><td>4,411</td><td></td></tr><tr><td>Taxes other than on income \( ^{1} \)</td><td>2,869</td><td>2,962</td><td>2,973</td><td>2,864</td><td>2,856</td><td>2,883</td><td>3,173</td><td>3,118</td><td></td></tr><tr><td>Interest and debt expense</td><td>58</td><td>64</td><td>79</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total Costs and Other Deductions</td><td>30,985</td><td>29,031</td><td>31,352</td><td>25,264</td><td>31,457</td><td>31,531</td><td>38,994</td><td>31,653</td><td></td></tr><tr><td>Income (Loss) Before Income Tax Expense</td><td>512</td><td>1,109</td><td>(2,070)</td><td>(1,711)</td><td>(2,210)</td><td>2,784</td><td>1,363</td><td>2,905</td><td></td></tr><tr><td>Income Tax Expense (Benefit)</td><td>74</td><td>(192)</td><td>(607)</td><td>(1,004)</td><td>(1,655)</td><td>727</td><td>755</td><td>305</td><td></td></tr><tr><td>Net Income (Loss)</td><td>$ 438</td><td>$ 1,301</td><td>$ (1,463)</td><td>$ (707)</td><td>$ (555)</td><td>$ 2,057</td><td>$ 608</td><td>$ 2,600</td><td></td></tr><tr><td>Less: Net income attributable to noncontrolling interests</td><td>23</td><td>18</td><td>7</td><td>18</td><td>33</td><td>20</td><td>37</td><td>33</td><td></td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation</td><td>$ 415</td><td>$ 1,283</td><td>$ (1,470)</td><td>$ (725)</td><td>$ (588)</td><td>$ 2,037</td><td>$ 571</td><td>$ 2,567</td><td></td></tr><tr><td>Per Share of Common Stock</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>- Basic</td><td>$ 0.22</td><td>$ 0.68</td><td>$ (0.78)</td><td>$ (0.39)</td><td>$ (0.31)</td><td>$ 1.09</td><td>$ 0.30</td><td>$ 1.38</td><td></td></tr><tr><td>- Diluted</td><td>$ 0.22</td><td>$ 0.68</td><td>$ (0.78)</td><td>$ (0.39)</td><td>$ (0.31)</td><td>$ 1.09</td><td>$ 0.30</td><td>$ 1.37</td><td></td></tr><tr><td>Dividends</td><td>$ 1.08</td><td>$ 1.07</td><td>$ 1.07</td><td>$ 1.07</td><td>$ 1.07</td><td>$ 1,07</td><td>$ 1.07</td><td>$ 1.07</td><td></td></tr><tr><td>Common Stock Price Range - High \( ^{2} \)</td><td>119.00</td><td>107.58</td><td>105.00</td><td>97.91</td><td>98.64</td><td>96.67</td><td>112.20</td><td>113.00</td><td></td></tr><tr><td>- Low \( ^{2} \)</td><td>99.61</td><td>97.53</td><td>92.43</td><td>75.33</td><td>77.31</td><td>69.58</td><td>96.22</td><td>98.88</td><td></td></tr><tr><td> \( ^{1} \)  Includes excise, value-added and similar taxes:</td><td>$ 1,697</td><td>$ 1,772</td><td>$ 1,784</td><td>$ 1,652</td><td>$ 1,717</td><td>$ 1,800</td><td>$ 1,965</td><td>$ 1,877</td><td></td></tr><tr><td> \( ^{2} \)  Intraday price.</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 15, 2017, stockholders of record numbered approximately 138,000. There are no restrictions on the company’s ability to pay dividends.



## 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, 2016. 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, 2016.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2016, 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

Patricia E. Yarrington
Vice President
and Chief Financial Officer

Jeanette L. Ourada
Vice President
and Comptroller

February 23, 2017



## 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, 2016 and December 31, 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 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, 2016, 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.

As discussed in Note 19 to the consolidated financial statements, the Company changed the manner in which it classifies deferred income taxes in the consolidated balance sheet.

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.

## PricewaterhouseCoopers LLP

San Francisco, California

February 23, 2017



<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Revenues and Other Income</td><td></td><td></td><td></td></tr><tr><td>Sales and other operating revenues*</td><td>$ 110,215</td><td>$ 129,925</td><td>$ 200,494</td></tr><tr><td>Income from equity affiliates</td><td>2,661</td><td>4,684</td><td>7,098</td></tr><tr><td>Other income</td><td>1,596</td><td>3,868</td><td>4,378</td></tr><tr><td>Total Revenues and Other Income</td><td>114,472</td><td>138,477</td><td>211,970</td></tr><tr><td>Costs and Other Deductions</td><td></td><td></td><td></td></tr><tr><td>Purchased crude oil and products</td><td>59,321</td><td>69,751</td><td>119,671</td></tr><tr><td>Operating expenses</td><td>20,268</td><td>23,034</td><td>25,285</td></tr><tr><td>Selling, general and administrative expenses</td><td>4,684</td><td>4,443</td><td>4,494</td></tr><tr><td>Exploration expenses</td><td>1,033</td><td>3,340</td><td>1,985</td></tr><tr><td>Depreciation, depletion and amortization</td><td>19,457</td><td>21,037</td><td>16,793</td></tr><tr><td>Taxes other than on income*</td><td>11,668</td><td>12,030</td><td>12,540</td></tr><tr><td>Interest and debt expense</td><td>201</td><td>—</td><td>—</td></tr><tr><td>Total Costs and Other Deductions</td><td>116,632</td><td>133,635</td><td>180,768</td></tr><tr><td>Income (Loss) Before Income Tax Expense</td><td>(2,160)</td><td>4,842</td><td>31,202</td></tr><tr><td>Income Tax Expense (Benefit)</td><td>(1,729)</td><td>132</td><td>11,892</td></tr><tr><td>Net Income (Loss)</td><td>(431)</td><td>4,710</td><td>19,310</td></tr><tr><td>Less: Net income attributable to noncontrolling interests</td><td>66</td><td>123</td><td>69</td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation</td><td>$ (497)</td><td>$ 4,587</td><td>$ 19,241</td></tr><tr><td>Per Share of Common Stock</td><td></td><td></td><td></td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation</td><td></td><td></td><td></td></tr><tr><td>- Basic</td><td>$ (0.27)</td><td>$ 2.46</td><td>$ 10.21</td></tr><tr><td>- Diluted</td><td>$ (0.27)</td><td>$ 2.45</td><td>$ 10.14</td></tr><tr><td>* Includes excise, value-added and similar taxes.</td><td>$ 6,905</td><td>$ 7,359</td><td>$ 8,186</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Net Income (Loss)</td><td>$ (431)</td><td>$ 4,710</td><td>$ 19,310</td></tr><tr><td>Currency translation adjustment</td><td></td><td></td><td></td></tr><tr><td>Unrealized net change arising during period</td><td>(22)</td><td>(44)</td><td>(73)</td></tr><tr><td>Unrealized holding gain (loss) on securities</td><td></td><td></td><td></td></tr><tr><td>Net gain (loss) arising during period</td><td>27</td><td>(21)</td><td>(2)</td></tr><tr><td>Derivatives</td><td></td><td></td><td></td></tr><tr><td>Net derivatives loss on hedge transactions</td><td>—</td><td>—</td><td>(66)</td></tr><tr><td>Reclassification to net income of net realized gain</td><td>—</td><td>—</td><td>(17)</td></tr><tr><td>Income taxes on derivatives transactions</td><td>—</td><td>—</td><td>29</td></tr><tr><td>Total</td><td>—</td><td>—</td><td>(54)</td></tr><tr><td>Defined benefit plans</td><td></td><td></td><td></td></tr><tr><td>Actuarial gain (loss)</td><td></td><td></td><td></td></tr><tr><td>Amortization to net income of net actuarial loss and settlements</td><td>918</td><td>794</td><td>757</td></tr><tr><td>Actuarial gain (loss) arising during period</td><td>(315)</td><td>109</td><td>(2,730)</td></tr><tr><td>Prior service credits (cost)</td><td></td><td></td><td></td></tr><tr><td>Amortization to net income of net prior service costs and curtailments</td><td>19</td><td>30</td><td>26</td></tr><tr><td>Prior service credits (costs) arising during period</td><td>345</td><td>6</td><td>(6)</td></tr><tr><td>Defined benefit plans sponsored by equity affiliates - (cost) benefit</td><td>(19)</td><td>30</td><td>(99)</td></tr><tr><td>Income (taxes) benefit on defined benefit plans</td><td>(505)</td><td>(336)</td><td>901</td></tr><tr><td>Total</td><td>443</td><td>633</td><td>(1,151)</td></tr><tr><td>Other Comprehensive Gain (Loss), Net of Tax</td><td>448</td><td>568</td><td>(1,280)</td></tr><tr><td>Comprehensive Income (Loss)</td><td>17</td><td>5,278</td><td>18,030</td></tr><tr><td>Comprehensive income attributable to noncontrolling interests</td><td>(66)</td><td>(123)</td><td>(69)</td></tr><tr><td>Comprehensive Income (Loss) Attributable to Chevron Corporation</td><td>$ (49)</td><td>$ 5,155</td><td>$ 17,961</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2016</td><td>2015</td></tr><tr><td>Assets</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 6,988</td><td>$ 11,022</td></tr><tr><td>Marketable securities</td><td>13</td><td>310</td></tr><tr><td>Accounts and notes receivable (less allowance: 2016 - $373; 2015 - $313)</td><td>14,092</td><td>12,860</td></tr><tr><td>Inventories:</td><td></td><td></td></tr><tr><td>Crude oil and petroleum products</td><td>2,720</td><td>3,535</td></tr><tr><td>Chemicals</td><td>455</td><td>490</td></tr><tr><td>Materials, supplies and other</td><td>2,244</td><td>2,309</td></tr><tr><td>Total inventories</td><td>5,419</td><td>6,334</td></tr><tr><td>Prepaid expenses and other current assets \( ^{1} \)</td><td>3,107</td><td>3,904</td></tr><tr><td>Total Current Assets</td><td>29,619</td><td>34,430</td></tr><tr><td>Long-term receivables, net</td><td>2,485</td><td>2,412</td></tr><tr><td>Investments and advances</td><td>30,250</td><td>27,110</td></tr><tr><td>Properties, plant and equipment, at cost</td><td>336,077</td><td>340,277</td></tr><tr><td>Less: Accumulated depreciation, depletion and amortization</td><td>153,891</td><td>151,881</td></tr><tr><td>Properties, plant and equipment, net</td><td>182,186</td><td>188,396</td></tr><tr><td>Deferred charges and other assets \( ^{1,2} \)</td><td>6,838</td><td>6,155</td></tr><tr><td>Goodwill</td><td>4,581</td><td>4,588</td></tr><tr><td>Assets held for sale</td><td>4,119</td><td>1,449</td></tr><tr><td>Total Assets</td><td>$ 260,078</td><td>$ 264,540</td></tr><tr><td>Liabilities and Equity</td><td></td><td></td></tr><tr><td>Short-term debt \( ^{2} \)  (net of unamortized discount and debt issuance costs: $3 in 2016, $1 in 2015)</td><td>$ 10,840</td><td>$ 4,927</td></tr><tr><td>Accounts payable</td><td>13,986</td><td>13,516</td></tr><tr><td>Accrued liabilities</td><td>4,882</td><td>4,833</td></tr><tr><td>Federal and other taxes on income \( ^{1} \)</td><td>1,050</td><td>1,073</td></tr><tr><td>Other taxes payable</td><td>1,027</td><td>1,118</td></tr><tr><td>Total Current Liabilities</td><td>31,785</td><td>25,467</td></tr><tr><td>Long-term debt \( ^{2} \)  (net of unamortized discount and debt issuance costs: $41 in 2016, $42 in 2015)</td><td>35,193</td><td>33,542</td></tr><tr><td>Capital lease obligations</td><td>93</td><td>80</td></tr><tr><td>Deferred credits and other noncurrent obligations</td><td>21,553</td><td>23,465</td></tr><tr><td>Noncurrent deferred income taxes \( ^{1} \)</td><td>17,516</td><td>20,165</td></tr><tr><td>Noncurrent employee benefit plans</td><td>7,216</td><td>7,935</td></tr><tr><td>Total Liabilities \( ^{3} \)</td><td>113,356</td><td>110,654</td></tr><tr><td>Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued)</td><td>—</td><td>—</td></tr><tr><td>Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares issued at December 31, 2016 and 2015)</td><td>1,832</td><td>1,832</td></tr><tr><td>Capital in excess of par value</td><td>16,595</td><td>16,330</td></tr><tr><td>Retained earnings</td><td>173,046</td><td>181,578</td></tr><tr><td>Accumulated other comprehensive loss</td><td>(3,843)</td><td>(4,291)</td></tr><tr><td>Deferred compensation and benefit plan trust</td><td>(240)</td><td>(240)</td></tr><tr><td>Treasury stock, at cost (2016 - 551,170,158 shares; 2015 - 559,862,580 shares)</td><td>(41,834)</td><td>(42,493)</td></tr><tr><td>Total Chevron Corporation Stockholders&#x27; Equity</td><td>145,556</td><td>152,716</td></tr><tr><td>Noncontrolling interests</td><td>1,166</td><td>1,170</td></tr><tr><td>Total Equity</td><td>146,722</td><td>153,886</td></tr><tr><td>Total Liabilities and Equity</td><td>$ 260,078</td><td>$ 264,540</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.

 \( ^{1} $  2015 adjusted to conform to ASU 2015-17. Refer to Note 19, “Income Taxes” beginning on page 57.

 \( ^{2} $  2015 adjusted to conform to ASU 2015-03. Refer to Note 5, “New Accounting Standards” beginning on page 42.

 \( ^{3} \)  Refer to Note 25, “Other Contingencies and Commitments” beginning on page 69.



<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Operating Activities</td><td></td><td></td><td></td></tr><tr><td>Net Income (Loss)</td><td>$ (431)</td><td>$ 4,710</td><td>$ 19,310</td></tr><tr><td>Adjustments</td><td></td><td></td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>19,457</td><td>21,037</td><td>16,793</td></tr><tr><td>Dry hole expense</td><td>489</td><td>2,309</td><td>875</td></tr><tr><td>Distributions less than income from equity affiliates</td><td>(1,227)</td><td>(760)</td><td>(2,202)</td></tr><tr><td>Net before-tax gains on asset retirements and sales</td><td>(1,149)</td><td>(3,215)</td><td>(3,540)</td></tr><tr><td>Net foreign currency effects</td><td>186</td><td>(82)</td><td>(277)</td></tr><tr><td>Deferred income tax provision</td><td>(3,835)</td><td>(1,861)</td><td>1,572</td></tr><tr><td>Net increase in operating working capital</td><td>(550)</td><td>(1,979)</td><td>(540)</td></tr><tr><td>(Increase) in long-term receivables</td><td>(131)</td><td>(59)</td><td>(9)</td></tr><tr><td>Decrease in other deferred charges</td><td>235</td><td>25</td><td>263</td></tr><tr><td>Cash contributions to employee pension plans</td><td>(870)</td><td>(868)</td><td>(392)</td></tr><tr><td>Other</td><td>672</td><td>199</td><td>(378)</td></tr><tr><td>Net Cash Provided by Operating Activities</td><td>12,846</td><td>19,456</td><td>31,475</td></tr><tr><td>Investing Activities</td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(18,109)</td><td>(29,504)</td><td>(35,407)</td></tr><tr><td>Proceeds and deposits related to asset sales</td><td>2,777</td><td>5,739</td><td>5,729</td></tr><tr><td>Net maturities of time deposits</td><td>—</td><td>8</td><td>—</td></tr><tr><td>Net sales (purchases) of marketable securities</td><td>297</td><td>122</td><td>(148)</td></tr><tr><td>Net (borrowing) repayment of loans by equity affiliates</td><td>(2,034)</td><td>(217)</td><td>140</td></tr><tr><td>Net sales (purchases) of other short-term investments</td><td>217</td><td>44</td><td>(207)</td></tr><tr><td>Net Cash Used for Investing Activities</td><td>(16,852)</td><td>(23,808)</td><td>(29,893)</td></tr><tr><td>Financing Activities</td><td></td><td></td><td></td></tr><tr><td>Net borrowings (repayments) of short-term obligations</td><td>2,130</td><td>(335)</td><td>3,431</td></tr><tr><td>Proceeds from issuances of long-term debt</td><td>6,924</td><td>11,091</td><td>4,000</td></tr><tr><td>Repayments of long-term debt and other financing obligations</td><td>(1,584)</td><td>(32)</td><td>(43)</td></tr><tr><td>Cash dividends - common stock</td><td>(8,032)</td><td>(7,992)</td><td>(7,928)</td></tr><tr><td>Distributions to noncontrolling interests</td><td>(63)</td><td>(128)</td><td>(47)</td></tr><tr><td>Net sales of treasury shares</td><td>650</td><td>211</td><td>(4,412)</td></tr><tr><td>Net Cash Provided by (Used for) Financing Activities</td><td>25</td><td>2,815</td><td>(4,999)</td></tr><tr><td>Effect of Exchange Rate Changes on Cash and Cash Equivalents</td><td>(53)</td><td>(226)</td><td>(43)</td></tr><tr><td>Net Change in Cash and Cash Equivalents</td><td>(4,034)</td><td>(1,763)</td><td>(3,460)</td></tr><tr><td>Cash and Cash Equivalents at January 1</td><td>11,022</td><td>12,785</td><td>16,245</td></tr><tr><td>Cash and Cash Equivalents at December 31</td><td>$ 6,988</td><td>$ 11,022</td><td>$ 12,785</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



<table><tr><td rowspan="2"></td><td colspan="2">2016</td><td colspan="2">2015</td><td colspan="2">2014</td></tr><tr><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td></tr><tr><td>Preferred Stock</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Common Stock</td><td>2,442,677</td><td>1,832</td><td>2,442,677</td><td>1,832</td><td>2,442,677</td><td>3,832</td></tr><tr><td>Capital in Excess of Par</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>16,330</td><td></td><td>16,041</td><td></td><td>15,713</td></tr><tr><td>Treasury stock transactions</td><td></td><td>265</td><td></td><td>289</td><td></td><td>328</td></tr><tr><td>Balance at December 31</td><td></td><td>16,595</td><td></td><td>16,330</td><td></td><td>16,041</td></tr><tr><td>Retained Earnings</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>181,578</td><td></td><td>184,987</td><td></td><td>173,677</td></tr><tr><td>Net income (loss) attributable to Chevron Corporation</td><td></td><td>(497)</td><td></td><td>4,587</td><td></td><td>19,241</td></tr><tr><td>Cash dividends on common stock</td><td></td><td>(8,032)</td><td></td><td>(7,992)</td><td></td><td>(7,928)</td></tr><tr><td>Stock dividends</td><td></td><td>(3)</td><td></td><td>(3)</td><td></td><td>(3)</td></tr><tr><td>Tax (charge) benefit from dividends paid on unallocated ESOP shares and other</td><td></td><td>—</td><td></td><td>(1)</td><td></td><td>—</td></tr><tr><td>Balance at December 31</td><td></td><td>173,046</td><td></td><td>181,578</td><td></td><td>184,987</td></tr><tr><td>Accumulated Other Comprehensive Loss</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Currency translation adjustment</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>(140)</td><td></td><td>(96)</td><td></td><td>(23)</td></tr><tr><td>Change during year</td><td></td><td>(22)</td><td></td><td>(44)</td><td></td><td>(73)</td></tr><tr><td>Balance at December 31</td><td></td><td>(162)</td><td></td><td>(140)</td><td></td><td>(96)</td></tr><tr><td>Unrealized net holding (loss) gain on securities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>(29)</td><td></td><td>(8)</td><td></td><td>(6)</td></tr><tr><td>Change during year</td><td></td><td>27</td><td></td><td>(21)</td><td></td><td>(2)</td></tr><tr><td>Balance at December 31</td><td></td><td>(2)</td><td></td><td>(29)</td><td></td><td>(8)</td></tr><tr><td>Net derivatives (loss) gain on hedge transactions</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>(2)</td><td></td><td>(2)</td><td></td><td>52</td></tr><tr><td>Change during year</td><td></td><td>—</td><td></td><td>—</td><td></td><td>(54)</td></tr><tr><td>Balance at December 31</td><td></td><td>(2)</td><td></td><td>(2)</td><td></td><td>(2)</td></tr><tr><td>Pension and other postretirement benefit plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>(4,120)</td><td></td><td>(4,753)</td><td></td><td>(3,602)</td></tr><tr><td>Change during year</td><td></td><td>443</td><td></td><td>633</td><td></td><td>(1,151)</td></tr><tr><td>Balance at December 31</td><td></td><td>(3,677)</td><td></td><td>(4,120)</td><td></td><td>(4,753)</td></tr><tr><td>Balance at December 31</td><td></td><td>(3,843)</td><td></td><td>(4,291)</td><td></td><td>(4,859)</td></tr><tr><td>Benefit Plan Trust (Common Stock)</td><td>14,168</td><td>(240)</td><td>14,168</td><td>(240)</td><td>14,168</td><td>(2,40)</td></tr><tr><td>Balance at December 31</td><td>14,168</td><td>(240)</td><td>14,168</td><td>(240)</td><td>14,168</td><td>(2,40)</td></tr><tr><td>Treasury Stock at Cost</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td>559,863</td><td>(42,493)</td><td>563,028</td><td>(42,733)</td><td>529,074</td><td>(38,290)</td></tr><tr><td>Purchases</td><td>20</td><td>(2)</td><td>15</td><td>(2)</td><td>41,592</td><td>(5,006)</td></tr><tr><td>Issuances - mainly employee benefit plans</td><td>(8,713)</td><td>661</td><td>(3,180)</td><td>242</td><td>(7,638)</td><td>563</td></tr><tr><td>Balance at December 31</td><td>551,170</td><td>(41,834)</td><td>559,863</td><td>(42,493)</td><td>563,028</td><td>(42,733)</td></tr><tr><td>Total Chevron Corporation Stockholders&#x27; Equity at December 31</td><td></td><td>145,556</td><td></td><td>152,716</td><td></td><td>155,028</td></tr><tr><td>Noncontrolling Interests</td><td></td><td>1,166</td><td></td><td>1,170</td><td></td><td>1,163</td></tr><tr><td>Total Equity</td><td></td><td>146,722</td><td></td><td>153,886</td><td></td><td>156,191</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



## 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



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 22, beginning on page 62, 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 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 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 10, beginning on page 45, 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 26, on page 70, 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.

Effective in the quarter ended December 31, 2016, the company has elected to move the annual review of the goodwill balance from the third to fourth quarter to better align with the preparation and review of the company’s business plan, which is used in the test. The change does not delay, accelerate or avoid an impairment charge.

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 26, on page 70, 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.

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 33. 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 in the first, second and third anniversaries of the date of grant. Beginning in 2017, stock options and stock appreciation rights granted under the company’s Long-Term Incentive Plan have graded vesting by which one third of each award vests annually on each January 31 on or after the first anniversary of the grant date. Standard restricted stock units have cliff vesting by which the total award will vest on January 31 on or after the fifth anniversary of the grant date. The company amortizes these 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, 2016, are reflected in the table below.

<table><tr><td></td><td></td><td></td><td colspan="5">Year Ended December 31, 2016 \( ^{1} \)</td></tr><tr><td></td><td>Currency Translation Adjustment</td><td>Unrealized Holding Gains (Losses) on Securities</td><td>Derivatives</td><td colspan="2">Defined Benefit Plans</td><td>Total</td><td></td></tr><tr><td>Balance at January 1</td><td>$ (140)</td><td>$ (29)</td><td>$ (2)</td><td>$ (4,120)</td><td>$ (4,291)</td><td></td><td></td></tr><tr><td>Components of Other Comprehensive Income (Loss):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Before Reclassifications</td><td>(22)</td><td>27</td><td>—</td><td>(161)</td><td>(156)</td><td></td><td></td></tr><tr><td>Reclassifications \( ^{2} \)</td><td>—</td><td>—</td><td>—</td><td>604</td><td>604</td><td></td><td></td></tr><tr><td>Net Other Comprehensive Income (Loss)</td><td>(22)</td><td>27</td><td>—</td><td>443</td><td>448</td><td></td><td></td></tr><tr><td>Balance at December 31</td><td>$ (162)</td><td>$ (2)</td><td>$ (2)</td><td>$ (3,677)</td><td>$ (3,843)</td><td></td><td></td></tr></table>

 \( ^{1} \)  All amounts are net of tax.

2 Refer to Note 24 beginning on page 64, for reclassified components totaling $937 that are included in employee benefit costs for the year ending December 31, 2016. Related income taxes for the same period, totaling $333, 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 (Loss) Attributable to Chevron Corporation.”

Activity for the equity attributable to noncontrolling interests for 2016, 2015 and 2014 is as follows:

<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Balance at January 1</td><td>$ 1,170</td><td>$ 1,163</td><td>$ 1,314</td></tr><tr><td>Net income</td><td>66</td><td>123</td><td>69</td></tr><tr><td>Distributions to noncontrolling interests</td><td>(63)</td><td>(128)</td><td>(47)</td></tr><tr><td>Other changes, net</td><td>(7)</td><td>12</td><td>(173)</td></tr><tr><td>Balance at December 31</td><td>$ 1,166</td><td>$ 1,170</td><td>$ 1,163</td></tr></table>

## Note 4

Information Relating to the Consolidated Statement of Cash Flows

<table><tr><td rowspan="2"></td><td colspan="4">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td><td></td></tr><tr><td>Net increase in operating working capital was composed of the following:</td><td></td><td></td><td></td><td></td></tr><tr><td>(Increase) decrease in accounts and notes receivable</td><td>$ (2,121)</td><td>$ 3,631</td><td>$ 4,491</td><td></td></tr><tr><td>Decrease (increase) in inventories</td><td>603</td><td>85</td><td>(146)</td><td></td></tr><tr><td>Decrease (increase) in prepaid expenses and other current assets</td><td>439</td><td>713</td><td>(407)</td><td></td></tr><tr><td>Increase (decrease) in accounts payable and accrued liabilities</td><td>533</td><td>(5,769)</td><td>(3,737)</td><td></td></tr><tr><td>Decrease in income and other taxes payable</td><td>(4)</td><td>(639)</td><td>(741)</td><td></td></tr><tr><td>Net increase in operating working capital</td><td>$ (550)</td><td>$ (1,979)</td><td>$ (540)</td><td></td></tr><tr><td>Net cash provided by operating activities includes the following cash payments for interest on debt and for income taxes:</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest on debt (net of capitalized interest)</td><td>$ 158</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Income taxes</td><td>1,935</td><td>4,645</td><td>10,562</td><td></td></tr><tr><td>Net sales (purchases) of marketable securities consisted of the following gross amounts:</td><td></td><td></td><td></td><td></td></tr><tr><td>Marketable securities purchased</td><td>$ (9)</td><td>$ (6)</td><td>$ (162)</td><td></td></tr><tr><td>Marketable securities sold</td><td>306</td><td>128</td><td>14</td><td></td></tr><tr><td>Net sales (purchases) of marketable securities</td><td>$ 297</td><td>$ 122</td><td>$ (148)</td><td></td></tr><tr><td>Net maturities of time deposits consisted of the following gross amounts:</td><td></td><td></td><td></td><td></td></tr><tr><td>Investments in time deposits</td><td>$ —</td><td>$ —</td><td>$ (317)</td><td></td></tr><tr><td>Maturities of time deposits</td><td>—</td><td>8</td><td>317</td><td></td></tr><tr><td>Net maturities of time deposits</td><td>$ —</td><td>$ 8</td><td>$ —</td><td></td></tr><tr><td>Net (borrowing) repayment of loans by equity affiliates:</td><td></td><td></td><td></td><td></td></tr><tr><td>Borrowing of loans by equity affiliates</td><td>$ (2,341)</td><td>$ (223)</td><td>$ (176)</td><td></td></tr><tr><td>Repayment of loans by equity affiliates</td><td>307</td><td>6</td><td>316</td><td></td></tr><tr><td>Net (borrowing) repayment of loans by equity affiliates</td><td>$ (2,034)</td><td>$ (217)</td><td>$ 140</td><td></td></tr><tr><td>Net sales (purchases) of other short-term investments:</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchases of other short-term investments</td><td>$ (1)</td><td>$ (75)</td><td>$ (223)</td><td></td></tr><tr><td>Sales of other short-term investments</td><td>218</td><td>119</td><td>16</td><td></td></tr><tr><td>Net sales (purchases) of other short-term investments</td><td>$ 217</td><td>$ 44</td><td>$ (207)</td><td></td></tr><tr><td>Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:</td><td></td><td></td><td></td><td></td></tr><tr><td>Proceeds from issuances of short-term obligations</td><td>$ 14,778</td><td>$ 13,805</td><td>$ 9,070</td><td></td></tr><tr><td>Repayments of short-term obligations</td><td>(12,558)</td><td>(16,379)</td><td>(4,612)</td><td></td></tr><tr><td>Net borrowings (repayments) of short-term obligations with three months or less maturity</td><td>(90)</td><td>2,239</td><td>(1,027)</td><td></td></tr><tr><td>Net borrowings (repayments) of short-term obligations</td><td>$ 2,130</td><td>$ (335)</td><td>$ 3,431</td><td></td></tr></table>

A loan to Tengizchevroil LLP for the development of the Future Growth and Wellhead Pressure Management Project represents the majority of “Net (borrowing) repayment of loans by equity affiliates.”

The “Net sales of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $2, $2 and $5,006 in 2016, 2015 and 2014, respectively. No purchases were



made under the company’s share repurchase program in 2016 or 2015. In 2014, the company purchased 41.5 million common shares for $5,000 under its share repurchase program.

In 2016, 2015 and 2014, “Net sales (purchases) of other short-term investments” generally consisted of restricted cash associated with upstream abandonment activities, tax payments and certain pension fund payments 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” and “Deferred income tax provision” collectively include approximately $2,800 in non-cash reductions to properties, plant and equipment recorded in 2016 relating to impairments and other non-cash charges due to reservoir performance and lower crude prices.

Refer also to Note 26, on page 70, 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, 2016.

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:

<table><tr><td rowspan="2"></td><td colspan="4">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td><td></td></tr><tr><td>Additions to properties, plant and equipment *</td><td>17,742</td><td>28,213</td><td>34,393</td><td></td></tr><tr><td>Additions to investments</td><td>55</td><td>555</td><td>526</td><td></td></tr><tr><td>Current-year dry hole expenditures</td><td>313</td><td>736</td><td>504</td><td></td></tr><tr><td>Payments for other liabilities and assets, net</td><td>(1)</td><td>—</td><td>(16)</td><td></td></tr><tr><td>Capital expenditures</td><td>18,109</td><td>29,504</td><td>35,407</td><td></td></tr><tr><td>Expensed exploration expenditures</td><td>544</td><td>1,031</td><td>1,110</td><td></td></tr><tr><td>Assets acquired through capital lease obligations and other financing obligations</td><td>5</td><td>47</td><td>332</td><td></td></tr><tr><td>Capital and exploratory expenditures, excluding equity affiliates</td><td>18,658</td><td>30,582</td><td>36,849</td><td></td></tr><tr><td>Company’s share of expenditures by equity affiliates</td><td>3,770</td><td>3,397</td><td>3,467</td><td></td></tr><tr><td>Capital and exploratory expenditures, including equity affiliates</td><td>22,428</td><td>33,979</td><td>40,316</td><td></td></tr></table>

* Excludes noncash additions of $56 in 2016, $1,362 in 2015 and $2,310 in 2014.

## Note 5

## New Accounting Standards

Revenue Recognition (Topic 606): Revenue from Contracts with Customers 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. The standard provides a single comprehensive revenue recognition model for contracts with customers, eliminates most industry-specific revenue recognition guidance, and expands disclosure requirements. The company has elected to adopt the standard using the modified retrospective transition method. “Sales and Other Operating Revenues” on the Consolidated Statement of Income includes excise, value-added and similar taxes on sales transactions. Upon adoption of the standard, revenue will exclude sales-based taxes collected on behalf of third parties, which will have no impact to earnings. The company’s implementation efforts are focused on accounting policy and disclosure updates and system enhancements necessary to meet the standard’s requirements. The company continues to evaluate the effect of the standard on its consolidated financial statements.

Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs Effective January 1, 2016, Chevron adopted ASU 2015-03 on a retrospective basis. The standard requires that debt issuance costs related to a recognized liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The effects of retrospective adoption on the December 31, 2015, Consolidated Balance Sheet were reductions of $43 in “Deferred charges and other assets,” $1 in “Short-term debt” and $42 in “Long-term debt.”

Leases (Topic 842) In February 2016, the FASB issued ASU 2016-02 which becomes effective for the company January 1, 2019. The standard requires that lessees present right-of-use assets and lease liabilities on the balance sheet. The company is evaluating the effect of the standard on the company’s consolidated financial statements.

Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting In March 2016, the FASB issued ASU 2016-09 which the company elected to early-adopt retrospective to January 1, 2016. The standard requires that all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement, regardless of whether the benefit reduces taxes payable in the current period. In addition, excess tax



benefits are to be classified along with other income tax cash flows as an operating activity in the statement of cash flows. The effect of the early adoption is not material to the company’s consolidated financial statements.

Financial Instruments - Credit Losses (Topic 326) In June 2016, the FASB issued ASU 2016-13, which becomes effective for the company beginning January 1, 2020. The standard requires companies to use forward-looking information to calculate credit loss estimates. The company is evaluating the effect of the standard on the company’s consolidated financial statements.

Intangibles - Goodwill and Other (Topic 350) In January 2017, the FASB issued ASU 2017-04. The standard simplifies the accounting for goodwill impairment, and the company has chosen to early adopt beginning January 1, 2017. Early adoption has no effect on the company’s consolidated financial statements.

## 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:

<table><tr><td rowspan="2"></td><td colspan="3">At December 31</td></tr><tr><td>2016</td><td>2015</td><td></td></tr><tr><td>Upstream</td><td>$ 676</td><td>$ 800</td><td></td></tr><tr><td>Downstream</td><td>99</td><td>98</td><td></td></tr><tr><td>All Other</td><td>—</td><td>—</td><td></td></tr><tr><td>Total</td><td>775</td><td>898</td><td></td></tr><tr><td>Less: Accumulated amortization</td><td>383</td><td>448</td><td></td></tr><tr><td>Net capitalized leased assets</td><td>$ 392</td><td>$ 450</td><td></td></tr></table>

Rental expenses incurred for operating leases during 2016, 2015 and 2014 were as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Minimum rentals</td><td>$ 943</td><td>$ 1,041</td><td>$ 1,080</td></tr><tr><td>Contingent rentals</td><td>2</td><td>2</td><td>1</td></tr><tr><td>Total</td><td>945</td><td>1,043</td><td>1,081</td></tr><tr><td>Less: Sublease rental income</td><td>7</td><td>9</td><td>14</td></tr><tr><td>Net rental expense</td><td>$ 938</td><td>$ 1,034</td><td>$ 1,067</td></tr></table>

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, 2016, 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:

<table><tr><td rowspan="2"></td><td colspan="3">At December 31</td></tr><tr><td>Operating Leases</td><td>Capital Leases</td><td></td></tr><tr><td>Year 2017</td><td>$ 615</td><td>$ 22</td><td></td></tr><tr><td>2018</td><td>554</td><td>20</td><td></td></tr><tr><td>2019</td><td>387</td><td>21</td><td></td></tr><tr><td>2020</td><td>298</td><td>12</td><td></td></tr><tr><td>2021</td><td>235</td><td>12</td><td></td></tr><tr><td>Thereafter</td><td>392</td><td>145</td><td></td></tr><tr><td>Total</td><td>$ 2,481</td><td>$ 232</td><td></td></tr><tr><td>Less: Amounts representing interest and executory costs</td><td></td><td>$ (125)</td><td></td></tr><tr><td>Net present values</td><td></td><td>107</td><td></td></tr><tr><td>Less: Capital lease obligations included in short-term debt</td><td></td><td>(14)</td><td></td></tr><tr><td>Long-term capital lease obligations</td><td></td><td>$ 93</td><td></td></tr></table>



## 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:

<table><tr><td rowspan="2"></td><td colspan="4">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td><td></td></tr><tr><td>Sales and other operating revenues</td><td>$ 83,715</td><td>$ 97,766</td><td>$ 157,198</td><td></td></tr><tr><td>Total costs and other deductions</td><td>87,429</td><td>101,565</td><td>153,139</td><td></td></tr><tr><td>Net income (loss) attributable to CUSA</td><td>(1,177)</td><td>(1,054)</td><td>3,849</td><td></td></tr><tr><td></td><td></td><td>2016</td><td>2015*</td><td></td></tr><tr><td>Current assets</td><td></td><td>$ 11,266</td><td>$ 9,096</td><td></td></tr><tr><td>Other assets</td><td></td><td>55,722</td><td>59,171</td><td></td></tr><tr><td>Current liabilities</td><td></td><td>16,660</td><td>13,664</td><td></td></tr><tr><td>Other liabilities</td><td></td><td>21,701</td><td>28,465</td><td></td></tr><tr><td>Total CUSA net equity</td><td></td><td>$ 28,627</td><td>$ 26,138</td><td></td></tr><tr><td>Memo: Total debt</td><td></td><td>$ 9,418</td><td>$ 14,462</td><td></td></tr></table>

* 2015 adjusted to conform to ASU 2015-17.

## Note 8

Summarized Financial Data – Tengizchevroil LLP

Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 16, beginning on page 51, for a discussion of TCO operations. Summarized financial information for 100 percent of TCO is presented in the table below:

<table><tr><td rowspan="2"></td><td colspan="4">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td><td></td></tr><tr><td>Sales and other operating revenues</td><td>$ 10,460</td><td>$ 12,811</td><td>$ 22,813</td><td></td></tr><tr><td>Costs and other deductions</td><td>6,822</td><td>7,257</td><td>10,275</td><td></td></tr><tr><td>Net income attributable to TCO</td><td>2,563</td><td>3,897</td><td>8,772</td><td></td></tr><tr><td></td><td></td><td></td><td>At December 31</td><td></td></tr><tr><td></td><td></td><td>2016</td><td>2015</td><td></td></tr><tr><td>Current assets</td><td></td><td>$ 7,001</td><td>$ 2,098</td><td></td></tr><tr><td>Other assets</td><td></td><td>20,476</td><td>17,094</td><td></td></tr><tr><td>Current liabilities</td><td></td><td>2,841</td><td>1,063</td><td></td></tr><tr><td>Other liabilities</td><td></td><td>6,210</td><td>2,266</td><td></td></tr><tr><td>Total TCO net equity</td><td></td><td>$ 18,426</td><td>$ 15,863</td><td></td></tr></table>

## Note 9

Summarized Financial Data – Chevron Phillips Chemical Company LLC

Chevron has a 50 percent equity ownership interest in Chevron Phillips Chemical Company LLC (CPChem). Refer to Note 16, beginning on page 51, for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem is presented in the table below:

<table><tr><td rowspan="2"></td><td colspan="4">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td><td></td></tr><tr><td>Sales and other operating revenues</td><td>$ 8,455</td><td>$ 9,248</td><td>$ 13,416</td><td></td></tr><tr><td>Costs and other deductions</td><td>7,017</td><td>7,136</td><td>10,776</td><td></td></tr><tr><td>Net income attributable to CPChem</td><td>1,687</td><td>2,651</td><td>3,288</td><td></td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="3">At December 31</td></tr><tr><td>2016</td><td>2015</td><td></td></tr><tr><td>Current assets</td><td>$ 2,695</td><td>$ 2,291</td><td></td></tr><tr><td>Other assets</td><td>12,770</td><td>11,306</td><td></td></tr><tr><td>Current liabilities</td><td>1,418</td><td>1,319</td><td></td></tr><tr><td>Other liabilities</td><td>2,569</td><td>2,013</td><td></td></tr><tr><td>Total CPChem net equity</td><td>$ 11,478</td><td>$ 10,265</td><td></td></tr></table>

## Note 10

## 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, 2016, and December 31, 2015.

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, 2016.

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 2016 primarily due to reservoir performance and lower crude oil prices. The company reported impairments for certain oil and gas properties in 2015 primarily as a result of downward revisions in the company’s longer-term crude oil price outlook. The impairments in 2016 and 2015 were primarily in Brazil and the United States.

Investments and Advances The company did not have any material investments and advances measured at fair value on a nonrecurring basis to report in 2016 or 2015.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

<table><tr><td rowspan="2"></td><td colspan="6">At December 31, 2016</td><td colspan="3">At December 31, 2015</td></tr><tr><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td></td></tr><tr><td>Marketable securities</td><td>$ 13</td><td>$ 13</td><td>$ —</td><td>$ —</td><td>$ 310</td><td>$ 310</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Derivatives</td><td>32</td><td>15</td><td>17</td><td>—</td><td>205</td><td>189</td><td>16</td><td>—</td><td></td></tr><tr><td>Total assets at fair value</td><td>$ 45</td><td>$ 28</td><td>$ 17</td><td>$ —</td><td>$ 515</td><td>$ 499</td><td>$ 16</td><td>$ —</td><td></td></tr><tr><td>Derivatives</td><td>109</td><td>78</td><td>31</td><td>—</td><td>53</td><td>47</td><td>6</td><td>—</td><td></td></tr><tr><td>Total liabilities at fair value</td><td>$ 109</td><td>$ 78</td><td>$ 31</td><td>$ —</td><td>$ 53</td><td>$ 47</td><td>$ 6</td><td>$ —</td><td></td></tr></table>

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

<table><tr><td rowspan="2"></td><td colspan="8">At December 31</td><td colspan="2">At December 31</td></tr><tr><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Before-Tax Loss Year 2016</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td></td></tr><tr><td>Properties, plant and equipment, net (held and used)</td><td>$ 582</td><td>—</td><td>$ 15</td><td>$ 567</td><td>$ 2,507</td><td>$ 3,051</td><td>$ —</td><td>$ 239</td><td>$ 2,812</td><td>$ 3,222</td></tr><tr><td>Properties, plant and equipment, net (held for sale)</td><td>891</td><td>—</td><td>888</td><td>3</td><td>679</td><td>937</td><td>—</td><td>937</td><td>—</td><td>844</td></tr><tr><td>Investments and advances</td><td>26</td><td>—</td><td>20</td><td>6</td><td>234</td><td>75</td><td>—</td><td>75</td><td>—</td><td>28</td></tr><tr><td>Total nonrecurring assets at fair value</td><td>$ 1,499</td><td>$ —</td><td>$ 923</td><td>$ 576</td><td>$ 3,420</td><td>$ 4,063</td><td>$ —</td><td>$ 1,251</td><td>$ 2,812</td><td>$ 4,094</td></tr></table>

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 $6,988 and



$11,022 at December 31, 2016, and December 31, 2015, respectively. The fair values of cash and cash equivalents are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2016.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,426 and $1,100 at December 31, 2016, and December 31, 2015, respectively. At December 31, 2016, these investments are classified as Level 1 and include restricted funds related to certain upstream abandonment activities, tax payments, funds held in escrow for tax-deferred exchanges and refundable deposits related to pending asset sales, which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $26,193 and $25,542 at December 31, 2016, and December 31, 2015, had estimated fair values of $26,627 and $25,884, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $25,860 and classified as Level 1. The fair value of other long-term debt 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, 2016 and 2015, were not material.

## Note 11

## 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, 2016, December 31, 2015, and December 31, 2014, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are below:

Consolidated Balance Sheet: Fair Value of Derivatives Not Designated as Hedging Instruments

<table><tr><td rowspan="2">Type of Contract</td><td rowspan="2">Balance Sheet Classification</td><td colspan="3">At December 31</td></tr><tr><td>2016</td><td>2015</td><td></td></tr><tr><td>Commodity</td><td>Accounts and notes receivable, net</td><td>$     30</td><td>$     200</td><td></td></tr><tr><td>Commodity</td><td>Long-term receivables, net</td><td>2</td><td>5</td><td></td></tr><tr><td>Total assets at fair value</td><td></td><td>$     32</td><td>$     205</td><td></td></tr><tr><td>Commodity</td><td>Accounts payable</td><td>$     99</td><td>$     51</td><td></td></tr><tr><td>Commodity</td><td>Deferred credits and other noncurrent obligations</td><td>10</td><td>2</td><td></td></tr><tr><td>Total liabilities at fair value</td><td></td><td>$     109</td><td>$     53</td><td></td></tr></table>

Consolidated Statement of Income: The Effect of Derivatives Not Designated as Hedging Instruments

<table><tr><td rowspan="2">Type of Derivative Contract</td><td rowspan="2">Statement of Income Classification</td><td colspan="3">Gain/(Loss) Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Commodity</td><td>Sales and other operating revenues</td><td>$ (269)</td><td>$ 277</td><td>$ 553</td></tr><tr><td>Commodity</td><td>Purchased crude oil and products</td><td>(31)</td><td>30</td><td>(17)</td></tr><tr><td>Commodity</td><td>Other income</td><td>—</td><td>(3)</td><td>(32)</td></tr><tr><td></td><td></td><td>$ (300)</td><td>$ 304</td><td>$ 504</td></tr></table>

The table on the following page represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2016 and December 31, 2015.



Consolidated Balance Sheet: The Effect of Netting Derivative Assets and Liabilities

<table><tr><td>At December 31, 2016</td><td>Gross Amount Recognized</td><td>Gross Amounts Offset</td><td>Net Amounts Presented</td><td>Gross Amounts Not Offset</td><td>Net Amount</td></tr><tr><td>Derivative Assets</td><td>$     1,052</td><td>$     1,020</td><td>$     32</td><td>$      —</td><td>$     32</td></tr><tr><td>Derivative Liabilities</td><td>$     1,129</td><td>$     1,020</td><td>$     109</td><td>$      —</td><td>$     109</td></tr><tr><td>At December 31, 2015</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Derivative Assets</td><td>$     2,459</td><td>$     2,254</td><td>$     205</td><td>$      —</td><td>$     205</td></tr><tr><td>Derivative Liabilities</td><td>$     2,307</td><td>$     2,254</td><td>$     53</td><td>$      —</td><td>$     53</td></tr></table>

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, 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 12

## Assets Held for Sale

At December 31, 2016, the company classified $4,119 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2016 were not material.

## Note 13

## Equity

Retained earnings at December 31, 2016 and 2015, included approximately $16,479 and $15,010, respectively, for the company’s share of undistributed earnings of equity affiliates.

At December 31, 2016, about 87 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, 859,746 shares remain available for issuance from the 1,600,000 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 14

## Earnings Per Share

Basic earnings per share (EPS) is based upon “Net Income (Loss) 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 23, “Stock Options and Other Share-Based Compensation,” beginning on page 63). The table on the following page sets forth the computation of basic and diluted EPS:



<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Basic EPS Calculation</td><td></td><td></td><td></td></tr><tr><td>Earnings available to common stockholders - Basic \( ^{1} \)</td><td>$ (497)</td><td>$ 4,587</td><td>$ 19,241</td></tr><tr><td>Weighted-average number of common shares outstanding \( ^{2} \)</td><td>1,872</td><td>1,867</td><td>1,883</td></tr><tr><td>Add: Deferred awards held as stock units</td><td>1</td><td>1</td><td>1</td></tr><tr><td>Total weighted-average number of common shares outstanding</td><td>1,873</td><td>1,868</td><td>1,884</td></tr><tr><td>Earnings per share of common stock - Basic</td><td>$ (0.27)</td><td>$ 2.46</td><td>$ 10.21</td></tr><tr><td>Diluted EPS Calculation</td><td></td><td></td><td></td></tr><tr><td>Earnings available to common stockholders - Diluted \( ^{1} \)</td><td>$ (497)</td><td>$ 4,587</td><td>$ 19,241</td></tr><tr><td>Weighted-average number of common shares outstanding \( ^{2} \)</td><td>1,872</td><td>1,867</td><td>1,883</td></tr><tr><td>Add: Deferred awards held as stock units</td><td>1</td><td>1</td><td>1</td></tr><tr><td>Add: Dilutive effect of employee stock-based awards</td><td>—</td><td>7</td><td>14</td></tr><tr><td>Total weighted-average number of common shares outstanding</td><td>1,873</td><td>1,875</td><td>1,898</td></tr><tr><td>Earnings per share of common stock - Diluted</td><td>$ (0.27)</td><td>$ 2.45</td><td>$ 10.14</td></tr></table>

 \( ^{1} \)  There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.

 \( ^{2} \)  Millions of shares; 10 million shares of employee-based awards were not included in the 2016 diluted EPS calculation as the result would be anti-dilutive.

## Note 15

## 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).

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 table on the following page:



<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Upstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ (2,054)</td><td>$ (4,055)</td><td>$ 3,327</td></tr><tr><td>International</td><td>(483)</td><td>2,094</td><td>13,566</td></tr><tr><td>Total Upstream</td><td>(2,537)</td><td>(1,961)</td><td>16,893</td></tr><tr><td>Downstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>1,307</td><td>3,182</td><td>2,637</td></tr><tr><td>International</td><td>2,128</td><td>4,419</td><td>1,699</td></tr><tr><td>Total Downstream</td><td>3,435</td><td>7,601</td><td>4,336</td></tr><tr><td>Total Segment Earnings</td><td>898</td><td>5,640</td><td>21,229</td></tr><tr><td>All Other</td><td></td><td></td><td></td></tr><tr><td>Interest expense</td><td>(168)</td><td>—</td><td>—</td></tr><tr><td>Interest income</td><td>58</td><td>65</td><td>77</td></tr><tr><td>Other</td><td>(1,285)</td><td>(1,118)</td><td>(2,065)</td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation</td><td>$ (497)</td><td>$ 4,587</td><td>$ 19,241</td></tr></table>

Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2016 and 2015 are as follows:

<table><tr><td rowspan="2"></td><td colspan="3">At December 31</td></tr><tr><td>2016</td><td>2015</td><td></td></tr><tr><td>Upstream</td><td></td><td></td><td></td></tr><tr><td>United States \( ^{1} \)</td><td>42,596</td><td>$ 46,383</td><td></td></tr><tr><td>International \) ^{1}</td><td>164,068</td><td>162,030</td><td></td></tr><tr><td>Goodwill</td><td>4,581</td><td>4,588</td><td></td></tr><tr><td>Total Upstream</td><td>211,245</td><td>213,001</td><td></td></tr><tr><td>Downstream</td><td></td><td></td><td></td></tr><tr><td>United States \( ^{1} \)</td><td>22,264</td><td>21,404</td><td></td></tr><tr><td>International</td><td>15,816</td><td>14,982</td><td></td></tr><tr><td>Total Downstream</td><td>38,080</td><td>36,386</td><td></td></tr><tr><td>Total Segment Assets</td><td>249,325</td><td>249,387</td><td></td></tr><tr><td>All Other</td><td></td><td></td><td></td></tr><tr><td>United States \( ^{1,2} \)</td><td>4,852</td><td>4,728</td><td></td></tr><tr><td>International</td><td>5,901</td><td>10,425</td><td></td></tr><tr><td>Total All Other</td><td>10,753</td><td>15,153</td><td></td></tr><tr><td>Total Assets - United States \( ^{1,2} \)</td><td>69,712</td><td>72,515</td><td></td></tr><tr><td>Total Assets - International \( ^{1} \)</td><td>185,785</td><td>187,437</td><td></td></tr><tr><td>Goodwill</td><td>4,581</td><td>4,588</td><td></td></tr><tr><td>Total Assets</td><td>$ 260,078</td><td>$ 264,540</td><td></td></tr></table>

 \( ^{1} $  2015 adjusted to conform to ASU 2015-17. Refer to Note 19, “Income Taxes” beginning on page 57.

 \( ^{2} $  2015 adjusted to conform to ASU 2015-03. Refer to Note 5, “New Accounting Standards” on page 42.

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2016, 2015 and 2014, 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.



<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Upstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 3,148</td><td>$ 4,117</td><td>$ 7,455</td></tr><tr><td>Intersegment</td><td>7,217</td><td>8,631</td><td>15,455</td></tr><tr><td>Total United States</td><td>10,365</td><td>12,748</td><td>22,910</td></tr><tr><td>International</td><td>13,262</td><td>15,587</td><td>23,808</td></tr><tr><td>Intersegment</td><td>9,518</td><td>11,492</td><td>23,107</td></tr><tr><td>Total International</td><td>22,780</td><td>27,079</td><td>46,915</td></tr><tr><td>Total Upstream</td><td>33,145</td><td>39,827</td><td>69,825</td></tr><tr><td>Downstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>40,366</td><td>48,420</td><td>73,942</td></tr><tr><td>Excise and similar taxes</td><td>4,335</td><td>4,426</td><td>4,633</td></tr><tr><td>Intersegment</td><td>16</td><td>26</td><td>31</td></tr><tr><td>Total United States</td><td>44,717</td><td>52,872</td><td>78,606</td></tr><tr><td>International</td><td>46,388</td><td>54,296</td><td>86,848</td></tr><tr><td>Excise and similar taxes</td><td>2,570</td><td>2,933</td><td>3,553</td></tr><tr><td>Intersegment</td><td>1,068</td><td>1,528</td><td>8,839</td></tr><tr><td>Total International</td><td>50,026</td><td>58,757</td><td>99,240</td></tr><tr><td>Total Downstream</td><td>94,743</td><td>111,629</td><td>177,846</td></tr><tr><td>All Other</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>145</td><td>141</td><td>252</td></tr><tr><td>Intersegment</td><td>960</td><td>1,372</td><td>1,475</td></tr><tr><td>Total United States</td><td>1,105</td><td>1,513</td><td>1,727</td></tr><tr><td>International</td><td>1</td><td>5</td><td>3</td></tr><tr><td>Intersegment</td><td>36</td><td>37</td><td>28</td></tr><tr><td>Total International</td><td>37</td><td>42</td><td>31</td></tr><tr><td>Total All Other</td><td>1,142</td><td>1,555</td><td>1,758</td></tr><tr><td>Segment Sales and Other Operating Revenues</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>56,187</td><td>67,133</td><td>103,243</td></tr><tr><td>International</td><td>72,843</td><td>85,878</td><td>146,186</td></tr><tr><td>Total Segment Sales and Other Operating Revenues</td><td>129,030</td><td>153,011</td><td>249,429</td></tr><tr><td>Elimination of intersegment sales</td><td>(18,815)</td><td>(23,086)</td><td>(48,935)</td></tr><tr><td>Total Sales and Other Operating Revenues</td><td>$ 110,215</td><td>$ 129,925</td><td>$ 200,494</td></tr></table>

Segment Income Taxes Segment income tax expense for the years 2016, 2015 and 2014 is as follows:

<table><tr><td></td><td colspan="3">Year ended December 31</td></tr><tr><td></td><td colspan="2">2016</td><td>2015</td></tr><tr><td>Upstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ (1,172)</td><td>$ (2,041)</td><td>$ 2,043</td></tr><tr><td>International</td><td>166</td><td>1,214</td><td>9,217</td></tr><tr><td>Total Upstream</td><td>(1,006)</td><td>(827)</td><td>11,260</td></tr><tr><td>Downstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>503</td><td>1,320</td><td>1,302</td></tr><tr><td>International</td><td>484</td><td>1,313</td><td>467</td></tr><tr><td>Total Downstream</td><td>987</td><td>2,633</td><td>1,769</td></tr><tr><td>All Other</td><td>(1,710)</td><td>(1,674)</td><td>(1,137)</td></tr><tr><td>Total Income Tax Expense (Benefit)</td><td>$ (1,729)</td><td>$ 132</td><td>$ 11,892</td></tr></table>

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 16, on page 51. Information related to properties, plant and equipment by segment is contained in Note 17, on page 52.



## Note 16

## 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.”

<table><tr><td rowspan="2"></td><td colspan="4">Investments and Advances At December 31</td><td colspan="3">Equity in Earnings Year ended December 31</td></tr><tr><td colspan="2">2016</td><td colspan="2">2015</td><td>2016</td><td colspan="2">2015</td></tr><tr><td>Upstream</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Tengizchevroil</td><td>$ 11,414</td><td>$ 8,077</td><td>$ 1,380</td><td>$ 1,939</td><td>$ 4,392</td><td></td><td></td></tr><tr><td>Petropiar</td><td>977</td><td>679</td><td>326</td><td>180</td><td>26</td><td></td><td></td></tr><tr><td>Caspian Pipeline Consortium</td><td>1,245</td><td>1,342</td><td>145</td><td>162</td><td>191</td><td></td><td></td></tr><tr><td>Petroborocan</td><td>982</td><td>1,163</td><td>(133)</td><td>219</td><td>186</td><td></td><td></td></tr><tr><td>Angola LNG Limited</td><td>2,744</td><td>3,284</td><td>(282)</td><td>(417)</td><td>(311)</td><td></td><td></td></tr><tr><td>Other</td><td>1,791</td><td>2,158</td><td>(193)</td><td>135</td><td>229</td><td></td><td></td></tr><tr><td>Total Upstream</td><td>19,153</td><td>16,703</td><td>1,243</td><td>2,218</td><td>4,713</td><td></td><td></td></tr><tr><td>Downstream</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>GS Caltex Corporation</td><td>3,767</td><td>3,620</td><td>373</td><td>824</td><td>420</td><td></td><td></td></tr><tr><td>Chevron Phillips Chemical Company LLC</td><td>5,767</td><td>5,196</td><td>840</td><td>1,367</td><td>1,606</td><td></td><td></td></tr><tr><td>Caltex Australia Ltd.</td><td>—</td><td>—</td><td>—</td><td>92</td><td>183</td><td></td><td></td></tr><tr><td>Other</td><td>1,118</td><td>1,077</td><td>209</td><td>186</td><td>180</td><td></td><td></td></tr><tr><td>Total Downstream</td><td>10,652</td><td>9,893</td><td>1,422</td><td>2,469</td><td>2,389</td><td></td><td></td></tr><tr><td>All Other</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other</td><td>(16)</td><td>(18)</td><td>(4)</td><td>(3)</td><td>(4)</td><td></td><td></td></tr><tr><td>Total equity method</td><td>$ 29,789</td><td>$ 26,578</td><td>$ 2,661</td><td>$ 4,684</td><td>$ 7,098</td><td></td><td></td></tr><tr><td>Other at or below cost</td><td>461</td><td>532</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total investments and advances</td><td>$ 30,250</td><td>$ 27,110</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total United States</td><td>$ 7,258</td><td>$ 6,863</td><td>$ 802</td><td>$ 1,342</td><td>$ 1,623</td><td></td><td></td></tr><tr><td>Total International</td><td>$ 22,992</td><td>$ 20,247</td><td>$ 1,859</td><td>$ 3,342</td><td>$ 5,475</td><td></td><td></td></tr></table>

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, 2016, the company’s carrying value of its investment in TCO was about $140 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. In July 2016, the company made a $2,000 long-term loan to TCO to fund the development of the Future Growth and Wellhead Pressure Management Project. See Note 8, on page 44, for summarized financial information for 100 percent of TCO.

Petropiar Chevron has a 30 percent interest in Petropar, a joint stock company which operates the Hamaca heavy-oil production and upgrading project in Venezuela’s Orinoco Belt. At December 31, 2016, the company’s carrying value of its investment in Petropar was approximately $150 less than the amount of underlying equity in Petropar’s net assets. The difference represents the excess of Chevron’s underlying equity in Petropar’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 $1,245, which includes long-term loans of $921 at year-end 2016. 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.

Petroborocan Chevron has a 39.2 percent interest in Petroborocan, a joint stock company which operates the Boscan Field in Venezuela. At December 31, 2016, the company’s carrying value of its investment in Petroborocan was approximately $120 higher than the amount of underlying equity in Petroborocan’s net assets. The difference reflects the excess of the net book value of the assets contributed by Chevron over its underlying equity in Petroborocan’s net assets. The company also has an outstanding long-term loan to Petroborocan of $626 at year-end 2016.



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.

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.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $5,786, $4,850 and $10,404 with affiliated companies for 2016, 2015 and 2014, respectively. “Purchased crude oil and products” includes $3,468, $4,240 and $6,735 with affiliated companies for 2016, 2015 and 2014, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $676 and $399 due from affiliated companies at December 31, 2016 and 2015, respectively. “Accounts payable” includes $383 and $286 due to affiliated companies at December 31, 2016 and 2015, 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 $3,535, $410 and $874 at December 31, 2016, 2015 and 2014, respectively.

<table><tr><td rowspan="2">Year ended December 31</td><td colspan="6">Affiliates</td><td colspan="2">Chevron Share</td></tr><tr><td colspan="2">2016</td><td colspan="2">2015</td><td colspan="2">2014</td><td>2016</td><td>2015</td></tr><tr><td>Total revenues</td><td>$ 59,253</td><td>$ 71,389</td><td>$ 123,003</td><td></td><td>$ 27,787</td><td>$ 33,492</td><td>$ 58,937</td><td></td></tr><tr><td>Income before income tax expense</td><td>6,587</td><td>13,129</td><td>20,609</td><td></td><td>3,670</td><td>6,279</td><td>9,968</td><td></td></tr><tr><td>Net income attributable to affiliates</td><td>5,127</td><td>10,649</td><td>14,758</td><td></td><td>2,876</td><td>4,691</td><td>7,237</td><td></td></tr><tr><td>At December 31</td><td colspan="4"></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 33,406</td><td>$ 27,162</td><td>$ 35,662</td><td></td><td>$ 13,743</td><td>$ 10,657</td><td>$ 13,465</td><td></td></tr><tr><td>Noncurrent assets</td><td>75,258</td><td>71,650</td><td>70,817</td><td></td><td>28,854</td><td>26,607</td><td>26,053</td><td></td></tr><tr><td>Current liabilities</td><td>24,793</td><td>20,559</td><td>25,308</td><td></td><td>8,996</td><td>7,351</td><td>9,588</td><td></td></tr><tr><td>Noncurrent liabilities</td><td>22,671</td><td>18,560</td><td>17,983</td><td></td><td>4,255</td><td>3,909</td><td>4,211</td><td></td></tr><tr><td>Total affiliates’ net equity</td><td>$ 61,200</td><td>$ 59,693</td><td>$ 63,188</td><td></td><td>$ 29,346</td><td>$ 26,004</td><td>$ 25,719</td><td></td></tr></table>

## Note 17

Properties, Plant and Equipment \( ^{1} \) 

<table><tr><td rowspan="3"></td><td colspan="10">At December 31</td><td colspan="2">Year ended December 31</td></tr><tr><td colspan="4">Gross Investment at Cost</td><td colspan="4">Net Investment</td><td colspan="2">Additions at Cost²</td><td colspan="2">Depreciation Expense³</td></tr><tr><td>2016</td><td>2015</td><td>2014</td><td>2016</td><td>2015</td><td>2014</td><td>2016</td><td>2015</td><td></td><td>2014</td><td>2016</td><td>2015</td></tr><tr><td>Upstream</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 83,929</td><td>$ 93,848</td><td>$ 96,850</td><td>$ 39,710</td><td>$ 43,125</td><td>$ 45,864</td><td>$ 4,432</td><td>$ 6,586</td><td>$ 9,688</td><td>$ 6,576</td><td>$ 8,545</td><td>$ 5,127</td></tr><tr><td>International</td><td>214,557</td><td>208,395</td><td>192,637</td><td>125,502</td><td>127,459</td><td>118,926</td><td>12,084</td><td>19,993</td><td>24,920</td><td>11,247</td><td>10,803</td><td>9,688</td></tr><tr><td>Total Upstream</td><td>298,486</td><td>302,243</td><td>289,487</td><td>165,212</td><td>170,584</td><td>164,790</td><td>16,516</td><td>26,579</td><td>34,608</td><td>17,823</td><td>19,348</td><td>14,815</td></tr><tr><td>Downstream</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>22,795</td><td>23,202</td><td>22,640</td><td>10,196</td><td>10,807</td><td>11,019</td><td>528</td><td>696</td><td>588</td><td>956</td><td>878</td><td>886</td></tr><tr><td>International</td><td>9,350</td><td>9,177</td><td>9,334</td><td>4,094</td><td>4,090</td><td>4,219</td><td>375</td><td>365</td><td>530</td><td>332</td><td>355</td><td>396</td></tr><tr><td>Total Downstream</td><td>32,145</td><td>32,379</td><td>31,974</td><td>14,290</td><td>14,897</td><td>15,238</td><td>903</td><td>1,061</td><td>1,118</td><td>1,288</td><td>1,233</td><td>1,282</td></tr><tr><td>All Other</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>5,263</td><td>5,500</td><td>5,673</td><td>2,635</td><td>2,859</td><td>3,077</td><td>198</td><td>357</td><td>581</td><td>328</td><td>439</td><td>680</td></tr><tr><td>International</td><td>183</td><td>155</td><td>155</td><td>49</td><td>56</td><td>68</td><td>6</td><td>5</td><td>25</td><td>18</td><td>17</td><td>16</td></tr><tr><td>Total All Other</td><td>5,446</td><td>5,655</td><td>5,828</td><td>2,684</td><td>2,915</td><td>3,145</td><td>204</td><td>362</td><td>606</td><td>346</td><td>456</td><td>696</td></tr><tr><td>Total United States</td><td>111,987</td><td>122,550</td><td>125,163</td><td>52,541</td><td>56,791</td><td>59,960</td><td>5,158</td><td>7,639</td><td>10,857</td><td>7,860</td><td>9,862</td><td>6,693</td></tr><tr><td>Total International</td><td>224,090</td><td>217,727</td><td>202,126</td><td>129,645</td><td>131,605</td><td>123,213</td><td>12,465</td><td>20,363</td><td>25,475</td><td>11,597</td><td>11,175</td><td>10,100</td></tr><tr><td>Total</td><td>$ 336,077</td><td>$ 340,277</td><td>$ 327,289</td><td>$ 182,186</td><td>$ 188,396</td><td>$ 183,173</td><td>$ 17,623</td><td>$ 28,002</td><td>$ 36,332</td><td>$ 19,457</td><td>$ 21,037</td><td>$ 16,793</td></tr></table>

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 2016. Australia had PP&E of $53,962, $49,205 and $41,012 in 2016, 2015, and 2014, respectively. Nigeria had PP&E of $17,922, $18,773 and $19,214 for 2016, 2015 and 2014, respectively.

 \( ^{2} \)  Net of dry hole expense related to prior years’ expenditures of $175, $1,573 and $371 in 2016, 2015 and 2014, respectively.

 \( ^{3} \)  Depreciation expense includes accretion expense of $749, $715 and $882 in 2016, 2015 and 2014, respectively, and impairments of $3,186, $4,066 and $1,274 in 2016, 2015 and 2014, respectively.



## Note 18

## 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 six 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.



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 28, 2015, the Court of Appeals denied the Government of Ecuador’s request for full appellate court review of the Federal District Court’s decision. On June 6, 2016, the United States Supreme Court denied the Government of Ecuador’s petition for Writ of Certiorari. On July 22, 2016, the Government of Ecuador paid the $96 award, plus interest, resulting in a payment to Chevron of approximately $113.

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 January 20, 2017, the Ontario Superior Court of Justice granted Chevron Canada Limited’s and Chevron Corporation’s motions for summary judgment, concluding that the two companies are separate legal entities with separate rights.



and obligations. As a result, the Superior Court dismissed the recognition and enforcement claim against Chevron Canada Limited. Chevron Corporation still remains as a defendant in the action. On February 3, 2017, the Lago Agrio plaintiffs appealed the Superior Court’s January 20, 2017 decision.

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 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. On April 19, 2016, the public prosecutor in Argentina issued a non-binding opinion recommending to the National Court, First Instance, of Argentina that it reject the Lago Agrio plaintiffs’ request to recognize the Ecuadorian judgment in Argentina.

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.

Company’s Bilateral Investment Treaty Arbitration Claims Chevron and Texpet filed an arbitration claim in 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. On April 13, 2016, the Republic of Ecuador appealed the decision.



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 Phase One, including whether the Republic of Ecuador breached the 1995 settlement agreement and the remedies 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. On August 8, 2016, the Second Circuit issued a unanimous opinion affirming in full the judgment of the Federal District Court in favor of Chevron. On October 27, 2016, the Second Circuit denied the defendants’ petitions for en banc rehearing of the opinion on their appeal.

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 19
Taxes

<table><tr><td rowspan="2">Income Taxes</td><td colspan="3">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Income tax expense (benefit)</td><td></td><td></td><td></td></tr><tr><td>U.S. federal</td><td></td><td></td><td></td></tr><tr><td>Current</td><td>$ (623)</td><td>$ (817)</td><td>$ 748</td></tr><tr><td>Deferred</td><td>(1,558)</td><td>(580)</td><td>1,330</td></tr><tr><td>State and local</td><td></td><td></td><td></td></tr><tr><td>Current</td><td>(15)</td><td>(187)</td><td>336</td></tr><tr><td>Deferred</td><td>(121)</td><td>(109)</td><td>36</td></tr><tr><td>Total United States</td><td>(2,317)</td><td>(1,693)</td><td>2,450</td></tr><tr><td>International</td><td></td><td></td><td></td></tr><tr><td>Current</td><td>2,744</td><td>2,997</td><td>9,235</td></tr><tr><td>Deferred</td><td>(2,156)</td><td>(1,172)</td><td>207</td></tr><tr><td>Total International</td><td>588</td><td>1,825</td><td>9,442</td></tr><tr><td>Total income tax expense (benefit)</td><td>$ (1,729)</td><td>$ 132</td><td>$ 11,892</td></tr></table>

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:

<table><tr><td></td><td>2016</td><td colspan="2">20151</td><td>20141</td></tr><tr><td>Income (loss) before income taxes</td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ (4,317)</td><td>$ (2,877)</td><td>$ 6,296</td><td></td></tr><tr><td>International</td><td>2,157</td><td>7,719</td><td>24,906</td><td></td></tr><tr><td>Total income (loss) before income taxes</td><td>(2,160)</td><td>4,842</td><td>31,202</td><td></td></tr><tr><td>Theoretical tax (at U.S. statutory rate of 35%)</td><td>(756)</td><td>1,695</td><td>10,921</td><td></td></tr><tr><td>Equity affiliate accounting effect</td><td>(704)</td><td>(1,286)</td><td>(2,039)</td><td></td></tr><tr><td>Effect of income taxes from international operations</td><td>608</td><td>72</td><td>2,708</td><td></td></tr><tr><td>State and local taxes on income, net of U.S. federal income tax benefit</td><td>(44)</td><td>(74)</td><td>234</td><td></td></tr><tr><td>Prior year tax adjustments, claims and settlements</td><td>(349)</td><td>84</td><td>(76)</td><td></td></tr><tr><td>Tax credits</td><td>(188)</td><td>(35)</td><td>(68)</td><td></td></tr><tr><td>Other2</td><td>(296)</td><td>(324)</td><td>212</td><td></td></tr><tr><td>Total income tax expense (benefit)</td><td>$ (1,729)</td><td>$ 132</td><td>$ 11,892</td><td></td></tr><tr><td>Effective income tax rate</td><td>80.0%</td><td>2.7%</td><td>38.1%</td><td></td></tr></table>

 \( ^{1} $  2014 and 2015 conformed to 2016 presentation.

 \( ^{2} \)  Includes one-time tax benefits associated with changes in uncertain tax positions and valuation allowances.

The 2016 decline in income tax expense of $1,861, from an expense of $132 in 2015 to a benefit of $1,729 in 2016, is a result of the year-over-year reduction in total income before income tax expense, which is primarily due to effects of lower crude oil prices. The company’s effective tax rate changed from 2.7 percent in 2015 to 80 percent in 2016. The change in effective tax rate is primarily a consequence of the mix effect resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions.



The company records its deferred taxes on a tax-jurisdiction basis. The reported deferred tax balances are composed of the following:

<table><tr><td></td><td colspan="3">At December 31</td></tr><tr><td></td><td>2016</td><td>2015</td><td></td></tr><tr><td>Deferred tax liabilities</td><td></td><td></td><td></td></tr><tr><td>Properties, plant and equipment</td><td>$ 25,180</td><td>$ 27,044</td><td></td></tr><tr><td>Investments and other</td><td>5,222</td><td>3,743</td><td></td></tr><tr><td>Total deferred tax liabilities</td><td>30,402</td><td>30,787</td><td></td></tr><tr><td>Deferred tax assets</td><td></td><td></td><td></td></tr><tr><td>Foreign tax credits</td><td>(10,976)</td><td>(10,534)</td><td></td></tr><tr><td>Abandonment/environmental reserves</td><td>(6,251)</td><td>(6,880)</td><td></td></tr><tr><td>Employee benefits</td><td>(4,392)</td><td>(4,801)</td><td></td></tr><tr><td>Deferred credits</td><td>(1,950)</td><td>(1,810)</td><td></td></tr><tr><td>Tax loss carryforwards</td><td>(6,030)</td><td>(2,748)</td><td></td></tr><tr><td>Other accrued liabilities</td><td>(510)</td><td>(525)</td><td></td></tr><tr><td>Inventory</td><td>(374)</td><td>(120)</td><td></td></tr><tr><td>Miscellaneous</td><td>(3,121)</td><td>(2,525)</td><td></td></tr><tr><td>Total deferred tax assets</td><td>(33,604)</td><td>(29,943)</td><td></td></tr><tr><td>Deferred tax assets valuation allowance</td><td>16,069</td><td>15,412</td><td></td></tr><tr><td>Total deferred taxes, net</td><td>$ 12,867</td><td>$ 16,256</td><td></td></tr></table>

Deferred tax liabilities at the end of 2016 were essentially unchanged from year-end 2015. Deferred tax assets increased by approximately $3,700 in 2016. The increase primarily related to increased 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 2016, the company had tax loss carryforwards of approximately $16,538 and tax credit carryforwards of approximately $1,423, 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 2017 through 2036. U.S. foreign tax credit carryforwards of $10,976 will expire between 2017 and 2026.

At December 31, 2016 and 2015, deferred taxes were classified on the Consolidated Balance Sheet as follows:

<table><tr><td rowspan="2"></td><td colspan="3">At December 31</td></tr><tr><td>2016</td><td>2015</td><td></td></tr><tr><td>Deferred charges and other assets</td><td>$ (4,649)</td><td>$ (3,909)</td><td></td></tr><tr><td>Noncurrent deferred income taxes</td><td>17,516</td><td>20,165</td><td></td></tr><tr><td>Total deferred income taxes, net</td><td>$ 12,867</td><td>$ 16,256</td><td></td></tr></table>

Effective January 1, 2016, Chevron early-adopted Income Taxes (Topic 740), Balance Sheet Classification of Deferred Taxes (ASU 2015-17), on a retrospective basis. The standard provides that all deferred income taxes be classified as noncurrent on the Consolidated Balance Sheet. The prior requirement was to classify most deferred tax assets and liabilities based on the classification of the underlying asset or liability. The December 31, 2015, Consolidated Balance Sheet has been restated and the effects are reductions of $917 in “Prepaid expenses and other current assets,” $603 in “Deferred charges and other assets,” $996 in “Federal and other taxes on income,” and $524 in “Noncurrent deferred income taxes.”

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 $46,400 at December 31, 2016. 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 2016, 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, 2016, 2015 and 2014. 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.

<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Balance at January 1</td><td>$ 3,042</td><td>$ 3,552</td><td>$ 3,848</td></tr><tr><td>Foreign currency effects</td><td>1</td><td>(27)</td><td>(25)</td></tr><tr><td>Additions based on tax positions taken in current year</td><td>245</td><td>154</td><td>354</td></tr><tr><td>Additions/reductions resulting from current-year asset acquisitions/sales</td><td>—</td><td>—</td><td>(22)</td></tr><tr><td>Additions for tax positions taken in prior years</td><td>181</td><td>218</td><td>37</td></tr><tr><td>Reductions for tax positions taken in prior years</td><td>(390)</td><td>(678)</td><td>(561)</td></tr><tr><td>Settlements with taxing authorities in current year</td><td>(36)</td><td>(5)</td><td>(50)</td></tr><tr><td>Reductions as a result of a lapse of the applicable statute of limitations</td><td>(12)</td><td>(172)</td><td>(29)</td></tr><tr><td>Balance at December 31</td><td>$ 3,031</td><td>$ 3,042</td><td>$ 3,552</td></tr></table>

Approximately 74 percent of the $3,031 of unrecognized tax benefits at December 31, 2016, 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, 2016. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – 2011, Nigeria – 2000, Angola – 2009 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.

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, 2016, accruals of $424 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $399 as of year-end 2015. Income tax expense associated with interest and penalties was $38, $195 and $4 in 2016, 2015 and 2014, respectively.

## Taxes Other Than on Income

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>United States</td><td></td><td></td><td></td></tr><tr><td>Excise and similar taxes on products and merchandise</td><td>$ 4,335</td><td>$ 4,426</td><td>$ 4,633</td></tr><tr><td>Import duties and other levies</td><td>9</td><td>4</td><td>6</td></tr><tr><td>Property and other miscellaneous taxes</td><td>1,680</td><td>1,367</td><td>1,002</td></tr><tr><td>Payroll taxes</td><td>252</td><td>270</td><td>273</td></tr><tr><td>Taxes on production</td><td>159</td><td>157</td><td>349</td></tr><tr><td>Total United States</td><td>6,435</td><td>6,224</td><td>6,263</td></tr><tr><td>International</td><td></td><td></td><td></td></tr><tr><td>Excise and similar taxes on products and merchandise</td><td>2,570</td><td>2,933</td><td>3,553</td></tr><tr><td>Import duties and other levies</td><td>33</td><td>40</td><td>45</td></tr><tr><td>Property and other miscellaneous taxes</td><td>2,379</td><td>2,548</td><td>2,277</td></tr><tr><td>Payroll taxes</td><td>145</td><td>161</td><td>172</td></tr><tr><td>Taxes on production</td><td>106</td><td>124</td><td>230</td></tr><tr><td>Total International</td><td>5,233</td><td>5,806</td><td>6,277</td></tr><tr><td>Total taxes other than on income</td><td>$ 11,668</td><td>$ 12,030</td><td>$ 12,540</td></tr></table>



## Note 20
Short-Term Debt

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2016</td><td>2015</td></tr><tr><td>Commercial paper \( ^{1} \)</td><td>10,410</td><td>8,252</td></tr><tr><td>Notes payable to banks and others with originating terms of one year or less</td><td>50</td><td>20</td></tr><tr><td>Current maturities of long-term debt \( ^{2} \)</td><td>6,253</td><td>1,486</td></tr><tr><td>Current maturities of long-term capital leases</td><td>14</td><td>17</td></tr><tr><td>Redeemable long-term obligations</td><td></td><td></td></tr><tr><td>Long-term debt</td><td>3,113</td><td>3,152</td></tr><tr><td>Capital leases</td><td>—</td><td>—</td></tr><tr><td>Subtotal</td><td>19,840</td><td>12,927</td></tr><tr><td>Reclassified to long-term debt</td><td>(9,000)</td><td>(8,000)</td></tr><tr><td>Total short-term debt</td><td>10,840</td><td>4,927</td></tr></table>

1 Weighted-average interest rates at December 31, 2016 and 2015, were 0.74 percent and 0.26 percent, respectively.

 \( ^{2} $  2015 adjusted to conform to ASU 2015-03. Refer to Note 5, “New Accounting Standards” on page 42.

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, 2016, the company had no interest rate swaps on short-term debt.

At December 31, 2016, the company had $9,000 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 $6,900 or the company can convert any amounts outstanding into a term loan for a period of up to one year, and a $2,100 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, 2016.

The company classified $9,000 and $8,000 of short-term debt as long-term at December 31, 2016 and 2015, respectively. 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.



## Note 21

## Long-Term Debt

Total long-term debt, excluding capital leases, at December 31, 2016, was $35,193. The company’s long-term debt outstanding at year-end 2016 and 2015 was as follows:

<table><tr><td rowspan="3"></td><td colspan="4">At December 31</td></tr><tr><td colspan="3">2016</td><td>2015</td></tr><tr><td>Principal</td><td>Unamortized discounts and debt issuance costs</td><td>Principal</td><td>Unamortized discounts and debt issuance costs</td></tr><tr><td>3.191% notes due 2023</td><td>$ 2,250</td><td>$ 4</td><td>$ 2,250</td><td>$ 4</td></tr><tr><td>2.954% notes due 2026</td><td>2,250</td><td>6</td><td>—</td><td>—</td></tr><tr><td>Floating rate notes due 2017 (1.091%)¹</td><td>2,050</td><td>1</td><td>2,050</td><td>2</td></tr><tr><td>1.104% notes due 2017</td><td>2,000</td><td>1</td><td>2,000</td><td>2</td></tr><tr><td>1.718% notes due 2018</td><td>2,000</td><td>1</td><td>2,000</td><td>2</td></tr><tr><td>2.355% notes due 2022</td><td>2,000</td><td>5</td><td>2,000</td><td>5</td></tr><tr><td>1.365% notes due 2018</td><td>1,750</td><td>1</td><td>1,750</td><td>2</td></tr><tr><td>1.961% notes due 2020</td><td>1,750</td><td>2</td><td>1,750</td><td>2</td></tr><tr><td>Floating rate notes due 2018 (1.310%)¹</td><td>1,650</td><td>2</td><td>800</td><td>1</td></tr><tr><td>4.95% notes due 2019</td><td>1,500</td><td>2</td><td>1,500</td><td>2</td></tr><tr><td>1.561% notes due 2019</td><td>1,350</td><td>2</td><td>—</td><td>—</td></tr><tr><td>2.100% notes due 2021</td><td>1,350</td><td>2</td><td>—</td><td>—</td></tr><tr><td>1.790% notes due 2018</td><td>1,250</td><td>1</td><td>1,250</td><td>2</td></tr><tr><td>2.419% notes due 2020</td><td>1,250</td><td>2</td><td>1,250</td><td>2</td></tr><tr><td>1.345% notes due 2017</td><td>1,100</td><td>—</td><td>1,100</td><td>2</td></tr><tr><td>1.344% notes due 2017</td><td>1,000</td><td>1</td><td>1,000</td><td>1</td></tr><tr><td>2.427% notes due 2020</td><td>1,000</td><td>1</td><td>1,000</td><td>2</td></tr><tr><td>2.193% notes due 2019</td><td>750</td><td>1</td><td>750</td><td>1</td></tr><tr><td>2.566% notes due 2023</td><td>750</td><td>1</td><td>—</td><td>—</td></tr><tr><td>3.326% notes due 2025</td><td>750</td><td>2</td><td>750</td><td>2</td></tr><tr><td>2.411% notes due 2022</td><td>700</td><td>1</td><td>700</td><td>1</td></tr><tr><td>Floating rate notes due 2021 (1.599%)¹</td><td>650</td><td>1</td><td>400</td><td>1</td></tr><tr><td>Floating rate notes due 2019 (1.316%)²</td><td>400</td><td>1</td><td>400</td><td>2</td></tr><tr><td>Floating rate notes due 2022 (1.472%)²</td><td>350</td><td>—</td><td>350</td><td>1</td></tr><tr><td>Amortizing bank loan due 2018 (1.527%)¹</td><td>178</td><td>—</td><td>110</td><td>—</td></tr><tr><td>8.625% debentures due 2032</td><td>147</td><td>1</td><td>147</td><td>1</td></tr><tr><td>8.625% debentures due 2031</td><td>108</td><td>1</td><td>108</td><td>1</td></tr><tr><td>8% debentures due 2032</td><td>75</td><td>1</td><td>74</td><td>1</td></tr><tr><td>9.75% debentures due 2020</td><td>54</td><td>—</td><td>54</td><td>—</td></tr><tr><td>8.875% debentures due 2021</td><td>40</td><td>—</td><td>40</td><td>—</td></tr><tr><td>Medium-term notes, maturing from 2021 to 2038 (6.133%)¹</td><td>38</td><td>—</td><td>38</td><td>—</td></tr><tr><td>0.889% notes due 2016</td><td>—</td><td>—</td><td>750</td><td>—</td></tr><tr><td>Floating rate notes due 2016</td><td>—</td><td>—</td><td>700</td><td>1</td></tr><tr><td>Total including debt due within one year</td><td>32,490</td><td>44</td><td>27,071</td><td>43</td></tr><tr><td>Debt due within one year</td><td>(6,256)</td><td>(3)</td><td>(1,487)</td><td>(1)</td></tr><tr><td>Reclassified from short-term debt</td><td>9,000</td><td></td><td>8,000</td><td></td></tr><tr><td>Total long-term debt</td><td>$ 35,234</td><td>$ 41</td><td>$ 33,584</td><td>$ 42</td></tr></table>

1 Weighted-average interest rate at December 31, 2016.

 \( ^{2} \)  Interest rate at December 31, 2016.

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 with a principal balance of $32,490 matures as follows: 2017 – $6,256; 2018 – $6,722; 2019 – $4,000; 2020 – $4,054; 2021 – $2,054; and after 2021 – $9,404.

The company completed a bond issuance of $6,800 in May 2016.



Effective January 1, 2016, Chevron adopted ASU 2015-03 on a retrospective basis. The standard requires that debt issuance costs related to a recognized liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. On the Consolidated Balance Sheet, long-term debt net of unamortized discounts and debt issuance costs was $35,193 at December 31, 2016, and $33,542 at December 31, 2015.

See Note 10, beginning on page 45, for information concerning the fair value of the company’s long-term debt.

## Note 22

## 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.

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2016:

<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Beginning balance at January 1</td><td>$ 3,312</td><td>$ 4,195</td><td>$ 3,245</td></tr><tr><td>Additions to capitalized exploratory well costs pending the determination of proved reserves</td><td>465</td><td>869</td><td>1,591</td></tr><tr><td>Reclassifications to wells, facilities and equipment based on the determination of proved reserves</td><td>(119)</td><td>(164)</td><td>(298)</td></tr><tr><td>Capitalized exploratory well costs charged to expense</td><td>(118)</td><td>(1,397)</td><td>(312)</td></tr><tr><td>Other reductions \( ^{*} \)</td><td>—</td><td>(191)</td><td>(31)</td></tr><tr><td>Ending balance at December 31</td><td>$ 3,540</td><td>$ 3,312</td><td>$ 4,195</td></tr></table>

 \( ^{*} \)  Represents property sales.

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.

<table><tr><td rowspan="2"></td><td colspan="3">At December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Exploratory well costs capitalized for a period of one year or less</td><td>$ 445</td><td>$ 489</td><td>$ 1,522</td></tr><tr><td>Exploratory well costs capitalized for a period greater than one year</td><td>3,095</td><td>2,823</td><td>2,673</td></tr><tr><td>Balance at December 31</td><td>$ 3,540</td><td>$ 3,312</td><td>$ 4,195</td></tr><tr><td>Number of projects with exploratory well costs that have been capitalized for a period greater than one year \( ^{*} \)</td><td>35</td><td>39</td><td>51</td></tr></table>

 \( ^{*} \)  Certain projects have multiple wells or fields or both.

Of the $3,095 of exploratory well costs capitalized for more than one year at December 31, 2016, $1,939 (15 projects) is related to projects that had drilling activities underway or firmly planned for the near future. The $1,156 balance is related to 20 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway 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 $1,156 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) $107 (two projects) – development concept under review by government; (c) $816 (seven projects) – development alternatives under review; (d) $43 (nine projects) – miscellaneous activities for projects with smaller amounts suspended. While progress was being made on all 35 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. More than half of these decisions are expected to occur in the next five years.



The $3,095 of suspended well costs capitalized for a period greater than one year as of December 31, 2016, represents 160 exploratory wells in 35 projects. The tables below contain the aging of these costs on a well and project basis:

<table><tr><td colspan="2">Aging based on drilling completion date of individual wells:</td><td>Amount</td><td>Number of wells</td></tr><tr><td>1998-2005</td><td></td><td>311</td><td>29</td></tr><tr><td>2006-2010</td><td></td><td>684</td><td>40</td></tr><tr><td>2011-2015</td><td></td><td>2,100</td><td>91</td></tr><tr><td>Total</td><td></td><td>3,095</td><td>160</td></tr><tr><td colspan="2">Aging based on drilling completion date of last suspended well in project:</td><td>Amount</td><td>Number of projects</td></tr><tr><td>2003-2008</td><td></td><td>212</td><td>4</td></tr><tr><td>2009-2012</td><td></td><td>437</td><td>8</td></tr><tr><td>2013-2016</td><td></td><td>2,446</td><td>23</td></tr><tr><td>Total</td><td></td><td>3,095</td><td>35</td></tr></table>

## Note 23

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2016, 2015 and 2014 was $271 ($176 after tax), $312 ($203 after tax) and $287 ($186 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $371 ($241 after tax), $32 ($21 after tax) and $71 ($46 after tax) for 2016, 2015 and 2014, respectively. No significant stock-based compensation cost was capitalized at December 31, 2016, or December 31, 2015.

Cash received in payment for option exercises under all share-based payment arrangements for 2016, 2015 and 2014 was $647, $195 and $527, respectively. Actual tax benefits realized for the tax deductions from option exercises were $21, $17 and $54 for 2016, 2015 and 2014, respectively.

Cash paid to settle performance shares and stock appreciation rights was $82, $104 and $204 for 2016, 2015 and 2014, 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 shares 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, 2016, the contractual terms vary between three years for the performance shares and restricted stock units, and 10 years for the stock options and stock appreciation rights. For awards that will be issued in 2017, contractual terms vary between three years for the performance shares and special restricted stock units, 5 years for standard restricted stock units and 10 years for the stock options and stock appreciation rights. Forfeitures for performance shares, restricted stock units, and stock appreciation rights are recognized as they occur. Forfeitures for stock options are estimated using historical forfeiture data dating back to 1990.

The fair market values of stock options and stock appreciation rights granted in 2016, 2015 and 2014 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Expected term in years \( ^{1} \)</td><td>6.3</td><td>6.1</td><td>6.0</td></tr><tr><td>Volatility \( ^{2} \)</td><td>21.7 %</td><td>21.9 %</td><td>30.3 %</td></tr><tr><td>Risk-free interest rate based on zero coupon U.S. treasury note</td><td>1.6 %</td><td>1.4 %</td><td>1.9 %</td></tr><tr><td>Dividend yield</td><td>4.5 %</td><td>3.6 %</td><td>3.3 %</td></tr><tr><td>Weighted-average fair value per option granted</td><td>9.53</td><td>13.89</td><td>25.86</td></tr></table>

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 2016 is presented below:

<table><tr><td></td><td>Shares (Thousands)</td><td>Weighted-Average Exercise Price</td><td>Averaged Remaining Contractual Term (Years)</td><td>Aggregate Intrinsic Value</td></tr><tr><td>Outstanding at January 1, 2016</td><td>94,292</td><td>96.67</td><td></td><td></td></tr><tr><td>Granted</td><td>30,913</td><td>83.31</td><td></td><td></td></tr><tr><td>Exercised</td><td>(8,589)</td><td>75.57</td><td></td><td></td></tr><tr><td>Forfeited</td><td>(4,341)</td><td>86.81</td><td></td><td></td></tr><tr><td>Outstanding at December 31, 2016</td><td>112,275</td><td>94.99</td><td>6.13</td><td>2,550</td></tr><tr><td>Exercisable at December 31, 2016</td><td>71,153</td><td>97.32</td><td>4.66</td><td>1,450</td></tr></table>



The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2016, 2015 and 2014 was $240, $120 and $398, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

As of December 31, 2016, there was $169 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, 2016, the number of LTIP performance units outstanding was equivalent to 2,192,937 shares. During 2016, 1,019,900 units were granted, 718,472 units vested with cash proceeds distributed to recipients and 100,937 units were forfeited. At December 31, 2016, units outstanding were 2,393,428. The fair value of the liability recorded for these instruments was $381, 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 5.4 million equivalent shares as of December 31, 2016. A liability of $125 was recorded for these awards.

## Note 24

## 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 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. Beginning in 2017, medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is provided through a third-party private exchange. The increase to the pre-Medicare 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 2016 and 2015 follows:

<table><tr><td rowspan="3"></td><td colspan="6">Pension Benefits</td></tr><tr><td colspan="3">2016</td><td colspan="2">2015</td><td rowspan="2">Other Benefits</td></tr><tr><td>U.S.</td><td>Int’l.</td><td>U.S.</td><td>Int’l.</td><td>2016</td></tr><tr><td>Change in Benefit Obligation</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Benefit obligation at January 1</td><td>$ 13,563</td><td>$ 5,336</td><td>$ 14,250</td><td>$ 5,767</td><td>$ 3,324</td><td>$ 3,660</td></tr><tr><td>Service cost</td><td>494</td><td>159</td><td>538</td><td>185</td><td>60</td><td>72</td></tr><tr><td>Interest cost</td><td>377</td><td>261</td><td>502</td><td>277</td><td>128</td><td>151</td></tr><tr><td>Plan participants’ contributions</td><td>—</td><td>5</td><td>—</td><td>6</td><td>148</td><td>148</td></tr><tr><td>Plan amendments</td><td>—</td><td>—</td><td>—</td><td>(6)</td><td>(345)</td><td>—</td></tr><tr><td>Actuarial (gain) loss</td><td>903</td><td>426</td><td>(345)</td><td>(309)</td><td>(437)</td><td>(326)</td></tr><tr><td>Foreign currency exchange rate changes</td><td>—</td><td>(524)</td><td>—</td><td>(326)</td><td>8</td><td>(37)</td></tr><tr><td>Benefits paid</td><td>(2,066)</td><td>(494)</td><td>(1,382)</td><td>(241)</td><td>(337)</td><td>(344)</td></tr><tr><td>Curtailment</td><td>—</td><td>—</td><td>—</td><td>(17)</td><td>—</td><td>—</td></tr><tr><td>Benefit obligation at December 31</td><td>13,271</td><td>5,169</td><td>13,563</td><td>5,336</td><td>2,549</td><td>3,324</td></tr><tr><td>Change in Plan Assets</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of plan assets at January 1</td><td>10,274</td><td>4,109</td><td>11,090</td><td>4,244</td><td>—</td><td>—</td></tr><tr><td>Actual return on plan assets</td><td>936</td><td>642</td><td>(75)</td><td>112</td><td>—</td><td>—</td></tr><tr><td>Foreign currency exchange rate changes</td><td>—</td><td>(552)</td><td>—</td><td>(239)</td><td>—</td><td>—</td></tr><tr><td>Employer contributions</td><td>406</td><td>464</td><td>641</td><td>227</td><td>189</td><td>196</td></tr><tr><td>Plan participants’ contributions</td><td>—</td><td>5</td><td>—</td><td>6</td><td>148</td><td>148</td></tr><tr><td>Benefits paid</td><td>(2,066)</td><td>(494)</td><td>(1,382)</td><td>(241)</td><td>(337)</td><td>(344)</td></tr><tr><td>Fair value of plan assets at December 31</td><td>9,550</td><td>4,174</td><td>10,274</td><td>4,109</td><td>—</td><td>—</td></tr><tr><td>Funded status at December 31</td><td>(3,721)</td><td>(995)</td><td>(3,289)</td><td>(1,227)</td><td>(2,549)</td><td>(3,324)</td></tr></table>



Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2016 and 2015, include:

<table><tr><td rowspan="3"></td><td colspan="6">Pension Benefits</td></tr><tr><td colspan="3">2016</td><td colspan="2">2015</td><td>Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td></td><td>2016</td></tr><tr><td>Deferred charges and other assets</td><td>$ 16</td><td>$ 199</td><td>$ 13</td><td>$ 333</td><td>$ —</td><td>$ —</td></tr><tr><td>Accrued liabilities</td><td>(222)</td><td>(75)</td><td>(153)</td><td>(77)</td><td>(163)</td><td>(191)</td></tr><tr><td>Noncurrent employee benefit plans</td><td>(3,515)</td><td>(1,119)</td><td>(3,149)</td><td>(1,483)</td><td>(2,386)</td><td>(3,133)</td></tr><tr><td>Net amount recognized at December 31</td><td>$ (3,721)</td><td>$ (995)</td><td>$ (3,289)</td><td>$ (1,227)</td><td>$ (2,549)</td><td>$ (3,324)</td></tr></table>

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $5,511 and $6,478 at the end of 2016 and 2015, respectively. These amounts consisted of:

<table><tr><td rowspan="3"></td><td colspan="6">Pension Benefits</td></tr><tr><td colspan="3">2016</td><td colspan="2">2015</td><td>Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td></td><td>2016</td></tr><tr><td>Net actuarial loss</td><td>$ 4,653</td><td>$ 1,145</td><td>$ 4,809</td><td>$ 1,143</td><td>$ (82)</td><td>$ 367</td></tr><tr><td>Prior service (credit) costs</td><td>4</td><td>106</td><td>(5)</td><td>120</td><td>(315)</td><td>44</td></tr><tr><td>Total recognized at December 31</td><td>$ 4,657</td><td>$ 1,251</td><td>$ 4,804</td><td>$ 1,263</td><td>$ (397)</td><td>$ 411</td></tr></table>

The accumulated benefit obligations for all U.S. and international pension plans were $11,954 and $4,676, respectively, at December 31, 2016, and $12,032 and $4,684, respectively, at December 31, 2015.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2016 and 2015, was:

<table><tr><td rowspan="3"></td><td colspan="6">Pension Benefits</td></tr><tr><td colspan="3">2016</td><td colspan="2">2015</td><td></td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td></td><td>Int&#x27;l.</td></tr><tr><td>Projected benefit obligations</td><td>$ 13,208</td><td>$ 1,449</td><td>$ 13,500</td><td>$ 1,623</td><td></td><td></td></tr><tr><td>Accumulated benefit obligations</td><td>11,891</td><td>1,258</td><td>11,969</td><td>1,357</td><td></td><td></td></tr><tr><td>Fair value of plan assets</td><td>9,471</td><td>287</td><td>10,198</td><td>207</td><td></td><td></td></tr></table>

The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2016, 2015 and 2014 are shown in the table below:

<table><tr><td rowspan="3"></td><td colspan="6">Pension Benefits</td></tr><tr><td colspan="3">2016</td><td colspan="2">2015</td><td>Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>2014</td></tr><tr><td>Net Periodic Benefit Cost</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 494</td><td>$ 159</td><td>$ 538</td><td>$ 185</td><td>$ 450</td><td>$ 190</td></tr><tr><td>Interest cost</td><td>377</td><td>261</td><td>502</td><td>277</td><td>494</td><td>340</td></tr><tr><td>Expected return on plan assets</td><td>(723)</td><td>(243)</td><td>(783)</td><td>(262)</td><td>(788)</td><td>(298)</td></tr><tr><td>Amortization of prior service costs (credits)</td><td>(9)</td><td>14</td><td>(8)</td><td>22</td><td>(9)</td><td>21</td></tr><tr><td>Recognized actuarial losses</td><td>335</td><td>47</td><td>356</td><td>78</td><td>209</td><td>96</td></tr><tr><td>Settlement losses</td><td>511</td><td>6</td><td>320</td><td>6</td><td>237</td><td>208</td></tr><tr><td>Curtailment losses (gains)</td><td>—</td><td>—</td><td>—</td><td>(14)</td><td>—</td><td>—</td></tr><tr><td>Total net periodic benefit cost</td><td>985</td><td>244</td><td>925</td><td>292</td><td>593</td><td>557</td></tr><tr><td>Changes Recognized in Comprehensive Income</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net actuarial (gain) loss during period</td><td>690</td><td>55</td><td>513</td><td>(260)</td><td>2,233</td><td>(17)</td></tr><tr><td>Amortization of actuarial loss</td><td>(846)</td><td>(53)</td><td>(676)</td><td>(84)</td><td>(446)</td><td>(304)</td></tr><tr><td>Prior service (credits) costs during period</td><td>—</td><td>—</td><td>—</td><td>(6)</td><td>—</td><td>4</td></tr><tr><td>Amortization of prior service (costs) credits</td><td>9</td><td>(14)</td><td>8</td><td>(24)</td><td>9</td><td>(21)</td></tr><tr><td>Total changes recognized in other comprehensive income</td><td>(147)</td><td>(12)</td><td>(155)</td><td>(374)</td><td>1,796</td><td>(338)</td></tr><tr><td>Recognized in Net Periodic Benefit Cost and Other Comprehensive Income</td><td>$ 838</td><td>$ 232</td><td>$ 770</td><td>$ (82)</td><td>$ 2,389</td><td>$ 219</td></tr></table>

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2016, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 10, 12 and 11 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 2017, the company estimates actuarial losses of $340, $41 and $5 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 $408 will be recognized from “Accumulated other comprehensive loss” during 2017 related to lump-sum settlement costs from the main U.S. pension plans.

The weighted average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, 2016, was approximately 4 and 10 years for U.S. and international pension plans, respectively, and 11 years for OPEB plans. During 2017, the company estimates prior service (credits) costs of 5, 12 and 28 respectively, will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively.

Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:

<table><tr><td rowspan="3"></td><td colspan="8">Pension Benefits</td></tr><tr><td colspan="3">2016</td><td colspan="2">2015</td><td colspan="2">2014</td><td colspan="2">Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>U.S.</td><td>Int&#x27;l.</td><td>2016</td><td>2015</td></tr><tr><td>Assumptions used to determine benefit obligations:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate</td><td>3.9%</td><td>4.3%</td><td>4.0%</td><td>5.3%</td><td>3.7%</td><td>5.0%</td><td>4.3%</td><td>4.6%</td><td>4.3%</td></tr><tr><td>Rate of compensation increase</td><td>4.5%</td><td>4.5%</td><td>4.5%</td><td>4.8%</td><td>4.5%</td><td>5.1%</td><td>N/A</td><td>N/A</td><td>N/A</td></tr><tr><td>Assumptions used to determine net periodic benefit cost:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate for service cost</td><td>4.4%</td><td>5.3%</td><td>3.7%</td><td>5.0%</td><td>4.3%</td><td>5.8%</td><td>4.9%</td><td>4.3%</td><td>4.9%</td></tr><tr><td>Discount rate for interest cost</td><td>3.0%</td><td>5.3%</td><td>3.7%</td><td>5.0%</td><td>4.3%</td><td>5.8%</td><td>4.0%</td><td>4.3%</td><td>4.9%</td></tr><tr><td>Expected return on plan assets</td><td>7.3%</td><td>6.3%</td><td>7.5%</td><td>6.3%</td><td>7.5%</td><td>6.6%</td><td>N/A</td><td>N/A</td><td>N/A</td></tr><tr><td>Rate of compensation increase</td><td>4.5%</td><td>4.8%</td><td>4.5%</td><td>5.1%</td><td>4.5%</td><td>5.5%</td><td>N/A</td><td>N/A</td><td>N/A</td></tr></table>

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 2016, the company used an expected long-term rate of return of 7.25 percent for U.S. pension plan assets, which account for 69 percent of the company’s pension plan assets. In both 2015 and 2014, 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. Beginning with the December 31, 2015 measurement date, 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 at the end of 2016 were 3.9 percent for the main U.S. pension plan and 4.1 percent for the main U.S. OPEB plan. The discount rates for these plans at the end of 2015 were 4.0 and 4.5 percent, respectively, while in 2014 they were 3.7 and 4.1 percent for these plans, respectively.

Beginning with the fiscal year ended December 31, 2016, the company changed the method used to estimate the service and interest cost associated with the company’s main U.S. pension and OPEB plans. Under the new method, these costs are estimated by applying spot rates along the yield curve to the relevant projected cash flows. 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.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2016, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 6.9 percent in 2017 and gradually decline to 4.5 percent for 2025 and beyond. For this measurement at December 31, 2015, the assumed health care cost-trend rates started with



7.1 percent in 2016 and gradually declined to 4.5 percent for 2025 and beyond. In both measurements, the annual increase to the company’s pre-Medicare contributions upon retirement 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 pre-Medicare 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:

<table><tr><td></td><td></td><td>1 Percent Increase</td><td>1 Percent Decrease</td></tr><tr><td>Effect on total service and interest cost components</td><td></td><td>$ 17</td><td>$ (15)</td></tr><tr><td>Effect on postretirement benefit obligation</td><td></td><td>$ 156</td><td>$ (128)</td></tr></table>

## Plan Assets and Investment Strategy

The fair value measurements of the company’s pension plans for 2016 and 2015 are below:

<table><tr><td rowspan="2"></td><td colspan="8">U.S.</td></tr><tr><td>Total Fair Value</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total Fair Value</td><td>Level 1</td><td>Level 2</td><td>Level 3</td></tr><tr><td>At December 31, 2015</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S.¹</td><td>$ 1,699</td><td>$ 1,699</td><td>$ —</td><td>$ —</td><td>$ 392</td><td>$ 382</td><td>$ 10</td><td>$ —</td></tr><tr><td>International</td><td>1,302</td><td>1,296</td><td>6</td><td>—</td><td>457</td><td>435</td><td>22</td><td>—</td></tr><tr><td>Collective Trusts/Mutual Funds²</td><td>2,460</td><td>18</td><td>2,442</td><td>—</td><td>572</td><td>7</td><td>565</td><td>—</td></tr><tr><td>Fixed Income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Government</td><td>257</td><td>46</td><td>211</td><td>—</td><td>1,089</td><td>93</td><td>996</td><td>—</td></tr><tr><td>Corporate</td><td>1,654</td><td>—</td><td>1,654</td><td>—</td><td>615</td><td>33</td><td>557</td><td>25</td></tr><tr><td>Bank Loans</td><td>148</td><td>—</td><td>148</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Mortgage-Backed Securities</td><td>1</td><td>—</td><td>1</td><td>—</td><td>1</td><td>—</td><td>1</td><td>—</td></tr><tr><td>Other Asset Backed</td><td>1</td><td>—</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Collective Trusts/Mutual Funds²</td><td>933</td><td>—</td><td>933</td><td>—</td><td>269</td><td>12</td><td>257</td><td>—</td></tr><tr><td>Mixed Funds³</td><td>—</td><td>—</td><td>—</td><td>—</td><td>85</td><td>4</td><td>81</td><td>—</td></tr><tr><td>Real Estate⁴</td><td>1,494</td><td>—</td><td>—</td><td>1,494</td><td>378</td><td>—</td><td>—</td><td>378</td></tr><tr><td>Cash and Cash Equivalents</td><td>253</td><td>253</td><td>—</td><td>—</td><td>232</td><td>232</td><td>—</td><td>—</td></tr><tr><td>Other⁵</td><td>72</td><td>(6)</td><td>26</td><td>52</td><td>19</td><td>(2)</td><td>19</td><td>2</td></tr><tr><td>Total at December 31, 2015</td><td>$ 10,274</td><td>$ 3,306</td><td>$ 5,422</td><td>$ 1,546</td><td>$ 4,109</td><td>$ 1,196</td><td>$ 2,508</td><td>$ 405</td></tr><tr><td>At December 31, 2016</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S.¹</td><td>$ 1,217</td><td>$ 1,217</td><td>$ —</td><td>$ —</td><td>$ 565</td><td>$ 564</td><td>$ 1</td><td>$ —</td></tr><tr><td>International</td><td>1,832</td><td>1,822</td><td>10</td><td>—</td><td>576</td><td>576</td><td>—</td><td>—</td></tr><tr><td>Collective Trusts/Mutual Funds²</td><td>1,132</td><td>24</td><td>1,108</td><td>—</td><td>196</td><td>8</td><td>188</td><td>—</td></tr><tr><td>Fixed Income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Government</td><td>222</td><td>—</td><td>222</td><td>—</td><td>1,125</td><td>51</td><td>1,074</td><td>—</td></tr><tr><td>Corporate</td><td>1,356</td><td>—</td><td>1,356</td><td>—</td><td>628</td><td>22</td><td>587</td><td>19</td></tr><tr><td>Bank Loans</td><td>118</td><td>—</td><td>107</td><td>11</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Mortgage-Backed Securities</td><td>1</td><td>—</td><td>1</td><td>—</td><td>10</td><td>—</td><td>10</td><td>—</td></tr><tr><td>Other Asset Backed</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Collective Trusts/Mutual Funds²</td><td>1,031</td><td>—</td><td>1,031</td><td>—</td><td>320</td><td>—</td><td>320</td><td>—</td></tr><tr><td>Mixed Funds³</td><td>—</td><td>—</td><td>—</td><td>—</td><td>72</td><td>2</td><td>70</td><td>—</td></tr><tr><td>Real Estate⁴</td><td>1,367</td><td>—</td><td>—</td><td>1,367</td><td>331</td><td>—</td><td>—</td><td>331</td></tr><tr><td>Alternative Investments⁵</td><td>955</td><td>—</td><td>955</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Cash and Cash Equivalents</td><td>252</td><td>243</td><td>9</td><td>—</td><td>331</td><td>325</td><td>6</td><td>—</td></tr><tr><td>Other⁵</td><td>67</td><td>(9)</td><td>25</td><td>51</td><td>20</td><td>—</td><td>18</td><td>2</td></tr><tr><td>Total at December 31, 2016</td><td>$ 9,550</td><td>$ 3,297</td><td>$ 4,824</td><td>$ 1,429</td><td>$ 4,174</td><td>$ 1,548</td><td>$ 2,274</td><td>$ 352</td></tr></table>

U.S. equities include investments in the company’s common stock in the amount of $12 at December 31, 2016, and $9 at December 31, 2015.

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).

6 Alternative investments focus on market-neutral strategies that have a low expected correlation to traditional asset classes. For these funds, the level 2 designation is mainly based on the restriction that advanced notification of redemptions, typically thirty days or less, is required.



The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:

<table><tr><td rowspan="2"></td><td colspan="6">Fixed Income</td></tr><tr><td>Corporate</td><td>Bank Loans</td><td>Real Estate</td><td>Other</td><td>Total</td><td></td></tr><tr><td>Total at December 31, 2014</td><td>$ 22</td><td>$ —</td><td>$ 1,693</td><td>$ 57</td><td>$ 1,772</td><td></td></tr><tr><td>Actual Return on Plan Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets held at the reporting date</td><td>(3)</td><td>—</td><td>149</td><td>(1)</td><td>145</td><td></td></tr><tr><td>Assets sold during the period</td><td>—</td><td>—</td><td>23</td><td>—</td><td>23</td><td></td></tr><tr><td>Purchases, Sales and Settlements</td><td>6</td><td>—</td><td>7</td><td>(2)</td><td>11</td><td></td></tr><tr><td>Transfers in and/or out of Level 3</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total at December 31, 2015</td><td>$ 25</td><td>$ —</td><td>$ 1,872</td><td>$ 54</td><td>$ 1,951</td><td></td></tr><tr><td>Actual Return on Plan Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets held at the reporting date</td><td>1</td><td>—</td><td>(85)</td><td>(1)</td><td>(85)</td><td></td></tr><tr><td>Assets sold during the period</td><td>—</td><td>—</td><td>121</td><td>1</td><td>122</td><td></td></tr><tr><td>Purchases, Sales and Settlements</td><td>(7)</td><td>11</td><td>(210)</td><td>(1)</td><td>(207)</td><td></td></tr><tr><td>Transfers in and/or out of Level 3</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total at December 31, 2016</td><td>$ 19</td><td>$ 11</td><td>$ 1,698</td><td>$ 53</td><td>$ 1,781</td><td></td></tr></table>

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 90 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 30–60 percent, Fixed Income and Cash 20–65 percent, Real Estate 0–15 percent, and Alternative Investments 0–15 percent. The Alternative Investments range was expanded in 2016 to further diversify the portfolio. 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 35–70 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 factors, including market conditions and illiquidity constraints. 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 2016, the company contributed $406 and $464 to its U.S. and international pension plans, respectively. In 2017, the company expects contributions to be approximately $200 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, tax law changes 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 $163 in 2017; $189 was paid in 2016.

The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:

<table><tr><td rowspan="2"></td><td colspan="4">Pension Benefits</td><td rowspan="2">Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td></td><td></td></tr><tr><td>2017</td><td>$ 1,502</td><td>$ 253</td><td>$ 163</td><td></td><td></td></tr><tr><td>2018</td><td>$ 1,362</td><td>$ 378</td><td>$ 163</td><td></td><td></td></tr><tr><td>2019</td><td>$ 1,310</td><td>$ 276</td><td>$ 164</td><td></td><td></td></tr><tr><td>2020</td><td>$ 1,267</td><td>$ 288</td><td>$ 164</td><td></td><td></td></tr><tr><td>2021</td><td>$ 1,234</td><td>$ 273</td><td>$ 164</td><td></td><td></td></tr><tr><td>2022-2026</td><td>$ 5,536</td><td>$ 1,542</td><td>$ 799</td><td></td><td></td></tr></table>

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 $281, $316 and $316 in 2016, 2015 and 2014, respectively.



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 2016, 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, 2016 and 2015, trust assets of $35 and $36, 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 $662, $690 and $965 in 2016, 2015 and 2014, 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 23, beginning on page 63.

## Note 25

## 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 19, beginning on page 57, 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 has two guarantees to equity affiliates totaling $1,157. Of this amount, $749 is associated with a financing arrangement with an equity affiliate. Over the approximate 5-year remaining term of this guarantee, the maximum amount will be reduced as payments are made by the affiliate. The remaining amount of $408 is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 11-year remaining term of this 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 either 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 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: 2017 – $1,527; 2018 – $1,566; 2019 – $1,389; 2020 – $1,071; 2021 – $968; 2022 and after – $2,572. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $1,300 in 2016, $1,900 in 2015 and $3,700 in 2014.

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, 2016, was $1,467. Included in this balance was $284 related to remediation activities at approximately 146 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 2016 environmental reserves balance of $1,183, $808 is related to the company’s U.S. downstream operations, $51 to its international downstream operations, $322 to upstream operations and $2 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 2016 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.

Refer to Note 26 on page 70 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; joint venture 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.

## Note 26

## 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 2016, 2015 and 2014:

<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Balance at January 1</td><td>$ 15,642</td><td>$ 15,053</td><td>$ 14,298</td></tr><tr><td>Liabilities incurred</td><td>204</td><td>51</td><td>133</td></tr><tr><td>Liabilities settled</td><td>(1,658)</td><td>(981)</td><td>(1,291)</td></tr><tr><td>Accretion expense</td><td>749</td><td>715</td><td>882</td></tr><tr><td>Revisions in estimated cash flows</td><td>(694)</td><td>804</td><td>1,031</td></tr><tr><td>Balance at December 31</td><td>$ 14,243</td><td>$ 15,642</td><td>$ 15,053</td></tr></table>

In the table above, the amount associated with “Revisions in estimated cash flows” in 2016 reflects decreased cost estimates to abandon wells, equipment and facilities and delayed timing of abandonment. The long-term portion of the $14,243 balance at the end of 2016 was $13,447.

## Note 27

## Restructuring and Reorganization Costs

In 2015 and early 2016, the company recorded accruals for employee reduction programs related to the restructuring and reorganization of its corporate staffs and certain upstream operations. The employee reduction programs are substantially completed and the remaining payments are anticipated to be made in early 2017.

A before-tax charge of $353 was recorded in 2015 associated with these programs, of which $293 remained outstanding at December 31, 2015. During 2016, the company recorded an additional before-tax charge of $83 and made payments of $316 associated with these liabilities. The following table summarizes the accrued severance liability, which is classified as current on the Consolidated Balance Sheet:

<table><tr><td></td><td>Amounts Before Tax</td></tr><tr><td>Balance at January 1, 2016</td><td>$ 293</td></tr><tr><td>Accruals/Adjustments</td><td>83</td></tr><tr><td>Payments</td><td>(316)</td></tr><tr><td>Balance at December 31, 2016</td><td>$ 60</td></tr></table>

## Note 28

## Other Financial Information

Earnings in 2016 included after-tax gains of approximately $800 relating to the sale of certain properties. Of this amount, approximately $600 and $200 related to downstream and upstream, respectively. Earnings in 2015 included after-tax gains of approximately $2,300 relating to the sale of certain properties, of which approximately $1,800 and $500 related to downstream and upstream assets, respectively. Earnings in 2016 included after-tax charges of approximately $2,900 for impairments and other asset write-offs related to upstream, and $110 related to downstream. Earnings in 2015 included after-tax charges of approximately $3,000 for impairments and other asset write-offs related to upstream.

Other financial information is as follows:

<table><tr><td rowspan="2"></td><td colspan="4">Year ended December 31</td></tr><tr><td>2016</td><td>2015</td><td>2014</td><td></td></tr><tr><td>Total financing interest and debt costs</td><td>$ 753</td><td>$ 495</td><td>$ 358</td><td></td></tr><tr><td>Less: Capitalized interest</td><td>552</td><td>495</td><td>358</td><td></td></tr><tr><td>Interest and debt expense</td><td>$ 201</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Research and development expenses</td><td>$ 476</td><td>$ 601</td><td>$ 707</td><td></td></tr><tr><td>Excess of replacement cost over the carrying value of inventories (LIFO method)</td><td>2,942</td><td>3,745</td><td>8,135</td><td></td></tr><tr><td>LIFO (losses) / profits on inventory drawdowns included in earnings</td><td>(88)</td><td>(65)</td><td>13</td><td></td></tr><tr><td>Foreign currency effects*</td><td>$ 58</td><td>$ 769</td><td>$ 487</td><td></td></tr></table>

* Includes $1, $344 and $118 in 2016, 2015 and 2014, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $4,581 in goodwill on the Consolidated Balance Sheet related primarily to the 2005 acquisition of Unocal. The company tested this goodwill for impairment during 2016 and no impairment was required.



<table><tr><td>Millions of dollars, except per-share amounts</td><td>2016</td><td>2015</td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td>Statement of Income Data</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues and Other Income</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total sales and other operating revenues¹</td><td>$ 110,215</td><td>$ 129,925</td><td>$ 200,494</td><td>$ 220,156</td><td>$ 230,590</td></tr><tr><td>Income from equity affiliates and other income</td><td>4,257</td><td>8,552</td><td>11,476</td><td>8,692</td><td>11,319</td></tr><tr><td>Total Revenues and Other Income</td><td>114,472</td><td>138,477</td><td>211,970</td><td>228,848</td><td>241,909</td></tr><tr><td>Total Costs and Other Deductions</td><td>116,632</td><td>133,635</td><td>180,768</td><td>192,943</td><td>195,577</td></tr><tr><td>Income Before Income Tax Expense (Benefit)</td><td>(2,160)</td><td>4,842</td><td>31,202</td><td>35,905</td><td>46,332</td></tr><tr><td>Income Tax Expense (Benefit)</td><td>(1,729)</td><td>132</td><td>11,892</td><td>14,308</td><td>19,996</td></tr><tr><td>Net Income</td><td>(431)</td><td>4,710</td><td>19,310</td><td>21,597</td><td>26,336</td></tr><tr><td>Less: Net income attributable to noncontrolling interests</td><td>66</td><td>123</td><td>69</td><td>174</td><td>157</td></tr><tr><td>Net Income (Loss) Attributable to Chevron Corporation</td><td>$ (497)</td><td>$ 4,587</td><td>$ 19,241</td><td>$ 21,423</td><td>$ 26,179</td></tr><tr><td>Per Share of Common Stock</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Income (Loss) Attributable to Chevron</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>- Basic</td><td>$ (0.27)</td><td>$ 2.46</td><td>$ 10.21</td><td>$ 11.18</td><td>$ 13.42</td></tr><tr><td>- Diluted</td><td>$ (0.27)</td><td>$ 2.45</td><td>$ 10.14</td><td>$ 11.09</td><td>$ 13.32</td></tr><tr><td>Cash Dividends Per Share</td><td>$ 4.29</td><td>$ 4.28</td><td>$ 4.21</td><td>$ 3.90</td><td>$ 3.51</td></tr><tr><td>Balance Sheet Data (at December 31)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets²</td><td>$ 29,619</td><td>$ 34,430</td><td>$ 41,161</td><td>$ 48,909</td><td>$ 54,354</td></tr><tr><td>Noncurrent assets²,³</td><td>230,459</td><td>230,110</td><td>223,723</td><td>203,884</td><td>177,672</td></tr><tr><td>Total Assets</td><td>260,078</td><td>264,540</td><td>264,884</td><td>252,793</td><td>232,026</td></tr><tr><td>Short-term debt³</td><td>10,840</td><td>4,927</td><td>3,790</td><td>374</td><td>127</td></tr><tr><td>Other current liabilities²</td><td>20,945</td><td>20,540</td><td>27,322</td><td>32,061</td><td>33,488</td></tr><tr><td>Long-term debt and capital lease obligations³</td><td>35,286</td><td>33,622</td><td>23,994</td><td>20,027</td><td>12,045</td></tr><tr><td>Other noncurrent liabilities²</td><td>46,285</td><td>51,565</td><td>53,587</td><td>49,904</td><td>48,534</td></tr><tr><td>Total Liabilities</td><td>113,356</td><td>110,654</td><td>108,693</td><td>102,366</td><td>94,194</td></tr><tr><td>Total Chevron Corporation Stockholders&#x27; Equity</td><td>$ 145,556</td><td>$ 152,716</td><td>$ 155,028</td><td>$ 149,113</td><td>$ 136,524</td></tr><tr><td>Noncontrolling interests</td><td>1,166</td><td>1,170</td><td>1,163</td><td>1,314</td><td>1,308</td></tr><tr><td>Total Equity</td><td>$ 146,722</td><td>$ 153,886</td><td>$ 156,191</td><td>$ 150,427</td><td>$ 137,832</td></tr><tr><td>1 Includes excise, value-added and similar taxes:</td><td>$ 6,905</td><td>$ 7,359</td><td>$ 8,186</td><td>$ 8,492</td><td>$ 8,010</td></tr><tr><td>2 2012-2015 adjusted to conform to ASU 2015-17. Refer to Note 19, “Income Taxes” beginning on page 57.</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>3 2012-2015 adjusted to conform to ASU 2015-03. Refer to Note 5, “New Accounting Standards” on page 42.</td><td></td><td></td><td></td><td></td><td></td></tr></table>



<table><tr><td colspan="6">Worldwide - Includes Equity in Affiliates</td></tr><tr><td colspan="6">Thousands of barrels per day, except natural gas data, which is millions cubic feet per day</td></tr><tr><td>United States</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net production of crude oil and natural gas liquids</td><td>504</td><td>501</td><td>456</td><td>449</td><td>455</td></tr><tr><td>Net production of natural gas¹</td><td>1,120</td><td>1,310</td><td>1,250</td><td>1,246</td><td>1,203</td></tr><tr><td>Net oil-equivalent production</td><td>691</td><td>720</td><td>664</td><td>657</td><td>655</td></tr><tr><td>Refinery input</td><td>900</td><td>924</td><td>871</td><td>774</td><td>833</td></tr><tr><td>Sales of refined products</td><td>1,213</td><td>1,228</td><td>1,210</td><td>1,182</td><td>1,211</td></tr><tr><td>Sales of natural gas liquids</td><td>145</td><td>153</td><td>141</td><td>142</td><td>157</td></tr><tr><td>Total sales of petroleum products</td><td>1,358</td><td>1,381</td><td>1,351</td><td>1,324</td><td>1,368</td></tr><tr><td>Sales of natural gas</td><td>3,317</td><td>3,913</td><td>3,995</td><td>5,483</td><td>5,470</td></tr><tr><td>International</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net production of crude oil and natural gas liquids²</td><td>1,215</td><td>1,243</td><td>1,253</td><td>1,282</td><td>1,309</td></tr><tr><td>Net production of natural gas¹</td><td>4,132</td><td>3,959</td><td>3,917</td><td>3,946</td><td>3,871</td></tr><tr><td>Net oil-equivalent production</td><td>1,903</td><td>1,902</td><td>1,907</td><td>1,940</td><td>1,955</td></tr><tr><td>Refinery input³</td><td>788</td><td>778</td><td>819</td><td>864</td><td>869</td></tr><tr><td>Sales of refined products⁴</td><td>1,462</td><td>1,507</td><td>1,501</td><td>1,529</td><td>1,554</td></tr><tr><td>Sales of natural gas liquids</td><td>85</td><td>89</td><td>86</td><td>88</td><td>88</td></tr><tr><td>Total sales of petroleum products</td><td>1,547</td><td>1,596</td><td>1,587</td><td>1,617</td><td>1,642</td></tr><tr><td>Sales of natural gas</td><td>4,491</td><td>4,299</td><td>4,304</td><td>4,251</td><td>4,315</td></tr><tr><td>Total Worldwide</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net production of crude oil and natural gas liquids</td><td>1,719</td><td>1,744</td><td>1,709</td><td>1,731</td><td>1,764</td></tr><tr><td>Net production of natural gas</td><td>5,252</td><td>5,269</td><td>5,167</td><td>5,192</td><td>5,074</td></tr><tr><td>Net oil-equivalent production</td><td>2,594</td><td>2,622</td><td>2,571</td><td>2,597</td><td>2,610</td></tr><tr><td>Refinery input</td><td>1,688</td><td>1,702</td><td>1,690</td><td>1,638</td><td>1,702</td></tr><tr><td>Sales of refined products</td><td>2,675</td><td>2,735</td><td>2,711</td><td>2,711</td><td>2,765</td></tr><tr><td>Sales of natural gas liquids</td><td>230</td><td>242</td><td>227</td><td>230</td><td>245</td></tr><tr><td>Total sales of petroleum products</td><td>2,905</td><td>2,977</td><td>2,938</td><td>2,941</td><td>3,010</td></tr><tr><td>Sales of natural gas</td><td>7,808</td><td>8,212</td><td>8,299</td><td>9,734</td><td>9,785</td></tr><tr><td>Worldwide - Excludes Equity in Affiliates</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Number of completed wells (net)⁵</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Oil and gas</td><td>971</td><td>1,848</td><td>2,248</td><td>1,833</td><td>1,618</td></tr><tr><td>Dry</td><td>12</td><td>18</td><td>28</td><td>20</td><td>19</td></tr><tr><td>Productive oil and gas wells (net)⁵</td><td>52,559</td><td>57,454</td><td>56,204</td><td>56,635</td><td>55,812</td></tr></table>



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 Development \( ^{1} \) 

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td colspan="6">Consolidated Companies</td><td colspan="2">Affiliated Companies</td></tr><tr><td>Australia/Oceania</td><td>Europe</td><td>Total</td><td>TCO</td><td>Other</td><td></td><td></td></tr><tr><td>Year Ended December 31, 2016</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Exploration</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Wells</td><td>$ 707</td><td>$ 51</td><td>$ 95</td><td>$ 31</td><td>$ 1</td><td>$ 1</td><td>$ 1</td><td>$ 886</td><td>$</td><td>—</td><td>$</td><td>—</td><td></td></tr><tr><td>Geological and geophysical</td><td>67</td><td>3</td><td>22</td><td>31</td><td>16</td><td>4</td><td>143</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rentals and other</td><td>139</td><td>40</td><td>70</td><td>57</td><td>54</td><td>32</td><td>392</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total exploration</td><td>913</td><td>94</td><td>187</td><td>119</td><td>71</td><td>37</td><td>1,421</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Property acquisitions²</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Proved</td><td>16</td><td>—</td><td>—</td><td>52</td><td>—</td><td>—</td><td>68</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved</td><td>27</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>27</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total property acquisitions</td><td>43</td><td>—</td><td>—</td><td>52</td><td>—</td><td>—</td><td>95</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Development³</td><td>3,814</td><td>1,631</td><td>2,014</td><td>1,866</td><td>3,733</td><td>550</td><td>13,608</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Costs Incurred⁴</td><td>$ 4,770</td><td>$ 1,725</td><td>$ 2,201</td><td>$ 2,037</td><td>$ 3,804</td><td>$ 587</td><td>$ 15,124</td><td>$ 2,211</td><td>$ 262</td><td></td><td></td><td></td><td></td></tr><tr><td>Year Ended December 31, 2015</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Exploration</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Wells</td><td>$ 857</td><td>$ 66</td><td>$ 172</td><td>$ 218</td><td>$ 81</td><td>$ 14</td><td>$ 1,408</td><td>$</td><td>—</td><td>$</td><td>—</td><td></td><td></td></tr><tr><td>Geological and geophysical</td><td>69</td><td>6</td><td>77</td><td>86</td><td>107</td><td>26</td><td>371</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rentals and other</td><td>218</td><td>56</td><td>121</td><td>109</td><td>71</td><td>68</td><td>643</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total exploration</td><td>1,144</td><td>128</td><td>370</td><td>413</td><td>259</td><td>108</td><td>2,422</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Property acquisitions²</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Proved</td><td>23</td><td>21</td><td>—</td><td>54</td><td>—</td><td>—</td><td>98</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved</td><td>554</td><td>3</td><td>30</td><td>—</td><td>—</td><td>—</td><td>587</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total property acquisitions</td><td>577</td><td>24</td><td>30</td><td>54</td><td>—</td><td>—</td><td>685</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Development³</td><td>6,275</td><td>2,048</td><td>3,701</td><td>3,924</td><td>6,715</td><td>995</td><td>23,658</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Costs Incurred⁴</td><td>$ 7,996</td><td>$ 2,200</td><td>$ 4,101</td><td>$ 4,391</td><td>$ 6,974</td><td>$ 1,103</td><td>$ 26,765</td><td>$ 1,641</td><td>$ 225</td><td></td><td></td><td></td><td></td></tr><tr><td>Year Ended December 31, 2014</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Exploration</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Wells</td><td>$ 965</td><td>$ 87</td><td>$ 436</td><td>$ 381</td><td>$ 207</td><td>$ 101</td><td>$ 2,177</td><td>$</td><td>—</td><td>$</td><td>—</td><td></td><td></td></tr><tr><td>Geological and geophysical</td><td>107</td><td>72</td><td>32</td><td>64</td><td>88</td><td>41</td><td>404</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rentals and other</td><td>150</td><td>37</td><td>198</td><td>98</td><td>101</td><td>103</td><td>687</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total exploration</td><td>1,222</td><td>196</td><td>666</td><td>543</td><td>396</td><td>245</td><td>3,268</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Property acquisitions²</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Proved</td><td>33</td><td>1</td><td>521</td><td>60</td><td>—</td><td>—</td><td>615</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved</td><td>196</td><td>2</td><td>39</td><td>—</td><td>—</td><td>—</td><td>237</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total property acquisitions</td><td>229</td><td>3</td><td>560</td><td>60</td><td>—</td><td>—</td><td>852</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Development³</td><td>8,207</td><td>3,226</td><td>3,771</td><td>4,363</td><td>7,182</td><td>887</td><td>27,636</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Costs Incurred⁴</td><td>$ 9,658</td><td>$ 3,425</td><td>$ 4,997</td><td>$ 4,966</td><td>$ 7,578</td><td>$ 1,132</td><td>$ 31,756</td><td>$ 1,598</td><td>$ 393</td><td></td><td></td><td></td><td></td></tr></table>

Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 26, “Asset Retirement Obligations,” on page 70.

 \( ^{2} \)  Does not include properties acquired in nonmonetary transactions.

 \( ^{3} \)  Includes 4S41, 3S25 and 3S49 costs incurred prior to assignment of proved reserves for consolidated companies in 2016, 2015, and 2014, respectively.

 \( ^{4} \)  Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions:

<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Total cost incurred</td><td>$ 17.6</td><td>$ 28.6</td><td>$ 33.7</td></tr><tr><td>Non-oil and gas activities</td><td>2.5</td><td>3.5</td><td>4.6</td></tr><tr><td>ARO</td><td>—</td><td>(1.0)</td><td>(1.2)</td></tr><tr><td>Upstream C&amp;E</td><td>$ 20.1</td><td>$ 31.1</td><td>$ 37.1</td></tr></table>



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 16, beginning on page 51, for a discussion of the company’s major equity affiliates.

Table II - Capitalized Costs Related to Oil and Gas Producing Activities

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td colspan="3">Consolidated Companies</td><td colspan="2">Affiliated Companies</td></tr><tr><td>Australia/Oceania</td><td>Europe</td><td>Total</td><td>TCO</td><td>Other</td></tr><tr><td>At December 31, 2016</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved properties</td><td>$ 9,052</td><td>$ 3,063</td><td>$ 263</td><td>$ 1,273</td><td>$ 1,986</td><td>$ 23</td><td>$ 15,660</td><td>$ 108</td><td>$ —</td></tr><tr><td>Proved properties and related producing assets</td><td>69,924</td><td>18,269</td><td>38,903</td><td>56,070</td><td>11,642</td><td>10,738</td><td>205,546</td><td>8,484</td><td>3,898</td></tr><tr><td>Support equipment</td><td>2,249</td><td>357</td><td>1,083</td><td>2,036</td><td>8,598</td><td>131</td><td>14,454</td><td>1,632</td><td>—</td></tr><tr><td>Deferred exploratory wells</td><td>750</td><td>190</td><td>415</td><td>602</td><td>1,322</td><td>261</td><td>3,540</td><td>—</td><td>—</td></tr><tr><td>Other uncompleted projects</td><td>7,018</td><td>5,900</td><td>6,152</td><td>2,743</td><td>17,559</td><td>1,804</td><td>41,176</td><td>5,075</td><td>517</td></tr><tr><td>Gross Capitalized Costs</td><td>88,993</td><td>27,779</td><td>46,816</td><td>62,724</td><td>41,107</td><td>12,957</td><td>280,376</td><td>15,299</td><td>4,415</td></tr><tr><td>Unproved properties valuation</td><td>1,673</td><td>903</td><td>222</td><td>483</td><td>107</td><td>23</td><td>3,411</td><td>55</td><td>—</td></tr><tr><td>Proved producing properties - Depreciation and depletion</td><td>45,820</td><td>11,635</td><td>24,463</td><td>38,757</td><td>2,300</td><td>8,643</td><td>131,618</td><td>4,148</td><td>1,170</td></tr><tr><td>Support equipment depreciation</td><td>1,165</td><td>226</td><td>657</td><td>1,502</td><td>571</td><td>118</td><td>4,239</td><td>750</td><td>—</td></tr><tr><td>Accumulated provisions</td><td>48,658</td><td>12,764</td><td>25,342</td><td>40,742</td><td>2,978</td><td>8,784</td><td>139,268</td><td>4,953</td><td>1,170</td></tr><tr><td>Net Capitalized Costs</td><td>$ 40,335</td><td>$ 15,015</td><td>$ 21,474</td><td>$ 21,982</td><td>$ 38,129</td><td>$ 4,173</td><td>$ 141,108</td><td>$ 10,346</td><td>$ 3,245</td></tr><tr><td>At December 31, 2015</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved properties</td><td>$ 9,880</td><td>$ 3,216</td><td>$ 271</td><td>$ 1,487</td><td>$ 1,990</td><td>$ 23</td><td>$ 16,867</td><td>$ 108</td><td>$ —</td></tr><tr><td>Proved properties and related producing assets</td><td>79,891</td><td>16,810</td><td>36,563</td><td>51,509</td><td>3,012</td><td>9,664</td><td>197,449</td><td>7,803</td><td>3,857</td></tr><tr><td>Support equipment</td><td>1,970</td><td>363</td><td>1,229</td><td>1,967</td><td>1,195</td><td>176</td><td>6,900</td><td>1,452</td><td>—</td></tr><tr><td>Deferred exploratory wells</td><td>438</td><td>237</td><td>443</td><td>612</td><td>1,321</td><td>261</td><td>3,312</td><td>—</td><td>—</td></tr><tr><td>Other uncompleted projects</td><td>7,700</td><td>5,566</td><td>6,517</td><td>5,070</td><td>29,843</td><td>2,332</td><td>57,028</td><td>3,732</td><td>425</td></tr><tr><td>Gross Capitalized Costs</td><td>99,879</td><td>26,192</td><td>45,023</td><td>60,645</td><td>37,361</td><td>12,456</td><td>281,556</td><td>13,095</td><td>4,282</td></tr><tr><td>Unproved properties valuation</td><td>1,667</td><td>873</td><td>209</td><td>438</td><td>107</td><td>23</td><td>3,317</td><td>51</td><td>—</td></tr><tr><td>Proved producing properties - Depreciation and depletion</td><td>53,718</td><td>8,950</td><td>21,904</td><td>35,004</td><td>1,950</td><td>8,074</td><td>129,600</td><td>3,714</td><td>984</td></tr><tr><td>Support equipment depreciation</td><td>800</td><td>208</td><td>740</td><td>1,420</td><td>480</td><td>161</td><td>3,809</td><td>661</td><td>—</td></tr><tr><td>Accumulated provisions</td><td>56,185</td><td>10,031</td><td>22,853</td><td>36,862</td><td>2,537</td><td>8,258</td><td>136,726</td><td>4,426</td><td>984</td></tr><tr><td>Net Capitalized Costs</td><td>$ 43,694</td><td>$ 16,161</td><td>$ 22,170</td><td>$ 23,783</td><td>$ 34,824</td><td>$ 4,198</td><td>$ 144,830</td><td>$ 8,669</td><td>$ 3,298</td></tr><tr><td>At December 31, 2014</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved properties</td><td>$ 10,095</td><td>$ 3,207</td><td>$ 286</td><td>$ 1,933</td><td>$ 1,990</td><td>$ 33</td><td>$ 17,544</td><td>$ 108</td><td>$ —</td></tr><tr><td>Proved properties and related producing assets</td><td>75,511</td><td>14,697</td><td>33,117</td><td>47,007</td><td>3,303</td><td>9,172</td><td>182,807</td><td>7,370</td><td>3,713</td></tr><tr><td>Support equipment</td><td>1,670</td><td>361</td><td>1,193</td><td>1,791</td><td>796</td><td>186</td><td>5,997</td><td>1,331</td><td>—</td></tr><tr><td>Deferred exploratory wells</td><td>1,012</td><td>220</td><td>647</td><td>734</td><td>1,330</td><td>252</td><td>4,195</td><td>—</td><td>—</td></tr><tr><td>Other uncompleted projects</td><td>7,714</td><td>5,566</td><td>6,691</td><td>5,997</td><td>23,487</td><td>1,841</td><td>51,296</td><td>2,679</td><td>458</td></tr><tr><td>Gross Capitalized Costs</td><td>96,002</td><td>24,051</td><td>41,934</td><td>57,462</td><td>30,906</td><td>11,484</td><td>261,839</td><td>11,488</td><td>4,171</td></tr><tr><td>Unproved properties valuation</td><td>1,332</td><td>796</td><td>213</td><td>634</td><td>46</td><td>33</td><td>3,054</td><td>48</td><td>—</td></tr><tr><td>Proved producing properties - Depreciation and depletion</td><td>48,315</td><td>6,516</td><td>19,729</td><td>31,207</td><td>2,259</td><td>7,540</td><td>115,566</td><td>3,295</td><td>845</td></tr><tr><td>Support equipment depreciation</td><td>711</td><td>203</td><td>694</td><td>1,276</td><td>202</td><td>159</td><td>3,245</td><td>611</td><td>—</td></tr><tr><td>Accumulated provisions</td><td>50,358</td><td>7,515</td><td>20,636</td><td>33,117</td><td>2,507</td><td>7,732</td><td>121,865</td><td>3,954</td><td>845</td></tr><tr><td>Net Capitalized Costs</td><td>$ 45,644</td><td>$ 16,536</td><td>$ 21,298</td><td>$ 24,345</td><td>$ 28,399</td><td>$ 3,752</td><td>$ 139,974</td><td>$ 7,534</td><td>$ 3,326</td></tr></table>



Table III - Results of Operations for Oil and Gas Producing Activities \( ^{1} \) , continued

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td colspan="3">Consolidated Companies</td><td colspan="3">Affiliated Companies</td></tr><tr><td>Australia/ Oceania</td><td>Europe</td><td>Total</td><td>TCO</td><td>Other</td><td></td></tr><tr><td>Year Ended December 31, 2014</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from net production</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Sales</td><td>$ 2,660</td><td>$ 1,338</td><td>$ 707</td><td>$ 8,290</td><td>$ 1,466</td><td>$ 1,037</td><td>$ 15,498</td><td>$ 7,717</td><td>$ 1,733</td><td></td><td></td><td></td></tr><tr><td>Transfers</td><td>13,023</td><td>2,285</td><td>12,546</td><td>8,153</td><td>888</td><td>1,277</td><td>38,172</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Total</td><td>15,683</td><td>3,623</td><td>13,253</td><td>16,443</td><td>2,354</td><td>2,314</td><td>53,670</td><td>7,717</td><td>1,733</td><td></td><td></td><td></td></tr><tr><td>Production expenses excluding taxes</td><td>(4,786)</td><td>(1,328)</td><td>(2,084)</td><td>(4,527)</td><td>(191)</td><td>(773)</td><td>(13,689)</td><td>(493)</td><td>(670)</td><td></td><td></td><td></td></tr><tr><td>Taxes other than on income</td><td>(654)</td><td>(122)</td><td>(140)</td><td>(82)</td><td>(329)</td><td>(4)</td><td>(1,331)</td><td>(344)</td><td>(418)</td><td></td><td></td><td></td></tr><tr><td>Proved producing properties:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and depletion</td><td>(4,605)</td><td>(793)</td><td>(3,092)</td><td>(3,977)</td><td>(208)</td><td>(351)</td><td>(13,026)</td><td>(567)</td><td>(175)</td><td></td><td></td><td></td></tr><tr><td>Accretion expense \( ^{2} \)</td><td>(334)</td><td>(22)</td><td>(130)</td><td>(142)</td><td>(32)</td><td>(84)</td><td>(744)</td><td>(9)</td><td>(4)</td><td></td><td></td><td></td></tr><tr><td>Exploration expenses</td><td>(581)</td><td>(119)</td><td>(383)</td><td>(309)</td><td>(269)</td><td>(281)</td><td>(1,942)</td><td>—</td><td>(5)</td><td></td><td></td><td></td></tr><tr><td>Unproved properties valuation</td><td>(140)</td><td>(219)</td><td>(12)</td><td>(289)</td><td>(40)</td><td>(3)</td><td>(703)</td><td>—</td><td>(38)</td><td></td><td></td><td></td></tr><tr><td>Other income (expense) \( ^{3} \)</td><td>654</td><td>674</td><td>221</td><td>115</td><td>102</td><td>358</td><td>2,124</td><td>(28)</td><td>(85)</td><td></td><td></td><td></td></tr><tr><td>Results before income taxes</td><td>5,237</td><td>1,694</td><td>7,633</td><td>7,232</td><td>1,387</td><td>1,176</td><td>24,359</td><td>6,276</td><td>338</td><td></td><td></td><td></td></tr><tr><td>Income tax expense</td><td>(1,955)</td><td>(471)</td><td>(4,924)</td><td>(3,604)</td><td>(392)</td><td>(579)</td><td>(11,925)</td><td>(1,883)</td><td>(284)</td><td></td><td></td><td></td></tr><tr><td>Results of Producing Operations</td><td>$ 3,282</td><td>$ 1,223</td><td>$ 2,709</td><td>$ 3,628</td><td>$ 995</td><td>$ 597</td><td>$ 12,434</td><td>$ 4,393</td><td>$ 54</td><td></td><td></td><td></td></tr></table>

 \( ^{1} \)  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 26, “Asset Retirement Obligations,” on page 70.

 \( ^{3} \)  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 Costs \( ^{1} \) 

<table><tr><td rowspan="2"></td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td colspan="3">Consolidated Companies</td><td colspan="3">Affiliated Companies</td></tr><tr><td>Australia/ Oceania</td><td>Europe</td><td>Total</td><td>TCO</td><td>Other</td><td></td></tr><tr><td>Year Ended December 31, 2016</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Average sales prices</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liquids, per barrel</td><td>$ 35.00</td><td>$ 43.89</td><td>$ 41.42</td><td>$ 37.55</td><td>$ 45.32</td><td>$ 39.64</td><td>$ 38.30</td><td>$ 31.83</td><td>$ 31.90</td><td></td><td></td><td></td></tr><tr><td>Natural gas, per thousand cubic feet</td><td>1.58</td><td>3.04</td><td>1.60</td><td>4.19</td><td>4.29</td><td>4.77</td><td>3.45</td><td>1.34</td><td>2.24</td><td></td><td></td><td></td></tr><tr><td>Average production costs, per barrel \( ^{2} \)</td><td>14.56</td><td>18.79</td><td>13.80</td><td>11.34</td><td>5.97</td><td>12.84</td><td>13.15</td><td>3.67</td><td>15.01</td><td></td><td></td><td></td></tr><tr><td>Year Ended December 31, 2015</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Average sales prices</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liquids, per barrel</td><td>$ 42.70</td><td>$ 49.66</td><td>$ 49.88</td><td>$ 46.19</td><td>$ 49.96</td><td>$ 48.53</td><td>$ 46.26</td><td>$ 38.71</td><td>$ 34.92</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas, per thousand cubic feet</td><td>1.89</td><td>3.24</td><td>1.84</td><td>4.94</td><td>6.17</td><td>5.28</td><td>3.96</td><td>1.57</td><td>2.51</td><td></td><td></td><td></td><td></td></tr><tr><td>Average production costs, per barrel \( ^{2} \)</td><td>16.60</td><td>20.45</td><td>12.23</td><td>13.55</td><td>5.03</td><td>17.14</td><td>14.60</td><td>4.32</td><td>17.44</td><td></td><td></td><td></td><td></td></tr><tr><td>Year Ended December 31, 2014</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Average sales prices</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liquids, per barrel</td><td>$ 84.13</td><td>$ 86.23</td><td>$ 96.43</td><td>$ 89.44</td><td>$ 95.17</td><td>$ 95.05</td><td>$ 89.44</td><td>$ 81.07</td><td>$ 76.07</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas, per thousand cubic feet</td><td>3.90</td><td>3.25</td><td>1.53</td><td>5.86</td><td>10.42</td><td>9.29</td><td>5.44</td><td>1.53</td><td>6.38</td><td></td><td></td><td></td><td></td></tr><tr><td>Average production costs, per barrel \( ^{2} \)</td><td>20.09</td><td>22.77</td><td>13.77</td><td>17.21</td><td>5.53</td><td>27.14</td><td>17.69</td><td>4.47</td><td>29.30</td><td></td><td></td><td></td><td></td></tr></table>

 \( ^{1} \)  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.



the American Association of Petroleum Geologists, the SEPM Society of Sedimentary Geologists and the Society of Petroleum Engineers.

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 Global 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 Global Reserves Manual. In addition, third-party engineering consultants are used to supplement the company’s own reserves estimation controls and procedures, including through the use of third-party audits of selected oil and gas assets.

Technologies Used in Establishing Proved Reserves Additions In 2016, 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 2016, proved undeveloped reserves totaled 3.6 billion barrels of oil-equivalent (BOE), a decrease of 656 million BOE from year-end 2015. The decrease was due to the transfer of 1.1 billion BOE to proved developed, 7 million BOE in revisions and 7 million BOE in sales, partially offset by increases of 277 million BOE in improved recovery, 189 million BOE in extensions and discoveries and 10 million BOE in acquisitions.

During 2016, investments totaling approximately $8.8 billion in oil and gas producing activities and about $1.9 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. Australia accounted for about $2.3 billion of the total, mainly for development and construction activities at the Wheatstone LNG Project. Expenditures of about $2.3 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 $2.9 billion, primarily related to development projects of the TCO affiliate in Kazakhstan, and in Thailand. In Africa, about $1.6 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of Congo. Development activities in Canada were primarily responsible for about $1.3 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.

At year-end 2016, 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 600 million BOE have remained undeveloped for five years or more related to the Gorgon and Wheatstone projects. 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 1.4 billion BOE of proved undeveloped reserves with about 1.0 billion BOE 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 2016, further 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 2016, 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 32 percent and 45 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, 2016, 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, 2016, proved reserves for the company were 11.1 billion BOE. The company’s estimated net proved reserves of liquids including crude oil, condensate, natural gas liquids and synthetic oil for the years 2014, 2015 and 2016 are shown in the table on page 81. The company’s estimated net proved reserves of natural gas are shown on page 82.

Noteworthy changes in liquids proved reserves for 2014 through 2016 are discussed below and shown in the table on the following page:

Revisions 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.

In 2016, entitlement effects were mainly responsible for the 64 million barrel increase in the TCO affiliate in Kazakhstan. Improved field performance at various Gulf of Mexico fields, including Jack/St Malo, and in the San Joaquin Valley were primarily responsible for the 109 million barrel increase in the United States. In Asia, entitlement effects, drilling and improved performance across numerous assets resulted in the 50 million barrel increase.

Improved Recovery 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.

In 2016, improved recovery increased reserves by 293 million barrels, primarily due to the Future Growth Project in the TCO affiliate in Kazakhstan.

Extensions and Discoveries 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.

In 2016, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 131 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.

In 2016, sales of 34 million barrels in the United States were primarily in the Gulf of Mexico shelf.



## Net Proved Reserves of Crude Oil, Condensate, Natural Gas Liquids and Synthetic Oil

<table><tr><td rowspan="2">Millions of barrels</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas¹</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td colspan="3">Consolidated Companies</td><td colspan="3">Affiliated Companies</td><td rowspan="2">Total Consolidated and Affiliated Companies</td></tr><tr><td>Australia/ Oceania</td><td>Europe</td><td>Synthetic Oil²</td><td>Total</td><td>Synthetic TCO</td><td>Oil</td><td>Other³</td></tr><tr><td>Reserves at January 1, 2014</td><td>1,330</td><td>243</td><td>1,104</td><td>792</td><td>131</td><td>166</td><td>537</td><td>4,303</td><td>1,668</td><td>220</td><td>154</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>90</td><td>—</td><td>74</td><td>80</td><td>19</td><td>9</td><td>(32)</td><td>240</td><td>41</td><td>(4)</td><td>—</td></tr><tr><td>Improved recovery</td><td>19</td><td>1</td><td>1</td><td>8</td><td>—</td><td>5</td><td>—</td><td>34</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Extensions and discoveries</td><td>164</td><td>18</td><td>2</td><td>7</td><td>—</td><td>8</td><td>19</td><td>218</td><td>—</td><td>—</td><td>1</td></tr><tr><td>Purchases</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>26</td><td>27</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Sales</td><td>(6)</td><td>—</td><td>(20)</td><td>—</td><td>—</td><td>(3)</td><td>—</td><td>(29)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Production</td><td>(166)</td><td>(24)</td><td>(140)</td><td>(135)</td><td>(8)</td><td>(19)</td><td>(16)</td><td>(508)</td><td>(94)</td><td>(12)</td><td>(10)</td></tr><tr><td>Reserves at December 31, 2014⁴</td><td>1,432</td><td>238</td><td>1,021</td><td>752</td><td>142</td><td>166</td><td>534</td><td>4,285</td><td>1,615</td><td>204</td><td>145</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>(1)</td><td>(9)</td><td>60</td><td>164</td><td>14</td><td>(3)</td><td>80</td><td>305</td><td>163</td><td>—</td><td>(4)</td></tr><tr><td>Improved recovery</td><td>7</td><td>—</td><td>11</td><td>2</td><td>—</td><td>—</td><td>—</td><td>20</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Extensions and discoveries</td><td>137</td><td>28</td><td>4</td><td>5</td><td>5</td><td>—</td><td>—</td><td>179</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Purchases</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>——</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Sales</td><td>(6)</td><td>—</td><td>(7)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(13)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Production</td><td>(183)</td><td>(21)</td><td>(132)</td><td>(133)</td><td>(8)</td><td>(20)</td><td>(17)</td><td>(514)</td><td>(102)</td><td>(11)</td><td>(10)</td></tr><tr><td>Reserves at December 31, 2015⁴</td><td>1,386</td><td>236</td><td>957</td><td>790</td><td>153</td><td>143</td><td>597</td><td>4,262</td><td>1,676</td><td>193</td><td>131</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>109</td><td>(20)</td><td>22</td><td>50</td><td>12</td><td>16</td><td>26</td><td>215</td><td>64</td><td>(12)</td><td>(5)</td></tr><tr><td>Improved recovery</td><td>5</td><td>—</td><td>11</td><td>2</td><td>—</td><td>—</td><td>—</td><td>18</td><td>273</td><td>—</td><td>2</td></tr><tr><td>Extensions and discoveries</td><td>131</td><td>23</td><td>9</td><td>1</td><td>—</td><td>—</td><td>—</td><td>164</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Purchases</td><td>—</td><td>10</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>10</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Sales</td><td>(34)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(34)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Production</td><td>(185)</td><td>(26)</td><td>(123)</td><td>(123)</td><td>(7)</td><td>(21)</td><td>(19)</td><td>(504)</td><td>(104)</td><td>(11)</td><td>(10)</td></tr><tr><td>Reserves at December 31, 2016⁴</td><td>1,412</td><td>223</td><td>876</td><td>720</td><td>158</td><td>138</td><td>604</td><td>4,131</td><td>1,909</td><td>170</td><td>118</td></tr></table>

1 Ending reserve balances in North America were 169, 155 and 142 and in South America were 54, 81 and 96 in 2016, 2015 and 2014, respectively.

 \( ^{2} \)  Reserves associated with Canada.

3 Ending reserve balances in Africa were 31, 34 and 37 and in South America were 87, 97 and 108 in 2016, 2015 and 2014, 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 19 percent, 20 percent and 19 percent for consolidated companies for 2016, 2015 and 2014, respectively.



## Net Proved Reserves of Natural Gas

<table><tr><td rowspan="2">Billions of cubic feet (BCF)</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas¹</td><td rowspan="2">Africa</td><td colspan="4">Consolidated Companies</td><td colspan="2">Affiliated Companies</td><td rowspan="2">Total Consolidated and Affiliated Companies</td></tr><tr><td>Africa</td><td>Australia/ Oceania</td><td>Europe</td><td>Total</td><td>TCO</td><td>Other²</td></tr><tr><td>Reserves at January 1, 2014</td><td>3,990</td><td>1,300</td><td>3,045</td><td>6,745</td><td>10,327</td><td>263</td><td>25,670</td><td>2,290</td><td>1,186</td><td>29,146</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>76</td><td>(110)</td><td>35</td><td>252</td><td>775</td><td>36</td><td>1,064</td><td>9</td><td>34</td><td>1,107</td></tr><tr><td>Improved recovery</td><td>2</td><td>1</td><td>1</td><td>—</td><td>—</td><td>1</td><td>5</td><td>—</td><td>—</td><td>5</td></tr><tr><td>Extensions and discoveries</td><td>614</td><td>56</td><td>—</td><td>79</td><td>—</td><td>3</td><td>752</td><td>—</td><td>32</td><td>784</td></tr><tr><td>Purchases</td><td>1</td><td>—</td><td>—</td><td>21</td><td>—</td><td>—</td><td>22</td><td>—</td><td>—</td><td>22</td></tr><tr><td>Sales</td><td>(53)</td><td>(1)</td><td>(3)</td><td>—</td><td>—</td><td>(5)</td><td>(62)</td><td>—</td><td>—</td><td>(62)</td></tr><tr><td>Production³</td><td>(456)</td><td>(123)</td><td>(110)</td><td>(831)</td><td>(161)</td><td>(63)</td><td>(1,744)</td><td>(122)</td><td>(20)</td><td>(1,886)</td></tr><tr><td>Reserves at December 31, 2014</td><td>4,174</td><td>1,123</td><td>2,968</td><td>6,266</td><td>10,941</td><td>235</td><td>25,707</td><td>2,177</td><td>1,232</td><td>29,116</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>(66)</td><td>(435)</td><td>27</td><td>480</td><td>974</td><td>49</td><td>1,029</td><td>218</td><td>2</td><td>1,249</td></tr><tr><td>Improved recovery</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1</td><td>—</td><td>—</td><td>1</td></tr><tr><td>Extensions and discoveries</td><td>659</td><td>147</td><td>61</td><td>61</td><td>118</td><td>—</td><td>1,046</td><td>—</td><td>—</td><td>1,046</td></tr><tr><td>Purchases</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td></tr><tr><td>Sales</td><td>(48)</td><td>—</td><td>(5)</td><td>—</td><td>—</td><td>—</td><td>(53)</td><td>—</td><td>—</td><td>(53)</td></tr><tr><td>Production³</td><td>(478)</td><td>(121)</td><td>(114)</td><td>(851)</td><td>(160)</td><td>(60)</td><td>(1,784)</td><td>(127)</td><td>(11)</td><td>(1,922)</td></tr><tr><td>Reserves at December 31, 2015</td><td>4,242</td><td>714</td><td>2,937</td><td>5,956</td><td>11,873</td><td>224</td><td>25,946</td><td>2,268</td><td>1,223</td><td>29,437</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>(6)</td><td>(24)</td><td>(29)</td><td>443</td><td>853</td><td>72</td><td>1,309</td><td>111</td><td>(107)</td><td>1,313</td></tr><tr><td>Improved recovery</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2</td><td>—</td><td>—</td><td>2</td></tr><tr><td>Extensions and discoveries</td><td>388</td><td>73</td><td>—</td><td>4</td><td>14</td><td>—</td><td>479</td><td>—</td><td>—</td><td>479</td></tr><tr><td>Purchases</td><td>4</td><td>3</td><td>—</td><td>—</td><td>—</td><td>—</td><td>7</td><td>—</td><td>—</td><td>7</td></tr><tr><td>Sales</td><td>(544)</td><td>(10)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(554)</td><td>—</td><td>—</td><td>(554)</td></tr><tr><td>Production³</td><td>(410)</td><td>(109)</td><td>(81)</td><td>(870)</td><td>(225)</td><td>(62)</td><td>(1,757)</td><td>(137)</td><td>(30)</td><td>(1,924)</td></tr><tr><td>Reserves at December 31, 2016</td><td>3,676</td><td>647</td><td>2,827</td><td>5,533</td><td>12,515</td><td>234</td><td>25,432</td><td>2,242</td><td>1,086</td><td>28,760</td></tr></table>

1 Ending reserve balances in North America and South America were 172, 174, 59 and 475, 540, 1,064 in 2016, 2015 and 2014, respectively.

2 Ending reserve balances in Africa and South America were 939, 1,044, 1,043 and 147,179, 189 in 2016, 2015 and 2014, respectively.

3 Total “as sold” volumes are 1,744, 1,742 and 1,695 for 2016, 2015 and 2014, respectively.

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 15 percent, 16 percent and 19 percent for consolidated companies for 2016, 2015 and 2014, respectively.

Noteworthy changes in natural gas proved reserves for 2014 through 2016 are discussed below and shown in the table above:

Revisions 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.

In 2016, development activities primarily at Wheatstone were responsible for the 853 BCF increase in Australia. Net revisions of 443 BCF in Asia were primarily due to improved field performance in China and Thailand.

Extensions and Discoveries 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.

In 2016, extensions and discoveries of 388 BCF in the United States were primarily in the Appalachian region and the Midland and Delaware basins.

Sales In 2016, sales of 544 BCF in the United States were primarily in the Gulf of Mexico shelf, Michigan and the midcontinent region.



## 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.

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S. Americas</td><td rowspan="2">Other Africa</td><td rowspan="2">Asia</td><td colspan="3">Consolidated Companies</td><td rowspan="2">Affiliated Companies</td><td rowspan="2">Total TCO</td><td rowspan="2">Total Consolidated and Affiliated Companies</td></tr><tr><td>Australia/ Oceania</td><td>Europe</td><td>Total</td></tr><tr><td>At December 31, 2016</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows from production</td><td>$ 53,777</td><td>$ 33,520</td><td>$ 39,072</td><td>$ 44,526</td><td>$ 63,781</td><td>$ 6,338</td><td>$ 241,014</td><td>$ 66,506</td><td>$ 11,244</td><td>$ 318,764</td></tr><tr><td>Future production costs</td><td>(26,530)</td><td>(20,413)</td><td>(19,749)</td><td>(19,815)</td><td>(11,058)</td><td>(5,500)</td><td>(103,065)</td><td>(13,610)</td><td>(5,254)</td><td>(121,929)</td></tr><tr><td>Future development costs</td><td>(7,830)</td><td>(4,277)</td><td>(4,186)</td><td>(4,603)</td><td>(7,804)</td><td>(977)</td><td>(29,677)</td><td>(20,855)</td><td>(2,192)</td><td>(52,724)</td></tr><tr><td>Future income taxes</td><td>(3,454)</td><td>(2,664)</td><td>(9,684)</td><td>(8,503)</td><td>(13,476)</td><td>69</td><td>(37,712)</td><td>(9,613)</td><td>(1,639)</td><td>(48,964)</td></tr><tr><td>Undiscounted future net cash flows</td><td>15,963</td><td>6,166</td><td>5,453</td><td>11,605</td><td>31,443</td><td>(70)</td><td>70,560</td><td>22,428</td><td>2,159</td><td>95,147</td></tr><tr><td>10 percent midyear annual discount for timing of estimated cash flows</td><td>(5,086)</td><td>(3,670)</td><td>(1,380)</td><td>(3,137)</td><td>(15,264)</td><td>330</td><td>(28,207)</td><td>(13,901)</td><td>(972)</td><td>(43,080)</td></tr><tr><td>Standardized Measure</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Cash Flows</td><td>$ 10,877</td><td>$ 2,496</td><td>$ 4,073</td><td>$ 8,468</td><td>$ 16,179</td><td>$ 260</td><td>$ 42,353</td><td>$ 8,527</td><td>$ 1,187</td><td>$ 52,067</td></tr><tr><td>At December 31, 2015</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows from production</td><td>$ 67,536</td><td>$ 39,363</td><td>$ 52,128</td><td>$ 58,645</td><td>$ 93,550</td><td>$ 8,561</td><td>$ 319,783</td><td>$ 75,378</td><td>$ 17,519</td><td>$ 412,680</td></tr><tr><td>Future production costs</td><td>(33,895)</td><td>(26,477)</td><td>(22,963)</td><td>(27,499)</td><td>(10,814)</td><td>(6,994)</td><td>(128,642)</td><td>(17,959)</td><td>(6,546)</td><td>(153,147)</td></tr><tr><td>Future development costs</td><td>(12,625)</td><td>(5,485)</td><td>(6,562)</td><td>(8,924)</td><td>(11,612)</td><td>(1,751)</td><td>(46,959)</td><td>(17,232)</td><td>(3,226)</td><td>(67,417)</td></tr><tr><td>Future income taxes</td><td>(4,161)</td><td>(2,316)</td><td>(14,681)</td><td>(9,229)</td><td>(21,337)</td><td>70</td><td>(51,654)</td><td>(12,056)</td><td>(3,460)</td><td>(67,170)</td></tr><tr><td>Undiscounted future net cash flows</td><td>16,855</td><td>5,085</td><td>7,922</td><td>12,993</td><td>49,787</td><td>(114)</td><td>92,528</td><td>28,131</td><td>4,287</td><td>124,946</td></tr><tr><td>10 percent midyear annual discount for timing of estimated cash flows</td><td>(5,871)</td><td>(2,830)</td><td>(2,230)</td><td>(3,673)</td><td>(26,179)</td><td>292</td><td>(40,491)</td><td>(15,249)</td><td>(2,239)</td><td>(57,979)</td></tr><tr><td>Standardized Measure</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Cash Flows</td><td>$ 10,984</td><td>$ 2,255</td><td>$ 5,692</td><td>$ 9,320</td><td>$ 23,608</td><td>$ 178</td><td>$ 52,037</td><td>$ 12,882</td><td>$ 2,048</td><td>$ 66,967</td></tr><tr><td>At December 31, 2014</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows from production</td><td>$ 138,385</td><td>$ 67,102</td><td>$ 103,304</td><td>$ 99,741</td><td>$ 142,541</td><td>$ 18,168</td><td>$ 569,241</td><td>$ 144,721</td><td>$ 37,511</td><td>$ 751,473</td></tr><tr><td>Future production costs</td><td>(42,817)</td><td>(30,899)</td><td>(29,002)</td><td>(34,359)</td><td>(12,744)</td><td>(10,814)</td><td>(158,625)</td><td>(30,015)</td><td>(17,061)</td><td>(205,701)</td></tr><tr><td>Future development costs</td><td>(13,616)</td><td>(8,283)</td><td>(9,486)</td><td>(12,629)</td><td>(15,681)</td><td>(3,031)</td><td>(62,726)</td><td>(19,349)</td><td>(4,454)</td><td>(86,529)</td></tr><tr><td>Future income taxes</td><td>(27,129)</td><td>(8,445)</td><td>(47,884)</td><td>(24,225)</td><td>(34,235)</td><td>(2,692)</td><td>(144,610)</td><td>(28,607)</td><td>(6,634)</td><td>(179,851)</td></tr><tr><td>Undiscounted future net cash flows</td><td>54,823</td><td>19,475</td><td>18,942</td><td>28,528</td><td>79,881</td><td>1,631</td><td>203,280</td><td>66,750</td><td>9,362</td><td>279,392</td></tr><tr><td>10 percent midyear annual discount for timing of estimated cash flows</td><td>(23,257)</td><td>(12,082)</td><td>(6,145)</td><td>(8,570)</td><td>(43,325)</td><td>(380)</td><td>(93,759)</td><td>(34,987)</td><td>(5,294)</td><td>(134,040)</td></tr><tr><td>Standardized Measure</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Cash Flows</td><td>$ 31,566</td><td>$ 7,393</td><td>$ 12,797</td><td>$ 19,958</td><td>$ 36,556</td><td>$ 1,251</td><td>$ 109,521</td><td>$ 31,763</td><td>$ 4,068</td><td>$ 145,352</td></tr></table>



## 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.”

<table><tr><td>Millions of dollars</td><td>Consolidated Companies</td><td>Affiliated Companies</td><td>Total Consolidated and Affiliated Companies</td></tr><tr><td>Present Value at January 1, 2014</td><td>$ 114,378</td><td>$ 42,538</td><td>$ 156,916</td></tr><tr><td>Sales and transfers of oil and gas produced net of production costs</td><td>(38,935)</td><td>(7,578)</td><td>(46,513)</td></tr><tr><td>Development costs incurred</td><td>25,687</td><td>1,963</td><td>27,650</td></tr><tr><td>Purchases of reserves</td><td>255</td><td>—</td><td>255</td></tr><tr><td>Sales of reserves</td><td>(1,178)</td><td>—</td><td>(1,178)</td></tr><tr><td>Extensions, discoveries and improved recovery less related costs</td><td>3,956</td><td>215</td><td>4,171</td></tr><tr><td>Revisions of previous quantity estimates</td><td>17,462</td><td>1,573</td><td>19,035</td></tr><tr><td>Net changes in prices, development and production costs</td><td>(34,953)</td><td>(12,496)</td><td>(47,449)</td></tr><tr><td>Accretion of discount</td><td>18,884</td><td>5,926</td><td>24,810</td></tr><tr><td>Net change in income tax</td><td>3,965</td><td>3,690</td><td>7,655</td></tr><tr><td>Net change for 2014</td><td>(4,857)</td><td>(6,707)</td><td>(11,564)</td></tr><tr><td>Present Value at December 31, 2014</td><td>$ 109,521</td><td>$ 35,831</td><td>$ 145,352</td></tr><tr><td>Sales and transfers of oil and gas produced net of production costs</td><td>(17,145)</td><td>(3,637)</td><td>(20,782)</td></tr><tr><td>Development costs incurred</td><td>21,703</td><td>1,863</td><td>23,566</td></tr><tr><td>Purchases of reserves</td><td>2</td><td>—</td><td>2</td></tr><tr><td>Sales of reserves</td><td>(109)</td><td>—</td><td>(109)</td></tr><tr><td>Extensions, discoveries and improved recovery less related costs</td><td>1,415</td><td>—</td><td>1,415</td></tr><tr><td>Revisions of previous quantity estimates</td><td>9,171</td><td>3,607</td><td>12,778</td></tr><tr><td>Net changes in prices, development and production costs</td><td>(143,055)</td><td>(37,056)</td><td>(180,111)</td></tr><tr><td>Accretion of discount</td><td>18,179</td><td>4,965</td><td>23,144</td></tr><tr><td>Net change in income tax</td><td>52,355</td><td>9,357</td><td>61,712</td></tr><tr><td>Net change for 2015</td><td>(57,484)</td><td>(20,901)</td><td>(78,385)</td></tr><tr><td>Present Value at December 31, 2015</td><td>$ 52,037</td><td>$ 14,930</td><td>$ 66,967</td></tr><tr><td>Sales and transfers of oil and gas produced net of production costs</td><td>(14,415)</td><td>(2,788)</td><td>(17,203)</td></tr><tr><td>Development costs incurred</td><td>12,732</td><td>2,473</td><td>15,205</td></tr><tr><td>Purchases of reserves</td><td>(41)</td><td>—</td><td>(41)</td></tr><tr><td>Sales of reserves</td><td>528</td><td>—</td><td>528</td></tr><tr><td>Extensions, discoveries and improved recovery less related costs</td><td>1,231</td><td>(917)</td><td>314</td></tr><tr><td>Revisions of previous quantity estimates</td><td>12,851</td><td>946</td><td>13,797</td></tr><tr><td>Net changes in prices, development and production costs</td><td>(37,198)</td><td>(9,798)</td><td>(46,996)</td></tr><tr><td>Accretion of discount</td><td>7,888</td><td>2,113</td><td>10,001</td></tr><tr><td>Net change in income tax</td><td>6,740</td><td>2,755</td><td>9,495</td></tr><tr><td>Net change for 2016</td><td>(9,684)</td><td>(5,216)</td><td>(14,900)</td></tr><tr><td>Present Value at December 31, 2016</td><td>$ 42,353</td><td>$ 9,714</td><td>$ 52,067</td></tr></table>



# 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, perfluorocarbons 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.
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 recoverable 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.

Reserves Crude oil and natural gas contained in underground rock formations called reservoirs and saleable hydrocarbons extracted from oil sands, shale, coalfields 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 economic 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, 2016.

Resources Estimated quantities of oil and gas resources are recorded under Chevron’s 6P system, which is modeled 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 commercially. 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 similar terms represent estimated remaining quantities 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 development 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 hydrocarbon 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, production 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 stockholder 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 stockholders' 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 stockholders as measured by stock price appreciation and reinvested dividends for a period of time.



# board of directors



## John S. Watson, 60

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.

## Michael K. Wirth, 56

Vice Chairman of the Board since February 2017 and Executive Vice President, since 2016. Responsible for supply and trading, the company’s midstream operating units engaged in transportation and power, as well as corporate strategy, business development, and policy, government and public affairs. 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.

## Wanda M. Austin, 62

Director since 2016. She holds an adjunct Research Professor appointment at the University of Southern California’s Viterbi School’s Department of Industrial and Systems Engineering. Previously she served as President and Chief Executive Officer of the Aerospace Corporation, a leading architect for the United States’ national security space programs. (2, 3)

## Linnet F. Deliy, 71

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, 71

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, 58

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. (2,3)



## Enrique Hernandez Jr., 61

Director since 2008. He is Chairman, Chief Executive Officer and President of Inter-Con Security Systems, Inc., a global provider of security and facility support services to governments, utilities and industrial customers. He is Chairman of the Board of McDonald's Corporation and a Director of Nordstrom, Inc., (retiring May 16, 2017) and Wells Fargo & Company. (2, 4)

## Jon M. Huntsman Jr., 57

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 Holdings Inc. (1)

## Charles W. Moorman IV, 65

Director since 2012. He is President and Chief Executive Officer of Amtrak, a passenger rail service provider. He is a retired Chairman of the Board and Chief Executive Officer of Norfolk Southern Corporation, a freight and transportation company. He also served as President at Norfolk Southern from 2004 to 2013. He is a Director of Duke Energy Corporation. (1)

## Dambisa F. Moyo, 48

Director since 2016. She is Chief Executive Officer of Midlstrom LLC, focusing on the global economy and international affairs. Previously, she worked at Goldman Sachs in various roles and at the World Bank in Washington, D.C. She is the author of three New York Times bestsellers and is a Director of Barclays plc, Barrick Gold Corporation and Seagate Technology. (1)

## Ronald D. Sugar, 68

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 Air Lease Corporation, Amgen Inc. and Apple Inc. (3, 4)

## Inge G. Thulin, 63

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)

## Committees of the Board

1) Audit: Charles W. Moorman IV, Chair

2) Public Policy: Linnet F. Deliy, Chair

3) Board Nominating and Governance: Ronald D. Sugar, Chair

4) Management Compensation: Enrique Hernandez Jr., Chair



# corporate officers



## Pierre R. Breber, 52

Executive Vice President, Downstream and Chemicals, since 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, 52

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 Chief Corporate Counsel, Corporation Law Department; General Counsel, Chevron Asia Pacific Exploration and Production Company. Joined the company in 2002.

## Joseph C. Geagea, 57

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, 58

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, 64

Vice President, Human Resources and Corporate Services, since 2008. Responsible for human resources, security, aviation, 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, 57

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, 62

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 the company in 1986.



## Rhonda J. Morris, 51

Vice President, Human Resources, since 2016. Responsible for human resources, diversity, ombuds, and global health and medical groups. Joined the company in 1991.

## Joseph M. Naylor, 56

Vice President, Policy, Government and Public Affairs, since 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.

## Mark A. Nelson, 53

Vice President, Strategic Planning, since 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, 51

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.

## R. Hewitt Pate, 54

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.

## Jay R. Pryor, 59

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.

## Randolph S. (Randy) Richards, 62

Vice President and Treasurer since 2016. Responsible for banking, financing, cash management, insurance, pension investments, and credit and receivables activities across the corporation. Previously Vice President, Finance, Upstream. Joined the company in 1979.

## Patricia E. Yarrington, 61

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.




# 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 505000
Louisville, KY 40233-5000
800 368 8357
www.computershare.com/investor

Overnight correspondence should be sent to:
Computershare
462 South 4 \( ^{th} \)  Street
Suite 1600
Louisville, KY 40202

The Computershare Investment Plan is a direct stock purchase and dividend reinvestment plan.

## 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. CDT, Wednesday, May 31, 2017, at: Chevron U.S.A., Inc. 6301 Deauville Boulevard Midland, TX 79706

## Electronic access

In an effort to conserve natural resources and reduce the cost of printing and mailing proxy materials, we encourage stockholders to register to receive these documents via email and vote their shares on the Internet. Stockholders 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. Beneficial stockholders may be able to request electronic access by contacting their broker or bank, or Broadridge Financial Solutions at: www.icsdelivery.com/cvx/.

## Investor information

Securities analysts, portfolio managers and representatives of financial institutions may contact:
Investor Relations
Chevron Corporation
6001 Bollinger Canyon Road, A3140
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 Chevron’s consolidated subsidiaries 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




Publications and other news sources
The Annual Report, distributed in
April, summarizes the company’s
financial performance in the
preceding 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 contacting:

Investor Relations
Chevron Corporation
6001 Bollinger Canyon Road, A3140
San Ramon, CA 94583-2324
925 842 5690
Email: invest@chevron.com
The 2016 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 2016 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.

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Chevron Corporation
6001 Bollinger Canyon Road, San Ramon, CA 94583-2324 USA
www.chevron.com

© 2017 Chevron Corporation. All rights reserved.





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