Chevron Annual Report 2019

FY2019 Annual Report · Chevron

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Chevron Corporation
6001 Bollinger Canyon Road, San Ramon, CA 94583-2324 USA
www.chevron.com
Chevron Corporation
6001 Bollinger Canyon Road, San Ramon, CA 94583-2324 USA
© 2020 Chevron Corporation. All rights reserved.
www.chevron.com

10% Recycled. 100% Recyclable.
100% Recyclable

912-0984
912-0983

2019 annual report

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rising to the challenge

For 140 years, the people of Chevron have been solving the most complex energy challenges against
the backdrop of ever-changing expectations.

This legacy informs our approach to everything we do — from high ethical standards and a passion
for operational excellence to strict capital discipline and transparent risk management. And it drives
our enduring pursuit to be the leader in the future of energy, known for delivering responsible and
sustainable results. Across our Upstream, Downstream and Midstream businesses, this mindset
pushes us to invest in cutting-edge technologies, strive for new innovations and develop the
next generation of problem-solvers.

Over our entire history, we have strived to meet the ever-evolving expectations of our stakeholders,
while delivering the affordable, reliable, ever-cleaner energy that enables human progress.

The right way.
The responsible way.
The Chevron Way.

On the cover: An employee at Chevron’s Pascagoula, Mississippi, refinery uses a HoloLens® augmented reality headset to transmit what she is
seeing in the field to a remote expert, enabling real-time collaboration across the globe. Through our partnership with Microsoft, Chevron is an early
adopter of the HoloLens technology, and our input is informing future model design. HoloLens technology enables Chevron to improve efficiency,
minimize downtime and reduce travel costs.

A digital version of this report is available at www.chevron.com/annualreport2019

HoloLens is a federally registered trademark of Microsoft Corporation.

table of contents

II letter to stockholders

X board of directors and corporate officers

27 financial review

VI winning in any environment

XII chevron by the numbers

91 five-year financial summary

VII our sources of competitive advantage

XIV chevron stock performance

104 our history

VIII lead director: one-on-one

XV financial and operating highlights

105 glossary of energy and financial terms

IX process safety

XVI strategies

106 stockholder and investor information

Since beginning operation in 1963, the Pascagoula Refinery
has grown to be Chevron’s largest U.S. refinery and one of the top
petroleum refineries in the United States.

$298
million
direct local
economic impact

3,312
employed
total employees and contractors
working at the refinery

350,000
barrels
per day of
operable capacity

Photo: The Pascagoula Refinery is the largest Chevron-operated refinery. With an operable capacity of 350,000 barrels per day, it supplies fuels
and specialty products such as premium base oil. Much of the 3,000-acre property is home to native U.S. Gulf Coast wildlife, and the refinery goes
beyond local environmental requirements to protect its wetland and forest habitats.

to our stockholders
our purpose

Affordable, reliable energy serves a vital human

need. It has driven the greatest advancements in

living standards in human history, and it enables

modern life today. We are proud to play a role in

providing the energy that makes human

progress possible.

This starts with our people.

At Chevron, we believe our greatest

resource is not the resource in the

ground — but rather the inspiration,

creativity and ingenuity

of our people.

Today, we are working to meet one of

humanity’s greatest opportunities: delivering

the affordable, reliable, ever-cleaner energy a

growing world requires to meet its essential

needs, while also achieving its environmental

goals. Rising to this challenge requires us to

perform at the highest level and inspires us

to strengthen a culture where we continually

raise performance standards.

As I write this letter, the world is facing

extraordinary events, with volatile markets and

an evolving global pandemic. While we cannot

predict the future, we can do what we do best:

provide the energy that society depends upon.

Chevron is well prepared to meet this challenge.

Our unwavering commitment to the health and

safety of our workforce, operating reliably, and

capital and cost discipline are core principles

that will serve us well as we work to meet the

vital energy needs of the world.

Chevron Corporation 2019 Annual Report
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to our stockholders

our results

In 2019, we faced an environment defined by volatile energy
markets. Global economic growth slowed to its lowest pace
since 2008 amid stagnant manufacturing and trade tensions.
Heightened political uncertainty included tighter U.S. sanctions
on Iran and Venezuela and unrest in the Middle East.

To counter slowing demand and surging U.S. supply, OPEC and
Russia adopted a more proactive oil market management role.
In natural gas markets, warmer weather and slower economic
activity tempered demand, while supply continued to grow at
a healthy pace through rising U.S. production and the ongoing
build-out of new liquefied natural gas (LNG) capacity.

Our results reflect balance, consistency and discipline
across all our businesses. In 2019, we led our peer group
on several key metrics as we:

delivered
15.2%

Total Stockholder Returns (TSR)
in 2019 and 8.5% over the past decade —
both leading the peer group

increased our dividend payout
6.2%

marking the 32nd consecutive
year of increased per-share
dividend payouts

increased share repurchases to a run-rate of

$5 billion per year

generated more than
$27 billion

in cash flow from operations and
returned $13 billion to shareholders1

lowered our net debt ratio to
12.8%2

further strengthening
the company’s balance sheet

Our Upstream business delivered record production even as
we streamlined our operational and geographic footprint. We
produced 3.06 million oil-equivalent barrels per day in 2019,
up more than 4 percent from 2018. We also embarked on
changes to define the next evolution of this segment, enhancing
our ability to compete in any price environment by driving
efficiencies, evolving our portfolio and optimizing the value
chain. Production increases in 2019 were driven by Permian
Basin growth, the ramp up of the Wheatstone LNG project
and other major capital projects. This growth was partially
offset by base decline and the impact of asset sales, primarily
in Denmark and the United Kingdom.

In Downstream & Chemicals, we strengthened our position in
key markets. Chevron Phillips Chemical Company announced
agreements with Qatar Petroleum to jointly develop new
petrochemical plants.

We enhanced our U.S. Gulf Coast value chain by purchasing the
Pasadena Refinery, allowing us to process Permian crude. We
signed an agreement to acquire terminals and service stations
in Australia. To position us for the energy transition, we are
also testing electric vehicle chargers at stations, increasing
the availability of renewable diesel and developing renewable
natural gas facilities.

Our Midstream business expanded market access for our
growing Permian production by increasing pipeline capacity
and adding offshore terminal access to open new export
opportunities. Chevron Shipping added five new tankers
to our fleet that feature technological advancements that
significantly reduce emissions. Our Pipeline and Power team
pursued opportunities to reduce energy consumption, cut
emissions and increase renewables in support of our business.

1 Includes $9 billion in dividends and $4 billion in share repurchases
2 See page 41 for additional information

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our commitment

We are proud of these results. But what was good before
simply isn’t good enough anymore. Expectations are rising
from all stakeholders — and responding to these expectations
is a responsibility we take seriously and a challenge we
embrace wholeheartedly. Our ability to continue to create
value for our stakeholders relies on maintaining financial,
operational and cultural strength — and we are committed
to building on that strength.

The 2020 capital and
exploratory program supports
investments in our world-
class Permian Basin position,
Tengizchevroil in Kazakhstan
and deepwater opportunities
in the Gulf of Mexico.

We elected not to pursue a major acquisition at a price that
would have eroded shareholder value and have announced
plans to reduce funding to gas-related assets, including
Appalachia Shale and Kitimat LNG.

Our disciplined approach to capital prioritizes investment in
lower risk, higher return projects that we expect to generate
cash flow within a few short years. Our flexible capital
program, coupled with our industry-leading balance sheet
and low dividend breakeven price, ensure that we continue
to have the cash-generating capacity to be a leader in
shareholder distributions.

health, environment
and safety
written safe-work practices are a
core part of our comprehensive
safety program

We are committed to a culture of operational excellence
that places the highest priority on process safety, the health
and safety of our workforce, and protection of communities
and the environment.

Our energy transition efforts prioritize lowering carbon
intensity cost efficiently, increasing renewables in support
of our business, and investing in future breakthrough
technologies. Our strong governance and disclosures are
aligned with the Financial Stability Board’s Task Force on
Climate-related Financial Disclosures (TCFD) and highlighted
in our 2019 Climate Change Resilience report update. And
we are in the process of aligning our ESG reporting with the
Sustainability Accounting Standards Board (SASB).

our future
We are fortunate to live at a time when the human condition
has never been better and prospects for the future have never
been brighter. We know the world faces challenges. But we
also know, from experience, the path to surmounting any
challenge: pursuit of innovation, commitment to partnership,
trust in markets and belief in the power of human energy.

This is why we view our commitment to shareholders and stake-
holders not only in financial terms but also in human terms.

An investment in Chevron is an investment that drives human
progress, lifts millions out of poverty and makes modern
life possible. It is an investment that values operating with
integrity, getting results the right way and striving for
humanity’s highest aspirations: to create a more prosperous,
equitable and sustainable world.

We are grateful for your support and honored by the trust you
place in us.

Sincerely,

Michael K. Wirth
Chairman of the Board and Chief Executive Officer

Chevron Corporation 2019 Annual Report
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Photo: Divers routinely conduct underwater
inspection and maintenance of our deep sea
operations. As in all areas of our business,
process and personal safety are top of mind.

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positioning chevron
to win in any environment
Building strength for the future starts with a focused, no-excuses mindset. It requires us to
anticipate and be proactive — so no matter what market conditions we face or what regulatory
and operating environments we confront, we can overcome obstacles and deliver industry-leading
results. Our strategy focuses on five elements that differentiate Chevron from its competitors:

an advantaged
portfolio

resilience
to price downside

commitment
to capital discipline

a superior capacity to
return cash to shareholders

sustainable value
creation for stakeholders

Photo: This production platform
in the Escravos area, offshore
Nigeria, is part of the natural gas
Sonam Field Development Project,
which started production in 2017.

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our sources of
competitive advantage

expertise
We leverage nearly a century and a
half of expertise to navigate global
markets, thrive in diverse economies
and cultures, operate in complex
regulatory environments, and develop
new energy solutions.

assets
We have diversified, high-quality
assets around the world that underpin
our financial strength and present
opportunities for future development.

purpose
We are committed to delivering the
energy that improves lives and enables
human progress, within a company
culture defined by trust, responsibility
and integrity. Our purpose guides our
aspirations, motivations and operations.

we put people at the center
of everything we do
We believe our greatest resource is the inspiration, creativity and ingenuity of our people.

Over our entire history, Chevron problem-solvers have strived to meet the evolving

expectations of our stakeholders, tackling the most complex challenges to deliver the

affordable, reliable, ever-cleaner energy that enables human progress.

partners
We partner around the world to deliver
the energy of today and explore the
energy opportunities of tomorrow.
Delivering energy — from exploration to
extraction to production to distribution —
requires a network of trusted partners
who succeed when we succeed.

technology
We leverage technology to push
energy’s frontiers. Every day, we scan
the landscape for opportunities to
make the world’s energy cleaner and
more affordable, our environmental
footprint smaller, and the industry’s
workforce safer.

financial strength
Our financial strength supports our
goal to invest in future opportunities
and deliver sustained shareholder value
in any economic environment. We put
our financial strength to work to shape
the future of energy — identifying the
most promising trends, making smart
investments and scaling the most
sustainable solutions.

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lead director: one-on-one
Chevron’s corporate secretary Mary Francis sits down
with Chevron’s lead independent director Ronald Sugar
as he shares his insights on current events and
topics that are top of mind for investors.

Francis: Chevron now ties executive compensation to
specific greenhouse gas intensity reduction metrics.
What prompted this change, and when will we know if
it has been effective?

Francis: Forecasts indicate the low-price environment
is likely to continue for the foreseeable future. How does
the Board ensure Chevron’s strategy will deliver value
through a challenged business cycle?

Sugar: This is a prime example of the accountability
called for by the Board. The metrics are not only tied to
compensation for executives, they affect compensation
for nearly all employees, about 45,000 worldwide.
The Board took this action to send a clear signal that
lowering Chevron’s carbon intensity is important. The
four metrics are based on net greenhouse gas intensity,
on an equity basis. Setting targets on an equity basis
means that the measure includes all Chevron operated
and non-operated production. A timeline of 2016-2023
is used to align with the period between the ratification
of the Paris Agreement and the first “stocktake.” We
believe tying these metrics to compensation is an
effective means to drive results, draw out the most
innovative solutions, and align the daily work of
employees to these metrics.

Francis: What was the Board’s response to the
company’s fourth quarter 2019 impairments and
write-down?

Sugar: The impairments and write-downs were a
result of management’s capital funding decisions.
The funding decisions were driven by management’s
focus on assets that generate the highest returns
for shareholders and demonstrate the company’s
commitment to capital discipline. Management made
the decision, with the Board’s support, to cut funding
for certain assets, primarily the Marcellus and Utica
shale, and the Kitimat LNG project, which could
no longer compete for investment funds. Capital
investment will instead be allocated to assets that
are expected to generate higher returns. Impairment
charges for other assets that remain in the portfolio
were the result of a reduction in management’s long-
term outlook for commodity prices. It’s ironic that
the write-down is due in part to the energy industry’s
success in increasing production of affordable energy.

Sugar: This is a complex business with long lead times,
so the strategy must always focus beyond the current
business cycle. Chevron does not base decisions on price
forecasts, and certainly not near-term prices, alone. The
company consults with experts and evaluates data on a
variety of fronts — geopolitical, technological, societal
and economic — to drive a strategy that is resilient to
withstand the downturns and agile to capitalize on
the upturns when the market shifts. This disciplined
approach has resulted in Chevron being able to increase
the annual per-share dividend payout again in 2019.

Francis: What is the Board’s role in overseeing
Chevron’s transition to a lower carbon future?

Sugar: The Board provides guidance and oversight
to management with respect to Chevron’s strategy,
including its strategy to navigate the energy transition
(see Board oversight discussion in 2020 Proxy Statement,
pp. 20-22). This means that the Board helps management
determine how to position the company for success in
a lower carbon future. It means we oversee Chevron’s
risk management policies, processes and practices
related to climate change. And it means we must
challenge the status quo. In 2018 and 2019, the Board
participated in expanded strategic planning sessions
that included third-party experts to discuss energy
transition issues. As the International Energy Agency
has stated, there is no single or simple solution to
addressing climate change. The solutions will come
from multiple points of innovation. Chevron’s strategy
to navigate the energy transition focuses on lowering
its carbon intensity, increasing the use of renewables,
and investing in breakthrough technologies. The Board
asked management to develop metrics that demonstrate
a commitment to transparency and accountability,
and we worked with management to establish specific
greenhouse gas intensity reduction metrics that
encourage continuous improvement.

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process safety
Developing the energy that powers the world forward comes with the responsibility to contain
that energy from the point of discovery, through ships, pipelines, refineries and service stations.
We call the work we do to meet this responsibility “process safety.”

Photo: Two Chevron colleagues review valve tags during a field walk in the alkylation unit at our Richmond Refinery in Richmond, California. Our
workforce is dedicated to delivering value through safe and reliable performance by managing the integrity of our equipment and operating systems.

Delivering value through safe and reliable performance

Why does process safety matter?

Process safety includes risk analysis, engineering and the
practices that help us manage the integrity of our operating
systems. In fact, nearly three-quarters of our workforce is
dedicated to designing, constructing, operating and
maintaining our equipment to safely and reliably provide
energy to customers.

Process safety is important to
our customers and is ever-
present at our service stations:
safety pylons protect pumps
from damage, breakaway hoses
help ensure fuel is contained if a
customer drives away with the
nozzle, and emergency buttons
act to shut down any machinery
in case of an emergency.

Sustaining a high level of process safety protects our workforce,
the community and the environment. We measure our progress
by the presence of effective safeguards, which in turn leads
to fewer incidents. In building better safeguards over the last
decade, we have significantly reduced the number of incidents,
even as our portfolio has become more complex.

As we strive to improve continually in process safety, we
benefit by viewing our business from an “asset class” approach:
similar types of assets should have similar safeguards to prevent
similar incidents. While much of our business is organized
geographically, we increasingly look at subsets of our business
on a more global basis, with support teams set up to help
monitor performance and drive best practices across operations.
We benchmark performance against our competitors and
freely share process safety practices as we collectively strive to
eliminate losses of containment in our industry.

Chevron’s commitment to process safety extends beyond our company. We actively participate in several leading efforts to improve safety

performance in the industry. We adopt practices from others, collaborate on the development of industry standards and practices, and continue

to increase effectiveness of safeguards. Our chemical plants are certified in the American Chemistry Council’s Responsible Care* program for

safety, environment and process safety management. We also validated our Operational Excellence Management System design against Center

for Chemical Process Safety guidance on Risk Based Process Safety, and our effectiveness against their Vision 20/20 industry tenets.

*Responsible Care is a federally registered service mark of the American Chemistry Council, Inc.

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board of directors
The Board of Directors of Chevron directs the affairs of the corporation and is committed to
sound principles of corporate governance. The Directors bring a proven track record of success
across a broad range of experiences at the policymaking level.

Michael K. (Mike) Wirth, 59
Chairman of the Board and Chief Executive Officer since February 2018. He was elected to these positions by Chevron’s
Independent Directors in September 2017 and assumed the roles on February 1, 2018. Prior to his current role, Wirth served as
vice chairman of the Board in 2017 and executive vice president of Midstream and Development for Chevron Corporation from
2016 to 2018. In that role, he was responsible for supply and trading, shipping, pipeline, and power operating units; corporate
strategy; business development; and policy, government and public affairs.

Wirth was executive vice president of Downstream & Chemicals from 2006 to 2015. Prior to that, he served as president of
Global Supply and Trading from 2003 to 2006. In 2001, Wirth was named president of Marketing for Chevron’s Asia/Middle
East/Africa business, based in Singapore. He also served on the board of directors for Caltex Australia Limited and GS Caltex
Corporation in South Korea.

Wirth serves on the board of directors of Catalyst. He also serves on the board of directors and executive committee of the
American Petroleum Institute and is a member of the National Petroleum Council, the Business Roundtable, the World Economic
Forum International Business Council and the American Society of Corporate Executives. Wirth joined Chevron in 1982 as a
design engineer. He earned a bachelor’s degree in chemical engineering from the University of Colorado in 1982.

Wanda M. Austin, 65
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. She
is a retired president and chief executive officer of The Aerospace
Corporation, a leading architect for the United States’ national
security space programs. She is a director of Amgen Inc. and
Virgin Galactic Holdings, Inc. (2,4)

John B. Frank, 63
Director since 2017. He is vice chairman of Oaktree Capital Group,
LLC, a global investment management company with expertise in
credit strategies. He is one of four members of Oaktree’s Executive
Committee and was previously the firm’s principal executive officer.
He is a director of Oaktree Capital Group, LLC, and its subsidiaries:
Oaktree Acquisition Corporation, Oaktree Specialty Lending
Corporation, and Oaktree Strategic Income Corporation. (1)

Alice P. Gast, 61
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. (2,4)

Enrique Hernandez Jr., 64
Director since 2008. He is chairman and chief executive officer 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.
(3,4)

Charles W. Moorman IV, 68
Director since 2012. He is a retired chairman of the board and
chief executive officer of Norfolk Southern Corporation, a freight
and transportation company. He is a senior advisor to Amtrak,
a passenger rail service provider, having previously served as
Amtrak’s president and chief executive officer. He is a director of
Duke Energy Corporation and Oracle Corporation. (1)

Dambisa F. Moyo, 51
Director since 2016. She is chief executive officer of Mildstorm
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 four
New York Times bestsellers and is a director of 3M Company. (1)

Debra Reed-Klages, 63
Director since 2018. She is a retired chairman, chief executive
officer and president of Sempra Energy, an energy-services
holding company. Previously, she was executive vice president
of Sempra Energy and president and chief executive officer of
San Diego Gas & Electric and Southern California Gas Co. She is a
director of Caterpillar Inc. and Lockheed Martin Corporation. (3,4)

Ronald D. Sugar, 71
Lead Director since 2015 and a Director since 2005. He is an
advisor and retired chairman and chief executive officer of Northrop
Grumman Corporation, an aerospace and defense company. He is a
senior advisor to Ares Management LLC; Bain & Company; Temasek
Americas Advisory Panel, Singapore; G100 Network; and World 50.
He is a director of Amgen Inc., Apple Inc., Uber Technologies, Inc.,
and Air Lease Corporation (retiring May 2020). (2,3)

D. James Umpleby III, 62
Director since 2018. He is chairman and chief executive officer of
Caterpillar Inc., a leading manufacturer of construction and mining
equipment, diesel and natural gas engines, industrial gas turbines,
and diesel-electric locomotives. Previously, he was group president
of Caterpillar’s Energy and Transportation business segment. (2,3)

Committees of the Board
1 Audit: Charles W. Moorman IV, Chair
2 Board Nominating and Governance: Ronald D. Sugar, Chair
3 Management Compensation: Enrique Hernandez Jr., Chair
4 Public Policy: Wanda M. Austin, Chair

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corporate officers

Pierre R. Breber, 55
Vice President and Chief Financial Officer since 2019. Responsible
for comptroller, tax, treasury, audit and investor relations activities
worldwide. Previously, Executive Vice President of Downstream
and Chemicals. Joined the company in 1989.

Mary A. Francis, 55
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. Joined the company in 2002.

Joseph C. Geagea, 60
Executive Vice President, Technology, Projects and Services,
since 2015. Responsible for energy technology; major capital
projects; procurement; IT; complex process facilities; environmental
management; HES; business and real estate; digital initiatives; and
talent selection. Previously, Senior Vice President, Technology,
Projects and Services, and Corporate Vice President and President,
Chevron Gas & Midstream. Joined the company in 1982.

David A. Inchausti, 56
Vice President and Comptroller since 2019. Responsible for
corporatewide accounting, financial reporting and analysis,
internal controls, accounting policy, and finance employee
development. Previously, Deputy Comptroller, and Upstream
Comptroller. Prior to that, 20 years abroad in multiple business
units. Joined the company in 1988.

James W. Johnson, 61
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.

Charles N. Macfarlane, 65
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.

Navin K. Mahajan, 53
Vice President and Treasurer since 2019. Responsible for
Chevron’s banking, financing, cash management, insurance,
pension investments, and credits and receivables activities.
Previously, Vice President of Finance for Downstream & Chemicals,
Assistant Treasurer of Operating Company Financing, and Chief
Compliance Officer. Joined the company in 1996.

Rhonda J. Morris, 54
Vice President since 2016 and Chief Human Resources Officer
since 2019. Responsible for human resources, diversity and
inclusion, ombuds, and employee assistance/work life services.
Previously, Vice President, Human Resources, Downstream &
Chemicals. Joined the company in 1991.

Mark A. Nelson, 56
Executive Vice President, Downstream & Chemicals, since
March 2019. Responsible for directing the company’s worldwide
manufacturing, marketing, lubricants, chemicals and Oronite
additives businesses. Also oversees Chevron’s joint venture
Chevron Phillips Chemical Company. Previously, Vice President,
Midstream, Strategy & Policy. Joined the company in 1985.

Bruce L. Niemeyer, 58
Vice President, Strategy & Sustainability, since February 2018.
Responsible for the company’s strategic direction, resource
allocation, and sustainability efforts. Previously, Vice President
of Chevron’s Mid-Continent Business Unit; Vice President of the
Appalachian/Michigan Strategic Business Unit; and General
Manager of Strategy and Planning for Chevron North America
Exploration & Production. Joined the company in 2000.

Colin E. Parfitt, 56
Vice President, Midstream, since 2019. Responsible for Chevron’s
Midstream business, including supply and trading activities,
shipping, pipeline, and power and energy management. Previously,
President, Supply and Trading. Joined the company in 1995.

R. Hewitt Pate, 57
Vice President and General Counsel since 2009. Responsible for
directing the company’s worldwide legal affairs, governance and
compliance. Previously, Chair, Competition Practice, Hunton &
Williams LLP, Washington, D.C., and Assistant Attorney General,
Antitrust Division, U.S. Department of Justice. Joined the company
in 2009.

J. David (Dave) Payne, 59
Vice President, Health, Environment and Safety (HES),
since 2018. Responsible for HES strategic planning and issues
management, compliance assurance and emergency response.
Previously, Vice President of Drilling and Completions. Prior to that,
Drilling Manager in Thailand. Joined the company in 1981.

Jay R. Pryor, 62
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 the company in 1979.

Dale A. Walsh, 61
Vice President, Corporate Affairs, since 2019. Responsible for
overseeing government affairs, public affairs, social investment
and performance, and the company’s worldwide efforts to protect
and enhance its reputation. Previously, President, Americas
Products, and President, Lubricants. Joined the company in 1983.

Executive Committee
Michael K. Wirth, Pierre R. Breber, Joseph C. Geagea, James W. Johnson, Rhonda J. Morris
Mark A. Nelson, Colin E. Parfitt and R. Hewitt Pate.

Chevron Corporation 2019 Annual Report
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chevron by the numbers

Chevron is one of the world’s leading integrated energy companies. 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.

Our success is driven by a dedicated, diverse and highly skilled global workforce united by the vision,
values and strategies of The Chevron Way and a commitment to deliver industry-leading results and
superior stockholder value in any operating environment.

Chevron Corporation 2019 Annual Report
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We operate responsibly, applying advanced technologies,
capturing new high-return opportunities, and producing returns
in a socially and environmentally responsible manner. We take great
pride in enabling human progress by developing the energy that
improves lives and powers the world forward.

3.06
million barrels
net oil-equivalent
daily production1

11.4
billion barrels
net oil-equivalent
proved reserves2, 3

$237.4
billion
total assets2

$139.9
billion
sales and other
operating revenues1

Photo: Technician at the Chevron-operated Gorgon natural gas facility located on Barrow Island, approximately 60 kilometers off the northwest
coast of Western Australia. The facility includes a three-train, 15.6 million-metric-ton-per-year liquefied natural gas (LNG) plant, a carbon dioxide
injection system and domestic gas plant. In steady-state operations, Gorgon is anticipated to have the lowest greenhouse gas emissions intensity
of any LNG facility in Australia.

1 Year ended December 31, 2019
2 At December 31, 2019
3 For definition of “reserves,” see glossary
of energy and financial terms, page 105

Chevron Corporation 2019 Annual Report
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chevron stock performance

32 consecutive years
2019 marked the 32nd consecutive year we increased
the annual per-share dividend payout

Indexed dividend growth
Basis 2009 = 100

~6%
CVX compound annual
growth rate

$300

$200

$100

2009

2019

Chevron

S&P 500

Peer group: BP p.l.c. (ADS), ExxonMobil, Royal Dutch Shell p.l.c. (ADS), Total S.A. (ADR).
Dividends include both cash and scrip share distributions for European peers.

Total stockholder returns*
(as of 12/31/2019)

1-year

5-year

10-year

15.2%

30%

20%

10%

15%

5.6%

10%

8.5%

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

* Annualized total stockholder return (TSR) as of 12/31/2019. 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.

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 31, 2014, and ending
December 31, 2019, 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 have been entitled to receive and is adjusted for
stock splits. The interim measurement points show the
value of $100 invested on December 31, 2014, as of the
end of each year between 2015 and 2019.

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

200

175

150

125

100

$174

$132
$117

2014

2015

2016

2017

2018

2019

Chevron

S&P 500

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

Chevron Corporation 2019 Annual Report
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financial and operating highlights

Financial highlights1

Net income (loss) attributable to Chevron Corporation
Sales and other operating revenues
Cash flow from operating activities
Capital and exploratory expenditures2
Total assets at year-end
Total debt and finance lease obligations
Chevron Corporation stockholders’ equity at year-end
Common shares outstanding at year-end (Thousands)
Per-share data

Net income (loss) attributable to Chevron Corporation — diluted
Cash dividends
Chevron Corporation stockholders’ equity

Debt ratio3
Return on stockholders’ equity3
Return on average capital employed3

1 Millions of dollars, except per-share amounts
2 Includes equity in affiliates
3 See pages 40-41 for additional information

$
$
$
$
$
$
$

$
$
$

2019

2,924
139,865
27,314
20,994
237,428
26,973
144,213
1,868,000

1.54
4.76
77.20
15.8%
2.0%
2.0%

2018

2017

$
14,824
$ 158,902
30,618
$
20,106
$
$ 253,863
$
34,459
$ 154,554
1,888,670

$
$
$

7.74
4.48
81.83
18.2%
9.8%
8.2%

$
9,195
$ 134,674
20,338
$
18,821
$
$ 253,806
$
38,763
$ 148,124
1,890,534

$
$
$

4.85
4.32
78.35
20.7%
6.3%
5.0%

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

Dividends include both cash and scrip share distributions for European peers.

Total capital and exploratory expenditures 4
($ - Billions)

Operating expense 5
($ - Billions)

15%

10%

~$19 billion reduction
(2014–2019)

$40

$34

$22

$19

$20

$21

$50

$40

$30

$20

$10

$35

$30

$25

$20

$15

~$4 billion reduction
(2014–2019)

$30

$27

$25

$24

$25

$26

2014

2015

2016

2017

2018

2019

2014

2015

2016

2017

2018

2019

4 Includes expenditures by equity affiliates. See our Annual Reports on Form 10-K for

additional information.

5 Includes operating expense, selling, general and administrative expense, and other
components of net periodic benefit costs. See our Annual Reports on Form 10-K for
additional information.

Operating highlights6

Net production of crude oil, condensate, NGLs and synthetic oil7 (Thousands of barrels per day)
Net production of natural gas (Millions of cubic feet per day)
Total net oil-equivalent production (Thousands of oil-equivalent barrels per day)
Net proved reserves of crude oil, condensate, NGLs and synthetic oil7,8 (Millions of barrels)
Net proved reserves of natural gas8 (Billions of cubic feet)
Net proved oil-equivalent reserves8 (Millions of barrels)
Refinery input (Thousands of barrels per day)
Sales of refined products (Thousands of barrels per day)
Number of employees at year-end9

2019

2018

2017

1,865
7,157
3,058
6,521
29,457
11,431
1,564
2,577
44,679

1,782
6,889
2,930
6,790
31,576
12,053
1,608
2,655
45,047

1,723
6,032
2,728
6,542
30,736
11,665
1,661
2,690
48,596

Peer group: BP p.l.c. (ADS), ExxonMobil,

Royal Dutch Shell p.l.c. (ADS),

Total S.A. (ADR)

6 Includes equity in affiliates, except number of employees
7 NGLs = natural gas liquids
8 At year-end
9 Excludes service station personnel

Chevron Corporation 2019 Annual Report
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strategies
our strategies guide our actions
to deliver industry-leading results and
superior shareholder value in any
business environment

major business strategies

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

Downstream & 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 & 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: Colleagues work to ready new equipment for installation at our
Tengizchevroil joint venture in Kazakhstan where we’ve been operating
one of the world’s deepest oil fields and supporting local communities
for more than 20 years.

Chevron Corporation 2019 Annual Report
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Financial Table of Contents

Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Key Financial Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Earnings by Major Operating Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Business Environment and Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Operating Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Consolidated Statement of Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Selected Operating Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Financial Ratios and Metrics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Notes to the Consolidated Financial Statements
Note 1

Summary of Significant Accounting Policies . . . . . . . . . . . . . . 57

Note 2

Note 3

Note 4

Note 5

Note 6

Note 7

Note 8

Note 9

Changes in Accumulated Other Comprehensive Losses . . . 60

Information Relating to the Consolidated
Statement of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

New Accounting Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

Lease Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

Summarized Financial Data – Chevron U.S.A. Inc. . . . . . . . . 64

Fair Value Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

Financial and Derivative Instruments . . . . . . . . . . . . . . . . . . . 66

Assets Held for Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Off-Balance-Sheet Arrangements, Contractual Obligations,

Note 10

Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Guarantees and Other Contingencies . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Note 11

Earnings Per Share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Financial and Derivative Instrument Market Risk . . . . . . . . . . . . . . . . . . . 42

Note 12 Operating Segments and Geographic Data . . . . . . . . . . . . . . 68

Transactions With Related Parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Note 13

Investments and Advances . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Litigation and Other Contingencies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Note 14

Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Environmental Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Note 15

Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Critical Accounting Estimates and Assumptions . . . . . . . . . . . . . . . . . . . . 44

Note 16

Properties, Plant and Equipment . . . . . . . . . . . . . . . . . . . . . . . 77

New Accounting Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Note 17

Short-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Quarterly Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Note 18

Long-Term Debt

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Consolidated Financial Statements
Reports of Management

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Note 19

Accounting for Suspended Exploratory Wells . . . . . . . . . . . . . 79

Note 20

Stock Options and Other Share-Based Compensation . . . . . 80

Note 21

Employee Benefit Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

Note 22 Other Contingencies and Commitments . . . . . . . . . . . . . . . . . 87

Report of Independent Registered Public Accounting Firm . . . . . . . . . . . 50

Note 23

Asset Retirement Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Consolidated Statement of Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Note 24

Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Consolidated Statement of Comprehensive Income . . . . . . . . . . . . . . . . . 53

Note 25 Other Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Consolidated Balance Sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Note 26

Consolidated Statement of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Consolidated Statement of Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Summarized Financial Data – Chevron Phillips Chemical
Company LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

Five-Year Financial Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

Supplemental Information on Oil and Gas Producing Activities . . . . . . . . 92

CAUTIONARY STATEMENTS 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,” “will,” “budgets,” “outlook,” “trends,” “guidance,” “focus,” “on schedule,” “on track,” “is slated,” “goals,” “objectives,” “strategies,”
“opportunities,” “poised” 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 projected 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 efficiencies
associated with enterprise transformation initiatives; 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, terrorist acts and public health crises, such as pandemics and epidemics; crude oil production quotas or other actions that might be imposed by the
Organization of Petroleum Exporting Countries and other producing countries, or other natural or human causes beyond the company’s 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 pending or future
litigation; the company’s future acquisitions or dispositions of assets or shares or the delay or failure of such transactions to close based on required closing
conditions; the potential for gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-
specific taxes, tariffs, sanctions, 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 18 through 21 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.

27
Chevron Corporation 2019 Annual Report
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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Key Financial Results

Millions of dollars, except per-share amounts

Net Income (Loss) Attributable to Chevron Corporation
Per Share Amounts:

Net Income (Loss) Attributable to Chevron Corporation

– Basic
– Diluted

Dividends

Sales and Other Operating Revenues
Return on:

Capital Employed
Stockholders’ Equity

Earnings by Major Operating Area

Millions of dollars

Upstream

United States
International

Total Upstream

Downstream

United States
International

Total Downstream

All Other
Net Income (Loss) Attributable to Chevron Corporation1,2

1 Includes foreign currency effects:
2 Income net of tax, also referred to as “earnings” in the discussions that follow.

2019

2,924

1.55
1.54
4.76
139,865

2.0%
2.0%

2019

(5,094)
7,670

2,576

1,559
922

2,481

(2,133)
2,924

(304)

$
$
$
$

2018

14,824

2017

9,195

7.81
7.74
4.48
158,902

$
$
$
$

4.88
4.85
4.32
134,674

8.2%
9.8%

5.0%
6.3%

2018

2017

3,278
10,038

13,316

2,103
1,695

3,798

3,640
4,510

8,150

2,938
2,276

5,214

(2,290)
14,824

611

(4,169)
9,195

(446)

Refer to the “Results of Operations” section beginning on page 32 for a discussion of financial results by major operating
area for the three years ended December 31, 2019.

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, Indonesia, Kazakhstan, Myanmar, Mexico, Nigeria, the
Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Korea, Thailand,
the United Kingdom, the United States, and Venezuela.

Earnings of the company depend mostly on the profitability of its upstream business segment. The most significant factor
affecting the results of operations for the upstream segment is the price of crude oil, which is determined in global markets
outside of the company’s control. 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 stockholder value in any business environment.
Periods of sustained lower prices could result in the impairment or write-off of specific assets in future periods and cause the
company to adjust operating expenses and capital and exploratory expenditures, along with other measures intended to
improve financial performance. Similarly, impairments or write-offs may occur as a result of managerial decisions not to
progress certain projects in the company’s portfolio.

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 15 provides the company’s effective income tax rate for the last three years.

Refer to the “Cautionary Statements Relevant to Forward-Looking Information” on page 2 and to “Risk Factors” in Part I,
Item 1A, on pages 18 through 21 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. Asset dispositions and restructurings may result in significant gains or losses in future periods. The company’s

28
Chevron Corporation 2019 Annual Report
28

asset sale program for 2018 through 2020 is targeting before-tax proceeds of $5-10 billion. Proceeds related to asset sales were

$2.0 billion in 2018 and $2.8 billion in 2019.

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 production and inventory levels, technology advancements, production

quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC) or other producers, 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 and other applicable

laws and regulations.

The company continues to actively manage its schedule of work, contracting, procurement, and supply-chain activities to

effectively manage costs and support operational goals. Price levels for capital, 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, but not limited to: the general level of inflation, tariffs or other taxes imposed on goods or services, and

commoditized prices charged by the industry’s material and service providers. The spot markets for many services and

materials fell as overall industry drilling activity in North America declined in 2019, particularly onshore. However, as

industry activity contracts, financial pressure on suppliers has increased, which may limit further de-escalation and/or lead to

consolidation across the supplier community impacting costs. The international and offshore rig markets are also showing

some signs of weaknesses as activity has pulled back; however, pricing for some products and services remains resilient as

many suppliers have reset expectations of higher industry spend and instead are looking to higher pricing and margins on a

more limited scope of work. Chevron utilizes contracts with various pricing mechanisms, so there may be a delay in when

the company’s costs reflect the changes in market trends.

Capital and exploratory expenditures and operating expenses could also be affected by damage to production facilities caused

by severe weather or civil unrest, delays in construction, or other factors.

WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Spot Prices - Quarterly Average

Oil

$/bbl

Brent

WTI

Henry Hub

2017

2018

2019

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 majority of the company’s equity crude production is priced based on the Brent benchmark. The

Brent price averaged $64 per barrel for the full-year 2019, compared to $71 in 2018. Brent prices increased through the first

half of 2019 due to OPEC production cuts and U.S. sanctions on Iran and Venezuela. Prices then started to decline due to

heightened concerns about a slowing macro economy and weakening oil demand growth amid trade tensions between the

$/mcf

145363_10K.indd 28

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

asset sale program for 2018 through 2020 is targeting before-tax proceeds of $5-10 billion. Proceeds related to asset sales were
$2.0 billion in 2018 and $2.8 billion in 2019.

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 production and inventory levels, technology advancements, production
quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC) or other producers, 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 and other applicable
laws and regulations.

Key Financial Results

Millions of dollars, except per-share amounts

Net Income (Loss) Attributable to Chevron Corporation

Per Share Amounts:

Net Income (Loss) Attributable to Chevron Corporation

– Basic

– Diluted

Dividends

Sales and Other Operating Revenues

Return on:

Capital Employed

Stockholders’ Equity

Earnings by Major Operating Area

Millions of dollars

Upstream

United States

International

Total Upstream

Downstream

United States

International

Total Downstream

All Other

Net Income (Loss) Attributable to Chevron Corporation1,2

1 Includes foreign currency effects:

2 Income net of tax, also referred to as “earnings” in the discussions that follow.

area for the three years ended December 31, 2019.

Business Environment and Outlook

2018

14,824

2017

9,195

7.81

7.74

4.48

4.88

4.85

4.32

139,865

158,902

134,674

2.0%

8.2%

9.8%

5.0%

6.3%

2019

2018

2017

2019

2,924

1.55

1.54

4.76

(5,094)

7,670

2,576

1,559

922

2,481

(2,133)

2,924

(304)

3,278

10,038

13,316

2,103

1,695

3,798

3,640

4,510

8,150

2,938

2,276

5,214

(2,290)

14,824

611

(4,169)

9,195

(446)

Oil

$/bbl

Refer to the “Results of Operations” section beginning on page 32 for a discussion of financial results by major operating

Chevron is a global energy company with substantial business activities in the following countries: Angola, Argentina,

Australia, Azerbaijan, Bangladesh, Brazil, Canada, China, Colombia, Indonesia, Kazakhstan, Myanmar, Mexico, Nigeria, the

Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Korea, Thailand,

the United Kingdom, the United States, and Venezuela.

outside of the company’s control. 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 stockholder value in any business environment.

Periods of sustained lower prices could result in the impairment or write-off of specific assets in future periods and cause the

company to adjust operating expenses and capital and exploratory expenditures, along with other measures intended to

improve financial performance. Similarly, impairments or write-offs may occur as a result of managerial decisions not to

progress certain projects in the company’s portfolio.

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 15 provides the company’s effective income tax rate for the last three years.

Refer to the “Cautionary Statements Relevant to Forward-Looking Information” on page 2 and to “Risk Factors” in Part I,

Item 1A, on pages 18 through 21 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. Asset dispositions and restructurings may result in significant gains or losses in future periods. The company’s

Earnings of the company depend mostly on the profitability of its upstream business segment. The most significant factor

affecting the results of operations for the upstream segment is the price of crude oil, which is determined in global markets

Brent

WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Spot Prices — Quarterly Average

WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Spot Prices — Quarterly Average
Oil
$/bbl

The company continues to actively manage its schedule of work, contracting, procurement, and supply-chain activities to
effectively manage costs and support operational goals. Price levels for capital, 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
HH
including, but not limited to: the general level of inflation, tariffs or other taxes imposed on goods or services, and
$/mcf
commoditized prices charged by the industry’s material and service providers. The spot markets for many services and
materials fell as overall industry drilling activity in North America declined in 2019, particularly onshore. However, as
industry activity contracts, financial pressure on suppliers has increased, which may limit further de-escalation and/or lead to
consolidation across the supplier community impacting costs. The international and offshore rig markets are also showing
some signs of weaknesses as activity has pulled back; however, pricing for some products and services remains resilient as
many suppliers have reset expectations of higher industry spend and instead are looking to higher pricing and margins on a
more limited scope of work. Chevron utilizes contracts with various pricing mechanisms, so there may be a delay in when
the company’s costs reflect the changes in market trends.

HH
$/mcf

Capital and exploratory expenditures and operating expenses could also be affected by damage to production facilities caused
by severe weather or civil unrest, delays in construction, or other factors.

0
3Q

1Q
WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Spot Prices - Quarterly Average
WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Spot Prices — Quarterly Average
Oil
Oil
Brent
$/bbl
$/bbl
80
WTI
80

Brent
Brent
WTI
WTI
Henry Hub
Henry Hub

WTI
Henry Hub

Henry Hub

2017
1Q

2018
1Q

2018

2017

2018

2019

2017

0
3Q

2019

60
60

40
40

20
20

0
0

HH
HH
$/mcf
$/mcf
12
12

9
9

6
6

3
3

0
0

2Q
2Q

3Q
3Q

4Q
4Q

1Q
1Q

2Q
2Q

3Q
3Q

4Q
4Q

1Q
1Q

2017
2017

2018
2018

Brent

WTI

Henry Hub

2019
2019

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 majority of the company’s equity crude production is priced based on the Brent benchmark. The
Brent price averaged $64 per barrel for the full-year 2019, compared to $71 in 2018. Brent prices increased through the first
half of 2019 due to OPEC production cuts and U.S. sanctions on Iran and Venezuela. Prices then started to decline due to
heightened concerns about a slowing macro economy and weakening oil demand growth amid trade tensions between the

29
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Management’s Discussion and Analysis of Financial Condition and Results of Operations

U.S. and China. OPEC announced additional production cuts in December 2019, leading to a price increase with Brent prices
at $67 at the end of the year. As of mid-February 2020, the Brent price was $57 per barrel, having declined more than
10 percent since December 2019, primarily due to concerns about demand erosion following the coronavirus outbreak.

The WTI price averaged $57 per barrel for the full-year 2019, compared to $65 in 2018. WTI traded at a discount to Brent
throughout 2019. Differentials to Brent have ranged between $4 to $10 in 2019, primarily due to pipeline infrastructure
constraints which have restricted flows of inland crude to export outlets on the Gulf Coast. Variability in other factors
impacting supply and demand of each benchmark crude also affect price differential. As of mid-February 2020, the WTI
price was $52 per barrel.

Chevron has interests 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 and China. (See page 37 for the company’s average U.S. and
international crude oil sales prices.)

In contrast to price movements in the global market for crude oil, price changes for natural gas are more closely aligned with
seasonal supply-and-demand and infrastructure conditions in local markets. In the United States, prices at Henry Hub
averaged $2.53 per thousand cubic feet (MCF) during 2019, compared with $3.12 during 2018. As of mid-February 2020, the
Henry Hub spot price was $1.84 per MCF. Increased production in the Permian Basin has resulted in insufficient gas pipeline
and fractionation capacity in the near-term, and over-supply conditions, leading to depressed natural gas and natural gas
liquids prices in West Texas. A sizable portion of Chevron’s U.S. natural gas production comes from the Permian Basin,
resulting in natural gas realizations that are significantly lower than the Henry Hub price.

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 many locations. In some locations, Chevron
has invested in long-term projects 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 $5.83 per MCF during 2019,
compared with $6.29 per MCF during 2018. (See page 37 for the company’s average natural gas realizations for the U.S. and
international regions.)

The company’s worldwide net oil-equivalent production in 2019 averaged 3.058 million barrels per day. About 15 percent of
the company’s net oil-equivalent production in 2019 occurred in the OPEC-member countries of Angola, Nigeria, Republic
of Congo and Venezuela. OPEC quotas had no material effect on the company’s net crude oil production in 2019 or 2018.

The company estimates that net oil-equivalent production in 2020 will grow up to 3 percent compared to 2019, assuming a
Brent crude oil price of $60 per barrel and excluding the impact of anticipated 2020 asset sales. This estimate is subject to
many factors and uncertainties, including quotas or other actions that may be imposed by OPEC; tariffs and trade sanctions;
price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in
construction; reservoir performance; greater-than-expected declines in production from mature fields; 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; or other disruptions to operations. The
outlook for future production levels is also affected by the size and number of economic investment opportunities and the
time lag between initial exploration and the beginning of production. The company has increased its investment emphasis on
short-cycle projects.

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. In December 2019, the
governments of Saudi Arabia and Kuwait signed a memorandum of understanding to resolve the dispute and allow
production to restart in the Partitioned Zone. In mid-February 2020, pre-startup activities commenced. The financial effects
from the loss of production in 2019 were not significant and are not expected to be significant in 2020.

Chevron has interests in Venezuelan crude oil production assets operated by independent equity affiliates. While the operating
environment in Venezuela has been deteriorating for some time, the equity affiliates have continued to operate consistent with
the authorization provided pursuant to general licenses issued by the United States government. It remains uncertain when the
the company remains committed to its personnel and operations in
environment

in Venezuela will stabilize, but

Venezuela. Refer to Note 22 on page 88 under the heading “Other Contingencies” for more information on the company’s

activities in Venezuela.

Net proved reserves for consolidated companies and affiliated companies totaled 11.4 billion barrels of oil-equivalent at

year-end 2019, a decrease of 5 percent from year-end 2018. The reserve replacement ratio in 2019 was 44 percent. The 5 and

10 year reserve replacement ratios were 106 percent and 101 percent, respectively. Refer to Table V beginning on page 96

for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2017 and each

year-end from 2017 through 2019, and an accompanying discussion of major changes to proved reserves by geographic area

for the three-year period ending December 31, 2019.

Refer to the “Results of Operations” section on pages 32 through 34 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 and changes in tax laws and regulations.

The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia. Chevron

operates or has significant ownership interests in refineries in each of these areas.

Refer to the “Results of Operations” section on pages 32 through 34 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.

30
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Management’s Discussion and Analysis of Financial Condition and Results of Operations

U.S. and China. OPEC announced additional production cuts in December 2019, leading to a price increase with Brent prices

at $67 at the end of the year. As of mid-February 2020, the Brent price was $57 per barrel, having declined more than

10 percent since December 2019, primarily due to concerns about demand erosion following the coronavirus outbreak.

The WTI price averaged $57 per barrel for the full-year 2019, compared to $65 in 2018. WTI traded at a discount to Brent

throughout 2019. Differentials to Brent have ranged between $4 to $10 in 2019, primarily due to pipeline infrastructure

constraints which have restricted flows of inland crude to export outlets on the Gulf Coast. Variability in other factors

impacting supply and demand of each benchmark crude also affect price differential. As of mid-February 2020, the WTI

price was $52 per barrel.

Chevron has interests 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 and China. (See page 37 for the company’s average U.S. and

international crude oil sales prices.)

In contrast to price movements in the global market for crude oil, price changes for natural gas are more closely aligned with

seasonal supply-and-demand and infrastructure conditions in local markets. In the United States, prices at Henry Hub

averaged $2.53 per thousand cubic feet (MCF) during 2019, compared with $3.12 during 2018. As of mid-February 2020, the

Henry Hub spot price was $1.84 per MCF. Increased production in the Permian Basin has resulted in insufficient gas pipeline

and fractionation capacity in the near-term, and over-supply conditions, leading to depressed natural gas and natural gas

liquids prices in West Texas. A sizable portion of Chevron’s U.S. natural gas production comes from the Permian Basin,

resulting in natural gas realizations that are significantly lower than the Henry Hub price.

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 many locations. In some locations, Chevron

has invested in long-term projects 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 $5.83 per MCF during 2019,

compared with $6.29 per MCF during 2018. (See page 37 for the company’s average natural gas realizations for the U.S. and

international regions.)

The company’s worldwide net oil-equivalent production in 2019 averaged 3.058 million barrels per day. About 15 percent of

the company’s net oil-equivalent production in 2019 occurred in the OPEC-member countries of Angola, Nigeria, Republic

of Congo and Venezuela. OPEC quotas had no material effect on the company’s net crude oil production in 2019 or 2018.

The company estimates that net oil-equivalent production in 2020 will grow up to 3 percent compared to 2019, assuming a

Brent crude oil price of $60 per barrel and excluding the impact of anticipated 2020 asset sales. This estimate is subject to

many factors and uncertainties, including quotas or other actions that may be imposed by OPEC; tariffs and trade sanctions;

price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in

construction; reservoir performance; greater-than-expected declines in production from mature fields; 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; or other disruptions to operations. The

outlook for future production levels is also affected by the size and number of economic investment opportunities and the

time lag between initial exploration and the beginning of production. The company has increased its investment emphasis on

short-cycle projects.

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. In December 2019, the

governments of Saudi Arabia and Kuwait signed a memorandum of understanding to resolve the dispute and allow

production to restart in the Partitioned Zone. In mid-February 2020, pre-startup activities commenced. The financial effects

from the loss of production in 2019 were not significant and are not expected to be significant in 2020.

Chevron has interests in Venezuelan crude oil production assets operated by independent equity affiliates. While the operating

environment in Venezuela has been deteriorating for some time, the equity affiliates have continued to operate consistent with

the authorization provided pursuant to general licenses issued by the United States government. It remains uncertain when the

environment

in Venezuela will stabilize, but

the company remains committed to its personnel and operations in

Venezuela. Refer to Note 22 on page 88 under the heading “Other Contingencies” for more information on the company’s
activities in Venezuela.

Net liquids production*
Thousands of barrels per day

Net natural gas production*
Millions of cubic feet per day

Net proved reserves
Billions of BOE

Net proved reserves
liquids & natural gas
Billions of BOE

2400

1800

1200

600

1,865

8000

6000

4000

2000

7,157

15.0

10.0

5.0

0.0

11.4

15.0

10.0

5.0

0.0

11.4

17 18 19

15 16 17 18 19

17 18 19

United States
International

* Includes equity in afﬁliates.

Natural gas
Liquids

Affiliates
Europe
Australia/Oceania
Asia
Africa
Other Americas
United States

Net proved reserves for consolidated companies and affiliated companies totaled 11.4 billion barrels of oil-equivalent at
year-end 2019, a decrease of 5 percent from year-end 2018. The reserve replacement ratio in 2019 was 44 percent. The 5 and
10 year reserve replacement ratios were 106 percent and 101 percent, respectively. Refer to Table V beginning on page 96
for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2017 and each
year-end from 2017 through 2019, and an accompanying discussion of major changes to proved reserves by geographic area
for the three-year period ending December 31, 2019.

Refer to the “Results of Operations” section on pages 32 through 34 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 and changes in tax laws and regulations.

The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia. Chevron
operates or has significant ownership interests in refineries in each of these areas.

Refer to the “Results of Operations” section on pages 32 through 34 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.

31
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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Operating Developments

Key operating developments and other events during 2019 and early 2020 included the following:

Upstream

Azerbaijan Signed an agreement to sell the company’s interest in the Azeri-Chirag-Gunashli fields and Baku-Tbilisi-Ceyhan
pipeline.

Brazil Completed the sale of an interest in the Frade field.

Denmark Completed the sale of Denmark upstream interests.

Philippines Signed an agreement to sell the company’s interest in the Malampaya field in late October.

United Kingdom Completed the sale of interest in the Rosebank field.

United Kingdom Completed the sale of Central North Sea assets.

United States Announced the sanction of a waterflood project in the St. Malo field in the Gulf of Mexico.

United States Announced final investment decision for the Anchor field in the Gulf of Mexico.

Downstream

United States Completed the acquisition of a refinery in Pasadena, Texas.

Australia Signed an agreement to acquire a network of terminals and service stations.

CPChem Announced agreements to jointly develop petrochemical complexes in Qatar and the U.S. Gulf Coast.

Other

Common Stock Dividends The 2019 annual dividend was $4.76 per share, making 2019 the 32nd consecutive year that the
company increased its annual per share dividend payout. In January 2020, the company’s Board of Directors approved a
$0.10 per share increase in the quarterly dividend to $1.29 per share, payable in March 2020, representing an increase of
8.4 percent.

Common Stock Repurchase Program The company purchased $4 billion of its common stock in 2019 under its stock
repurchase programs. The company currently expects to repurchase $5 billion of its common stock in 2020.

The company’s average realization for U.S. crude oil and natural gas liquids in 2019 was $48.54 per barrel compared with

$58.17 in 2018. The average natural gas realization was $1.09 per thousand cubic feet in 2019, compared with $1.86 in 2018.

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 12, beginning on page 68, 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 28 through 32. Refer to the “Selected Operating Data” table on page 37 for a
three-year comparison of production volumes, refined product sales volumes, and refinery inputs. A discussion of variances
between 2018 and 2017 can be found in the “Results of Operations” section on pages 32 through 34 of the company’s 2018
Annual Report on Form 10-K filed with the SEC on February 22, 2019.

U.S. Upstream

Millions of dollars

Earnings

2019

2018

(5,094)

3,278

2017

3,640

U.S. upstream recorded a loss of $5.09 billion in 2019, compared with earnings of $3.28 billion in 2018. The decrease in

earnings was largely due to $8.17 billion in 2019 impairment charges primarily associated with Appalachia shale and Big

Foot, partially offset by the absence of 2018 write-offs and impairments of $660 million, largely due to the Tigris Project in

the Gulf of Mexico. Also contributing to the decrease was lower crude oil and natural gas prices of $1.72 billion, higher

operating expenses of $260 million and the absence of several 2018 asset sale gains totaling $220 million, partially offset by

higher crude oil and natural gas production of $1.33 billion.

Net oil-equivalent production in 2019 averaged 929,000 barrels per day, up 17 percent from 2018. The production increase

was largely due to shale and tight properties in the Permian Basin in Texas and New Mexico.

The net liquids component of oil-equivalent production for 2019 averaged 724,000 barrels per day, up 17 percent from 2018.

Net natural gas production averaged 1.23 billion cubic feet per day in 2019, up 18 percent from 2018.

International Upstream

Millions of dollars

Earnings*

*Includes foreign currency effects:

2019

7,670

(323)

2018

10,038

545

2017

4,510

(456)

International upstream earnings were $7.67 billion in 2019, compared with $10.04 billion in 2018. Lower crude oil and

natural gas realizations of $1.4 billion and $830 million, respectively, were partially offset by lower depreciation and tax

expenses of $560 million and $280 million, respectively. There were also a number of special items that largely offset each

other in 2019 and 2018. Included in 2019 earnings were items totaling $800 million for write-offs and impairment charges of

$2.2 billion associated with Kitimat LNG and other gas projects partially offset by a gain of $1.2 billion on the sale of the

U.K. Central North Sea assets and a benefit of $180 million related to a reduction in the corporate income tax rate in Alberta,

Canada. Offsetting these items were the absence of 2018 special items of $920 million associated with impairments, write-

offs, a receivable write-down and a contractual settlement. Foreign currency effects had an unfavorable impact on earnings of

$868 million between periods.

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Upstream

pipeline.

Downstream

Other

8.4 percent.

Operating Developments

Key operating developments and other events during 2019 and early 2020 included the following:

Azerbaijan Signed an agreement to sell the company’s interest in the Azeri-Chirag-Gunashli fields and Baku-Tbilisi-Ceyhan

Brazil Completed the sale of an interest in the Frade field.

Denmark Completed the sale of Denmark upstream interests.

Philippines Signed an agreement to sell the company’s interest in the Malampaya field in late October.

United Kingdom Completed the sale of interest in the Rosebank field.

United Kingdom Completed the sale of Central North Sea assets.

United States Announced the sanction of a waterflood project in the St. Malo field in the Gulf of Mexico.

United States Announced final investment decision for the Anchor field in the Gulf of Mexico.

Common Stock Dividends The 2019 annual dividend was $4.76 per share, making 2019 the 32nd consecutive year that the

company increased its annual per share dividend payout. In January 2020, the company’s Board of Directors approved a

$0.10 per share increase in the quarterly dividend to $1.29 per share, payable in March 2020, representing an increase of

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 12, beginning on page 68, 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 28 through 32. Refer to the “Selected Operating Data” table on page 37 for a

three-year comparison of production volumes, refined product sales volumes, and refinery inputs. A discussion of variances

between 2018 and 2017 can be found in the “Results of Operations” section on pages 32 through 34 of the company’s 2018

Annual Report on Form 10-K filed with the SEC on February 22, 2019.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Worldwide Upstream
earnings
Billions of dollars

Exploration expenses
Billions of dollars (before-tax)

Worldwide Downstream
earnings
Billions of dollars

Worldwide reﬁned
product sales
Thousands of barrels per day

18.0

12.0

6.0

0.0

(6.0)

$2.6

3.5

3.0

2.5

2.0

1.5

1.0

0.5

8.0

6.0

4.0

2.0

0.0

3000

2250

1500

750

$2.5

$0.8

2,577

17 18 19

United States Completed the acquisition of a refinery in Pasadena, Texas.

Australia Signed an agreement to acquire a network of terminals and service stations.

CPChem Announced agreements to jointly develop petrochemical complexes in Qatar and the U.S. Gulf Coast.

U.S. Upstream

Millions of dollars

Earnings

United States
International

Other
Fuel oil
Jet fuel
Diesel/Gas oil
Gasoline

2019

2018

(5,094)

3,278

2017

3,640

Common Stock Repurchase Program The company purchased $4 billion of its common stock in 2019 under its stock

repurchase programs. The company currently expects to repurchase $5 billion of its common stock in 2020.

The company’s average realization for U.S. crude oil and natural gas liquids in 2019 was $48.54 per barrel compared with
$58.17 in 2018. The average natural gas realization was $1.09 per thousand cubic feet in 2019, compared with $1.86 in 2018.

U.S. upstream recorded a loss of $5.09 billion in 2019, compared with earnings of $3.28 billion in 2018. The decrease in
earnings was largely due to $8.17 billion in 2019 impairment charges primarily associated with Appalachia shale and Big
Foot, partially offset by the absence of 2018 write-offs and impairments of $660 million, largely due to the Tigris Project in
the Gulf of Mexico. Also contributing to the decrease was lower crude oil and natural gas prices of $1.72 billion, higher
operating expenses of $260 million and the absence of several 2018 asset sale gains totaling $220 million, partially offset by
higher crude oil and natural gas production of $1.33 billion.

Net oil-equivalent production in 2019 averaged 929,000 barrels per day, up 17 percent from 2018. The production increase
was largely due to shale and tight properties in the Permian Basin in Texas and New Mexico.

The net liquids component of oil-equivalent production for 2019 averaged 724,000 barrels per day, up 17 percent from 2018.
Net natural gas production averaged 1.23 billion cubic feet per day in 2019, up 18 percent from 2018.

International Upstream

Millions of dollars

Earnings*

*Includes foreign currency effects:

2019

7,670

(323)

2018

10,038

545

2017

4,510

(456)

International upstream earnings were $7.67 billion in 2019, compared with $10.04 billion in 2018. Lower crude oil and
natural gas realizations of $1.4 billion and $830 million, respectively, were partially offset by lower depreciation and tax
expenses of $560 million and $280 million, respectively. There were also a number of special items that largely offset each
other in 2019 and 2018. Included in 2019 earnings were items totaling $800 million for write-offs and impairment charges of
$2.2 billion associated with Kitimat LNG and other gas projects partially offset by a gain of $1.2 billion on the sale of the
U.K. Central North Sea assets and a benefit of $180 million related to a reduction in the corporate income tax rate in Alberta,
Canada. Offsetting these items were the absence of 2018 special items of $920 million associated with impairments, write-
offs, a receivable write-down and a contractual settlement. Foreign currency effects had an unfavorable impact on earnings of
$868 million between periods.

33
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Management’s Discussion and Analysis of Financial Condition and Results of Operations

The company’s average realization for international crude oil and natural gas liquids in 2019 was $58.14 per barrel compared
with $64.25 in 2018. The average natural gas realization was $5.83 per thousand cubic feet in 2019 compared with $6.29 in
2018.

International net oil-equivalent production was 2.13 million barrels per day in 2019, essentially unchanged from 2018.
Production increases from Wheatstone and major capital projects were offset by normal field declines and the impact of asset
sales in 2019.

The net liquids component of international oil-equivalent production was 1.14 million barrels per day in 2019, down
2 percent from 2018. International net natural gas production of 5.93 billion cubic feet per day in 2019 increased 1 percent
from 2018.

U.S. Downstream
Millions of dollars

Earnings

2019

2018

1,559

2,103

2017

2,938

U.S. downstream earned $1.56 billion in 2019, compared with $2.10 billion in 2018. The decrease was primarily due to
lower margins on refined product sales of $300 million, lower equity earnings from the 50 percent-owned CPChem of
$140 million and higher depreciation expense of $100 million following first production at the new hydrogen plant at the
Richmond refinery.

Total refined product sales of 1.25 million barrels per day in 2019 were up 3 percent from 2018.

lower product prices and volumes.

Millions of dollars

Operating, selling, general and administrative expenses

International Downstream
Millions of dollars

Earnings*

*Includes foreign currency effects:

2019

922

2018

1,695

2017

2,276

(90)

Millions of dollars

Exploration expense

Operating, selling, general and administrative expenses increased $1.1 billion in 2019. The increase is mainly due to higher

services and fees, materials and supplies expense and higher transportation expense, partially offset by the absence of a 2018

receivable write-down and contractual settlement.

International downstream earned $922 million in 2019, compared with $1.70 billion in 2018. The decrease in earnings was
due to lower margins on refined product sales of $570 million, lower gains on asset sales of $300 million, primarily due to
the absence of the 2018 gains from the southern Africa asset sale, partially offset by favorable tax items of $100 million.
Foreign currency effects had an unfavorable impact on earnings of $54 million between periods.

Total refined product sales of 1.33 million barrels per day in 2019 were down 8 percent from 2018, primarily due to the sale
of the southern Africa refining and marketing business in third quarter 2018.

All Other
Millions of dollars

Net charges*

*Includes foreign currency effects:

2019

(2,133)

2018

2017

(2,290) $

(4,169)

(5) $

100

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 2019 decreased $157 million from 2018. The change between periods was mainly due to receipt of the
Anadarko merger termination fee, partially offset by higher tax items. Foreign currency effects decreased net charges by
$7 million between periods.

Consolidated Statement of Income

Millions of dollars

Income from equity affiliates

2019

2018

3,968

6,327

2017

4,438

Income from equity affiliates decreased in 2019 mainly due to lower upstream-related earnings from Tengizchevroil in

Kazakhstan, Petroboscan and Petropiar in Venezuela, and lower downstream-related earnings from GS Caltex in South

Korea. In addition, two upstream affiliates were written-down in 2019.

Refer to Note 13, beginning on page 71, for a discussion of Chevron’s investments in affiliated companies.

Millions of dollars

Other income

2019

2018

2,683

1,110

2017

2,610

Other income increased in 2019 mainly due to the receipt of the Anadarko merger termination fee and higher gains from

asset sales, partially offset by unfavorable swings in foreign currency effects.

Millions of dollars

Purchased crude oil and products

2019

2018

2017

80,113

94,578

75,765

Crude oil and product purchases decreased $14.5 billion in 2019, primarily due to lower crude oil volumes and prices, and

2019

2018

2017

25,528

24,382

23,237

2019

2018

770

1,210

2017

864

2019

2018

2017

29,218

19,419

19,349

2019

2018

2017

4,136

4,867

12,331

2019

2018

798

748

2019

2018

2,691

5,715

2017

307

2017

(48)

Exploration expenses in 2019 decreased primarily due to lower charges for well write-offs, partially offset by higher

Depreciation, depletion and amortization expenses increased in 2019 mainly due to higher impairments, production and well

Taxes other than on income decreased in 2019 mainly due to lower local and municipal taxes and licenses as a result of the

company’s divestment of its downstream interest in southern Africa in third quarter 2018, partially offset by higher U.S. state

geological and geophysical expenses.

Millions of dollars

Depreciation, depletion and amortization

write-offs, partially offset by lower rates.

Millions of dollars

Taxes other than on income

carbon emissions regulatory expenses.

Millions of dollars

Interest and debt expense

expense resulting from lower debt balances.

Millions of dollars

Income tax expense (benefit)

Interest and debt expenses increased in 2019 mainly due to lower capitalized interest, partially offset by lower interest

The decrease in income tax expense in 2019 of $3.02 billion is due to the decrease in total income before tax for the company

of $15.04 billion. The decrease in income before taxes for the company is primarily the result of the upstream impairment

and project write-off charges along with lower commodity prices, partially offset by higher gains on asset sales.

Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2018 and
2017 can be found in the “Consolidated Statement of Income” section on pages 34 through 36 of the company’s 2018 Annual
Report on Form 10-K.
Millions of dollars

2018

2019

2017

Sales and other operating revenues

139,865

158,902

134,674

Sales and other operating revenues decreased in 2019 mainly due to lower refined product, crude oil and natural gas prices,
and lower crude oil and refined product volumes.

U.S. income before tax decreased from a profit of $4.73 billion in 2018 to a loss of $5.48 billion in 2019. This decrease in

earnings before tax was primarily driven by the effect of upstream impairments and lower crude oil and natural gas prices,

34
Chevron Corporation 2019 Annual Report
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2018.

sales in 2019.

from 2018.

U.S. Downstream

Millions of dollars

Earnings

Richmond refinery.

International Downstream

Millions of dollars

Earnings*

*Includes foreign currency effects:

All Other

Millions of dollars

Net charges*

*Includes foreign currency effects:

International net oil-equivalent production was 2.13 million barrels per day in 2019, essentially unchanged from 2018.

Production increases from Wheatstone and major capital projects were offset by normal field declines and the impact of asset

The net liquids component of international oil-equivalent production was 1.14 million barrels per day in 2019, down

2 percent from 2018. International net natural gas production of 5.93 billion cubic feet per day in 2019 increased 1 percent

U.S. downstream earned $1.56 billion in 2019, compared with $2.10 billion in 2018. The decrease was primarily due to

lower margins on refined product sales of $300 million, lower equity earnings from the 50 percent-owned CPChem of

$140 million and higher depreciation expense of $100 million following first production at the new hydrogen plant at the

Total refined product sales of 1.25 million barrels per day in 2019 were up 3 percent from 2018.

2019

2018

1,559

2,103

2017

2,938

International downstream earned $922 million in 2019, compared with $1.70 billion in 2018. The decrease in earnings was

due to lower margins on refined product sales of $570 million, lower gains on asset sales of $300 million, primarily due to

the absence of the 2018 gains from the southern Africa asset sale, partially offset by favorable tax items of $100 million.

Foreign currency effects had an unfavorable impact on earnings of $54 million between periods.

Total refined product sales of 1.33 million barrels per day in 2019 were down 8 percent from 2018, primarily due to the sale

of the southern Africa refining and marketing business in third quarter 2018.

2019

922

2018

1,695

2017

2,276

(90)

2019

(2,133)

2018

2017

(2,290) $

(4,169)

(5) $

100

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 2019 decreased $157 million from 2018. The change between periods was mainly due to receipt of the

Anadarko merger termination fee, partially offset by higher tax items. Foreign currency effects decreased net charges by

Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2018 and

2017 can be found in the “Consolidated Statement of Income” section on pages 34 through 36 of the company’s 2018 Annual

$7 million between periods.

Consolidated Statement of Income

Report on Form 10-K.

Millions of dollars

Sales and other operating revenues

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The company’s average realization for international crude oil and natural gas liquids in 2019 was $58.14 per barrel compared

with $64.25 in 2018. The average natural gas realization was $5.83 per thousand cubic feet in 2019 compared with $6.29 in

Millions of dollars

Income from equity affiliates

2019

2018

3,968

6,327

2017

4,438

Income from equity affiliates decreased in 2019 mainly due to lower upstream-related earnings from Tengizchevroil in
Kazakhstan, Petroboscan and Petropiar in Venezuela, and lower downstream-related earnings from GS Caltex in South
Korea. In addition, two upstream affiliates were written-down in 2019.

Refer to Note 13, beginning on page 71, for a discussion of Chevron’s investments in affiliated companies.

Millions of dollars

Other income

2019

2018

2,683

1,110

2017

2,610

Other income increased in 2019 mainly due to the receipt of the Anadarko merger termination fee and higher gains from
asset sales, partially offset by unfavorable swings in foreign currency effects.

Millions of dollars

Purchased crude oil and products

2019

2018

2017

80,113

94,578

75,765

Crude oil and product purchases decreased $14.5 billion in 2019, primarily due to lower crude oil volumes and prices, and
lower product prices and volumes.

Millions of dollars

Operating, selling, general and administrative expenses

2019

2018

2017

25,528

24,382

23,237

Operating, selling, general and administrative expenses increased $1.1 billion in 2019. The increase is mainly due to higher
services and fees, materials and supplies expense and higher transportation expense, partially offset by the absence of a 2018
receivable write-down and contractual settlement.

Millions of dollars

Exploration expense

2019

2018

770

1,210

2017

864

Exploration expenses in 2019 decreased primarily due to lower charges for well write-offs, partially offset by higher
geological and geophysical expenses.

Millions of dollars

Depreciation, depletion and amortization

2019

2018

2017

29,218

19,419

19,349

Depreciation, depletion and amortization expenses increased in 2019 mainly due to higher impairments, production and well
write-offs, partially offset by lower rates.

Millions of dollars

Taxes other than on income

2019

2018

2017

4,136

4,867

12,331

Taxes other than on income decreased in 2019 mainly due to lower local and municipal taxes and licenses as a result of the
company’s divestment of its downstream interest in southern Africa in third quarter 2018, partially offset by higher U.S. state
carbon emissions regulatory expenses.

Millions of dollars

Interest and debt expense

2019

2018

798

748

2017

307

Interest and debt expenses increased in 2019 mainly due to lower capitalized interest, partially offset by lower interest
expense resulting from lower debt balances.

Millions of dollars

Income tax expense (benefit)

2019

2018

2,691

5,715

2017

(48)

Sales and other operating revenues decreased in 2019 mainly due to lower refined product, crude oil and natural gas prices,

and lower crude oil and refined product volumes.

U.S. income before tax decreased from a profit of $4.73 billion in 2018 to a loss of $5.48 billion in 2019. This decrease in
earnings before tax was primarily driven by the effect of upstream impairments and lower crude oil and natural gas prices,

35
Chevron Corporation 2019 Annual Report
35

2019

2018

2017

139,865

158,902

134,674

The decrease in income tax expense in 2019 of $3.02 billion is due to the decrease in total income before tax for the company
of $15.04 billion. The decrease in income before taxes for the company is primarily the result of the upstream impairment
and project write-off charges along with lower commodity prices, partially offset by higher gains on asset sales.

145363_10K.indd 35

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

partially offset by the Anadarko merger termination fee and higher production. The U.S. tax decreased from a tax charge of
$724 million in 2018 to a tax benefit of $1.17 billion in 2019 primarily due to the before-tax loss.

Selected Operating Data1,2

2018

2017

International income before tax decreased from $15.84 billion in 2018 to $11.02 billion in 2019. This decrease was primarily
driven by the effects of upstream project write-off and impairment charges and lower crude oil and natural gas prices,
partially offset by gains on asset sales. The lower before-tax income primarily drove the $1.13 billion decrease in
international income tax expense, from $4.99 billion in 2018 to $3.86 billion in 2019.

Refer also to the discussion of the effective income tax rate in Note 15 beginning on page 74.

U.S. Upstream

Net Crude Oil and Natural Gas Liquids Production (MBPD)

Net Crude Oil and Natural Gas Liquids Production (MBPD)4

Net Natural Gas Production (MMCFPD)3

Net Oil-Equivalent Production (MBOEPD)

Sales of Natural Gas (MMCFPD)

Sales of Natural Gas Liquids (MBPD)

Revenues from Net Production

Liquids ($/Bbl)

Natural Gas ($/MCF)

International Upstream

Net Natural Gas Production (MMCFPD)3

Net Oil-Equivalent Production (MBOEPD)4

Sales of Natural Gas (MMCFPD)

Sales of Natural Gas Liquids (MBPD)

Revenues from Liftings

Liquids ($/Bbl)

Natural Gas ($/MCF)

Worldwide Upstream

United States

International

Total

Net Oil-Equivalent Production (MBOEPD)4

U.S. Downstream

Gasoline Sales (MBPD)5

Other Refined Product Sales (MBPD)

Total Refined Product Sales (MBPD)

Sales of Natural Gas Liquids (MBPD)

Refinery Input (MBPD)6

International Downstream

Gasoline Sales (MBPD)5

Other Refined Product Sales (MBPD)

Total Refined Product Sales (MBPD)7

Sales of Natural Gas Liquids (MBPD)

Refinery Input (MBPD)8

Includes company share of equity affiliates.

Includes net production of synthetic oil:

United States

International

Canada

Venezuela affiliate

Includes branded and unbranded gasoline.

110,000 barrels per day.

Includes sales of affiliates (MBPD):

58.17

1.86

64.25

6.29

618

1,034

791

3,481

110

1,164

5,855

2,139

5,604

791

2,139

2,930

627

591

1,218

905

336

1,101

1,437

706

584

519

970

681

3,331

44.53

2.10

1,204

5,062

2,047

5,081

49.46

4.62

681

2,047

2,728

625

572

1,197

109

901

365

1,128

1,493

760

528

2019

724

1,225

929

4,016

130

48.54

1.09

1,141

5,932

2,129

5,869

58.14

5.83

929

2,129

3,058

667

583

1,250

101

947

289

1,038

1,327

617

602

379

2 MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day; MBOEPD – thousands of barrels of oil-equivalents per day; Bbl – barrel; MCF – thousands

of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.

Includes natural gas consumed in operations (MMCFPD):

In May 2019, the company acquired the Pasadena Refinery in Pasadena, Texas, which has an operable capacity of

In September 2018, the company sold its interest in the Cape Town Refinery in Cape Town, South Africa, which had an operable capacity of 110,000 barrels per day.

373

366

36
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Management’s Discussion and Analysis of Financial Condition and Results of Operations

partially offset by the Anadarko merger termination fee and higher production. The U.S. tax decreased from a tax charge of

Selected Operating Data1,2

$724 million in 2018 to a tax benefit of $1.17 billion in 2019 primarily due to the before-tax loss.

International income before tax decreased from $15.84 billion in 2018 to $11.02 billion in 2019. This decrease was primarily

driven by the effects of upstream project write-off and impairment charges and lower crude oil and natural gas prices,

partially offset by gains on asset sales. The lower before-tax income primarily drove the $1.13 billion decrease in

international income tax expense, from $4.99 billion in 2018 to $3.86 billion in 2019.

Refer also to the discussion of the effective income tax rate in Note 15 beginning on page 74.

U.S. Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)
Net Natural Gas Production (MMCFPD)3
Net Oil-Equivalent Production (MBOEPD)
Sales of Natural Gas (MMCFPD)
Sales of Natural Gas Liquids (MBPD)
Revenues from Net Production

Liquids ($/Bbl)
Natural Gas ($/MCF)
International Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)4
Net Natural Gas Production (MMCFPD)3
Net Oil-Equivalent Production (MBOEPD)4
Sales of Natural Gas (MMCFPD)
Sales of Natural Gas Liquids (MBPD)
Revenues from Liftings

Liquids ($/Bbl)
Natural Gas ($/MCF)
Worldwide Upstream
Net Oil-Equivalent Production (MBOEPD)4

United States
International

Total

U.S. Downstream
Gasoline Sales (MBPD)5
Other Refined Product Sales (MBPD)

Total Refined Product Sales (MBPD)

Sales of Natural Gas Liquids (MBPD)
Refinery Input (MBPD)6
International Downstream
Gasoline Sales (MBPD)5
Other Refined Product Sales (MBPD)

Total Refined Product Sales (MBPD)7

Sales of Natural Gas Liquids (MBPD)
Refinery Input (MBPD)8

Includes company share of equity affiliates.

$
$

2019

724
1,225
929
4,016
130

48.54
1.09

1,141
5,932
2,129
5,869
34

58.14
5.83

929
2,129

3,058

667
583

1,250
101
947

289
1,038

1,327
72
617

2018

2017

618
1,034
791
3,481
110

58.17
1.86

$
$

1,164
5,855
2,139
5,604
34

64.25
6.29

$
$

791
2,139

2,930

627
591

1,218
74
905

336
1,101

1,437
62
706

519
970
681
3,331
30

44.53
2.10

1,204
5,062
2,047
5,081
29

49.46
4.62

681
2,047

2,728

625
572

1,197
109
901

365
1,128

1,493
64
760

2 MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day; MBOEPD – thousands of barrels of oil-equivalents per day; Bbl – barrel; MCF – thousands

of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
Includes natural gas consumed in operations (MMCFPD):

United States
International

Includes net production of synthetic oil:

Canada
Venezuela affiliate

36
602

53
3

35
584

53
24

Includes branded and unbranded gasoline.
In May 2019, the company acquired the Pasadena Refinery in Pasadena, Texas, which has an operable capacity of
110,000 barrels per day.
Includes sales of affiliates (MBPD):
In September 2018, the company sold its interest in the Cape Town Refinery in Cape Town, South Africa, which had an operable capacity of 110,000 barrels per day.

379

373

37
528

51
28

366

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Liquidity and Capital Resources

Sources and uses of cash

The strength of the company’s balance sheet enabled it to fund any timing differences throughout the year between cash
inflows and outflows.

Cash, Cash Equivalents, Marketable Securities and Time Deposits Total balances were $5.7 billion and $10.3 billion at
December 31, 2019 and 2018, respectively. Cash provided by operating activities in 2019 was $27.3 billion, compared to
$30.6 billion in 2018, primarily due to lower crude oil prices. Cash provided by operating activities was net of contributions
to employee pension plans of approximately $1.4 billion in 2019 and $1.0 billion in 2018. Cash provided by investing
activities included proceeds and deposits related to asset sales of $2.8 billion in 2019 and $2.0 billion in 2018.

Restricted cash of $1.2 billion and $1.1 billion at December 31, 2019 and 2018, respectively, was held in cash and short-term
marketable securities and recorded as “Deferred charges and other assets” and “Prepaid expenses and other current assets” on
the Consolidated Balance Sheet. These amounts are generally associated with upstream decommissioning 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 $9.0 billion in 2019 and $8.5 billion in 2018.

Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $27.0 billion at December 31, 2019, down
from $34.5 billion at year-end 2018.

The $7.5 billion decrease in total debt and finance lease liabilities during 2019 was primarily due to the repayment of long-
term notes totaling $5.0 billion as they matured during 2019, and a reduction in commercial paper. The company’s debt and
finance lease liabilities due within one year, consisting primarily of commercial paper, redeemable long-term obligations and
the current portion of long-term debt, totaled $13.0 billion at December 31, 2019, compared with $15.6 billion at year-end
2018. Of these amounts, $9.75 billion and $9.9 billion were reclassified to long-term debt at the end of 2019 and 2018,
respectively.

At year-end 2019, settlement of these obligations was not expected to require the use of working capital in 2020, 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 May 2021 for an unspecified amount of nonconvertible
debt securities issued or guaranteed by the company.

Cash provided by
operating activities
Billions of dollars

Total debt at year-end
Billions of dollars

Capital & exploratory
expenditures*
Billions of dollars

Ratio of total debt to total
debt-plus-Chevron Corporation
stockholders’ equity
Percent

40.0

30.0

20.0

10.0

0.0

$27.3

50.0

40.0

30.0

20.0

10.0

0.0

$27.0

50.0

40.0

30.0

20.0

10.0

0.0

$21.0

25.0

20.0

15.0

10.0

5.0

0.0

15.8%

Of the $21.0 billion of expenditures in 2019, 85 percent, or $17.8 billion, related to upstream activities. Approximately

88 percent was expended for upstream operations in 2018. International upstream accounted for 54 percent of the worldwide

upstream investment in 2019 and 60 percent in 2018.

17 18 19

All Other
Downstream
Upstream

* 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

United States.

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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, cash that may be generated from asset

dispositions, the capital program and shareholder distributions. 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 and discontinue or curtail the stock repurchase program 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 17, Short-Term Debt, on

page 78.

Common Stock Repurchase Program In January 2019, the company purchased shares for $0.3 billion under the July 2010

stock repurchase program. On February 1, 2019, the company announced that the Board of Directors authorized a new stock

repurchase program with a maximum dollar limit of $25 billion and no set term limits. As of December 31, 2019, the

company had purchased a total of 31.1 million shares for $3.7 billion, resulting in $21.3 billion remaining under the program

authorized in February 2019. The company currently expects to repurchase $5 billion of its common stock in 2020.

Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or

in such other manner as determined by the company. The timing of the repurchases and the actual amount repurchased will

depend on a variety of factors, including the market price of the company’s shares, general market and economic conditions,

and other factors. The stock repurchase program does not obligate the company to acquire any particular amount of common

stock, and it may be suspended or discontinued at any time.

Capital and Exploratory Expenditures

Capital and exploratory expenditures by business segment for 2019, 2018 and 2017 are as follows:

Millions of dollars

Upstream

Downstream

All Other

Total

9,627

$ 17,824

$ 10,529

$ 17,657

$ 11,243

$ 16,388

U.S.

8,197

1,868

365

Int’l.

920

U.S.

7,128

1,582

243

Int’l.

611

2019

Total

2,788

382

U.S.

5,145

1,656

239

Int’l.

534

2017

Total

2,190

243

2018

Total

2,193

256

Total, Excluding Equity in Affiliates

$ 10,062

4,820

$ 14,882

8,651

5,739

$ 14,390

6,295

7,783

$ 14,078

$ 10,430

$ 10,564

$ 20,994

8,953

$ 11,153

$ 20,106

7,040

$ 11,781

$ 18,821

Total expenditures for 2019 were $21.0 billion,

including $6.1 billion for the company’s share of equity-affiliate

expenditures, which did not require cash outlays by the company. In 2018, expenditures were $20.1 billion, including the

company’s share of affiliates’ expenditures of $5.7 billion.

The company estimates that 2020 organic capital and exploratory expenditures will be $20 billion, including $6.2 billion of

spending by affiliates. This is in line with 2019 expenditures, and reflects a robust portfolio of upstream and downstream

investments, highlighted by the company’s Permian Basin position, and additional shale and tight development in other

basins. Approximately 84 percent of the total, or $16.8 billion, is budgeted for exploration and production activities.

Approximately $11 billion of planned upstream capital spending relates to base producing assets, including $4 billion for the

Permian and $1 billion for other shale and tight rock investments. Approximately $5 billion of the upstream program is

planned for major capital projects underway, including $4 billion associated with the Future Growth and Wellhead Pressure

Management Project at the Tengiz field in Kazakhstan. Global exploration funding is expected to be about $1 billion.

Remaining upstream spend is budgeted for early stage projects supporting potential future developments. The company

monitors crude oil market conditions and is able to adjust future capital outlays should oil price conditions deteriorate.

Worldwide downstream spending in 2020 is estimated to be $2.8 billion, with $1.6 billion estimated for projects in the

Investments in technology businesses and other corporate operations in 2020 are budgeted at $0.4 billion.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Liquidity and Capital Resources

Sources and uses of cash

inflows and outflows.

The strength of the company’s balance sheet enabled it to fund any timing differences throughout the year between cash

Cash, Cash Equivalents, Marketable Securities and Time Deposits Total balances were $5.7 billion and $10.3 billion at

December 31, 2019 and 2018, respectively. Cash provided by operating activities in 2019 was $27.3 billion, compared to

$30.6 billion in 2018, primarily due to lower crude oil prices. Cash provided by operating activities was net of contributions

to employee pension plans of approximately $1.4 billion in 2019 and $1.0 billion in 2018. Cash provided by investing

activities included proceeds and deposits related to asset sales of $2.8 billion in 2019 and $2.0 billion in 2018.

Restricted cash of $1.2 billion and $1.1 billion at December 31, 2019 and 2018, respectively, was held in cash and short-term

marketable securities and recorded as “Deferred charges and other assets” and “Prepaid expenses and other current assets” on

the Consolidated Balance Sheet. These amounts are generally associated with upstream decommissioning 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 $9.0 billion in 2019 and $8.5 billion in 2018.

Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $27.0 billion at December 31, 2019, down

from $34.5 billion at year-end 2018.

The $7.5 billion decrease in total debt and finance lease liabilities during 2019 was primarily due to the repayment of long-

term notes totaling $5.0 billion as they matured during 2019, and a reduction in commercial paper. The company’s debt and

finance lease liabilities due within one year, consisting primarily of commercial paper, redeemable long-term obligations and

the current portion of long-term debt, totaled $13.0 billion at December 31, 2019, compared with $15.6 billion at year-end

2018. Of these amounts, $9.75 billion and $9.9 billion were reclassified to long-term debt at the end of 2019 and 2018,

respectively.

At year-end 2019, settlement of these obligations was not expected to require the use of working capital in 2020, 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 May 2021 for an unspecified amount of nonconvertible

debt securities issued or guaranteed by the company.

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, cash that may be generated from asset
dispositions, the capital program and shareholder distributions. 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 and discontinue or curtail the stock repurchase program 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 17, Short-Term Debt, on
page 78.

Common Stock Repurchase Program In January 2019, the company purchased shares for $0.3 billion under the July 2010
stock repurchase program. On February 1, 2019, the company announced that the Board of Directors authorized a new stock
repurchase program with a maximum dollar limit of $25 billion and no set term limits. As of December 31, 2019, the
company had purchased a total of 31.1 million shares for $3.7 billion, resulting in $21.3 billion remaining under the program
authorized in February 2019. The company currently expects to repurchase $5 billion of its common stock in 2020.
Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or
in such other manner as determined by the company. The timing of the repurchases and the actual amount repurchased will
depend on a variety of factors, including the market price of the company’s shares, general market and economic conditions,
and other factors. The stock repurchase program does not obligate the company to acquire any particular amount of common
stock, and it may be suspended or discontinued at any time.

Capital and Exploratory Expenditures

Capital and exploratory expenditures by business segment for 2019, 2018 and 2017 are as follows:

Millions of dollars

Upstream
Downstream
All Other

Total

U.S.

8,197
1,868
365

Int’l.

9,627
920
17

2019
Total

$ 17,824
2,788
382

$ 10,430

$ 10,564

$ 20,994

Total, Excluding Equity in Affiliates

$ 10,062

4,820

$ 14,882

Int’l.

2018

Total

$ 10,529
611
13

$ 17,657
2,193
256

U.S.

7,128
1,582
243

8,953

$ 11,153

$ 20,106

8,651

5,739

$ 14,390

Int’l.

2017

Total

$ 11,243
534
4

$ 16,388
2,190
243

U.S.

5,145
1,656
239

7,040

$ 11,781

$ 18,821

6,295

7,783

$ 14,078

including $6.1 billion for the company’s share of equity-affiliate
Total expenditures for 2019 were $21.0 billion,
expenditures, which did not require cash outlays by the company. In 2018, expenditures were $20.1 billion, including the
company’s share of affiliates’ expenditures of $5.7 billion.

Of the $21.0 billion of expenditures in 2019, 85 percent, or $17.8 billion, related to upstream activities. Approximately
88 percent was expended for upstream operations in 2018. International upstream accounted for 54 percent of the worldwide
upstream investment in 2019 and 60 percent in 2018.

The company estimates that 2020 organic capital and exploratory expenditures will be $20 billion, including $6.2 billion of
spending by affiliates. This is in line with 2019 expenditures, and reflects a robust portfolio of upstream and downstream
investments, highlighted by the company’s Permian Basin position, and additional shale and tight development in other
basins. Approximately 84 percent of the total, or $16.8 billion, is budgeted for exploration and production activities.
Approximately $11 billion of planned upstream capital spending relates to base producing assets, including $4 billion for the
Permian and $1 billion for other shale and tight rock investments. Approximately $5 billion of the upstream program is
planned for major capital projects underway, including $4 billion associated with the Future Growth and Wellhead Pressure
Management Project at the Tengiz field in Kazakhstan. Global exploration funding is expected to be about $1 billion.
Remaining upstream spend is budgeted for early stage projects supporting potential future developments. The company
monitors crude oil market conditions and is able to adjust future capital outlays should oil price conditions deteriorate.

Worldwide downstream spending in 2020 is estimated to be $2.8 billion, with $1.6 billion estimated for projects in the
United States.

Investments in technology businesses and other corporate operations in 2020 are budgeted at $0.4 billion.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Noncontrolling Interests The company had noncontrolling interests of $1.0 billion at December 31, 2019 and $1.1 billion at
December 31, 2018. Distributions to noncontrolling interests totaled $18 million and $91 million in 2019 and 2018,
respectively.

Net Debt Ratio Total debt less cash and cash equivalents, time deposits, and marketable securities as a percentage of total

debt less cash and cash equivalents, time deposits, and marketable securities, plus Chevron Corporation Stockholders’

Equity, which indicates the company’s leverage, net of its cash balances.

Pension Obligations Information related to pension plan contributions is included beginning on page 82 in Note 21,
Employee Benefit Plans, under the heading “Cash Contributions and Benefit Payments.”

Financial Ratios and Metrics

The following represent several metrics the company believes are useful measures to monitor the financial health of the
company and its performance over time:

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 2019, the book value of inventory was lower than replacement costs,
based on average acquisition costs during the year, by approximately $4.5 billion.

Millions of dollars

Current assets
Current liabilities

Current Ratio

At December 31

2019

$ 28,329
26,530

1.1

2018

34,021
27,171

1.3

2017

$ 28,560
27,737

1.0

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 2019 was lower than 2018
due to lower income.

Millions of dollars

Income (Loss) Before Income Tax Expense

Plus: Interest and debt expense
Plus: Before tax amortization of capitalized interest
Less: Net income attributable to noncontrolling interests

Subtotal for calculation

Total financing interest and debt costs

Interest Coverage Ratio

2019

$ 5,536
798
240
(79)

6,653

817

8.1

Year ended December 31

2018

20,575
748
280
36

21,567

921

23.4

2017

9,221
307
197
74

9,651

902

10.7

Free Cash Flow The cash provided by operating activities less cash capital expenditures, which represents the cash
available to creditors and investors after investing in the business.

Millions of dollars

Net cash provided by operating activities

Less: Capital expenditures

Free Cash Flow

2019

$ 27,314
14,116

$ 13,198

Year ended December 31

2018

30,618
13,792

2017

$ 20,338
13,404

16,826

6,934

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 was 15.8 percent at year-end 2019, compared with 18.2 percent at year-end
2018.

Millions of dollars

Short-term debt
Long-term debt

Total debt

Total Chevron Corporation Stockholders’ Equity

Total debt plus total Chevron Corporation Stockholders’ Equity

Debt Ratio

2019

3,282
23,691

26,973

At December 31

2018

5,726 $
28,733

34,459

2017

5,192
33,571

38,763

144,213

154,554

148,124

$ 171,186

$ 189,013 $ 186,887

15.8 %

18.2 %

20.7 %

Millions of dollars

Short-term debt

Long-term debt

Total Debt

Less: Cash and cash equivalents

Less: Time deposits

Less: Marketable securities

Total adjusted debt

Total Chevron Corporation Stockholders’ Equity

Millions of dollars

Chevron Corporation Stockholders’ Equity

Plus: Short-term debt

Plus: Long-term debt

Plus: Noncontrolling interest

Capital Employed at December 31

Millions of dollars

Net income attributable to Chevron

Plus: After-tax interest and debt expense

Plus: Noncontrolling interest

Net income after adjustments

Average capital employed

Return on Average Capital Employed

Millions of dollars

Net income attributable to Chevron

Chevron Corporation Stockholders’ Equity at December 31

Average Chevron Corporation Stockholders’ Equity

Return on Average Stockholders’ Equity

Total adjusted debt plus total Chevron Corporation Stockholders’ Equity

$ 165,437

$ 178,668 $ 182,065

Net Debt Ratio

12.8 %

13.5 %

18.6 %

Capital Employed The sum of Chevron Corporation Stockholders’ Equity, total debt and noncontrolling interests, which

represents the net investment in the business.

Return on Average Capital Employed (ROCE) Net income attributable to Chevron (adjusted for after-tax interest expense

and noncontrolling interest) divided by average capital employed. Average capital employed is computed by averaging the

sum of capital employed at the beginning and end of the year. ROCE is a ratio intended to measure annual earnings as a

percentage of historical investments in the business.

Return on Stockholders’ Equity (ROSE) Net income attributable to Chevron divided by average Chevron Corporation

Stockholders’ Equity. Average stockholder’s equity is computed by averaging the sum of stockholder’s equity at the

beginning and end of the year. ROSE is a ratio intended to measure earnings as a percentage of shareholder investments.

5,726 $

At December 31

2018

28,733

34,459

9,342

950

2017

5,192

33,571

38,763

4,813

—

24,114

33,941

154,554

148,124

$ 144,213

$ 154,554 $ 148,124

At December 31

2018

2017

5,726

28,733

1,088

5,192

33,571

1,195

$ 172,181

$ 190,101 $ 188,082

2019

3,282

23,691

26,973

5,686

—

21,224

144,213

2019

3,282

23,691

995

2,924

14,824 $

9,195

2019

761

(79)

3,606

Year ended December 31

2018

2017

713

264

15,573

9,533

$ 181,141

$ 189,092 $ 190,465

2.0 %

8.2 %

5.0 %

2019

2,924

144,213

149,384

Year ended December 31

2018

2017

14,824 $

9,195

154,554

151,339

148,124

146,840

2.0 %

9.8 %

6.3 %

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Noncontrolling Interests The company had noncontrolling interests of $1.0 billion at December 31, 2019 and $1.1 billion at

December 31, 2018. Distributions to noncontrolling interests totaled $18 million and $91 million in 2019 and 2018,

respectively.

Net Debt Ratio Total debt less cash and cash equivalents, time deposits, and marketable securities as a percentage of total
debt less cash and cash equivalents, time deposits, and marketable securities, plus Chevron Corporation Stockholders’
Equity, which indicates the company’s leverage, net of its cash balances.

Pension Obligations Information related to pension plan contributions is included beginning on page 82 in Note 21,

Employee Benefit Plans, under the heading “Cash Contributions and Benefit Payments.”

Financial Ratios and Metrics

company and its performance over time:

The following represent several metrics the company believes are useful measures to monitor the financial health of the

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 2019, the book value of inventory was lower than replacement costs,

based on average acquisition costs during the year, by approximately $4.5 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 2019 was lower than 2018

Millions of dollars

Current assets

Current liabilities

Current Ratio

due to lower income.

Millions of dollars

Income (Loss) Before Income Tax Expense

Plus: Interest and debt expense

Plus: Before tax amortization of capitalized interest

Less: Net income attributable to noncontrolling interests

Subtotal for calculation

Total financing interest and debt costs

Interest Coverage Ratio

Millions of dollars

Net cash provided by operating activities

Less: Capital expenditures

Free Cash Flow

2018.

Millions of dollars

Short-term debt

Long-term debt

Total debt

Debt Ratio

Total Chevron Corporation Stockholders’ Equity

Total debt plus total Chevron Corporation Stockholders’ Equity

At December 31

$ 28,329

2019

26,530

1.1

2018

34,021

27,171

1.3

2017

$ 28,560

27,737

1.0

Year ended December 31

2019

2018

2017

$ 5,536

20,575

9,221

21,567

9,651

921

748

280

23.4

307

197

902

10.7

798

240

(79)

6,653

817

8.1

2019

$ 27,314

14,116

$ 13,198

Year ended December 31

2018

30,618

13,792

2017

$ 20,338

13,404

16,826

6,934

5,726 $

2019

3,282

23,691

26,973

At December 31

2018

28,733

34,459

2017

5,192

33,571

38,763

144,213

154,554

148,124

$ 171,186

$ 189,013 $ 186,887

15.8 %

18.2 %

20.7 %

Free Cash Flow The cash provided by operating activities less cash capital expenditures, which represents the cash

available to creditors and investors after investing in the business.

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 was 15.8 percent at year-end 2019, compared with 18.2 percent at year-end

Millions of dollars

Short-term debt
Long-term debt

Total Debt

Less: Cash and cash equivalents
Less: Time deposits
Less: Marketable securities

Total adjusted debt

Total Chevron Corporation Stockholders’ Equity

2019

3,282
23,691

26,973

5,686
—
63

21,224

144,213

At December 31

2018

5,726 $
28,733

34,459

9,342
950
53

2017

5,192
33,571

38,763

4,813
—
9

24,114

33,941

154,554

148,124

Total adjusted debt plus total Chevron Corporation Stockholders’ Equity

$ 165,437

$ 178,668 $ 182,065

Net Debt Ratio

12.8 %

13.5 %

18.6 %

Capital Employed The sum of Chevron Corporation Stockholders’ Equity, total debt and noncontrolling interests, which
represents the net investment in the business.

Millions of dollars

Chevron Corporation Stockholders’ Equity

Plus: Short-term debt
Plus: Long-term debt
Plus: Noncontrolling interest

Capital Employed at December 31

2019

$ 144,213
3,282
23,691
995

$ 172,181

At December 31

2018

2017

$ 154,554 $ 148,124
5,192
33,571
1,195

5,726
28,733
1,088

$ 190,101 $ 188,082

Return on Average Capital Employed (ROCE) Net income attributable to Chevron (adjusted for after-tax interest expense
and noncontrolling interest) divided by average capital employed. Average capital employed is computed by averaging the
sum of capital employed at the beginning and end of the year. ROCE is a ratio intended to measure annual earnings as a
percentage of historical investments in the business.

Millions of dollars

Net income attributable to Chevron

Plus: After-tax interest and debt expense
Plus: Noncontrolling interest

Net income after adjustments

Average capital employed

Return on Average Capital Employed

2019

2,924
761
(79)

3,606

Year ended December 31

2018

14,824 $
713
36

15,573

2017

9,195
264
74

9,533

$ 181,141

$ 189,092 $ 190,465

2.0 %

8.2 %

5.0 %

Return on Stockholders’ Equity (ROSE) Net income attributable to Chevron divided by average Chevron Corporation
Stockholders’ Equity. Average stockholder’s equity is computed by averaging the sum of stockholder’s equity at the
beginning and end of the year. ROSE is a ratio intended to measure earnings as a percentage of shareholder investments.

Millions of dollars

Net income attributable to Chevron
Chevron Corporation Stockholders’ Equity at December 31
Average Chevron Corporation Stockholders’ Equity

Return on Average Stockholders’ Equity

2019

2,924
144,213
149,384

Year ended December 31

2018

2017

14,824 $
154,554
151,339

9,195
148,124
146,840

2.0 %

9.8 %

6.3 %

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements
Information related to these matters is included on page 87 in Note 22, Other Contingencies and Commitments.

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

Millions of dollars

On Balance Sheet:2

Short-Term Debt3, 4

Long-Term Debt3, 4

Leases

Interest4

Off Balance Sheet:

Throughput and Take-or-Pay Agreements5

Other Unconditional Purchase Obligations5

Total1

2020

2021-2022

2023-2024 After 2024

Payments Due by Period

3,264

$ 3,264

— $

—

23,426

4,662

3,040

11,422

1,257

—

1,409

565

854

16,072

1,693

903

1,720

457

4,003

613

554

1,956

438

3,351

947

1,018

6,892

286

1 Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 21 beginning on page 82.
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.
$9.75 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 2021–2022 period. The amounts represent only the principal balance.

4 Excludes finance lease liabilities.
5 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

Millions of dollars

Total

2020

2021-2022

2023-2024 After 2024

reserves, including those for federal Superfund sites and analogous sites under state laws.

Commitment Expiration by Period

Environmental The following table displays the annual changes to the company’s before-tax environmental remediation

Guarantee of nonconsolidated affiliate or joint-venture obligations

704

314

214

Additional information related to guarantees is included on page 87 in Note 22, Other Contingencies and Commitments.

Indemnifications Information related to indemnifications is included on page 87 in Note 22, Other Contingencies and
Commitments.

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 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 2019.

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 2019 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

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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, 2019 and 2018 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, 2019.

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 2019, 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 71, in Note 13, 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

heading “MTBE.”

MTBE Information related to methyl tertiary butyl ether (MTBE) matters is included on page 72 in Note 14 under the

Ecuador Information related to Ecuador matters is included in Note 14 under the heading “Ecuador,” beginning on page 72.

Millions of dollars

Balance at January 1

Net Additions

Expenditures

Balance at December 31

1,327

1,429

2018

197

(299)

2017

1,467

323

(361)

2019

200

(293)

1,234

1,327

1,429

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 $12.8 billion for asset retirement obligations at year-end 2019

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 decommission 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 2019 environmental expenditures. Refer to Note 22 on page 87 for additional discussion of environmental

remediation provisions and year-end reserves. Refer also to Note 23 on page 89 for additional discussion of the company’s

asset retirement obligations.

Wells, beginning on page 79.

Suspended Wells Information related to suspended wells is included in Note 19, Accounting for Suspended Exploratory

Income Taxes Information related to income tax contingencies is included on pages 74 through 76 in Note 15 and page 87 in

Note 22 under the heading “Income Taxes.”

Other Contingencies Information related to other contingencies is included on page 88 in Note 22 to the Consolidated

Financial Statements under the heading “Other Contingencies.”

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements

Information related to these matters is included on page 87 in Note 22, Other Contingencies and Commitments.

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

Millions of dollars

On Balance Sheet:2

Short-Term Debt3, 4

Long-Term Debt3, 4

Leases

Interest4

Off Balance Sheet:

Throughput and Take-or-Pay Agreements5

Other Unconditional Purchase Obligations5

Total1

2020

2021-2022

2023-2024 After 2024

Payments Due by Period

3,264

$ 3,264

— $

—

23,426

4,662

3,040

11,422

1,257

—

1,409

565

854

16,072

1,693

903

1,720

457

4,003

613

554

1,956

438

3,351

947

1,018

6,892

286

1 Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 21 beginning on page 82.

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.

$9.75 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 2021–2022 period. The amounts represent only the principal balance.

4 Excludes finance lease liabilities.

5 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.

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, 2019 and 2018 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, 2019.

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 2019, 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 71, in Note 13, 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 72 in Note 14 under the
heading “MTBE.”

Ecuador Information related to Ecuador matters is included in Note 14 under the heading “Ecuador,” beginning on page 72.

Guarantee of nonconsolidated affiliate or joint-venture obligations

704

314

214

Additional information related to guarantees is included on page 87 in Note 22, Other Contingencies and Commitments.

Indemnifications Information related to indemnifications is included on page 87 in Note 22, Other Contingencies and

Millions of dollars

Balance at January 1
Net Additions
Expenditures

Balance at December 31

2019

1,327
200
(293)

2018

1,429
197
(299)

2017

1,467
323
(361)

1,234

1,327

1,429

Total

2020

2021-2022

2023-2024 After 2024

Commitment Expiration by Period

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.

Direct Guarantees

Millions of dollars

Commitments.

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 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 2019.

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 2019 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

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 $12.8 billion for asset retirement obligations at year-end 2019
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 decommission 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 2019 environmental expenditures. Refer to Note 22 on page 87 for additional discussion of environmental
remediation provisions and year-end reserves. Refer also to Note 23 on page 89 for additional discussion of the company’s
asset retirement obligations.

Suspended Wells Information related to suspended wells is included in Note 19, Accounting for Suspended Exploratory
Wells, beginning on page 79.

Income Taxes Information related to income tax contingencies is included on pages 74 through 76 in Note 15 and page 87 in
Note 22 under the heading “Income Taxes.”

Other Contingencies Information related to other contingencies is included on page 88 in Note 22 to the Consolidated
Financial Statements under the heading “Other Contingencies.”

43
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Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 and national, regional, and state legislation and regulatory measures
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
regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools
and processes, 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 national, state and local levels. Refer to “Risk Factors” in Part I,
Item 1A, on pages 18 through 21 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 or other pollutants into the environment; remediate
and restore areas damaged by prior releases of 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 2019 at approximately $2.0 billion for its consolidated companies. Included in these expenditures
were approximately $0.6 billion of environmental capital expenditures and $1.4 billion of costs associated with the
prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites,
and the decommissioning and restoration of sites.
For 2020, 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 accounting principles generally accepted in the
United States of America (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:

the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment
necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and
the impact of the estimates and assumptions on the company’s financial condition or operating performance is
material.

The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the
associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of
Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as
follows:

44
Chevron Corporation 2019 Annual Report
44

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 2019, Chevron’s UOP Depreciation, Depletion and Amortization

(DD&A) for oil and gas properties was $14.2 billion, and proved developed reserves at the beginning of 2019

were 6.3 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 2019 would have increased by approximately $700 million.

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 96, for the changes in proved reserve estimates for the

three years ended December 31, 2019, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net

Cash Flows From Proved Reserves” on page 103 for estimates of proved reserve values for each of the three years ended

December 31, 2019.

This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of

Note 1, beginning on page 57, 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, operating expenses, production profiles, and the outlook for global or regional market

supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products. However,

the

impairment reviews and calculations are based on assumptions that are generally consistent with the company’s business

plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in

Note 16 on page 77 and to the section on Properties, Plant and Equipment in Note 1, “Summary of Significant Accounting

Policies,” beginning on page 57.

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

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 and national, regional, and state legislation and regulatory measures

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

regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools

and processes, 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 national, state and local levels. Refer to “Risk Factors” in Part I,

Item 1A, on pages 18 through 21 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 or other pollutants into the environment; remediate

and restore areas damaged by prior releases of 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 2019 at approximately $2.0 billion for its consolidated companies. Included in these expenditures

were approximately $0.6 billion of environmental capital expenditures and $1.4 billion of costs associated with the

prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites,

and the decommissioning and restoration of sites.

For 2020, 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 accounting principles generally accepted in the

United States of America (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:

the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment

necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and

the impact of the estimates and assumptions on the company’s financial condition or operating performance is

material.

The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the

associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of

Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as

follows:

Oil and Gas Reserves Crude oil and natural gas reserves are estimates of future production that impact certain asset and
expense accounts included in the Consolidated Financial Statements. Proved reserves are the estimated quantities of oil and
gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future
under existing economic conditions, operating methods and government regulations. Proved reserves include both developed
and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells
with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from
new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for
recompletion. Variables impacting Chevron’s estimated volumes of crude oil and natural gas reserves include field
performance, available technology, commodity prices, and development and production costs.

The estimates of crude oil and natural gas reserves are important to the timing of expense recognition for costs incurred and
to the valuation of certain oil and gas producing assets. Impacts of oil and gas reserves on Chevron’s Consolidated Financial
Statements, using the successful efforts method of accounting, include the following:

1. Amortization - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production
(UOP) basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP
basis using total proved reserves. During 2019, Chevron’s UOP Depreciation, Depletion and Amortization
(DD&A) for oil and gas properties was $14.2 billion, and proved developed reserves at the beginning of 2019
were 6.3 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 2019 would have increased by approximately $700 million.

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 96, for the changes in proved reserve estimates for the
three years ended December 31, 2019, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net
Cash Flows From Proved Reserves” on page 103 for estimates of proved reserve values for each of the three years ended
December 31, 2019.

This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of
Note 1, beginning on page 57, 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, operating expenses, production profiles, and the outlook for global or regional market
supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products. However,
the
impairment reviews and calculations are based on assumptions that are generally consistent with the company’s business
plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in
Note 16 on page 77 and to the section on Properties, Plant and Equipment in Note 1, “Summary of Significant Accounting
Policies,” beginning on page 57.

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

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

disposed. 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.

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 $401 million, and would have decreased the plan’s underfunded status

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.

In 2019, the company recorded impairments and write-offs for certain oil and gas properties following the review and
approval of its business plan and capital expenditure program. As a result of the company’s disciplined approach to capital
allocation and a downward revision in its longer-term commodity price outlook, the company will reduce funding to various
natural gas-related upstream opportunities including Appalachia shale, Kitimat LNG and other international projects. In
addition, the revised long-term oil price outlook resulted in an impairment of Big Foot. No individually material impairments
of PP&E or Investments were recorded for 2018 or 2017. 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 2019 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 23 on page 89 for additional discussions on asset
retirement obligations.

Pension and Other Postretirement Benefit Plans Note 21, beginning on page 82, 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 84 in
Note 21 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes
beyond the company’s control.

For 2019, the company used an expected long-term rate of return of 6.75 percent and a discount rate for service costs of
4.4 percent and a discount rate for interest cost of 3.7 percent for U.S. pension plans. The actual return for 2019 was
18.3 percent. For the 10 years ended December 31, 2019, actual asset returns averaged 8.1 percent for these plans.
Additionally, with the exception of three years within this 10-year period, actual asset returns for these plans equaled or
exceeded 6.75 percent during each year.

Total pension expense for 2019 was $0.9 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 59 percent of companywide pension expense, would have reduced total pension plan expense for 2019
by approximately $79 million. A 1 percent increase in the discount rates for this same plan would have reduced pension
expense for 2019 by approximately $197 million.

The aggregate funded status recognized at December 31, 2019, was a net liability of approximately $5.2 billion. An increase
in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2019,
the company used a discount rate of 3.1 percent to measure the obligations for the U.S. pension plans. As an indication of the

from approximately $2.5 billion to $2.1 billion.

For the company’s OPEB plans, expense for 2019 was $101 million, and the total liability, all unfunded at the end of 2019,

was $2.5 billion. For the main U.S. OPEB plan, the company used a discount rate for service cost of 4.5 percent and a

discount rate for interest cost of 3.9 percent to measure expense in 2019, and a 3.1 percent discount rate to measure the

benefit obligations at December 31, 2019. Discount rate changes, similar to those used in the pension sensitivity analysis,

resulted in an immaterial impact on 2019 OPEB expense and OPEB liabilities at the end of 2019. For information on the

sensitivity of the health care cost-trend rate, refer to page 84 in Note 21 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 83 in Note 21 for a description of the method used to amortize

the $6.5 billion of before-tax actuarial losses recorded by the company as of December 31, 2019, and an estimate of the costs

to be recognized in expense during 2020. In addition, information related to company contributions is included on page 86 in

Note 21 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 22 beginning on page 87. 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, 2019.

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. For

further information, refer to “Changes in management’s estimates and assumptions may have a material impact on the

company’s consolidated financial statements and financial or operational performance in any given period” in “Risk Factors”

in Part I, Item 1A, on page 21, of the company’s Annual Report on Form 10-K.

New Accounting Standards

Refer to Note 4 beginning on page 62 for information regarding new accounting standards.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

disposed. 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.

In 2019, the company recorded impairments and write-offs for certain oil and gas properties following the review and

approval of its business plan and capital expenditure program. As a result of the company’s disciplined approach to capital

allocation and a downward revision in its longer-term commodity price outlook, the company will reduce funding to various

natural gas-related upstream opportunities including Appalachia shale, Kitimat LNG and other international projects. In

addition, the revised long-term oil price outlook resulted in an impairment of Big Foot. No individually material impairments

of PP&E or Investments were recorded for 2018 or 2017. 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 2019 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 23 on page 89 for additional discussions on asset

retirement obligations.

assumptions.

Pension and Other Postretirement Benefit Plans Note 21, beginning on page 82, 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

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 84 in

Note 21 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes

beyond the company’s control.

For 2019, the company used an expected long-term rate of return of 6.75 percent and a discount rate for service costs of

4.4 percent and a discount rate for interest cost of 3.7 percent for U.S. pension plans. The actual return for 2019 was

18.3 percent. For the 10 years ended December 31, 2019, actual asset returns averaged 8.1 percent for these plans.

Additionally, with the exception of three years within this 10-year period, actual asset returns for these plans equaled or

exceeded 6.75 percent during each year.

Total pension expense for 2019 was $0.9 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 59 percent of companywide pension expense, would have reduced total pension plan expense for 2019

by approximately $79 million. A 1 percent increase in the discount rates for this same plan would have reduced pension

expense for 2019 by approximately $197 million.

The aggregate funded status recognized at December 31, 2019, was a net liability of approximately $5.2 billion. An increase

in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2019,

the company used a discount rate of 3.1 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 $401 million, and would have decreased the plan’s underfunded status
from approximately $2.5 billion to $2.1 billion.

For the company’s OPEB plans, expense for 2019 was $101 million, and the total liability, all unfunded at the end of 2019,
was $2.5 billion. For the main U.S. OPEB plan, the company used a discount rate for service cost of 4.5 percent and a
discount rate for interest cost of 3.9 percent to measure expense in 2019, and a 3.1 percent discount rate to measure the
benefit obligations at December 31, 2019. Discount rate changes, similar to those used in the pension sensitivity analysis,
resulted in an immaterial impact on 2019 OPEB expense and OPEB liabilities at the end of 2019. For information on the
sensitivity of the health care cost-trend rate, refer to page 84 in Note 21 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 83 in Note 21 for a description of the method used to amortize
the $6.5 billion of before-tax actuarial losses recorded by the company as of December 31, 2019, and an estimate of the costs
to be recognized in expense during 2020. In addition, information related to company contributions is included on page 86 in
Note 21 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 22 beginning on page 87. 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, 2019.

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. For
further information, refer to “Changes in management’s estimates and assumptions may have a material impact on the
company’s consolidated financial statements and financial or operational performance in any given period” in “Risk Factors”
in Part I, Item 1A, on page 21, of the company’s Annual Report on Form 10-K.

New Accounting Standards

Refer to Note 4 beginning on page 62 for information regarding new accounting standards.

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Quarterly Results
Unaudited

Millions of dollars, except per-share amounts

4th Q

3rd Q

2nd Q

2019

1st Q

4th Q

3rd Q

2nd Q

2018

1st Q

Revenues and Other Income

Sales and other operating revenues

Income from equity affiliates

Other income

Total Revenues and Other Income

Costs and Other Deductions

Purchased crude oil and products

Operating expenses

Selling, general and administrative expenses

Exploration expenses

Depreciation, depletion and amortization

Taxes other than on income

Interest and debt expense

Other components of net periodic benefit costs

$34,574

$34,779

$36,323

$34,189

$40,338

$42,105

$40,491

$35,968

538

1,238

1,172

165

1,196

1,331

1,062

(51)

1,642

372

1,555

327

1,493

252

1,637

159

36,350

36,116

38,850

35,200

42,352

43,987

42,236

37,764

19,693

19,882

20,835

19,703

23,920

24,681

24,744

21,233

5,987

1,129

272

16,429

969

178

5,325

954

168

4,361

1,059

197

121

5,187

1,076

141

4,334

1,047

198

4,886

984

189

4,094

1,061

225

101

5,645

1,080

250

5,252

901

190

216

4,985

1,018

625

5,380

1,259

182

158

5,213

1,017

177

4,498

1,363

217

102

4,701

723

158

4,289

1,344

159

Total Costs and Other Deductions

44,755

32,067

32,915

31,243

37,454

38,288

37,331

32,691

Income (Loss) Before Income Tax Expense
Income Tax Expense (Benefit)

(8,405)
(1,738)

4,049
1,469

5,935
1,645

3,957
1,315

4,898
1,175

5,699
1,643

4,905
1,483

5,073
1,414

Net Income (Loss)

$ (6,667) $ 2,580

$ 4,290

$ 2,642

$ 3,723

$ 4,056

$ 3,422

$ 3,659

Less: Net income attributable to noncontrolling interests

(57)

—

(15)

(7)

Net Income (Loss) Attributable to Chevron Corporation

$ (6,610) $ 2,580

$ 4,305

$ 2,649

$ 3,730

$ 4,047

$ 3,409

$ 3,638

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron Corporation

– Basic
– Diluted

Dividends

$ (3.51) $
$ (3.51) $

1.38
1.36

1.19

$
$

2.28
2.27

1.19

$
$

1.40
1.39

1.19

$
$

1.97
1.95

1.12

$
$

2.13
2.11

1.12

$
$

1.79
1.78

1.12

$
$

1.92
1.90

1.12

2019.

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, 2019. 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,

The effectiveness of the company’s internal control over financial reporting as of December 31, 2019, has been audited by

PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.

Michael K. Wirth

Chairman of the Board

Pierre R. Breber

Vice President

and Chief Executive Officer

and Chief Financial Officer

David A. Inchausti

Vice President

and Comptroller

February 21, 2020

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Millions of dollars, except per-share amounts

4th Q

3rd Q

2nd Q

4th Q

3rd Q

2nd Q

2019

1st Q

2018

1st Q

Quarterly Results

Unaudited

Revenues and Other Income

Sales and other operating revenues

Income from equity affiliates

Other income

Total Revenues and Other Income

Costs and Other Deductions

Purchased crude oil and products

Operating expenses

Selling, general and administrative expenses

Exploration expenses

Depreciation, depletion and amortization

Taxes other than on income

Interest and debt expense

Other components of net periodic benefit costs

$34,574

$34,779

$36,323

$34,189

$40,338

$42,105

$40,491

$35,968

538

1,238

1,172

165

1,196

1,331

1,062

(51)

1,642

372

1,555

327

1,493

252

1,637

159

36,350

36,116

38,850

35,200

42,352

43,987

42,236

37,764

19,693

19,882

20,835

19,703

23,920

24,681

24,744

21,233

5,987

1,129

272

16,429

969

178

5,325

954

168

4,361

1,059

197

121

5,187

1,076

141

4,334

1,047

198

4,886

984

189

4,094

1,061

225

101

5,645

1,080

250

5,252

901

190

216

4,985

1,018

625

5,380

1,259

182

158

5,213

1,017

177

4,498

1,363

217

102

4,701

723

158

4,289

1,344

159

Total Costs and Other Deductions

44,755

32,067

32,915

31,243

37,454

38,288

37,331

32,691

Income (Loss) Before Income Tax Expense

Income Tax Expense (Benefit)

(8,405)

(1,738)

4,049

1,469

5,935

1,645

3,957

1,315

4,898

1,175

5,699

1,643

4,905

1,483

5,073

1,414

Net Income (Loss)

$ (6,667) $ 2,580

$ 4,290

$ 2,642

$ 3,723

$ 4,056

$ 3,422

$ 3,659

Less: Net income attributable to noncontrolling interests

(57)

—

(15)

(7)

Net Income (Loss) Attributable to Chevron Corporation

$ (6,610) $ 2,580

$ 4,305

$ 2,649

$ 3,730

$ 4,047

$ 3,409

$ 3,638

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron Corporation

– Basic

– Diluted

Dividends

$ (3.51) $

1.38

1.36

1.19

2.28

2.27

1.19

1.40

1.39

1.19

1.97

1.95

1.12

2.13

2.11

1.12

1.79

1.78

1.12

1.92

1.90

1.12

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, 2019. 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,
2019.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2019, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.

Michael K. Wirth
Chairman of the Board
and Chief Executive Officer

February 21, 2020

Pierre R. Breber
Vice President
and Chief Financial Officer

David A. Inchausti
Vice President
and Comptroller

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Report of Independent Registered Public Accounting Firm

Critical Audit Matters

To the Board of Directors and Shareholders of Chevron Corporation:

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheet of Chevron Corporation and its subsidiaries (the
“Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income, of comprehensive
income, of equity and of cash flows for each of the three years in the period ended December 31, 2019, including the
related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s
internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control -
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2019 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, 2019, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the COSO.

Basis for Opinions

The Company’s management is responsible for these consolidated 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 the Company’s consolidated financial statements and on the Company’s internal control over
financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting
Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance
with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material
misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was
maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial
statements. 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.

Definition and Limitations of Internal Control over Financial Reporting

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.

50
Chevron Corporation 2019 Annual Report
50

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated

financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to

accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially

challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our

opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit

matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Crude Oil and Natural Gas Reserves and Other Factors on Upstream Property, Plant, and Equipment, Net

As described in Notes 1 and 16 to the consolidated financial statements, the Company’s upstream property, plant and

equipment, net balance was $133.7 billion as of December 31, 2019, and related depreciation, depletion and amortization

expense was $27.8 billion, including impairments of $10.8 billion for the year ended December 31, 2019. Management

uses the successful efforts method for crude oil and natural gas exploration and production activities. 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. Upstream property, plant, and equipment 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. Impaired assets are written down to their

estimated fair values, generally their discounted, future net cash flows. As disclosed by management, determination as to

whether and how much an asset is impaired involves management estimates on uncertain matters, such as future

commodity prices, 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. 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. Reserves are estimated by Company asset teams composed of

earth scientists and engineers. As part of the internal control process related to reserves estimation, the Company

maintains a Reserves Advisory Committee (RAC) (the RAC is referred to as “management’s specialists”).

The principal considerations for our determination that performing procedures relating to the impact of crude oil and

natural gas reserves and other factors on upstream property, plant, and equipment, net is a critical audit matter are there

was significant judgment by management, including the use of management’s specialists, when developing the estimates

of proved crude oil and natural gas reserves and assessing upstream property, plant, and equipment to be held and used for

impairment. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and

evaluating audit evidence obtained related to the significant assumptions used by management,

including future

commodity prices, production profiles, development costs, and operating expenses.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our

overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls

relating to management’s calculation of upstream depreciation, depletion and amortization expense, assessment of

upstream property, plant, and equipment to be held and used for impairment, and estimates of proved crude oil and natural

gas reserves. These procedures also included, among others, (i) testing the unit-of-production rates used to calculate

depreciation, depletion and amortization expense, (ii) testing the completeness, accuracy, and relevance of underlying data

used in management’s estimates, and (iii) evaluating the significant assumptions used by management in developing these

estimates, including future commodity prices, production profiles, development costs and operating expenses. Evaluating

the significant assumptions relating to the estimates of crude oil and natural gas reserves also involved obtaining evidence

to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the

past performance of the company, and whether they were consistent with evidence obtained in other areas of the audit.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of these

estimates of proved crude oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications and

objectivity were understood, as well as the methods and assumptions used by the specialists. The procedures performed

also included tests of the data used by the specialists and an evaluation of the specialists’ findings.

San Francisco, California

February 21, 2020

We have served as the Company’s auditor since 1935.

145363_10K.indd 50

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Report of Independent Registered Public Accounting Firm

Critical Audit Matters

To the Board of Directors and Shareholders of Chevron Corporation:

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheet of Chevron Corporation and its subsidiaries (the

“Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income, of comprehensive

income, of equity and of cash flows for each of the three years in the period ended December 31, 2019, including the

related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s

internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control -

Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission

(COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial

position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of

the three years in the period ended December 31, 2019 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, 2019, based on criteria established in Internal Control - Integrated Framework

(2013) issued by the COSO.

Basis for Opinions

The Company’s management is responsible for these consolidated 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 the Company’s consolidated financial statements and on the Company’s internal control over

financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting

Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance

with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission

and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and

perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material

misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was

maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material

misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that

respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and

disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used

and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial

statements. 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.

Definition and Limitations of Internal Control over Financial Reporting

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.

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated
financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to
accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially
challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our
opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit
matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Crude Oil and Natural Gas Reserves and Other Factors on Upstream Property, Plant, and Equipment, Net

As described in Notes 1 and 16 to the consolidated financial statements, the Company’s upstream property, plant and
equipment, net balance was $133.7 billion as of December 31, 2019, and related depreciation, depletion and amortization
expense was $27.8 billion, including impairments of $10.8 billion for the year ended December 31, 2019. Management
uses the successful efforts method for crude oil and natural gas exploration and production activities. 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. Upstream property, plant, and equipment 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. Impaired assets are written down to their
estimated fair values, generally their discounted, future net cash flows. As disclosed by management, determination as to
whether and how much an asset is impaired involves management estimates on uncertain matters, such as future
commodity prices, 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. 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. Reserves are estimated by Company asset teams composed of
earth scientists and engineers. As part of the internal control process related to reserves estimation, the Company
maintains a Reserves Advisory Committee (RAC) (the RAC is referred to as “management’s specialists”).

The principal considerations for our determination that performing procedures relating to the impact of crude oil and
natural gas reserves and other factors on upstream property, plant, and equipment, net is a critical audit matter are there
was significant judgment by management, including the use of management’s specialists, when developing the estimates
of proved crude oil and natural gas reserves and assessing upstream property, plant, and equipment to be held and used for
impairment. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and
evaluating audit evidence obtained related to the significant assumptions used by management,
including future
commodity prices, production profiles, development costs, and operating expenses.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our
overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls
relating to management’s calculation of upstream depreciation, depletion and amortization expense, assessment of
upstream property, plant, and equipment to be held and used for impairment, and estimates of proved crude oil and natural
gas reserves. These procedures also included, among others, (i) testing the unit-of-production rates used to calculate
depreciation, depletion and amortization expense, (ii) testing the completeness, accuracy, and relevance of underlying data
used in management’s estimates, and (iii) evaluating the significant assumptions used by management in developing these
estimates, including future commodity prices, production profiles, development costs and operating expenses. Evaluating
the significant assumptions relating to the estimates of crude oil and natural gas reserves also involved obtaining evidence
to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the
past performance of the company, and whether they were consistent with evidence obtained in other areas of the audit.
The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of these
estimates of proved crude oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications and
objectivity were understood, as well as the methods and assumptions used by the specialists. The procedures performed
also included tests of the data used by the specialists and an evaluation of the specialists’ findings.

San Francisco, California

February 21, 2020

We have served as the Company’s auditor since 1935.

51
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51

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Consolidated Statement of Income
Millions of dollars, except per-share amounts

Consolidated Statement of Comprehensive Income

Millions of dollars

Revenues and Other Income

Sales and other operating revenues1
Income from equity affiliates
Other income

Total Revenues and Other Income

Costs and Other Deductions

Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Taxes other than on income1
Interest and debt expense
Other components of net periodic benefit costs

Total Costs and Other Deductions

Income (Loss) Before Income Tax Expense
Income Tax Expense (Benefit)

Net Income (Loss)

Less: Net income (loss) attributable to noncontrolling interests

Net Income (Loss) Attributable to Chevron Corporation

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron Corporation

- Basic
- Diluted

Year ended December 31

2019

2018

2017

139,865
3,968
2,683

146,516

158,902
6,327
1,110

166,339

134,674
4,438
2,610

141,722

80,113
21,385
4,143
770
29,218
4,136
798
417

94,578
20,544
3,838
1,210
19,419
4,867
748
560

75,765
19,127
4,110
864
19,349
12,331
307
648

140,980

145,764

132,501

5,536
2,691

2,845
(79)

2,924

1.55
1.54

$
$

20,575
5,715

14,860
36

14,824

9,221
(48)

9,269
74

9,195

7.81
7.74

$
$

4.88
4.85

$
$

1 2017 include excise, value-added and similar taxes of $7,189, collected on behalf of third parties. Beginning in 2018, these taxes are netted in “Taxes other than on

Comprehensive Income (Loss) Attributable to Chevron Corporation

1,478

15,431

$ 9,449

income” in accordance with Accounting Standards Update (ASU) 2014-09.
Refer to Note 24, “Revenue” beginning on page 89.

See accompanying Notes to the Consolidated Financial Statements.

Net Income (Loss)

Currency translation adjustment

Unrealized net change arising during period

Unrealized holding gain (loss) on securities

Net gain (loss) arising during period

Derivatives

Net derivatives loss on hedge transactions

Reclassification to net income of net realized gain

Income taxes on derivatives transactions

Total

Defined benefit plans

Actuarial gain (loss)

Amortization to net income of net actuarial loss and settlements

Actuarial gain (loss) arising during period

Prior service credits (cost)

Amortization to net income of net prior service costs and curtailments

Prior service (costs) credits arising during period

Defined benefit plans sponsored by equity affiliates - benefit (cost)

Income (taxes) benefit on defined benefit plans

Total

Other Comprehensive Gain (Loss), Net of Tax

Comprehensive Income

Comprehensive loss (income) attributable to noncontrolling interests

See accompanying Notes to the Consolidated Financial Statements.

Year ended December 31

2019

2018

2017

2,845

14,860

$ 9,269

(18)

(1)

—

519

(2,404)

(28)

(33)

510

(1,432)

(1,446)

1,399

(19)

(5)

—

792

(13)

(26)

(230)

631

607

(3)

—

817

(571)

(20)

(1)

(44)

200

254

15,467

9,523

(36)

(74)

52
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Consolidated Statement of Income

Millions of dollars, except per-share amounts

Consolidated Statement of Comprehensive Income
Millions of dollars

Net Income (Loss)

Currency translation adjustment

Unrealized net change arising during period

Unrealized holding gain (loss) on securities
Net gain (loss) arising during period

Derivatives

Net derivatives loss on hedge transactions
Reclassification to net income of net realized gain
Income taxes on derivatives transactions

Total

Defined benefit plans

Actuarial gain (loss)

Amortization to net income of net actuarial loss and settlements
Actuarial gain (loss) arising during period

Prior service credits (cost)

Amortization to net income of net prior service costs and curtailments
Prior service (costs) credits arising during period

Defined benefit plans sponsored by equity affiliates - benefit (cost)
Income (taxes) benefit on defined benefit plans

14,824

Total

Other Comprehensive Gain (Loss), Net of Tax

Comprehensive Income

Comprehensive loss (income) attributable to noncontrolling interests

Year ended December 31

2019

2018

2017

2,845

14,860

$ 9,269

(18)

(1)
—
3

519
(2,404)

4
(28)
(33)
510

(1,432)

(1,446)

1,399

(19)

(5)

—
—
—

—

792
85

(13)
(26)
23
(230)

631

607

(3)

—
—
—

—

817
(571)

(20)
(1)
19
(44)

200

254

15,467

9,523

(36)

(74)

1 2017 include excise, value-added and similar taxes of $7,189, collected on behalf of third parties. Beginning in 2018, these taxes are netted in “Taxes other than on

Comprehensive Income (Loss) Attributable to Chevron Corporation

1,478

15,431

$ 9,449

See accompanying Notes to the Consolidated Financial Statements.

Revenues and Other Income

Sales and other operating revenues1

Income from equity affiliates

Other income

Total Revenues and Other Income

Costs and Other Deductions

Purchased crude oil and products

Operating expenses

Selling, general and administrative expenses

Exploration expenses

Depreciation, depletion and amortization

Taxes other than on income1

Interest and debt expense

Other components of net periodic benefit costs

Total Costs and Other Deductions

Income (Loss) Before Income Tax Expense

Income Tax Expense (Benefit)

Net Income (Loss)

Less: Net income (loss) attributable to noncontrolling interests

Net Income (Loss) Attributable to Chevron Corporation

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron Corporation

- Basic

- Diluted

income” in accordance with Accounting Standards Update (ASU) 2014-09.

Refer to Note 24, “Revenue” beginning on page 89.

See accompanying Notes to the Consolidated Financial Statements.

Year ended December 31

2019

2018

2017

139,865

158,902

134,674

3,968

2,683

6,327

1,110

4,438

2,610

146,516

166,339

141,722

94,578

20,544

3,838

1,210

19,419

4,867

748

560

20,575

5,715

14,860

75,765

19,127

4,110

864

19,349

12,331

307

648

9,221

(48)

9,269

9,195

140,980

145,764

132,501

7.81

7.74

4.88

4.85

80,113

21,385

4,143

770

29,218

4,136

798

417

5,536

2,691

2,845

(79)

2,924

1.55

1.54

53
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Consolidated Balance Sheet
Millions of dollars, except per-share amounts

Consolidated Statement of Cash Flows

Millions of dollars

Assets

Cash and cash equivalents
Time deposits
Marketable securities
Accounts and notes receivable (less allowance: 2019 - $746; 2018 - $869)
Inventories:

Crude oil and petroleum products
Chemicals
Materials, supplies and other

Total inventories

Prepaid expenses and other current assets

Total Current Assets
Long-term receivables, net
Investments and advances
Properties, plant and equipment, at cost
Less: Accumulated depreciation, depletion and amortization

Properties, plant and equipment, net

Deferred charges and other assets
Goodwill
Assets held for sale

Total Assets

Liabilities and Equity
Short-term debt
Accounts payable
Accrued liabilities
Federal and other taxes on income
Other taxes payable

Total Current Liabilities
Long-term debt1
Deferred credits and other noncurrent obligations
Noncurrent deferred income taxes
Noncurrent employee benefit plans

Total Liabilities2

Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued)
Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares

issued at December 31, 2019 and 2018)

Capital in excess of par value
Retained earnings
Accumulated other comprehensive losses
Deferred compensation and benefit plan trust
Treasury stock, at cost (2019 - 560,508,479 shares; 2018 - 539,838,890 shares)

Total Chevron Corporation Stockholders’ Equity

Noncontrolling interests

Total Equity

Total Liabilities and Equity

Includes finance lease liabilities of $282 and $127 at December 31, 2019 and 2018, respectively.

2 Refer to Note 22, “Other Contingencies and Commitments” beginning on page 87.

See accompanying Notes to the Consolidated Financial Statements.

At December 31

2019

2018

5,686
—
63
13,325

3,722
492
1,634

5,848
3,407

28,329
1,511
38,688
326,722
176,228

150,494
10,532
4,463
3,411

237,428

3,282
14,103
6,589
1,554
1,002

26,530
23,691
20,445
13,688
7,866

9,342
950
53
15,050

3,383
487
1,834

5,704
2,922

34,021
1,942
35,546
340,244
171,037

169,207
6,766
4,518
1,863

253,863

5,726
13,953
4,927
1,628
937

27,171
28,733
19,742
15,921
6,654

92,220

98,221

—

1,832
17,265
174,945
(4,990)
(240)
(44,599)

144,213

995

145,208

1,832
17,112
180,987
(3,544)
(240)
(41,593)

154,554

1,088

155,642

237,428

253,863

Operating Activities

Net Income (Loss)

Adjustments

Depreciation, depletion and amortization

Dry hole expense

Distributions less than income from equity affiliates

Net before-tax gains on asset retirements and sales

Net foreign currency effects

Deferred income tax provision

Net decrease (increase) in operating working capital

Decrease (increase) in long-term receivables

Net decrease (increase) in other deferred charges

Cash contributions to employee pension plans

Other

Net Cash Provided by Operating Activities

Investing Activities

Capital expenditures

Proceeds and deposits related to asset sales and returns of investment

Net maturities of (investments in) time deposits

Net sales (purchases) of marketable securities

Net repayment (borrowing) of loans by equity affiliates

Net Cash Used for Investing Activities

Financing Activities

Net borrowings (repayments) of short-term obligations

Proceeds from issuances of long-term debt

Repayments of long-term debt and other financing obligations

Cash dividends - common stock

Distributions to noncontrolling interests

Net sales (purchases) of treasury shares

Year ended December 31

2019

2018

2017

2,845

14,860

9,269

29,218

172

(2,073)

(1,367)

272

(1,966)

1,494

502

(69)

(1,362)

(352)

27,314

(14,116)

2,951

950

(1,245)

(11,458)

(2,821)

—

(5,025)

(8,959)

(18)

(2,935)

332

(3,570)

10,481

19,419

687

(3,580)

(619)

123

1,050

(718)

418

—

(1,035)

30,618

(13,792)

2,392

(950)

(51)

111

2,021

218

(6,741)

(8,502)

(91)

(604)

(91)

4,538

5,943

19,349

198

(2,380)

(2,195)

131

(3,203)

520

(368)

(254)

(980)

251

20,338

(13,404)

5,096

—

(16)

(5,142)

3,991

(6,310)

(8,132)

(78)

1,117

(2,471)

8,414

(12,290)

(8,320)

Net Cash Provided by (Used for) Financing Activities

(19,758)

(13,699)

(14,554)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash

Net Change in Cash, Cash Equivalents and Restricted Cash

Cash, Cash Equivalents and Restricted Cash at January 1

Cash, Cash Equivalents and Restricted Cash at December 31

6,911

10,481

5,943

See accompanying Notes to the Consolidated Financial Statements.

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Consolidated Balance Sheet

Millions of dollars, except per-share amounts

Consolidated Statement of Cash Flows
Millions of dollars

Accounts and notes receivable (less allowance: 2019 - $746; 2018 - $869)

Assets

Cash and cash equivalents

Time deposits

Marketable securities

Inventories:

Chemicals

Crude oil and petroleum products

Materials, supplies and other

Total inventories

Prepaid expenses and other current assets

Total Current Assets

Long-term receivables, net

Investments and advances

Properties, plant and equipment, at cost

Less: Accumulated depreciation, depletion and amortization

Properties, plant and equipment, net

Deferred charges and other assets

Goodwill

Assets held for sale

Total Assets

Liabilities and Equity

Short-term debt

Accounts payable

Accrued liabilities

Federal and other taxes on income

Other taxes payable

Total Current Liabilities

Long-term debt1

Deferred credits and other noncurrent obligations

Noncurrent deferred income taxes

Noncurrent employee benefit plans

Total Liabilities2

issued at December 31, 2019 and 2018)

Capital in excess of par value

Retained earnings

Accumulated other comprehensive losses

Deferred compensation and benefit plan trust

Treasury stock, at cost (2019 - 560,508,479 shares; 2018 - 539,838,890 shares)

Total Chevron Corporation Stockholders’ Equity

Noncontrolling interests

Total Equity

Total Liabilities and Equity

Includes finance lease liabilities of $282 and $127 at December 31, 2019 and 2018, respectively.

2 Refer to Note 22, “Other Contingencies and Commitments” beginning on page 87.

See accompanying Notes to the Consolidated Financial Statements.

At December 31

2019

2018

5,686

—

13,325

3,722

492

1,634

5,848

3,407

28,329

1,511

38,688

326,722

176,228

150,494

10,532

4,463

3,411

237,428

3,282

14,103

6,589

1,554

1,002

26,530

23,691

20,445

13,688

7,866

1,832

17,265

174,945

(4,990)

(240)

(44,599)

144,213

995

145,208

9,342

950

15,050

3,383

487

1,834

5,704

2,922

34,021

1,942

35,546

340,244

171,037

169,207

6,766

4,518

1,863

253,863

5,726

13,953

4,927

1,628

937

27,171

28,733

19,742

15,921

6,654

1,832

17,112

180,987

(3,544)

(240)

(41,593)

154,554

1,088

155,642

237,428

253,863

Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued)

Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares

92,220

98,221

—

Operating Activities
Net Income (Loss)
Adjustments

Depreciation, depletion and amortization
Dry hole expense
Distributions less than income from equity affiliates
Net before-tax gains on asset retirements and sales
Net foreign currency effects
Deferred income tax provision
Net decrease (increase) in operating working capital
Decrease (increase) in long-term receivables
Net decrease (increase) in other deferred charges
Cash contributions to employee pension plans
Other

Net Cash Provided by Operating Activities

Investing Activities

Capital expenditures
Proceeds and deposits related to asset sales and returns of investment
Net maturities of (investments in) time deposits
Net sales (purchases) of marketable securities
Net repayment (borrowing) of loans by equity affiliates

Net Cash Used for Investing Activities

Financing Activities

Net borrowings (repayments) of short-term obligations
Proceeds from issuances of long-term debt
Repayments of long-term debt and other financing obligations
Cash dividends - common stock
Distributions to noncontrolling interests
Net sales (purchases) of treasury shares

Year ended December 31

2019

2018

2017

2,845

14,860

9,269

29,218
172
(2,073)
(1,367)
272
(1,966)
1,494
502
(69)
(1,362)
(352)

27,314

(14,116)
2,951
950
2
(1,245)

(11,458)

(2,821)
—
(5,025)
(8,959)
(18)
(2,935)

19,419
687
(3,580)
(619)
123
1,050
(718)
418
—
(1,035)
13

30,618

(13,792)
2,392
(950)
(51)
111

(12,290)

2,021
218
(6,741)
(8,502)
(91)
(604)

19,349
198
(2,380)
(2,195)
131
(3,203)
520
(368)
(254)
(980)
251

20,338

(13,404)
5,096
—
4
(16)

(8,320)

(5,142)
3,991
(6,310)
(8,132)
(78)
1,117

Net Cash Provided by (Used for) Financing Activities

(19,758)

(13,699)

(14,554)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash

Net Change in Cash, Cash Equivalents and Restricted Cash
Cash, Cash Equivalents and Restricted Cash at January 1

332

(3,570)
10,481

(91)

4,538
5,943

(2,471)
8,414

Cash, Cash Equivalents and Restricted Cash at December 31

6,911

10,481

5,943

See accompanying Notes to the Consolidated Financial Statements.

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Consolidated Statement of Equity
Amounts in millions of dollars

Common
Stock1

Retained
Earnings

Acc. Other
Comprehensive
Income (Loss)

Treasury
Stock
(at cost)

Chevron Corp.
Stockholders’
Equity

Noncontrolling
Interests

Total
Equity

Balance at December 31, 2016

$ 18,187

173,046

(3,843) $

(41,834) $

145,556

1,166

$146,722

Treasury stock transactions
Net income (loss)
Cash dividends
Stock dividends
Other comprehensive income
Purchases of treasury shares
Issuances of treasury shares
Other changes, net

253
—
—
—
—
—
—
—

—
9,195
(8,132)
(3)
—
—
—
—

—
—
—
—
254
—
—
—

—
—
—
—
—
(1)
1,002
—

253
9,195
(8,132)
(3)
254
(1)
1,002
—

—
74
(78)
—
—
—
—
33

253
9,269
(8,210)
(3)
254
(1)
1,002
33

Balance at December 31, 2017

$ 18,440

174,106

(3,589) $

(40,833) $

148,124

1,195

$149,319

Treasury stock transactions
Net income (loss)
Cash dividends
Stock dividends
Other comprehensive income
Purchases of treasury shares
Issuances of treasury shares
Other changes, net

264
—
—
—
—
—
—
—

—
14,824
(8,502)
(3)
—
—
—
562

—
—
—
—
607
—
—
(562)

—
—
—
—
—
(1,751)
991
—

264
14,824
(8,502)
(3)
607
(1,751)
991
—

—
36
(91)
—
—
—
—
(52)

264
14,860
(8,593)
(3)
607
(1,751)
991
(52)

Balance at December 31, 2018

$ 18,704

180,987

(3,544) $

(41,593) $

154,554

1,088

$155,642

Treasury stock transactions
Net income (loss)
Cash dividends
Stock dividends
Other comprehensive income
Purchases of treasury shares
Issuances of treasury shares
Other changes, net

153
—
—
—
—
—
—
—

—
2,924
(8,959)
(3)
—
—
—
(4)

—
—
—
—
(1,446)
—
—
—

—
—
—
—
—
(4,039)
1,033
—

153
2,924
(8,959)
(3)
(1,446)
(4,039)
1,033
(4)

—
(79)
(18)
—
—
—
—
4

153
2,845
(8,977)
(3)
(1,446)
(4,039)
1,033
—

Balance at December 31, 2019

$ 18,857

174,945

(4,990) $

(44,599) $

144,213

995

$145,208

Balance at December 31, 2016

2,442,676,580

Issued2

Purchases
Issuances

—
—

Balance at December 31, 2017

2,442,676,580

Purchases
Issuances

—
—

Balance at December 31, 2018

2,442,676,580

Purchases
Issuances

—
—

Balance at December 31, 2019

2,442,676,580

Common Stock Share Activity

Treasury

(551,170,158)

(10,237)
13,205,700

(537,974,695)

(14,912,039)
13,047,844

(539,838,890)

(33,955,300)
13,285,711

(560,508,479)

Outstanding

1,891,506,422

(10,237)
13,205,700

1,904,701,885

(14,912,039)
13,047,844

1,902,837,690

(33,955,300)
13,285,711

1,882,168,101

1 Beginning and ending balances for all periods include capital in excess of par, common stock issued at par for $1,832, and $(240) associated with Chevron’s Benefit

Plan Trust. Changes reflect capital in excess of par.

2 Beginning and ending total issued share balances include 14,168 shares associated with Chevron’s Benefit Plan Trust.

See accompanying Notes to the Consolidated Financial Statements.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 1

Summary of Significant Accounting Policies

General The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally

accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities,

revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including

discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results

could differ from these estimates as circumstances change and additional information becomes known.

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.

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.

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 and Consolidated Statement of Equity.

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.

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 are primarily stated at

cost or net realizable value.

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

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Consolidated Statement of Equity

Amounts in millions of dollars

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Common

Stock1

Retained

Earnings

Comprehensive

Income (Loss)

Acc. Other

Treasury

Stock

(at cost)

Chevron Corp.

Stockholders’

Equity

Noncontrolling

Interests

Total

Equity

Balance at December 31, 2016

$ 18,187

173,046

(3,843) $

(41,834) $

145,556

1,166

$146,722

Treasury stock transactions

253

Balance at December 31, 2018

$ 18,704

180,987

(3,544) $

(41,593) $

154,554

1,088

$155,642

Treasury stock transactions

153

Balance at December 31, 2017

$ 18,440

174,106

(3,589) $

(40,833) $

148,124

1,195

$149,319

Treasury stock transactions

264

Net income (loss)

Cash dividends

Stock dividends

Other comprehensive income

Purchases of treasury shares

Issuances of treasury shares

Other changes, net

Net income (loss)

Cash dividends

Stock dividends

Other comprehensive income

Purchases of treasury shares

Issuances of treasury shares

Other changes, net

Net income (loss)

Cash dividends

Stock dividends

Other comprehensive income

Purchases of treasury shares

Issuances of treasury shares

Other changes, net

—

Balance at December 31, 2016

2,442,676,580

Balance at December 31, 2017

2,442,676,580

Balance at December 31, 2018

2,442,676,580

Purchases

Issuances

Purchases

Issuances

Purchases

Issuances

—

9,195

(8,132)

(3)

—

14,824

(8,502)

(3)

—

562

—

2,924

(8,959)

(3)

—

(4)

Issued2

—

254

—

607

—

(562)

—

(1,446)

—

(1)

1,002

—

(1,751)

991

—

(4,039)

1,033

—

Treasury

(551,170,158)

(10,237)

13,205,700

(537,974,695)

(14,912,039)

13,047,844

(539,838,890)

(33,955,300)

13,285,711

(560,508,479)

253

9,195

(8,132)

(3)

254

(1)

1,002

—

264

14,824

(8,502)

(3)

607

(1,751)

991

—

153

2,924

(8,959)

(3)

(1,446)

(4,039)

1,033

(4)

(78)

(8,210)

—

(91)

(52)

—

(79)

(18)

—

253

9,269

(3)

254

(1)

1,002

264

14,860

(8,593)

(1,751)

(3)

607

991

(52)

153

2,845

(8,977)

(3)

(1,446)

(4,039)

1,033

—

Outstanding

1,891,506,422

(10,237)

13,205,700

1,904,701,885

(14,912,039)

13,047,844

1,902,837,690

(33,955,300)

13,285,711

1,882,168,101

Balance at December 31, 2019

$ 18,857

174,945

(4,990) $

(44,599) $

144,213

995

$145,208

Common Stock Share Activity

Balance at December 31, 2019

2,442,676,580

1 Beginning and ending balances for all periods include capital in excess of par, common stock issued at par for $1,832, and $(240) associated with Chevron’s Benefit

Plan Trust. Changes reflect capital in excess of par.

2 Beginning and ending total issued share balances include 14,168 shares associated with Chevron’s Benefit Plan Trust.

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 circumstances change and additional information becomes known.

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.

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.

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 and Consolidated Statement of Equity.

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.

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 are primarily stated at
cost or net realizable value.

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

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 19, beginning on page 79, 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 7, beginning on page 65, 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 23, on page 89, 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
interests are recognized using the
for capitalized costs of proved mineral
unit-of-production method by individual field as the related proved reserves are produced. Impairments 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 finance lease right-of-use 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 annually at December 31, or more frequently if an event occurs or circumstances
change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.

Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past
operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable
and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO
is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 23, on
page 89, 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

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Chevron Corporation 2019 Annual Report
58

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 The company accounts for each delivery order of crude oil, natural gas, petroleum and chemical

products as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which

typically occurs at the point in time when control of the product transfers to the customer. Payment is generally due within 30

days of delivery. The company accounts for delivery transportation as a fulfillment cost, not a separate performance

obligation, and recognizes these costs as an operating expense in the period when revenue for the related commodity is

recognized.

Revenue is measured as the amount the company expects to receive in exchange for transferring commodities to the

customer. The company’s commodity sales are typically based on prevailing market-based prices and may include discounts

and allowances. Until market prices become known under terms of the company’s contracts, the transaction price included in

revenue is based on the company’s estimate of the most likely outcome.

Discounts and allowances are estimated using a combination of historical and recent data trends. When deliveries contain

multiple products, an observable standalone selling price is generally used to measure revenue for each product. The

company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in

subsequent periods.

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 net basis in “Taxes other than on income” on the Consolidated Statement of Income,

on page 52. 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.

Prior to the adoption of ASC 606 on January 1, 2018, revenues associated with sales of crude oil, natural gas, petroleum and

chemicals products, and all other sources were recorded when title passed 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 were 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 were presented on a gross basis

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 in which an employee becomes eligible to retain the

award at retirement. The company’s Long-Term Incentive Plan (LTIP) awards include stock options and stock appreciation

rights, which have graded vesting provisions by which one-third of each award vests on each of the first, second and third

anniversaries of the date of grant. In addition, performance shares granted under the company’s LTIP will vest at the end of

the three-year performance period. For awards granted under the company’s LTIP beginning in 2017, stock options and stock

appreciation rights 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 unit awards have cliff vesting by which the total award will vest

on January 31 on or after the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the

satisfaction of certain criteria. The company amortizes these awards on a straight-line basis.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 19, beginning on page 79, for additional discussion of accounting for suspended exploratory well

costs.

AROs.

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 7, beginning on page 65, 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 23, on page 89, relating to

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. Impairments 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 finance lease right-of-use 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

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

income.”

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 annually at December 31, or more frequently if an event occurs or circumstances

change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.

Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past

operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable

and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO

is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 23, on

page 89, 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 The company accounts for each delivery order of crude oil, natural gas, petroleum and chemical
products as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which
typically occurs at the point in time when control of the product transfers to the customer. Payment is generally due within 30
days of delivery. The company accounts for delivery transportation as a fulfillment cost, not a separate performance
obligation, and recognizes these costs as an operating expense in the period when revenue for the related commodity is
recognized.

Revenue is measured as the amount the company expects to receive in exchange for transferring commodities to the
customer. The company’s commodity sales are typically based on prevailing market-based prices and may include discounts
and allowances. Until market prices become known under terms of the company’s contracts, the transaction price included in
revenue is based on the company’s estimate of the most likely outcome.

Discounts and allowances are estimated using a combination of historical and recent data trends. When deliveries contain
multiple products, an observable standalone selling price is generally used to measure revenue for each product. The
company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in
subsequent periods.

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 net basis in “Taxes other than on income” on the Consolidated Statement of Income,
on page 52. 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.

Prior to the adoption of ASC 606 on January 1, 2018, revenues associated with sales of crude oil, natural gas, petroleum and
chemicals products, and all other sources were recorded when title passed 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 were 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 were presented on a gross basis
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 in which an employee becomes eligible to retain the
award at retirement. The company’s Long-Term Incentive Plan (LTIP) awards include stock options and stock appreciation
rights, which have graded vesting provisions by which one-third of each award vests on each of the first, second and third
anniversaries of the date of grant. In addition, performance shares granted under the company’s LTIP will vest at the end of
the three-year performance period. For awards granted under the company’s LTIP beginning in 2017, stock options and stock
appreciation rights 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 unit awards have cliff vesting by which the total award will vest
on January 31 on or after the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the
satisfaction of certain criteria. The company amortizes these awards on a straight-line basis.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 ended December 31, 2019, are reflected in the table below.

Currency
Translation
Adjustments

Unrealized
Holding Gains
(Losses) on

Securities Derivatives

Defined
Benefit Plans

Total

Balance at December 31, 2016

(162) $

(2) $

(3,677) $

(3,843)

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications
Reclassifications2

Net Other Comprehensive Income (Loss)

Balance at December 31, 2017

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications
Reclassifications2

Net Other Comprehensive Income (Loss)
Stranded Tax Reclassification to Retained Earnings3

57
—
57

(3)
—
(3)

—
—
—

(310)
510
200

(256)
510
254

(105) $

(5) $

(2) $

(3,477) $

(3,589)

(19)
—
(19)
—

(5)
—
(5)
—

—
—
—
—

28
603
631
(562)

4
603
607
(562)

Balance at December 31, 2018

(124) $

(10) $

(2) $

(3,408) $

(3,544)

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications
Reclassifications2

Net Other Comprehensive Income (Loss)

Balance at December 31, 2019

(18)
—
(18)

2
—
2

(1)
3
2

(1,838)
406
(1,432)

(1,855)
409
(1,446)

(142) $

(8) $

— $

(4,840) $

(4,990)

1 All amounts are net of tax.
2 Refer to Note 21 beginning on page 82, for reclassified components totaling $523 that are included in employee benefit costs for the year ended December 31, 2019. Related
income taxes for the same period, totaling $117, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were
insignificant.

3 Stranded tax reclassification to retained earnings per ASU 2018-02.

Note 3

Information Relating to the Consolidated Statement of Cash Flows

Net decrease (increase) in operating working capital was composed of the following:

Decrease (increase) in accounts and notes receivable

Decrease (increase) in inventories

Decrease (increase) in prepaid expenses and other current assets

Increase (decrease) in accounts payable and accrued liabilities

Increase (decrease) in income and other taxes payable

Net decrease (increase) in operating working capital

Net cash provided by operating activities includes the following cash payments:

Proceeds and deposits related to asset sales and returns of investment consisted of the

Interest on debt (net of capitalized interest)

Income taxes

following gross amounts:

Proceeds and deposits related to asset sales

Returns of investment from equity affiliates

Proceeds and deposits related to asset sales and returns of investment

Net maturities (investments) of time deposits consisted of the following gross amounts:

Net sales (purchases) of marketable securities consisted of the following gross amounts:

Investments in time deposits

Maturities of time deposits

Net maturities of (investments in) time deposits

Marketable securities purchased

Marketable securities sold

Net sales (purchases) of marketable securities

Net repayment (borrowing) of loans by equity affiliates:

Borrowing of loans by equity affiliates

Repayment of loans by equity affiliates

Net repayment (borrowing) of loans by equity affiliates

Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:

Proceeds from issuances of short-term obligations

Repayments of short-term obligations

Net borrowings (repayments) of short-term obligations with three months or less maturity

Net borrowings (repayments) of short-term obligations

Net sales (purchases) of treasury shares consists of the following gross and net amounts:

Shares issued for share-based compensation plans

Shares purchased under share repurchase and deferred compensation plans

Net sales (purchases) of treasury shares

— $

(950) $

Year ended December 31

2019

2018

2017

1,852

(323)

(109)

1,494

810

4,817

2,809

142

2,951

950

(1)

(1,350)

105

(1,245)

2,586

(1,430)

(3,977)

(2,821)

1,104

(4,039)

(2,935)

437

(424)

(149)

(494)

(88)

(718) $

(915)

(267)

173

998

531

520

736

4,748

265

3,132

2,000

392

2,392

4,930

166

5,096

—

(950) $

(51) $

—

(51) $

— $

111

2,486

(4,136)

3,671

2,021

1,147

(1,751)

(604) $

—

(3)

(142)

126

(16)

5,051

(8,820)

(1,373)

(5,142)

1,118

(1)

1,117

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash.

The “Other” line in the Operating Activities section includes changes in postretirement benefits obligations and other long-

term liabilities.

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash.

“Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense” collectively include

approximately $9.3 billion and $1.1 billion in non-cash reductions recorded in 2019 and 2018, respectively, relating to

impairments and other non-cash charges.

Refer also to Note 23, on page 89, 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, 2019.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 ended December 31, 2019, are reflected in the table below.

Balance at December 31, 2016

(162) $

(2) $

(3,677) $

(3,843)

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications

Reclassifications2

Net Other Comprehensive Income (Loss)

Balance at December 31, 2017

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications

Reclassifications2

Net Other Comprehensive Income (Loss)

Stranded Tax Reclassification to Retained Earnings3

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications

Reclassifications2

Net Other Comprehensive Income (Loss)

Balance at December 31, 2019

1 All amounts are net of tax.

Currency

Translation

Adjustments

Unrealized

Holding Gains

(Losses) on

Securities Derivatives

Benefit Plans

Total

Defined

(105) $

(5) $

(2) $

(3,477) $

(3,589)

—

(19)

—

(19)

—

(18)

—

(18)

(3)

—

(3)

(5)

—

(5)

—

(1)

(310)

510

200

603

631

(562)

(256)

510

254

603

607

(562)

(1,838)

406

(1,432)

(1,855)

409

(1,446)

(142) $

(8) $

— $

(4,840) $

(4,990)

Balance at December 31, 2018

(124) $

(10) $

(2) $

(3,408) $

(3,544)

2 Refer to Note 21 beginning on page 82, for reclassified components totaling $523 that are included in employee benefit costs for the year ended December 31, 2019. Related

income taxes for the same period, totaling $117, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were

insignificant.

3 Stranded tax reclassification to retained earnings per ASU 2018-02.

Note 3
Information Relating to the Consolidated Statement of Cash Flows

Net decrease (increase) in operating working capital was composed of the following:
Decrease (increase) in accounts and notes receivable
Decrease (increase) in inventories
Decrease (increase) in prepaid expenses and other current assets
Increase (decrease) in accounts payable and accrued liabilities
Increase (decrease) in income and other taxes payable

Net decrease (increase) in operating working capital

Net cash provided by operating activities includes the following cash payments:
Interest on debt (net of capitalized interest)
Income taxes

Proceeds and deposits related to asset sales and returns of investment consisted of the

following gross amounts:

Proceeds and deposits related to asset sales
Returns of investment from equity affiliates

Proceeds and deposits related to asset sales and returns of investment

Net maturities (investments) of time deposits consisted of the following gross amounts:
Investments in time deposits
Maturities of time deposits

Net maturities of (investments in) time deposits

Net sales (purchases) of marketable securities consisted of the following gross amounts:
Marketable securities purchased
Marketable securities sold

Net sales (purchases) of marketable securities

Net repayment (borrowing) of loans by equity affiliates:
Borrowing of loans by equity affiliates
Repayment of loans by equity affiliates

Net repayment (borrowing) of loans by equity affiliates

Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:
Proceeds from issuances of short-term obligations
Repayments of short-term obligations
Net borrowings (repayments) of short-term obligations with three months or less maturity

Net borrowings (repayments) of short-term obligations

Net sales (purchases) of treasury shares consists of the following gross and net amounts:
Shares issued for share-based compensation plans
Shares purchased under share repurchase and deferred compensation plans

Net sales (purchases) of treasury shares

Year ended December 31

2019

2018

2017

1,852
7
(323)
(109)
67

1,494

810
4,817

2,809
142

2,951

— $
950

950

(1)
3

(1,350)
105

(1,245)

2,586
(1,430)
(3,977)

(2,821)

1,104
(4,039)

(2,935)

437
(424)
(149)
(494)
(88)

(718) $

736
4,748

2,000
392

2,392

(950) $
—

(950) $

(51) $
—

(51) $

— $
111

111

2,486
(4,136)
3,671

2,021

1,147
(1,751)

(604) $

(915)
(267)
173
998
531

520

265
3,132

4,930
166

5,096

—
—

—

(3)
7

(142)
126

(16)

5,051
(8,820)
(1,373)

(5,142)

1,118
(1)

1,117

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash.

The “Other” line in the Operating Activities section includes changes in postretirement benefits obligations and other long-
term liabilities.

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash.
“Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense” collectively include
approximately $9.3 billion and $1.1 billion in non-cash reductions recorded in 2019 and 2018, respectively, relating to
impairments and other non-cash charges.

Refer also to Note 23, on page 89, 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, 2019.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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:

and vessels.

exploration and production equipment, office buildings and warehouses, and land. Finance leases primarily include facilities

Year ended December 31

Additions to properties, plant and equipment *
Additions to investments
Current-year dry hole expenditures
Payments for other assets and liabilities, net

Capital expenditures
Expensed exploration expenditures
Assets acquired through finance leases and other obligations
Payments for other assets and liabilities, net

Capital and exploratory expenditures, excluding equity affiliates
Company’s share of expenditures by equity affiliates

2019

13,839
140
124
13

14,116
598
181
(13)

14,882
6,112

2018

13,384
65
344
(1)

13,792
523
75
—

14,390
5,716

Capital and exploratory expenditures, including equity affiliates

20,994

20,106

* Excludes non-cash movements of $(239) in 2019, $25 in 2018 and $1,183 in 2017.

2017

13,222
25
157
—

13,404
666
8
—

14,078
4,743

18,821

The table below quantifies the beginning and ending balances of restricted cash and restricted cash equivalents in the
Consolidated Balance Sheet:

Cash and cash equivalents
Restricted cash included in “Prepaid expenses and other current assets”
Restricted cash included in “Deferred charges and other assets”

Total cash, cash equivalents and restricted cash

Year ended December 31

2019

5,686
452
773

6,911

2018

9,342
341
798

10,481

2017

4,813
405
725

5,943

Note 4
New Accounting Standards
Leases (Topic 842) Effective January 1, 2019, Chevron adopted Accounting Standards Update (ASU) 2016-02 and its
related amendments. For additional information on the company’s leases, refer to Note 5 beginning on page 62.

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 completed the accounting policy and work process changes necessary to meet
the standard’s requirements. The company does not expect the implementation of the standard to have a material effect on its
consolidated financial statements.

Note 5
Lease Commitments
Chevron implemented the new lease standard at the effective date of January 1, 2019. The cumulative-effect adjustment to
the opening balance of 2019 retained earnings is de minimis. The company elected the option to apply the transition
provisions at the adoption date instead of the earliest comparative period presented in the financial statements. By making
this election, the company has not applied retrospective reporting for the comparable periods. The company elected the short-
term lease exception provided for in the standard and therefore only recognizes right-of-use assets and lease liabilities for
leases with a term greater than one year.

The company elected the package of practical expedients to not re-evaluate existing contracts as containing a lease or the
lease classification unless it was not previously assessed against the lease criteria. In addition, the company did not reassess
initial direct costs for any existing leases. The company applied the land easement practical expedient. The company has
elected the practical expedient to not separate non-lease components from lease components for most asset classes except for
certain asset classes that have significant non-lease (i.e., service) components. The company assessed some contracts,
including those for drill ships, drilling rigs, and storage tanks, not previously assessed against the lease criteria, as operating
leases under the new standard, increasing the lease commitments by approximately $2 billion.

The company enters into leasing arrangements as a lessee; any lessor arrangements are not significant. Leases are classified
as operating or finance leases. Both operating and finance leases recognize lease liabilities and associated right-of-use assets.
Operating lease arrangements mainly involve drill ships, drilling rigs, time chartered vessels, bareboat charters, terminals,

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Chevron uses various assumptions and judgments in preparing the quantitative data and qualitative information that is

material to the company’s overall lease population. Where leases are used in joint ventures, the company recognizes 100% of

the right-of-use assets and lease liabilities when the company is the sole signatory for the lease (in most cases, where the

company is the operator of a joint venture). Lease costs reflect only the costs associated with the operator’s working interest

share. The lease term includes the committed lease term identified in the contract, taking into account renewal and

termination options that management is reasonably certain to exercise. The company uses its incremental borrowing rate as a

proxy for the discount rate based on the term of the lease unless the implicit rate is available.

Details of the right-of-use assets and lease liabilities for operating and finance leases,

including the balance sheet

presentation, are as follows:

Deferred charges and other assets

Properties, plant and equipment, net

Right-of-use assets1, 2

Accrued Liabilities

Short-term Debt

Current lease liabilities

Long-term Debt

Noncurrent lease liabilities

Total lease liabilities

Deferred credits and other noncurrent obligations

Weighted-average remaining lease term (in years)

Weighted-average discount rate

1 Capitalized leased assets of $818 are primarily from the Upstream segment, with accumulated amortization of $617 at December 31, 2018.

Includes non-cash additions of $1,201 and $184 right-of-use assets obtained in exchange for new and modified lease liabilities in 2019 for operating and finance leases,

respectively.

Total lease costs consist of both amounts recognized in the Consolidated Statement of Income during the period and amounts

capitalized as part of the cost of another asset. Total lease costs incurred for operating and finance leases were as follows:

Operating lease costs1, 2

Finance lease costs

Total lease costs

1 Net rental expense of $816 and $721 for 2018 and 2017, respectively.

Includes variable and short-term lease costs.

Cash paid for amounts included in the measurement of lease liabilities was as follows:

Operating cash flows from operating leases

Investing cash flows from operating leases

Operating cash flows from finance leases

Financing cash flows from finance leases

At December 31, 2019

Operating

Leases

Finance

Leases

4,074

—

4,074

1,277

—

1,277

2,608

—

2,608

3,885

5.2

3.2%

16.0

4.7%

—

329

—

282

300

2,621

2,687

1,574

1,047

Year Ended

December 31, 2019

Year Ended

December 31, 2019

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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:

exploration and production equipment, office buildings and warehouses, and land. Finance leases primarily include facilities
and vessels.

Additions to properties, plant and equipment *

Additions to investments

Current-year dry hole expenditures

Payments for other assets and liabilities, net

Capital expenditures

Expensed exploration expenditures

Assets acquired through finance leases and other obligations

Payments for other assets and liabilities, net

Capital and exploratory expenditures, excluding equity affiliates

Company’s share of expenditures by equity affiliates

Cash and cash equivalents

Restricted cash included in “Prepaid expenses and other current assets”

Restricted cash included in “Deferred charges and other assets”

Total cash, cash equivalents and restricted cash

Note 4

New Accounting Standards

Year ended December 31

2019

2018

13,839

13,384

14,116

13,792

13,404

140

124

598

181

(13)

344

(1)

523

—

14,882

6,112

14,390

5,716

2017

13,222

157

—

666

—

14,078

4,743

18,821

Year ended December 31

2019

5,686

452

773

6,911

2018

9,342

341

798

10,481

2017

4,813

405

725

5,943

Capital and exploratory expenditures, including equity affiliates

20,994

20,106

* Excludes non-cash movements of $(239) in 2019, $25 in 2018 and $1,183 in 2017.

The table below quantifies the beginning and ending balances of restricted cash and restricted cash equivalents in the

Consolidated Balance Sheet:

Leases (Topic 842) Effective January 1, 2019, Chevron adopted Accounting Standards Update (ASU) 2016-02 and its

related amendments. For additional information on the company’s leases, refer to Note 5 beginning on page 62.

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 completed the accounting policy and work process changes necessary to meet

the standard’s requirements. The company does not expect the implementation of the standard to have a material effect on its

consolidated financial statements.

Note 5

Lease Commitments

Chevron implemented the new lease standard at the effective date of January 1, 2019. The cumulative-effect adjustment to

the opening balance of 2019 retained earnings is de minimis. The company elected the option to apply the transition

provisions at the adoption date instead of the earliest comparative period presented in the financial statements. By making

this election, the company has not applied retrospective reporting for the comparable periods. The company elected the short-

term lease exception provided for in the standard and therefore only recognizes right-of-use assets and lease liabilities for

leases with a term greater than one year.

The company elected the package of practical expedients to not re-evaluate existing contracts as containing a lease or the

lease classification unless it was not previously assessed against the lease criteria. In addition, the company did not reassess

initial direct costs for any existing leases. The company applied the land easement practical expedient. The company has

elected the practical expedient to not separate non-lease components from lease components for most asset classes except for

certain asset classes that have significant non-lease (i.e., service) components. The company assessed some contracts,

including those for drill ships, drilling rigs, and storage tanks, not previously assessed against the lease criteria, as operating

leases under the new standard, increasing the lease commitments by approximately $2 billion.

The company enters into leasing arrangements as a lessee; any lessor arrangements are not significant. Leases are classified

as operating or finance leases. Both operating and finance leases recognize lease liabilities and associated right-of-use assets.

Operating lease arrangements mainly involve drill ships, drilling rigs, time chartered vessels, bareboat charters, terminals,

Chevron uses various assumptions and judgments in preparing the quantitative data and qualitative information that is
material to the company’s overall lease population. Where leases are used in joint ventures, the company recognizes 100% of
the right-of-use assets and lease liabilities when the company is the sole signatory for the lease (in most cases, where the
company is the operator of a joint venture). Lease costs reflect only the costs associated with the operator’s working interest
share. The lease term includes the committed lease term identified in the contract, taking into account renewal and
termination options that management is reasonably certain to exercise. The company uses its incremental borrowing rate as a
proxy for the discount rate based on the term of the lease unless the implicit rate is available.

Details of the right-of-use assets and lease liabilities for operating and finance leases,
presentation, are as follows:

including the balance sheet

Deferred charges and other assets
Properties, plant and equipment, net

Right-of-use assets1, 2

Accrued Liabilities
Short-term Debt

Current lease liabilities

Deferred credits and other noncurrent obligations
Long-term Debt

Noncurrent lease liabilities

Total lease liabilities

Weighted-average remaining lease term (in years)
Weighted-average discount rate

At December 31, 2019

Operating
Leases

Finance
Leases

4,074
—

4,074

1,277
—

1,277

2,608
—

2,608

3,885

—
329

329

—
18

—
282

282

300

5.2
3.2%

16.0
4.7%

1 Capitalized leased assets of $818 are primarily from the Upstream segment, with accumulated amortization of $617 at December 31, 2018.
2

Includes non-cash additions of $1,201 and $184 right-of-use assets obtained in exchange for new and modified lease liabilities in 2019 for operating and finance leases,
respectively.

Total lease costs consist of both amounts recognized in the Consolidated Statement of Income during the period and amounts
capitalized as part of the cost of another asset. Total lease costs incurred for operating and finance leases were as follows:

Operating lease costs1, 2
Finance lease costs

Total lease costs

1 Net rental expense of $816 and $721 for 2018 and 2017, respectively.
2

Includes variable and short-term lease costs.

Cash paid for amounts included in the measurement of lease liabilities was as follows:

Operating cash flows from operating leases
Investing cash flows from operating leases
Operating cash flows from finance leases
Financing cash flows from finance leases

Year Ended
December 31, 2019

2,621
66

2,687

Year Ended
December 31, 2019

1,574
1,047
13
24

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At December 31, 2019, the estimated future undiscounted cash flows for operating and finance leases were as follows:

Year 2020
2021
2022
2023
2024
Thereafter

Total

Less: Amounts representing interest

Total lease liabilities

At December 31, 2019

Operating Leases

Finance Leases

1,374
1,083
546
336
216
696

4,251

366

3,885

35
33
31
31
30
251

411

111

300

Current assets

Other assets

Current liabilities

Other liabilities

Total CUSA net equity

Memo: Total debt

Note 7

Fair Value Measurements

At December 31

2019

13,059

50,796

18,291

12,565

32,999

3,222

2018

12,819

55,814

16,376

12,906

39,351

3,049

Additionally, the company has $790 in future undiscounted cash flows for operating leases not yet commenced. These leases
are primarily for a drill ship, a facility, a bareboat charter, and a drilling rig. For those leasing arrangements where the
underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset.

At December 31, 2018, the estimated future minimum lease payments (net of noncancelable sublease rentals) under
operating and capital leases, which at inception had a noncancelable term of more than one year, were as follows:

Year 2019
2020
2021
2022
2023
Thereafter

Total

Less: Amounts representing interest and executory costs

Net present values
Less: Capital lease obligations included in short-term debt

Long-term capital lease obligations

At December 31, 2018

Operating Leases

Capital Leases *

540
492
378
242
166
341

2,159

30
22
17
16
16
132

233

(88)

145
(18)

127

* Excluded from the table is an executed but not-yet-commenced capital lease with payments of $14, $15, $22, $21, $21 and $219 for 2019, 2020, 2021, 2022, 2023 and

thereafter, respectively.

Note 6
Summarized Financial Data – Chevron U.S.A. Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate
most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas
and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from
petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in
the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. The
summarized financial information for CUSA and its consolidated subsidiaries is as follows:

Sales and other operating revenues
Total costs and other deductions
Net income (loss) attributable to CUSA

2019

109,314
116,365
(5,061)

Year ended December 31

2018

125,076
121,351
4,334

2017

104,054
103,904
4,842

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The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and

nonrecurring basis at December 31, 2019, and December 31, 2018.

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,

2019.

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 upstream properties during 2019 primarily

due to capital allocation decisions and a lower long-term commodity price outlook. The company did not have any

individually material impairments in 2018.

Investments and Advances The company reported impairments for certain upstream equity companies during 2019

primarily due to capital allocation decisions and a lower long-term commodity price outlook. The company did not have any

individually material impairments of investments and advances in 2018.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Marketable securities

Derivatives

Total assets at fair value

Derivatives

Total liabilities at fair value

At December 31, 2019

At December 31, 2018

Total

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

63 $

74 $

63 $

64 $

26 $

— $

10 $

48 $

— $

—

— $

—

— $

53 $

283

336 $

12 $

53 $

185

238 $

—

— $

98 $

12 $

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Total Level 1 Level 2 Level 3

Year 2019

Total Level 1 Level 2 Level 3

At December 31

Before-Tax Loss

At December 31

Before-Tax Loss

Year 2018

Properties, plant and equipment, net (held

and used)

for sale)

Investments and advances

$ 2,177 $ — $ — $ 2,177 $

2,095

102 $ — $

62 $

40 $

1,412

— 1,412

—

8,702

594

1,694

— 1,273

—

421

Total nonrecurring assets at fair value

$ 3,641 $ — $ 1,442 $ 2,199 $

11,391

$ 1,877 $ — $ 1,355 $

522 $

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 $5,686 and $9,342 at

—

638

804

At December 31, 2019

Operating Leases

Finance Leases

1,374

1,083

546

336

216

696

4,251

366

3,885

540

492

378

242

166

341

2,159

251

411

111

300

132

233

(88)

145

(18)

127

At December 31, 2018

Operating Leases

Capital Leases *

Year 2020

2021

2022

2023

2024

Thereafter

Total

Less: Amounts representing interest

Total lease liabilities

Year 2019

2020

2021

2022

2023

Thereafter

Total

thereafter, respectively.

Note 6

Less: Amounts representing interest and executory costs

Net present values

Less: Capital lease obligations included in short-term debt

Long-term capital lease obligations

Additionally, the company has $790 in future undiscounted cash flows for operating leases not yet commenced. These leases

are primarily for a drill ship, a facility, a bareboat charter, and a drilling rig. For those leasing arrangements where the

underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset.

At December 31, 2018, 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:

* Excluded from the table is an executed but not-yet-commenced capital lease with payments of $14, $15, $22, $21, $21 and $219 for 2019, 2020, 2021, 2022, 2023 and

Summarized Financial Data – Chevron U.S.A. Inc.

Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate

most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas

and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from

petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in

the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. The

summarized financial information for CUSA and its consolidated subsidiaries is as follows:

Sales and other operating revenues

Total costs and other deductions

Net income (loss) attributable to CUSA

Year ended December 31

2019

109,314

116,365

(5,061)

2018

125,076

121,351

4,334

2017

104,054

103,904

4,842

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At December 31, 2019, the estimated future undiscounted cash flows for operating and finance leases were as follows:

Current assets
Other assets
Current liabilities
Other liabilities

Total CUSA net equity

Memo: Total debt

At December 31
2018

12,819
55,814
16,376
12,906

39,351

3,049

2019

13,059
50,796
18,291
12,565

32,999

3,222

Note 7
Fair Value Measurements
The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and
nonrecurring basis at December 31, 2019, and December 31, 2018.

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,
2019.

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 upstream properties during 2019 primarily
due to capital allocation decisions and a lower long-term commodity price outlook. The company did not have any
individually material impairments in 2018.

Investments and Advances The company reported impairments for certain upstream equity companies during 2019
primarily due to capital allocation decisions and a lower long-term commodity price outlook. The company did not have any
individually material impairments of investments and advances in 2018.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Marketable securities
Derivatives

Total assets at fair value

Derivatives

Total liabilities at fair value

Total

Level 1

At December 31, 2019
Level 3

Level 2

At December 31, 2018

Total

Level 1

Level 2

Level 3

63 $
11

74 $

63 $
1

64 $

26 $

— $
10

10 $

48 $

— $
—

— $

—

— $

53 $
283

336 $

12 $

53 $
185

238 $

—

— $

— $
98

98 $

12 $

—
—

—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Total Level 1 Level 2 Level 3

At December 31

Before-Tax Loss
Year 2019

Total Level 1 Level 2 Level 3

At December 31

Before-Tax Loss
Year 2018

Properties, plant and equipment, net (held

and used)

$ 2,177 $ — $ — $ 2,177 $

2,095

102 $ — $

62 $

40 $

Properties, plant and equipment, net (held

for sale)

Investments and advances

1,412
52

— 1,412
30
—

—
22

8,702
594

1,694
81

— 1,273
20
—

421
61

Total nonrecurring assets at fair value

$ 3,641 $ — $ 1,442 $ 2,199 $

11,391

$ 1,877 $ — $ 1,355 $

522 $

638
69

804

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 $5,686 and $9,342 at

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

December 31, 2019, and December 31, 2018, respectively. The instruments held in “Time deposits” are bank time deposits with
maturities greater than 90 days and had carrying/fair values of zero and $950 at December 31, 2019, and December 31, 2018,
respectively. The fair values of cash, cash equivalents and bank time deposits are classified as Level 1 and reflect the cash that
would have been received if the instruments were settled at December 31, 2019.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,225 and $1,139 at December 31,
2019, and December 31, 2018, respectively. At December 31, 2019, these investments are classified as Level 1 and include
restricted funds related to certain upstream decommissioning activities, refundable deposits held in escrow related to pending
asset sales, tax payments and a financing program, which are reported in “Deferred charges and other assets” on the
Consolidated Balance Sheet. Long-term debt, excluding finance lease liabilities, of $13,659 and $18,706 at December 31,
2019, and December 31, 2018, respectively, had estimated fair values of $14,326 and $18,729, respectively. Long-term debt
primarily includes corporate issued bonds. The fair value of corporate bonds is $13,460 and classified as Level 1. The fair
value of other long-term debt is $866 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, 2019 and 2018, were not material.

Note 8
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, 2019, December 31, 2018, and December 31, 2017, 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

undistributed earnings of equity affiliates.

Type of Contract

Balance Sheet Classification

Commodity
Commodity

Accounts and notes receivable, net
Long-term receivables, net

Total assets at fair value

Commodity
Commodity

Total liabilities at fair value

Accounts payable
Deferred credits and other noncurrent obligations

2019

11
—

74
—

At December 31

2018

279
4

283

12
—

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

Type of Derivative

Contract

Commodity
Commodity
Commodity

Statement of

Income Classification

Sales and other operating revenues
Purchased crude oil and products
Other income

Gain/(Loss)
Year ended December 31

2019

(291) $
(17)
(2)

(310) $

2018

135
(33)
3

105

2017

(105)
(9)
(2)

(116)

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated
Balance Sheet at December 31, 2019 and December 31, 2018.

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

At December 31, 2019

Derivative Assets

Derivative Liabilities

At December 31, 2018

Derivative Assets

Derivative Liabilities

Gross Amounts

Recognized

Gross Amounts

Offset

Net Amounts

Presented

Gross Amounts

Not Offset

Net Amounts

656

719

3,685

3,414

645

3,402

283

— $

283

Derivative assets and liabilities are classified on the Consolidated Balance Sheet as accounts and notes receivable, long-term

receivables, accounts payable, and deferred credits and other noncurrent obligations. Amounts not offset on the Consolidated

Balance Sheet represent positions that do not meet all the conditions for “a right of offset.”

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist

primarily of its cash equivalents, time deposits, marketable securities, derivative financial instruments and trade receivables.

The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings.

Company investment policies limit the company’s exposure both to credit risk and to concentrations of credit risk. Similar

policies on diversification and creditworthiness are applied to the company’s counterparties in derivative instruments.

The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s

broad customer base worldwide. As a result, the company believes concentrations of credit risk are limited. The company

routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered

sufficient, alternative risk mitigation measures may be deployed, including requiring pre-payments, letters of credit or other

acceptable collateral instruments to support sales to customers.

At December 31, 2019, the company classified $3,411 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 2019 were not material.

Retained earnings at December 31, 2019 and 2018, included $25,319 and $22,362, respectively, for the company’s share of

At December 31, 2019, about 72 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, 688,303 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 9

Assets Held for Sale

Note 10

Equity

Note 11

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 20, “Stock Options and Other

Share-Based Compensation,” beginning on page 80). The table on the following page sets forth the computation of basic and

diluted EPS:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

December 31, 2019, and December 31, 2018, respectively. The instruments held in “Time deposits” are bank time deposits with

maturities greater than 90 days and had carrying/fair values of zero and $950 at December 31, 2019, and December 31, 2018,

respectively. The fair values of cash, cash equivalents and bank time deposits are classified as Level 1 and reflect the cash that

would have been received if the instruments were settled at December 31, 2019.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,225 and $1,139 at December 31,

2019, and December 31, 2018, respectively. At December 31, 2019, these investments are classified as Level 1 and include

restricted funds related to certain upstream decommissioning activities, refundable deposits held in escrow related to pending

asset sales, tax payments and a financing program, which are reported in “Deferred charges and other assets” on the

Consolidated Balance Sheet. Long-term debt, excluding finance lease liabilities, of $13,659 and $18,706 at December 31,

2019, and December 31, 2018, respectively, had estimated fair values of $14,326 and $18,729, respectively. Long-term debt

primarily includes corporate issued bonds. The fair value of corporate bonds is $13,460 and classified as Level 1. The fair

value of other long-term debt is $866 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, 2019 and 2018, were not material.

Note 8

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.

also be required.

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

Derivative instruments measured at fair value at December 31, 2019, December 31, 2018, and December 31, 2017, 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

Type of Contract

Balance Sheet Classification

Accounts and notes receivable, net

Long-term receivables, net

Commodity

Total assets at fair value

Total liabilities at fair value

Accounts payable

Deferred credits and other noncurrent obligations

Type of Derivative

Contract

Commodity

Statement of

Income Classification

Sales and other operating revenues

Purchased crude oil and products

Other income

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

At December 31

2019

—

Gain/(Loss)

Year ended December 31

2019

(291) $

(17)

(2)

2018

135

(33)

(310) $

105

2018

279

283

—

2017

(105)

(9)

(2)

(116)

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated

Balance Sheet at December 31, 2019 and December 31, 2018.

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

At December 31, 2019

Derivative Assets
Derivative Liabilities

At December 31, 2018
Derivative Assets
Derivative Liabilities

Gross Amounts
Recognized

Gross Amounts
Offset

Net Amounts
Presented

Gross Amounts
Not Offset

Net Amounts

$
$

656
719

3,685
3,414

$
$

645
645

3,402
3,402

$
$

11
74

283
12

$
$

— $
— $

11
74

283
12

Derivative assets and liabilities are classified on the Consolidated Balance Sheet as accounts and notes receivable, long-term
receivables, accounts payable, and deferred credits and other noncurrent obligations. Amounts not offset on the Consolidated
Balance Sheet represent positions that do not meet all the conditions for “a right of offset.”

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist
primarily of its cash equivalents, time deposits, marketable securities, derivative financial instruments and trade receivables.
The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings.
Company investment policies limit the company’s exposure both to credit risk and to concentrations of credit risk. Similar
policies on diversification and creditworthiness are applied to the company’s counterparties in derivative instruments.

The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s
broad customer base worldwide. As a result, the company believes concentrations of credit risk are limited. The company
routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered
sufficient, alternative risk mitigation measures may be deployed, including requiring pre-payments, letters of credit or other
acceptable collateral instruments to support sales to customers.

Note 9
Assets Held for Sale
At December 31, 2019, the company classified $3,411 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 2019 were not material.

Note 10
Equity
Retained earnings at December 31, 2019 and 2018, included $25,319 and $22,362, respectively, for the company’s share of
undistributed earnings of equity affiliates.

At December 31, 2019, about 72 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, 688,303 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 11
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 20, “Stock Options and Other
Share-Based Compensation,” beginning on page 80). The table on the following page sets forth the computation of basic and
diluted EPS:

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Basic EPS Calculation

Earnings available to common stockholders - Basic1

Weighted-average number of common shares outstanding2

Add: Deferred awards held as stock units

Total weighted-average number of common shares outstanding

Earnings per share of common stock - Basic

Diluted EPS Calculation

Earnings available to common stockholders - Diluted1

Weighted-average number of common shares outstanding2

Add: Deferred awards held as stock units
Add: Dilutive effect of employee stock-based awards

Total weighted-average number of common shares outstanding

Earnings per share of common stock - Diluted

Year ended December 31

2019

2018

2,924

14,824

1,882
—

1,882

1.55

1,897
1

1,898

7.81

2,924

14,824

1,882
—
13

1,895

1,897
1
16

1,914

1.54

7.74

2017

9,195

1,882
1

1,883

4.88

9,195

1,882
1
15

1,898

4.85

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.

Note 12
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 activities.

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).

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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 are not allocated to the operating segments. However,

operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All

Other.” Earnings by major operating area are presented in the following table:

Net Income (Loss) Attributable to Chevron Corporation

2,924

14,824

Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2019 and 2018

Year ended December 31

2019

2018

(5,094) $

7,670

2,576

1,559

922

2,481

5,057

(761)

181

(1,553)

3,278

10,038

13,316

2,103

1,695

3,798

17,114

(713)

137

(1,714)

145,648

4,463

186,037

25,197

16,955

42,152

228,189

3,475

5,764

9,239

64,598

168,367

4,463

2017

3,640

4,510

8,150

2,938

2,276

5,214

13,364

(264)

(3,965)

9,195

42,594

153,861

4,518

200,973

23,866

15,622

39,488

240,461

5,100

8,302

13,402

71,560

177,785

4,518

253,863

At December 31

2019

2018

35,926

Upstream

United States

International

Total Upstream

Downstream

United States

International

Total Downstream

Total Segment Earnings

All Other

Interest expense

Interest income

Other

are as follows:

Upstream

United States

International

Goodwill

Total Upstream

Downstream

United States

International

Total Downstream

Total Segment Assets

All Other

United States

International

Total All Other

Total Assets – United States

Total Assets – International

Goodwill

Total Assets

237,428

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal

transfers, for the years 2019, 2018 and 2017, 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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Basic EPS Calculation

Earnings available to common stockholders - Basic1

Weighted-average number of common shares outstanding2

Add: Deferred awards held as stock units

Total weighted-average number of common shares outstanding

Earnings per share of common stock - Basic

Diluted EPS Calculation

Earnings available to common stockholders - Diluted1

Weighted-average number of common shares outstanding2

Add: Deferred awards held as stock units

Add: Dilutive effect of employee stock-based awards

Total weighted-average number of common shares outstanding

Earnings per share of common stock - Diluted

2 Millions of shares.

Note 12

Year ended December 31

2019

2018

2,924

14,824

1,882

—

1,882

1.55

2,924

1,882

—

1,895

1,897

1,898

7.81

14,824

1,897

1,914

1.54

7.74

2017

9,195

1,882

1,883

4.88

9,195

1,882

1,898

4.85

1 There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.

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 activities.

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 are not allocated to the operating segments. However,
operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All
Other.” Earnings by major operating area are presented in the following table:

Year ended December 31

Upstream

United States
International

Total Upstream

Downstream

United States
International

Total Downstream

Total Segment Earnings
All Other

Interest expense
Interest income
Other

2019

2018

(5,094) $
7,670

2,576

1,559
922

2,481

5,057

(761)
181
(1,553)

3,278
10,038

13,316

2,103
1,695

3,798

17,114

(713)
137
(1,714)

Net Income (Loss) Attributable to Chevron Corporation

2,924

14,824

2017

3,640
4,510

8,150

2,938
2,276

5,214

13,364

(264)
60
(3,965)

9,195

Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2019 and 2018
are as follows:

Upstream

United States
International
Goodwill

Total Upstream

Downstream

United States
International

Total Downstream

Total Segment Assets

All Other

United States
International

Total All Other

Total Assets – United States
Total Assets – International
Goodwill

Total Assets

At December 31

2019

2018

35,926
145,648
4,463

186,037

25,197
16,955

42,152

228,189

3,475
5,764

9,239

64,598
168,367
4,463

237,428

42,594
153,861
4,518

200,973

23,866
15,622

39,488

240,461

5,100
8,302

13,402

71,560
177,785
4,518

253,863

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal
transfers, for the years 2019, 2018 and 2017, 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.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Year ended December 311

2018

2017

Note 13

Investments and Advances

Upstream

United States
International

Subtotal

Intersegment Elimination – United States
Intersegment Elimination – International

Total Upstream

Downstream

United States
International

Subtotal

Intersegment Elimination – United States
Intersegment Elimination – International

Total Downstream

All Other

United States
International

Subtotal

Intersegment Elimination – United States
Intersegment Elimination – International

Total All Other

Sales and Other Operating Revenues

United States
International

Subtotal

Intersegment Elimination – United States
Intersegment Elimination – International

2019

23,358
35,628

58,986

(14,944)
(12,335)

31,707

55,271
57,654

112,925

(3,924)
(1,089)

107,912

1,064
20

1,084

(818)
(20)

246

79,693
93,302

172,995

(19,686)
(13,444)

22,891
37,822

60,713

(13,965)
(13,679)

33,069

59,376
70,095

129,471

(2,742)
(1,132)

125,597

1,022
22

1,044

(786)
(22)

236

83,289
107,939

191,228

(17,493)
(14,833)

13,242
28,680

41,922

(9,341)
(11,471)

21,110

53,140
61,395

114,535

(14)
(1,166)

113,355

1,022
26

1,048

(814)
(25)

209

67,404
90,101

157,505

(10,169)
(12,662)

134,674

Total Sales and Other Operating Revenues

139,865

158,902

1 Other than the United States, no other country accounted for 10 percent or more of the company’s Sales and Other Operating Revenues.

Segment Income Taxes Segment income tax expense for the years 2019, 2018 and 2017 is as follows:

Year ended December 31

Upstream

United States
International

Total Upstream

Downstream

United States
International

Total Downstream

All Other

2019

(1,550)
3,492

1,942

392
170

562

187

2018

811
4,687

5,498

534
328

862

(645)

Total Income Tax Expense (Benefit)

2,691

5,715

2017

(3,538)
2,249

(1,289)

(419)
650

231

1,010

(48)

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 13,
on page 71. Information related to properties, plant and equipment by segment is contained in Note 16, on page 77.

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Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other

investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its

share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are

reported on the Consolidated Statement of Income as “Income tax expense.”

Upstream

Tengizchevroil

Petropiar

Petroboscan

Other

Total Upstream

Downstream

Caspian Pipeline Consortium

Angola LNG Limited

GS Caltex Corporation

Other

Total Downstream

All Other

Other

Chevron Phillips Chemical Company LLC

Investments and Advances

At December 31

2019

2018

2019

Equity in Earnings

Year ended December 31

2018

2017

20,214

16,017

3,067

3,614

2,581

1,396

1,139

883

2,423

881

26,936

6,241

3,796

1,443

11,480

(14)

38,402

286

38,688

7,203

31,485

1,361

1,315

1,022

2,496

1,541

23,752

6,218

3,924

1,383

11,525

(16)

35,261

285

35,546

7,500

28,046

(11)

155

(26)

(478)

2,787

880

288

1,181

—

3,968

641

3,327

317

357

170

172

4,649

1,034

373

273

1,680

175

154

155

104

3,196

723

290

230

1,243

(2)

(1)

6,327

4,438

1,033

5,294

788

3,650

Total equity method

Other non-equity method investments

Total investments and advances

Total United States

Total International

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, 2019, the company’s carrying value of its investment in TCO was

about $110 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.

Included in the investment is a loan to TCO to fund the development of the Future Growth and Wellhead Pressure

Management Project with a balance of $3,350.

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company which operates the heavy oil Huyapari Field

and upgrading project in Venezuela’s Orinoco Belt. At December 31, 2019, the company’s carrying value of its investment

in Petropiar was approximately $130 less than the amount of underlying equity in Petropiar’s net assets. The difference

represents the excess of Chevron’s underlying equity in Petropiar’s net assets over the net book value of the assets

contributed to the venture.

Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in

Venezuela. At December 31, 2019, the company’s carrying value of its investment in Petroboscan was approximately $90

higher than the amount of underlying equity in Petroboscan’s net assets. The difference reflects the excess of the net book

value of the assets contributed by Chevron over its underlying equity in Petroboscan’s net assets. The company also has an

outstanding long-term loan to Petroboscan of $566 at year-end 2019.

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 $883, which includes long-term loans of $199 at year-end 2019. 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.

Intersegment Elimination – United States

Intersegment Elimination – International

Intersegment Elimination – United States

Intersegment Elimination – International

Intersegment Elimination – United States

Intersegment Elimination – International

Sales and Other Operating Revenues

Intersegment Elimination – United States

Intersegment Elimination – International

Upstream

United States

International

Subtotal

Total Upstream

Downstream

United States

International

Subtotal

Total Downstream

All Other

United States

International

Subtotal

Total All Other

United States

International

Subtotal

Upstream

United States

International

Total Upstream

Downstream

United States

International

Total Downstream

All Other

2019

23,358

35,628

58,986

(14,944)

(12,335)

31,707

55,271

57,654

112,925

(3,924)

(1,089)

107,912

1,064

1,084

(818)

(20)

246

79,693

93,302

172,995

(19,686)

(13,444)

2019

(1,550)

3,492

1,942

392

170

562

187

22,891

37,822

60,713

(13,965)

(13,679)

33,069

59,376

70,095

129,471

(2,742)

(1,132)

125,597

1,022

1,044

(786)

(22)

236

83,289

107,939

191,228

(17,493)

(14,833)

2018

4,687

5,498

534

328

862

(645)

13,242

28,680

41,922

(9,341)

(11,471)

21,110

53,140

61,395

114,535

(14)

(1,166)

113,355

1,022

1,048

(814)

(25)

209

67,404

90,101

157,505

(10,169)

(12,662)

134,674

2017

(3,538)

2,249

(1,289)

(419)

650

231

1,010

(48)

Total Sales and Other Operating Revenues

139,865

158,902

1 Other than the United States, no other country accounted for 10 percent or more of the company’s Sales and Other Operating Revenues.

Segment Income Taxes Segment income tax expense for the years 2019, 2018 and 2017 is as follows:

Year ended December 31

811

Total Income Tax Expense (Benefit)

2,691

5,715

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 13,

on page 71. Information related to properties, plant and equipment by segment is contained in Note 16, on page 77.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Year ended December 311

2018

2017

Note 13
Investments and Advances
Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other
investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its
share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are
reported on the Consolidated Statement of Income as “Income tax expense.”

Upstream

Tengizchevroil
Petropiar
Petroboscan
Caspian Pipeline Consortium
Angola LNG Limited
Other

Total Upstream

Downstream

Chevron Phillips Chemical Company LLC
GS Caltex Corporation
Other

Total Downstream

All Other
Other

Total equity method
Other non-equity method investments

Total investments and advances

Total United States
Total International

Investments and Advances
At December 31

2019

2018

20,214
1,396
1,139
883
2,423
881

26,936

6,241
3,796
1,443

11,480

(14)

38,402
286

38,688

7,203
31,485

$
$

16,017
1,361
1,315
1,022
2,496
1,541

23,752

6,218
3,924
1,383

11,525

(16)

35,261
285

35,546

7,500
28,046

$
$

Equity in Earnings
Year ended December 31

2018

3,614
317
357
170
172
19

4,649

1,034
373
273

1,680

2017

2,581
175
154
155
27
104

3,196

723
290
230

1,243

(2)

(1)

6,327

4,438

1,033
5,294

$
$

788
3,650

2019

3,067
80
(11)
155
(26)
(478)

2,787

880
13
288

1,181

—

3,968

641
3,327

$
$

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, 2019, the company’s carrying value of its investment in TCO was
about $110 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.
Included in the investment is a loan to TCO to fund the development of the Future Growth and Wellhead Pressure
Management Project with a balance of $3,350.

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company which operates the heavy oil Huyapari Field
and upgrading project in Venezuela’s Orinoco Belt. At December 31, 2019, the company’s carrying value of its investment
in Petropiar was approximately $130 less than the amount of underlying equity in Petropiar’s net assets. The difference
represents the excess of Chevron’s underlying equity in Petropiar’s net assets over the net book value of the assets
contributed to the venture.

Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in
Venezuela. At December 31, 2019, the company’s carrying value of its investment in Petroboscan was approximately $90
higher than the amount of underlying equity in Petroboscan’s net assets. The difference reflects the excess of the net book
value of the assets contributed by Chevron over its underlying equity in Petroboscan’s net assets. The company also has an
outstanding long-term loan to Petroboscan of $566 at year-end 2019.

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 $883, which includes long-term loans of $199 at year-end 2019. 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.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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.

Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. The
other half is owned by Phillips 66.

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.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $8,006, $10,378
and $8,165 with affiliated companies for 2019, 2018 and 2017, respectively. “Purchased crude oil and products” includes
$5,694, $6,598 and $4,800 with affiliated companies for 2019, 2018 and 2017, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $810 and $884 due from affiliated companies at
December 31, 2019 and 2018, respectively. “Accounts payable” includes $506 and $631 due to affiliated companies at
December 31, 2019 and 2018, 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 $4,331, $3,402 and $3,853 at December 31, 2019,
2018 and 2017, respectively.

Year ended December 31

Total revenues
Income before income tax expense
Net income attributable to affiliates

At December 31

Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities

Total affiliates’ net equity

Note 14
Litigation

2019

66,473
13,197
9,809

30,791
97,177
26,032
21,593

2018

84,469
16,693
13,321

32,657
87,614
26,006
20,000

Affiliates

2017

70,744
13,487
10,751

33,883
82,261
26,873
21,447

Chevron Share

2019

32,628
5,954
4,366

12,998
41,531
10,610
5,068

2018

40,679
6,755
6,384

12,813
36,369
9,843
4,446

2017

33,460
5,712
4,468

13,568
32,643
10,201
4,224

80,343

74,265

67,824

38,851

34,893

31,786

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 civil litigation proceedings stemming from a lawsuit filed in the Superior Court for
the province of Nueva Loja in Lago Agrio, Ecuador in May 2003 by plaintiffs who claim to be representatives of residents of
an area where an oil production consortium formerly operated. The lawsuit alleged harm to the environment from the
consortium’s oil production activities and sought monetary damages and other relief. Texaco Petroleum Company (Texpet), a
subsidiary of Texaco Inc., was a minority member of the consortium from 1967 until 1992, with state-owned Petroecuador as
the majority partner. Since 1992, Petroecuador has been the sole owner and operator in the concession area. After the
termination of the consortium and following an independent third-party environmental audit of the concession area, in 1995,
Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador under which Texpet agreed to
remediate specific sites assigned by the government in proportion to Texpet’s minority share of the consortium. Pursuant to
that agreement, Texpet conducted a three-year remediation program. After certifying that the assigned sites were properly
remediated, in 1998, Ecuador granted Texpet and all related corporate entities a full release from any and all environmental
liability arising from the consortium operations.

Chevron defended itself in the Lago Agrio lawsuit on the grounds that the claims lacked both legal and factual merit. As to
matters of law, Chevron asserted that the court lacked jurisdiction, the plaintiffs sought to improperly apply a 1999 law

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72

retroactively, the claims were time-barred, and the lawsuit was barred by releases signed by the Republic of Ecuador,

Petroecuador, and the pertinent provincial and municipal governments. With regard to the facts, the company asserted that the

evidence confirmed Texpet’s remediation was properly conducted and that any remaining environmental impacts reflected

Petroecuador’s failure to timely fulfill its own legal obligation to remediate the concession area and Petroecuador’s conduct after

it assumed control over operations. In February 2011, the provincial court rendered a judgment against Chevron, awarding

approximately $8,600 in damages plus, approximately $900 for the plaintiffs’ representatives, and approximately $8,600 in

additional punitive damages unless the company issued a public apology within 15 days, which Chevron did not do. In

January 2012 an appellate panel affirmed the judgment and ordered that Chevron pay an additional 0.10% in attorneys’ fees. In

November 2013, Ecuador’s National Court of Justice ratified the judgment but nullified the $8,600 punitive damage assessment,

resulting in a judgment of $9,500. In December 2013, Chevron appealed the decision to Ecuador’s highest Constitutional Court,

which rejected Chevron’s appeal in July 2018. No further appeals are available in Ecuador.

The Lago Agrio plaintiffs’ lawyers have sought to enforce the judgment in Ecuador and other jurisdictions. In May 2012,

they filed a recognition and enforcement action against Chevron Corporation, Chevron Canada Limited and another

subsidiary (which was later dismissed as a party) in the Superior Court of Justice in Ontario, Canada. In September 2015, the

Supreme Court of Canada ruled that the Ontario Superior Court of Justice had jurisdiction over Chevron Corporation and

Chevron Canada Limited for purposes of the action. In January 2017, the Superior Court ruled that Chevron Canada Limited

and Chevron Corporation are separate legal entities with separate rights and obligations, and dismissed the action against

Chevron Canada Limited. In May 2018, the Court of Appeal for Ontario upheld the dismissal of Chevron Canada Limited.

The Supreme Court of Canada denied the plaintiffs’ application for leave to appeal in April 2019, rendering the dismissal of

Chevron Canada Limited final. In July 2019, by consent of the parties, the Ontario Superior Court dismissed the recognition

and enforcement action against Chevron Corporation with prejudice and with costs in favor of Chevron. In June 2012, the

plaintiffs filed a recognition and enforcement action against Chevron Corporation in the Superior Court of Justice in Brasilia,

Brazil. In May 2015, the Brazilian public prosecutor issued an opinion recommending that the court reject the plaintiffs’

action on grounds including that the Lago Agrio judgment was procured through fraud and corruption and violated Brazilian

and international public order. In November 2017, the Superior Court of Justice dismissed the plaintiffs’ recognition and

enforcement action on jurisdictional grounds, and in June 2018 the dismissal became final in Brazil. In October 2012, the

provincial court in Ecuador issued an ex parte embargo order purporting to order the seizure of assets belonging to separate

Chevron subsidiaries in Ecuador, Argentina and Colombia. In November 2012, at the request of the plaintiffs, a court in

Argentina issued a freeze order against Chevron Argentina S.R.L. and another Chevron subsidiary. In January 2013, an

appellate court upheld the freeze order, but in June 2013, the Supreme Court of Argentina revoked the freeze order in its

entirety. In December 2013, Chevron was served with the plaintiffs’ complaint seeking recognition and enforcement of the

judgment in Argentina. In April 2016, the public prosecutor in Argentina issued an opinion recommending rejection of the

plaintiffs’ request to recognize the Ecuadorian judgment in Argentina. In November 2017, the National Court, First Instance,

dismissed the complaint on jurisdictional grounds and the Federal Civil Court of Appeals affirmed the dismissal in July 2018.

The plaintiffs’ appeal to the Supreme Court of Argentina remains pending. Chevron continues to believe the Ecuadorian

judgment is illegitimate and unenforceable because it is the product of fraud and corruption, and contrary to the law and all

legitimate scientific evidence. Chevron cannot predict the timing or outcome of any pending or threatened enforcement

action, but expects to continue a vigorous defense against any imposition of liability and to contest and defend any and all

enforcement actions.

In February 2011, Chevron filed a civil lawsuit in the U.S. District Court for the Southern District of New York against the

Lago Agrio plaintiffs and several of their lawyers and supporters, asserting violations of the Racketeer Influenced and

Corrupt Organizations (RICO) Act and state law. In March 2014, the District Court entered a judgment in favor of Chevron,

finding that the Ecuadorian judgment had been procured through fraud, bribery and corruption, and prohibiting the RICO

defendants from seeking to enforce the Lago Agrio judgment in the United States or profiting from their illegal acts. In

August 2016, the U.S. Court of Appeals for the Second Circuit issued a unanimous decision affirming the New York

judgment in full. In June 2017, the U.S. Supreme Court denied the RICO defendants’ petition for a Writ of Certiorari,

rendering the New York judgment in favor of Chevron final.

Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before an arbitral tribunal

administered by the Permanent Court of Arbitration in The Hague, under the Rules of the United Nations Commission on

International Trade Law. The claim alleged violations of Ecuador’s obligations under the United States-Ecuador Bilateral

Investment Treaty (BIT) and breaches of the settlement and release agreements between Ecuador and Texpet. In

January 2012, the Tribunal issued its First Interim Measures Award requiring Ecuador to take all measures at its disposal to

suspend or cause to be suspended the enforcement or recognition within and outside of Ecuador of any judgment against

Chevron in the Lago Agrio case pending further order of the Tribunal. In February 2012, the Tribunal issued a Second

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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.

Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. The

other half is owned by Phillips 66.

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.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $8,006, $10,378

and $8,165 with affiliated companies for 2019, 2018 and 2017, respectively. “Purchased crude oil and products” includes

$5,694, $6,598 and $4,800 with affiliated companies for 2019, 2018 and 2017, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $810 and $884 due from affiliated companies at

December 31, 2019 and 2018, respectively. “Accounts payable” includes $506 and $631 due to affiliated companies at

December 31, 2019 and 2018, 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 $4,331, $3,402 and $3,853 at December 31, 2019,

2019

66,473

13,197

9,809

30,791

97,177

26,032

21,593

2018

84,469

16,693

13,321

32,657

87,614

26,006

20,000

Affiliates

2017

70,744

13,487

10,751

33,883

82,261

26,873

21,447

Chevron Share

2019

32,628

5,954

4,366

12,998

41,531

10,610

5,068

2018

40,679

6,755

6,384

12,813

36,369

9,843

4,446

2017

33,460

5,712

4,468

13,568

32,643

10,201

4,224

Total affiliates’ net equity

80,343

74,265

67,824

38,851

34,893

31,786

2018 and 2017, respectively.

Year ended December 31

Total revenues

Income before income tax expense

Net income attributable to affiliates

At December 31

Current assets

Noncurrent assets

Current liabilities

Noncurrent liabilities

Note 14

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 civil litigation proceedings stemming from a lawsuit filed in the Superior Court for

the province of Nueva Loja in Lago Agrio, Ecuador in May 2003 by plaintiffs who claim to be representatives of residents of

an area where an oil production consortium formerly operated. The lawsuit alleged harm to the environment from the

consortium’s oil production activities and sought monetary damages and other relief. Texaco Petroleum Company (Texpet), a

subsidiary of Texaco Inc., was a minority member of the consortium from 1967 until 1992, with state-owned Petroecuador as

the majority partner. Since 1992, Petroecuador has been the sole owner and operator in the concession area. After the

termination of the consortium and following an independent third-party environmental audit of the concession area, in 1995,

Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador under which Texpet agreed to

remediate specific sites assigned by the government in proportion to Texpet’s minority share of the consortium. Pursuant to

that agreement, Texpet conducted a three-year remediation program. After certifying that the assigned sites were properly

remediated, in 1998, Ecuador granted Texpet and all related corporate entities a full release from any and all environmental

liability arising from the consortium operations.

Chevron defended itself in the Lago Agrio lawsuit on the grounds that the claims lacked both legal and factual merit. As to

matters of law, Chevron asserted that the court lacked jurisdiction, the plaintiffs sought to improperly apply a 1999 law

retroactively, the claims were time-barred, and the lawsuit was barred by releases signed by the Republic of Ecuador,
Petroecuador, and the pertinent provincial and municipal governments. With regard to the facts, the company asserted that the
evidence confirmed Texpet’s remediation was properly conducted and that any remaining environmental impacts reflected
Petroecuador’s failure to timely fulfill its own legal obligation to remediate the concession area and Petroecuador’s conduct after
it assumed control over operations. In February 2011, the provincial court rendered a judgment against Chevron, awarding
approximately $8,600 in damages plus, approximately $900 for the plaintiffs’ representatives, and approximately $8,600 in
additional punitive damages unless the company issued a public apology within 15 days, which Chevron did not do. In
January 2012 an appellate panel affirmed the judgment and ordered that Chevron pay an additional 0.10% in attorneys’ fees. In
November 2013, Ecuador’s National Court of Justice ratified the judgment but nullified the $8,600 punitive damage assessment,
resulting in a judgment of $9,500. In December 2013, Chevron appealed the decision to Ecuador’s highest Constitutional Court,
which rejected Chevron’s appeal in July 2018. No further appeals are available in Ecuador.

The Lago Agrio plaintiffs’ lawyers have sought to enforce the judgment in Ecuador and other jurisdictions. In May 2012,
they filed a recognition and enforcement action against Chevron Corporation, Chevron Canada Limited and another
subsidiary (which was later dismissed as a party) in the Superior Court of Justice in Ontario, Canada. In September 2015, the
Supreme Court of Canada ruled that the Ontario Superior Court of Justice had jurisdiction over Chevron Corporation and
Chevron Canada Limited for purposes of the action. In January 2017, the Superior Court ruled that Chevron Canada Limited
and Chevron Corporation are separate legal entities with separate rights and obligations, and dismissed the action against
Chevron Canada Limited. In May 2018, the Court of Appeal for Ontario upheld the dismissal of Chevron Canada Limited.
The Supreme Court of Canada denied the plaintiffs’ application for leave to appeal in April 2019, rendering the dismissal of
Chevron Canada Limited final. In July 2019, by consent of the parties, the Ontario Superior Court dismissed the recognition
and enforcement action against Chevron Corporation with prejudice and with costs in favor of Chevron. In June 2012, the
plaintiffs filed a recognition and enforcement action against Chevron Corporation in the Superior Court of Justice in Brasilia,
Brazil. In May 2015, the Brazilian public prosecutor issued an opinion recommending that the court reject the plaintiffs’
action on grounds including that the Lago Agrio judgment was procured through fraud and corruption and violated Brazilian
and international public order. In November 2017, the Superior Court of Justice dismissed the plaintiffs’ recognition and
enforcement action on jurisdictional grounds, and in June 2018 the dismissal became final in Brazil. In October 2012, the
provincial court in Ecuador issued an ex parte embargo order purporting to order the seizure of assets belonging to separate
Chevron subsidiaries in Ecuador, Argentina and Colombia. In November 2012, at the request of the plaintiffs, a court in
Argentina issued a freeze order against Chevron Argentina S.R.L. and another Chevron subsidiary. In January 2013, an
appellate court upheld the freeze order, but in June 2013, the Supreme Court of Argentina revoked the freeze order in its
entirety. In December 2013, Chevron was served with the plaintiffs’ complaint seeking recognition and enforcement of the
judgment in Argentina. In April 2016, the public prosecutor in Argentina issued an opinion recommending rejection of the
plaintiffs’ request to recognize the Ecuadorian judgment in Argentina. In November 2017, the National Court, First Instance,
dismissed the complaint on jurisdictional grounds and the Federal Civil Court of Appeals affirmed the dismissal in July 2018.
The plaintiffs’ appeal to the Supreme Court of Argentina remains pending. Chevron continues to believe the Ecuadorian
judgment is illegitimate and unenforceable because it is the product of fraud and corruption, and contrary to the law and all
legitimate scientific evidence. Chevron cannot predict the timing or outcome of any pending or threatened enforcement
action, but expects to continue a vigorous defense against any imposition of liability and to contest and defend any and all
enforcement actions.

In February 2011, Chevron filed a civil lawsuit in the U.S. District Court for the Southern District of New York against the
Lago Agrio plaintiffs and several of their lawyers and supporters, asserting violations of the Racketeer Influenced and
Corrupt Organizations (RICO) Act and state law. In March 2014, the District Court entered a judgment in favor of Chevron,
finding that the Ecuadorian judgment had been procured through fraud, bribery and corruption, and prohibiting the RICO
defendants from seeking to enforce the Lago Agrio judgment in the United States or profiting from their illegal acts. In
August 2016, the U.S. Court of Appeals for the Second Circuit issued a unanimous decision affirming the New York
judgment in full. In June 2017, the U.S. Supreme Court denied the RICO defendants’ petition for a Writ of Certiorari,
rendering the New York judgment in favor of Chevron final.

Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before an arbitral tribunal
administered by the Permanent Court of Arbitration in The Hague, under the Rules of the United Nations Commission on
International Trade Law. The claim alleged violations of Ecuador’s obligations under the United States-Ecuador Bilateral
Investment Treaty (BIT) and breaches of the settlement and release agreements between Ecuador and Texpet. In
January 2012, the Tribunal issued its First Interim Measures Award requiring Ecuador to take all measures at its disposal to
suspend or cause to be suspended the enforcement or recognition within and outside of Ecuador of any judgment against
Chevron in the Lago Agrio case pending further order of the Tribunal. In February 2012, the Tribunal issued a Second

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Interim Award mandating that Ecuador take all measures necessary to suspend or cause to be suspended enforcement and
recognition proceedings within and outside of Ecuador. Also in February 2012, the Tribunal issued a Third Interim Award
confirming its jurisdiction to hear Chevron and Texpet’s claims. In February 2013, the Tribunal issued its Fourth Interim
Award in which it declared that Ecuador had violated the First and Second Interim Awards. The Tribunal divided the merits
phase of the arbitration into three phases. In September 2013, after the conclusion of Phase One, the Tribunal issued its First
Partial Award, finding that the settlement agreements between Ecuador and Texpet applied to both Texpet and Chevron and
released them from public environmental claims arising from the consortium’s operations, but did not preclude individual
claims for personal harm. In August 2018, the Tribunal issued its Phase Two award, again in favor of Chevron and Texpet.
The Tribunal unanimously held that the Lago Agrio judgment was procured through fraud, bribery and corruption and was
based on public claims that Ecuador had settled and released. According to the Tribunal, the Ecuadorian judgment “violates
international public policy” and “should not be recognized or enforced by the courts of other States.” The Tribunal found
that: (i) Ecuador breached its obligations under the settlement agreements releasing Texpet and its affiliates from public
environmental claims; (ii) Ecuador committed a denial of justice under international law and violated the U.S.-Ecuador BIT
due to the fraud and corruption in the Lago Agrio litigation; and (iii) Texpet satisfied its environmental remediation
obligations through the remediation program that Ecuador supervised and approved. The Tribunal ordered Ecuador to:
(a) take immediate steps to remove the status of enforceability from the Ecuadorian judgment; (b) take measures to “wipe out
all the consequences” of Ecuador’s “internationally wrongful acts in regard to the Ecuadorian judgment;” and (c) compensate
Chevron for any injuries resulting from the Ecuadorian judgment. The final Phase Three of the arbitration, at which damages
for Chevron’s injuries will be determined, was set for hearing in March 2021. Ecuador filed in the District Court of The
Hague a request to set aside the Tribunal’s Interim Awards and its First Partial Award, and in January 2016 that court denied
Ecuador’s request. In July 2017, the Appeals Court of the Netherlands denied Ecuador’s appeal, and in April 2019, the
Supreme Court of the Netherlands upheld the decision of the Appeals Court and finally rejected Ecuador’s challenges to the
Tribunal’s Interim Awards and its First Partial Award. In December 2018, Ecuador filed in the District Court of The Hague a
request to set aside the Tribunal’s Phase Two Award.

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, management does not believe the judgment has 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 15
Taxes

Income Taxes

Income tax expense (benefit)
U.S. federal
Current
Deferred
State and local
Current
Deferred

Total United States

International
Current
Deferred

Total International

Year ended December 31

2019

2018

2017

(73)
(1,074)

(181) $
738

153
(172)

(1,166)

4,577
(720)

3,857

2,691

183
(16)

724

4,662
329

4,991

5,715

(382)
(2,561)

(97)
66

(2,974)

3,634
(708)

2,926

(48)

Total income tax expense (benefit)

The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed
in the table on the following page:

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Income (loss) before income taxes

United States

International

Total income (loss) before income taxes

Theoretical tax (at U.S. statutory rate of 21% - 2019 & 2018, 35% - 2017)

Effect of U.S. tax reform

Equity affiliate accounting effect

Effect of income taxes from international operations*

State and local taxes on income, net of U.S. federal income tax benefit

Prior year tax adjustments, claims and settlements

Tax credits

Other U.S.*

Total income tax expense (benefit)

Effective income tax rate

2019

2018

2017

(5,483)

11,019

5,536

1,163

(687)

2,196

(18)

192

(18)

(140)

2,691

4,730

15,845

20,575

4,321

(26)

(1,526)

3,132

162

(51)

(163)

(134)

(441)

9,662

9,221

3,227

(2,020)

(1,373)

(130)

(39)

(199)

447

(48)

5,715

48.6%

27.8%

(0.5)%

* Includes one-time tax costs (benefits) associated with changes in uncertain tax positions and valuation allowances.

The 2019 decrease in income tax expense of $3,024 is a result of the year-over-year decrease in total income before income

tax expense, which is primarily due to the impairment and project write-off charges in 2019. The company’s effective tax

rate changed from 28 percent in 2018 to 49 percent in 2019. The change in effective tax rate is a consequence of mix effect

resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions,

including a tax charge related to cash repatriation and the impact of asset sales and corporate rate reductions.

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

following:

Asset retirement obligations/environmental reserves

Deferred tax liabilities

Properties, plant and equipment

Investments and other*

Total deferred tax liabilities

Deferred tax assets

Foreign tax credits

Employee benefits

Deferred credits

Tax loss carryforwards

Other accrued liabilities

Inventory

Operating leases*

Miscellaneous

Total deferred tax assets

Deferred tax assets valuation allowance

Total deferred taxes, net

Note 5, “Lease Commitments” beginning on page 62.

At December 31

2019

2018

17,251

5,372

22,623

(9,840)

(4,329)

(3,454)

(1,083)

(5,262)

(441)

(662)

(1,211)

(2,796)

(29,078)

15,965

20,159

4,943

25,102

(10,536)

(5,328)

(2,787)

(1,373)

(4,948)

(595)

(505)

—

(3,481)

(29,553)

15,973

9,510

11,522

* Beginning in 2019, the deferred taxes that are the consequence of ASU 2016-02 are included in the “Investments and other” and Operating lease” balances above. Refer to

Deferred tax liabilities at the end of 2019 decreased by approximately $2,500 from year-end 2018. The decrease was

primarily related to property, plant and equipment temporary differences due to upstream asset impairments. Deferred tax

assets were essentially unchanged from year-end 2018.

The overall valuation allowance relates to deferred tax assets for U.S. foreign tax credit carryforwards, tax loss carryforwards

and temporary differences. The valuation allowance reduces the deferred tax assets to amounts that are, in management’s

assessment, more likely than not to be realized. At the end of 2019, the company had tax loss carryforwards of approximately

$13,419 and tax credit carryforwards of approximately $1,058, 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 2020

through 2034. U.S. foreign tax credit carryforwards of $9,840 will expire between 2020 and 2029.

Interim Award mandating that Ecuador take all measures necessary to suspend or cause to be suspended enforcement and

recognition proceedings within and outside of Ecuador. Also in February 2012, the Tribunal issued a Third Interim Award

confirming its jurisdiction to hear Chevron and Texpet’s claims. In February 2013, the Tribunal issued its Fourth Interim

Award in which it declared that Ecuador had violated the First and Second Interim Awards. The Tribunal divided the merits

phase of the arbitration into three phases. In September 2013, after the conclusion of Phase One, the Tribunal issued its First

Partial Award, finding that the settlement agreements between Ecuador and Texpet applied to both Texpet and Chevron and

released them from public environmental claims arising from the consortium’s operations, but did not preclude individual

claims for personal harm. In August 2018, the Tribunal issued its Phase Two award, again in favor of Chevron and Texpet.

The Tribunal unanimously held that the Lago Agrio judgment was procured through fraud, bribery and corruption and was

based on public claims that Ecuador had settled and released. According to the Tribunal, the Ecuadorian judgment “violates

international public policy” and “should not be recognized or enforced by the courts of other States.” The Tribunal found

that: (i) Ecuador breached its obligations under the settlement agreements releasing Texpet and its affiliates from public

environmental claims; (ii) Ecuador committed a denial of justice under international law and violated the U.S.-Ecuador BIT

due to the fraud and corruption in the Lago Agrio litigation; and (iii) Texpet satisfied its environmental remediation

obligations through the remediation program that Ecuador supervised and approved. The Tribunal ordered Ecuador to:

(a) take immediate steps to remove the status of enforceability from the Ecuadorian judgment; (b) take measures to “wipe out

all the consequences” of Ecuador’s “internationally wrongful acts in regard to the Ecuadorian judgment;” and (c) compensate

Chevron for any injuries resulting from the Ecuadorian judgment. The final Phase Three of the arbitration, at which damages

for Chevron’s injuries will be determined, was set for hearing in March 2021. Ecuador filed in the District Court of The

Hague a request to set aside the Tribunal’s Interim Awards and its First Partial Award, and in January 2016 that court denied

Ecuador’s request. In July 2017, the Appeals Court of the Netherlands denied Ecuador’s appeal, and in April 2019, the

Supreme Court of the Netherlands upheld the decision of the Appeals Court and finally rejected Ecuador’s challenges to the

Tribunal’s Interim Awards and its First Partial Award. In December 2018, Ecuador filed in the District Court of The Hague a

request to set aside the Tribunal’s Phase Two Award.

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, management does not believe the judgment has 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).

Income tax expense (benefit)

Note 15

Taxes

Income Taxes

U.S. federal

Current

Deferred

State and local

Current

Deferred

Total United States

International

Current

Deferred

Total International

Year ended December 31

2019

2018

2017

(73)

(181) $

738

(1,074)

153

(172)

(1,166)

4,577

(720)

3,857

2,691

183

(16)

724

4,662

329

4,991

(382)

(2,561)

(97)

(2,974)

3,634

(708)

2,926

(48)

Total income tax expense (benefit)

5,715

The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed

in the table on the following page:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

2019

2018

2017

Income (loss) before income taxes

United States
International

Total income (loss) before income taxes

Theoretical tax (at U.S. statutory rate of 21% - 2019 & 2018, 35% - 2017)
Effect of U.S. tax reform
Equity affiliate accounting effect
Effect of income taxes from international operations*
State and local taxes on income, net of U.S. federal income tax benefit
Prior year tax adjustments, claims and settlements
Tax credits
Other U.S.*

Total income tax expense (benefit)

Effective income tax rate

(5,483)
11,019

5,536

1,163
3
(687)
2,196
(18)
192
(18)
(140)

2,691

4,730
15,845

20,575

4,321
(26)
(1,526)
3,132
162
(51)
(163)
(134)

5,715

48.6%

27.8%

(441)
9,662

9,221

3,227
(2,020)
(1,373)
(130)
39
(39)
(199)
447

(48)

(0.5)%

* Includes one-time tax costs (benefits) associated with changes in uncertain tax positions and valuation allowances.

The 2019 decrease in income tax expense of $3,024 is a result of the year-over-year decrease in total income before income
tax expense, which is primarily due to the impairment and project write-off charges in 2019. The company’s effective tax
rate changed from 28 percent in 2018 to 49 percent in 2019. The change in effective tax rate is a consequence of mix effect
resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions,
including a tax charge related to cash repatriation and the impact of asset sales and corporate rate reductions.

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

Deferred tax liabilities

Properties, plant and equipment
Investments and other*

Total deferred tax liabilities

Deferred tax assets

Foreign tax credits
Asset retirement obligations/environmental reserves
Employee benefits
Deferred credits
Tax loss carryforwards
Other accrued liabilities
Inventory
Operating leases*
Miscellaneous

Total deferred tax assets

Deferred tax assets valuation allowance

Total deferred taxes, net

At December 31

2019

2018

17,251
5,372

22,623

(9,840)
(4,329)
(3,454)
(1,083)
(5,262)
(441)
(662)
(1,211)
(2,796)

(29,078)

15,965

20,159
4,943

25,102

(10,536)
(5,328)
(2,787)
(1,373)
(4,948)
(595)
(505)
—
(3,481)

(29,553)

15,973

9,510

11,522

* Beginning in 2019, the deferred taxes that are the consequence of ASU 2016-02 are included in the “Investments and other” and Operating lease” balances above. Refer to

Note 5, “Lease Commitments” beginning on page 62.

Deferred tax liabilities at the end of 2019 decreased by approximately $2,500 from year-end 2018. The decrease was
primarily related to property, plant and equipment temporary differences due to upstream asset impairments. Deferred tax
assets were essentially unchanged from year-end 2018.

The overall valuation allowance relates to deferred tax assets for U.S. foreign tax credit carryforwards, tax loss carryforwards
and temporary differences. The valuation allowance reduces the deferred tax assets to amounts that are, in management’s
assessment, more likely than not to be realized. At the end of 2019, the company had tax loss carryforwards of approximately
$13,419 and tax credit carryforwards of approximately $1,058, 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 2020
through 2034. U.S. foreign tax credit carryforwards of $9,840 will expire between 2020 and 2029.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At December 31, 2019 and 2018, deferred taxes were classified on the Consolidated Balance Sheet as follows:

Taxes Other Than on Income

Deferred charges and other assets
Noncurrent deferred income taxes

Total deferred income taxes, net

At December 31

2019

(4,178)
13,688

9,510

2018

(4,399)
15,921

11,522

Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be
reinvested indefinitely. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax
liabilities for U.S. state and foreign withholding tax purposes.

U.S. state and foreign withholding 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 $52,500 at
December 31, 2019. This amount represents earnings reinvested as part of the company’s ongoing international business. It is
not practicable to estimate the amount of state and foreign taxes that might be payable on the possible remittance of earnings
that are intended to be reinvested indefinitely. 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,
2019, 2018 and 2017. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the
differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in
the financial statements. Interest and penalties are not included.

Balance at January 1

Foreign currency effects
Additions based on tax positions taken in current year
Additions for tax positions taken in prior years
Reductions for tax positions taken in prior years
Settlements with taxing authorities in current year
Reductions as a result of a lapse of the applicable statute of limitations

2019

5,070
1
94
313
(194)
(78)
(219)

2018

4,828
(6)
239
153
(131)
(13)
—

Balance at December 31

4,987

5,070

2017

3,031
43
1,853
1,166
(90)
(1,173)
(2)

4,828

Approximately 81 percent of the $4,987 of unrecognized tax benefits at December 31, 2019, 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, 2019. For these jurisdictions, the latest years for which income tax examinations had
been finalized were as follows: United States – 2013, Nigeria – 2000, Australia – 2009 and Kazakhstan – 2012.

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, 2019, accruals of $30 for anticipated interest and penalty obligations
were included on the Consolidated Balance Sheet, compared with accruals of $33 as of year-end 2018. Income tax expense
(benefit) associated with interest and penalties was $(3), $8 and $(161) in 2019, 2018 and 2017, respectively.

Year ended December 31

2019

2018

4,990

(4,990)

4,830

2017

4,398

—

1,824

241

206

6,680

2,791

—

2,563

137

115

5,651

(4,830)

1,577

246

325

2,163

3,031

(3,031)

2,370

132

165

2,704

1,785

254

355

2,396

2,801

(2,801)

1,435

125

145

1,740

4,136

United States

Excise and similar taxes on products and merchandise*

Consumer excise taxes collected on behalf of third parties*

Import duties and other levies

Property and other miscellaneous taxes

Payroll taxes

Taxes on production

Total United States

International

Payroll taxes

Taxes on production

Total International

Excise and similar taxes on products and merchandise*

Consumer excise taxes collected on behalf of third parties*

Import duties and other levies

Property and other miscellaneous taxes

Note 16

Properties, Plant and Equipment1

Total taxes other than on income

4,867

12,331

* Beginning in 2018, these taxes are netted in “Taxes other than on income” in accordance with ASU 2014-09. Refer to Note 24, “Revenue” beginning on page 89.

Gross Investment at Cost

Additions at Cost2

Depreciation Expense3

2019

2018

2017

2019

2018

2017

2019

2018

2017

2019

2018

2017

At December 31

Net Investment

Year ended December 31

Upstream

United States

International

Downstream

United States

International

Total Downstream

All Other

United States

International

Total All Other

82,117 $ 88,155 $ 84,602

31,082 $ 39,526 $ 38,722

7,751 $ 6,434 $ 4,995

$ 15,222 $

5,328 $

206,292

215,329

224,211

102,639

113,603

123,191

3,664

4,865

7,934

12,618

12,726

5,527

12,096

Total Upstream

288,409

303,484

308,813

133,721

153,129

161,913

11,415

11,299

12,929

27,840

18,054

17,623

25,968

7,480

33,448

24,685

7,237

23,598

7,094

31,922

30,692

11,398

3,114

14,512

10,838

3,023

10,346

3,074

13,861

13,420

1,452

355

1,807

1,259

278

1,537

4,719

146

4,865

4,667

171

4,838

4,798

182

4,980

2,236

2,261

2,186

2,217

2,341

2,379

324

333

224

230

1,213

1,125

1,033

1,035

907

306

218

222

869

256

243

253

751

282

320

332

753

282

677

691

Total United States

Total International

112,804

213,918

117,507

222,737

112,998

231,487

44,716

105,778

52,550

116,657

51,409

126,303

9,527

4,028

7,917

5,149

6,120

8,244

16,334

12,884

6,399

13,020

6,957

12,392

Total

$ 326,722 $340,244 $344,485 $ 150,494 $169,207 $177,712

$ 13,555 $13,066 $14,364

$ 29,218 $ 19,419 $ 19,349

1 Other than the United States and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2019. Australia

had PP&E of $51,359, $53,768 and $55,514 in 2019, 2018 and 2017, respectively.

2 Net of dry hole expense related to prior years’ expenditures of $124, $343 and $42 in 2019, 2018 and 2017, respectively.

3 Depreciation expense includes accretion expense of $628, $654 and $668 in 2019, 2018 and 2017, respectively, and impairments of $10,797, $735 and $1,021 in 2019, 2018

and 2017, respectively.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At December 31, 2019 and 2018, deferred taxes were classified on the Consolidated Balance Sheet as follows:

Taxes Other Than on Income

Year ended December 31

At December 31

2019

(4,178)

13,688

9,510

2018

(4,399)

15,921

11,522

Deferred charges and other assets

Noncurrent deferred income taxes

Total deferred income taxes, net

Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be

reinvested indefinitely. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax

liabilities for U.S. state and foreign withholding tax purposes.

U.S. state and foreign withholding 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 $52,500 at

December 31, 2019. This amount represents earnings reinvested as part of the company’s ongoing international business. It is

not practicable to estimate the amount of state and foreign taxes that might be payable on the possible remittance of earnings

that are intended to be reinvested indefinitely. 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,

2019, 2018 and 2017. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the

differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in

the financial statements. Interest and penalties are not included.

Balance at January 1

Foreign currency effects

Additions based on tax positions taken in current year

Additions for tax positions taken in prior years

Reductions for tax positions taken in prior years

Settlements with taxing authorities in current year

Reductions as a result of a lapse of the applicable statute of limitations

2019

2018

5,070

4,828

313

(194)

(78)

(219)

(6)

239

153

(131)

(13)

—

2017

3,031

1,853

1,166

(90)

(1,173)

(2)

4,828

Balance at December 31

4,987

5,070

Approximately 81 percent of the $4,987 of unrecognized tax benefits at December 31, 2019, 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, 2019. For these jurisdictions, the latest years for which income tax examinations had

been finalized were as follows: United States – 2013, Nigeria – 2000, Australia – 2009 and Kazakhstan – 2012.

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, 2019, accruals of $30 for anticipated interest and penalty obligations

were included on the Consolidated Balance Sheet, compared with accruals of $33 as of year-end 2018. Income tax expense

(benefit) associated with interest and penalties was $(3), $8 and $(161) in 2019, 2018 and 2017, respectively.

2019

2018

United States

Excise and similar taxes on products and merchandise*
Consumer excise taxes collected on behalf of third parties*
Import duties and other levies
Property and other miscellaneous taxes
Payroll taxes
Taxes on production

Total United States

International

Total International

Total taxes other than on income

4,990
(4,990)
2
1,785
254
355

2,396

2,801
(2,801)
35
1,435
125
145

1,740

4,136

4,830
(4,830)
15
1,577
246
325

2,163

3,031
(3,031)
37
2,370
132
165

2,704

2017

4,398
—
11
1,824
241
206

6,680

2,791
—
45
2,563
137
115

5,651

4,867

12,331

* Beginning in 2018, these taxes are netted in “Taxes other than on income” in accordance with ASU 2014-09. Refer to Note 24, “Revenue” beginning on page 89.

Note 16
Properties, Plant and Equipment1

Gross Investment at Cost

At December 31

Net Investment

Additions at Cost2

Depreciation Expense3

Year ended December 31

2019

2018

2017

2019

2018

2017

2019

2018

2017

2019

2018

2017

Upstream

United States
International

82,117 $ 88,155 $ 84,602
224,211
215,329
206,292

31,082 $ 39,526 $ 38,722
123,191
113,603
102,639

7,751 $ 6,434 $ 4,995
7,934
4,865
3,664

$ 15,222 $
12,618

5,328 $
12,726

5,527
12,096

Total Upstream

288,409

303,484

308,813

133,721

153,129

161,913

11,415

11,299

12,929

27,840

18,054

17,623

Downstream

United States
International

Total Downstream

All Other

United States
International

Total All Other

25,968
7,480

33,448

24,685
7,237

23,598
7,094

31,922

30,692

11,398
3,114

14,512

10,838
3,023

10,346
3,074

13,861

13,420

1,452
355

1,807

1,259
278

1,537

907
306

869
256

751
282

753
282

1,213

1,125

1,033

1,035

4,719
146

4,865

4,667
171

4,838

4,798
182

4,980

2,236
25

2,261

2,186
31

2,217

2,341
38

2,379

324
9

333

224
6

230

218
4

222

243
10

253

320
12

332

677
14

691

Total United States
Total International

112,804
213,918

117,507
222,737

112,998
231,487

44,716
105,778

52,550
116,657

51,409
126,303

9,527
4,028

7,917
5,149

6,120
8,244

16,334
12,884

6,399
13,020

6,957
12,392

Total

$ 326,722 $340,244 $344,485 $ 150,494 $169,207 $177,712

$ 13,555 $13,066 $14,364

$ 29,218 $ 19,419 $ 19,349

1 Other than the United States and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2019. Australia

had PP&E of $51,359, $53,768 and $55,514 in 2019, 2018 and 2017, respectively.

2 Net of dry hole expense related to prior years’ expenditures of $124, $343 and $42 in 2019, 2018 and 2017, respectively.
3 Depreciation expense includes accretion expense of $628, $654 and $668 in 2019, 2018 and 2017, respectively, and impairments of $10,797, $735 and $1,021 in 2019, 2018

and 2017, respectively.

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Total long-term debt including finance lease liabilities at December 31, 2019, was $23,691. The company’s long-term debt

outstanding at year-end 2019 and 2018 was as follows:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 17
Short-Term Debt

Commercial paper1
Notes payable to banks and others with originating terms of one year or less
Current maturities of long-term debt2
Current maturities of long-term finance leases
Redeemable long-term obligations

Long-term debt

Subtotal

Reclassified to long-term debt

Total short-term debt

At December 31

2019

4,654
228
5,054
18

3,078

13,032
(9,750)

2018

7,503
28
4,999
18

3,078

15,626
(9,900)

3,282

5,726

1 Weighted-average interest rates at December 31, 2019 and 2018, were 1.69 percent and 2.43 percent, respectively.
2 Net of unamortized discounts and issuance costs: $0 in 2019 and $1 in 2018.

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, 2019, the
company had no interest rate swaps on short-term debt.

At December 31, 2019, the company had $9,750 in 364-day committed credit facilities with various major banks that enable
the refinancing of short-term obligations on a long-term basis. The credit facilities allow the company to convert any
amounts outstanding into a term loan for a period of up to one year. This supports 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 facility 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 this facility at December 31, 2019.

The company classified $9,750 and $9,900 of short-term debt as long-term at December 31, 2019 and 2018, 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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 18

Long-Term Debt

3.191% notes due 2023

2.954% notes due 2026

2.355% notes due 2022

1.961% notes due 2020

2.100% notes due 2021

2.419% notes due 2020

2.427% notes due 2020

2.895% notes due 2024

2.566% notes due 2023

3.326% notes due 2025

2.498% notes due 2022

2.411% notes due 2022

Floating rate notes due 2021 (2.599%)1

Floating rate notes due 2022 (2.412%)1

1.991% notes due 2020

Floating rate notes due 2020 (2.116%)2

3.400% loan3

8.625% debentures due 2032

8.625% debentures due 2031

8.000% debentures due 2032

9.750% debentures due 2020

8.875% debentures due 2021

4.950% notes due 2019

1.561% notes due 2019

Floating rate notes due 2019

2.193% notes due 2019

1.686% notes due 2019

Total including debt due within one year

Debt due within one year

Reclassified from short-term debt

Unamortized discounts and debt issuance costs

Finance lease liabilities4

Total long-term debt

1 Weighted-average interest rate at December 31, 2019.

Interest rate at December 31, 2019.

Medium-term notes, maturing from 2021 to 2038 (6.431%)1

At December 31

2019

Principal

2018

Principal

2,250

2,000

1,750

1,350

1,250

1,000

750

700

650

600

400

218

147

108

—

18,730

(5,054)

9,750

(17)

282

2,250

2,000

1,750

1,350

1,250

1,000

750

700

650

600

400

218

147

108

1,500

1,350

850

750

550

23,730

(5,000)

9,900

(24)

127

23,691

28,733

3 Maturity date is conditional upon the occurrence of certain events. 2022 is the earliest period in which the loan may become payable.

4 For details on finance lease liabilities, see Note 5 beginning on page 62.

Chevron has an automatic shelf registration statement that expires in May 2021. This registration statement is for an

unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

Long-term debt excluding finance lease liabilities with a principal balance of $18,730 matures as follows: 2020 – $5,054;

2021 – $2,054; 2022 – $4,268; 2023 – $3,003; 2024 – $1,000; and after 2024 – $3,351.

See Note 7, beginning on page 65, for information concerning the fair value of the company’s long-term debt.

Note 19

Accounting for Suspended Exploratory Wells

The company continues to capitalize exploratory well costs after the completion of drilling when the well has found a

sufficient quantity of reserves to justify completion as a producing well, and 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.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 17

Short-Term Debt

Commercial paper1

Notes payable to banks and others with originating terms of one year or less

Current maturities of long-term debt2

Current maturities of long-term finance leases

Redeemable long-term obligations

Long-term debt

Subtotal

Reclassified to long-term debt

Total short-term debt

At December 31

2019

4,654

228

5,054

3,078

13,032

(9,750)

2018

7,503

4,999

3,078

15,626

(9,900)

3,282

5,726

1 Weighted-average interest rates at December 31, 2019 and 2018, were 1.69 percent and 2.43 percent, respectively.

2 Net of unamortized discounts and issuance costs: $0 in 2019 and $1 in 2018.

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, 2019, the

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

At December 31, 2019, the company had $9,750 in 364-day committed credit facilities with various major banks that enable

the refinancing of short-term obligations on a long-term basis. The credit facilities allow the company to convert any

amounts outstanding into a term loan for a period of up to one year. This supports 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 facility 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 this facility at December 31, 2019.

The company classified $9,750 and $9,900 of short-term debt as long-term at December 31, 2019 and 2018, 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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 18
Long-Term Debt
Total long-term debt including finance lease liabilities at December 31, 2019, was $23,691. The company’s long-term debt
outstanding at year-end 2019 and 2018 was as follows:

3.191% notes due 2023
2.954% notes due 2026
2.355% notes due 2022
1.961% notes due 2020
2.100% notes due 2021
2.419% notes due 2020
2.427% notes due 2020
2.895% notes due 2024
2.566% notes due 2023
3.326% notes due 2025
2.498% notes due 2022
2.411% notes due 2022
Floating rate notes due 2021 (2.599%)1
Floating rate notes due 2022 (2.412%)1
1.991% notes due 2020
Floating rate notes due 2020 (2.116%)2
3.400% loan3
8.625% debentures due 2032
8.625% debentures due 2031
8.000% debentures due 2032
9.750% debentures due 2020
8.875% debentures due 2021
Medium-term notes, maturing from 2021 to 2038 (6.431%)1
4.950% notes due 2019
1.561% notes due 2019
Floating rate notes due 2019
2.193% notes due 2019
1.686% notes due 2019

Total including debt due within one year

Debt due within one year
Reclassified from short-term debt
Unamortized discounts and debt issuance costs
Finance lease liabilities4

Total long-term debt

1 Weighted-average interest rate at December 31, 2019.
2

Interest rate at December 31, 2019.

At December 31

2019

Principal

2018

Principal

2,250
2,250
2,000
1,750
1,350
1,250
1,000
1,000
750
750
700
700
650
650
600
400
218
147
108
75
54
40
38
—
—
—
—
—

2,250
2,250
2,000
1,750
1,350
1,250
1,000
1,000
750
750
700
700
650
650
600
400
218
147
108
75
54
40
38
1,500
1,350
850
750
550

18,730
(5,054)
9,750
(17)
282

23,730
(5,000)
9,900
(24)
127

23,691

28,733

3 Maturity date is conditional upon the occurrence of certain events. 2022 is the earliest period in which the loan may become payable.
4 For details on finance lease liabilities, see Note 5 beginning on page 62.

Chevron has an automatic shelf registration statement that expires in May 2021. This registration statement is for an
unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

Long-term debt excluding finance lease liabilities with a principal balance of $18,730 matures as follows: 2020 – $5,054;
2021 – $2,054; 2022 – $4,268; 2023 – $3,003; 2024 – $1,000; and after 2024 – $3,351.

See Note 7, beginning on page 65, for information concerning the fair value of the company’s long-term debt.

Note 19
Accounting for Suspended Exploratory Wells
The company continues to capitalize exploratory well costs after the completion of drilling when the well has found a
sufficient quantity of reserves to justify completion as a producing well, and 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.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended
December 31, 2019:

Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $119, $157 and $187 for

2019, 2018 and 2017, respectively.

Beginning balance at January 1
Additions to capitalized exploratory well costs pending the determination of proved reserves
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
Capitalized exploratory well costs charged to expense
Other reductions*

Ending balance at December 31

* Represents property sales.

2019

3,563
244
(500)
(125)
(141)

2018

3,702
207
(13)
(333)
—

2017

3,540
323
(113)
(39)
(9)

3,041

3,563

3,702

The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs
have been capitalized for a period greater than one year since the completion of drilling.

Exploratory well costs capitalized for a period of one year or less
Exploratory well costs capitalized for a period greater than one year

Balance at December 31

2019

214
2,827

At December 31

2018

202
3,361

2017

307
3,395

3,041

3,563

3,702

Number of projects with exploratory well costs that have been capitalized for a period greater than one year*

* Certain projects have multiple wells or fields or both.

Of the $2,827 of exploratory well costs capitalized for more than one year at December 31, 2019, $1,867 is related to 12 projects
that had drilling activities underway or firmly planned for the near future. The $960 balance is related to 10 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 $960 referenced above had the following activities associated with assessing the reserves and the
projects’ economic viability: (a) $256 (four projects) – undergoing front-end engineering and design with final investment
decision expected within four years; (b) $704 (six projects) – development alternatives under review. While progress was
being made on all 22 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 $2,827 of suspended well costs capitalized for a period greater than one year as of December 31, 2019, represents 123
exploratory wells in 22 projects. The tables below contain the aging of these costs on a well and project basis:

Aging based on drilling completion date of individual wells:

Amount

Number of wells

1998-2008
2009-2013
2014-2018

Total

Aging based on drilling completion date of last suspended well in project:

2003-2011
2012-2015
2016-2019

Total

244
1,166
1,417

2,827

27
56
40

123

Amount Number of projects

318
1,653
856

2,827

4
11
7

Note 20
Stock Options and Other Share-Based Compensation
Compensation expense for stock options for 2019, 2018 and 2017 was $81 ($64 after tax), $105 ($83 after tax) and $137 ($89
after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and
restricted stock units was $313 ($266 after tax), $60 ($47 after tax) and $231 ($150 after tax) for 2019, 2018 and 2017,
respectively. No significant stock-based compensation cost was capitalized at December 31, 2019, or December 31, 2018.

Cash received in payment for option exercises under all share-based payment arrangements for 2019, 2018 and 2017 was
$1,090, $1,159 and $1,100, respectively. Actual tax benefits realized for the tax deductions from option exercises were $43,
$43 and $48 for 2019, 2018 and 2017, respectively.

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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 issued before January 1, 2017, 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 issued after January 1, 2017, contractual terms vary between three years for

the performance shares and special restricted stock units, five 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 2019, 2018 and 2017 were measured on the

date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:

Expected term in years1

Volatility2

Risk-free interest rate based on zero coupon U.S. treasury note

Dividend yield

Weighted-average fair value per option granted

1 Expected term is based on historical exercise and post-vesting 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 2019 is presented below:

2019

6.6

20.5 %

2.6 %

3.8 %

Year ended December 31

2018

6.5

21.2 %

2.6 %

3.8 %

2017

6.3

21.7 %

2.2 %

4.2 %

15.82

18.18

15.31

Shares (Thousands)

Exercise Price

Contractual Term (Years) Aggregate Intrinsic Value

Weighted-Average

Averaged Remaining

Outstanding at January 1, 2019

Granted

Exercised

Forfeited

Outstanding at December 31, 2019

Exercisable at December 31, 2019

94,724

5,771

(13,190)

(664)

86,641

77,671

99.92

113.04

83.36

111.57

103.22

101.63

4.69

4.25

1,518

1,474

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during

2019, 2018 and 2017 was $516, $506 and $407, respectively. During this period, the company continued its practice of

issuing treasury shares upon exercise of these awards.

As of December 31, 2019, there was $55 of total unrecognized before-tax compensation cost related to nonvested share-

based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average

period of 1.8 years.

At January 1, 2019, the number of LTIP performance shares outstanding was equivalent to 3,669,730 shares. During 2019,

1,813,188 performance shares were granted, 684,620 shares vested with cash proceeds distributed to recipients and 411,514

shares were forfeited. At December 31, 2019, performance shares outstanding were 4,386,784. The fair value of the liability

recorded for these instruments was $370, and was measured using the Monte Carlo simulation method.

At January 1, 2019, the number of restricted stock units outstanding was equivalent to 1,737,479 shares. During 2019,

1,054,556 restricted stock units were granted, 244,744 units vested with cash proceeds distributed to recipients and 120,332

units were forfeited. At December 31, 2019, restricted stock units outstanding were 2,426,959. The fair value of the liability

recorded for the vested portion of these instruments was $192, valued at the stock price as of December 31, 2019. In addition,

outstanding stock appreciation rights that were granted under LTIP totaled approximately 4.0 million equivalent shares as of

December 31, 2019. The fair value of the liability recorded for the vested portion of these instruments was $82.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended

December 31, 2019:

Beginning balance at January 1

Additions to capitalized exploratory well costs pending the determination of proved reserves

Reclassifications to wells, facilities and equipment based on the determination of proved reserves

Capitalized exploratory well costs charged to expense

Other reductions*

Ending balance at December 31

* Represents property sales.

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.

2019

2018

2017

3,563

3,702

3,540

244

(500)

(125)

(141)

207

(13)

(333)

—

323

(113)

(39)

(9)

3,041

3,563

3,702

2019

214

2,827

At December 31

2018

202

3,361

2017

307

3,395

3,041

3,563

3,702

Exploratory well costs capitalized for a period of one year or less

Exploratory well costs capitalized for a period greater than one year

Balance at December 31

* Certain projects have multiple wells or fields or both.

Number of projects with exploratory well costs that have been capitalized for a period greater than one year*

Of the $2,827 of exploratory well costs capitalized for more than one year at December 31, 2019, $1,867 is related to 12 projects

that had drilling activities underway or firmly planned for the near future. The $960 balance is related to 10 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 $960 referenced above had the following activities associated with assessing the reserves and the

projects’ economic viability: (a) $256 (four projects) – undergoing front-end engineering and design with final investment

decision expected within four years; (b) $704 (six projects) – development alternatives under review. While progress was

being made on all 22 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 $2,827 of suspended well costs capitalized for a period greater than one year as of December 31, 2019, represents 123

exploratory wells in 22 projects. The tables below contain the aging of these costs on a well and project basis:

Aging based on drilling completion date of individual wells:

Amount

Number of wells

Aging based on drilling completion date of last suspended well in project:

Amount Number of projects

244

1,166

1,417

2,827

318

1,653

856

2,827

123

1998-2008

2009-2013

2014-2018

Total

2003-2011

2012-2015

2016-2019

Total

Note 20

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2019, 2018 and 2017 was $81 ($64 after tax), $105 ($83 after tax) and $137 ($89

after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and

restricted stock units was $313 ($266 after tax), $60 ($47 after tax) and $231 ($150 after tax) for 2019, 2018 and 2017,

respectively. No significant stock-based compensation cost was capitalized at December 31, 2019, or December 31, 2018.

Cash received in payment for option exercises under all share-based payment arrangements for 2019, 2018 and 2017 was

$1,090, $1,159 and $1,100, respectively. Actual tax benefits realized for the tax deductions from option exercises were $43,

$43 and $48 for 2019, 2018 and 2017, respectively.

Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $119, $157 and $187 for
2019, 2018 and 2017, 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 issued before January 1, 2017, 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 issued after January 1, 2017, contractual terms vary between three years for
the performance shares and special restricted stock units, five 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 2019, 2018 and 2017 were measured on the
date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:

Expected term in years1
Volatility2
Risk-free interest rate based on zero coupon U.S. treasury note
Dividend yield
Weighted-average fair value per option granted

2019

6.6
20.5 %
2.6 %
3.8 %

Year ended December 31

2018

6.5
21.2 %
2.6 %
3.8 %

2017

6.3
21.7 %
2.2 %
4.2 %

15.82

18.18

15.31

1 Expected term is based on historical exercise and post-vesting 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 2019 is presented below:

Shares (Thousands)

Weighted-Average
Exercise Price

Averaged Remaining

Contractual Term (Years) Aggregate Intrinsic Value

Outstanding at January 1, 2019

Granted
Exercised
Forfeited

Outstanding at December 31, 2019

Exercisable at December 31, 2019

94,724
5,771
(13,190)
(664)
86,641

77,671

$
$
$
$
$

99.92
113.04
83.36
111.57
103.22

101.63

4.69

4.25

1,518

1,474

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during
2019, 2018 and 2017 was $516, $506 and $407, respectively. During this period, the company continued its practice of
issuing treasury shares upon exercise of these awards.

As of December 31, 2019, there was $55 of total unrecognized before-tax compensation cost related to nonvested share-
based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average
period of 1.8 years.

At January 1, 2019, the number of LTIP performance shares outstanding was equivalent to 3,669,730 shares. During 2019,
1,813,188 performance shares were granted, 684,620 shares vested with cash proceeds distributed to recipients and 411,514
shares were forfeited. At December 31, 2019, performance shares outstanding were 4,386,784. The fair value of the liability
recorded for these instruments was $370, and was measured using the Monte Carlo simulation method.

At January 1, 2019, the number of restricted stock units outstanding was equivalent to 1,737,479 shares. During 2019,
1,054,556 restricted stock units were granted, 244,744 units vested with cash proceeds distributed to recipients and 120,332
units were forfeited. At December 31, 2019, restricted stock units outstanding were 2,426,959. The fair value of the liability
recorded for the vested portion of these instruments was $192, valued at the stock price as of December 31, 2019. In addition,
outstanding stock appreciation rights that were granted under LTIP totaled approximately 4.0 million equivalent shares as of
December 31, 2019. The fair value of the liability recorded for the vested portion of these instruments was $82.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 21
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. For the company’s main U.S. medical plan, 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 2019 and 2018 follows:

Pension Benefits

Change in Benefit Obligation

Benefit obligation at January 1
Service cost
Interest cost
Plan participants’ contributions
Plan amendments
Actuarial (gain) loss
Foreign currency exchange rate changes
Benefits paid
Divestitures/Acquisitions
Curtailment

Benefit obligation at December 31

Change in Plan Assets

Fair value of plan assets at January 1
Actual return on plan assets
Foreign currency exchange rate changes
Employer contributions
Plan participants’ contributions
Benefits paid
Divestitures/Acquisitions

Fair value of plan assets at December 31

U.S.

11,726
406
397
—
—
2,922
—
(1,035)
49
—

14,465

8,532
1,548
—
1,096
—
(1,035)
36

10,177

2019

Int’l.

4,820
139
199
4
29
673
121
(302)
—
(3)

5,680

4,142
566
115
266
4
(302)
—

4,791

U.S.

13,580
480
370
—
—
(1,051)
—
(1,653)
—
—

11,726

9,948
(566)
—
803
—
(1,653)
—

8,532

Funded status at December 31

(4,288)

(889)

(3,194)

2018

Int’l.

5,540
141
206
4
23
(239)
(227)
(432)
(196)
—

4,820

4,766
(9)
(221)
232
4
(432)
(198)

4,142

(678)

Other Benefits

2019

2018

2,430
36
96
72
—
125
2
(240)
(1)
—

2,520

—
—
—
168
72
(240)
—

—

2,788
42
94
71
2
(272)
(9)
(237)
(49)
—

2,430

—
—
—
166
71
(237)
—

—

(2,520)

(2,430)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2019
and 2018, include:

Deferred charges and other assets
Accrued liabilities
Noncurrent employee benefit plans

Net amount recognized at December 31

U.S.

23
(239)
(4,072)

2019

Int’l.

413
(71)
(1,231)

(4,288)

(889)

Pension Benefits

U.S.

17
(180)
(3,031)

2018

Int’l.

412
(66)
(1,024)

(3,194)

(678)

Other Benefits

2018

—
(175)
(2,255)

(2,430)

2019

—
(174)
(2,346)

(2,520)

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Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB

plans were $6,357 and $4,448 at the end of 2019 and 2018, respectively. These amounts consisted of:

Net actuarial loss

Prior service (credit) costs

Total recognized at December 31

Pension Benefits

U.S.

5,135

5,140

2019

Int’l.

1,269

102

1,371

U.S.

3,694

3,701

2018

Int’l.

955

104

1,059

Other Benefits

2019

(228)

(154)

2018

(56)

(256)

(312)

The accumulated benefit obligations for all U.S. and international pension plans were $12,781 and $5,203, respectively, at

December 31, 2019, and $10,514 and $4,360, respectively, at December 31, 2018.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at

December 31, 2019 and 2018, was:

The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive

Income for 2019, 2018 and 2017 are shown in the table below:

Projected benefit obligations

Accumulated benefit obligations

Fair value of plan assets

Net Periodic Benefit Cost

Service cost

Interest cost

Expected return on plan assets

Amortization of prior service costs (credits)

Recognized actuarial losses

Settlement losses

Curtailment losses (gains)

Total net periodic benefit cost

Changes Recognized in Comprehensive Income

Net actuarial (gain) loss during period

Amortization of actuarial loss

Prior service (credits) costs during period

Amortization of prior service (costs) credits

Total changes recognized in other

comprehensive income

Pension Benefits

U.S.

11,667

10,456

8,456

2018

Int’l.

1,277

1,062

198

U.S.

2018

Int’l.

2017

Int’l.

Other Benefits

2019

2018

2017

480

370

(636)

141

206

(253)

151

219

(239)

(565)

(231)

U.S.

14,401

12,718

10,091

2019

Int’l.

1,554

1,268

278

Pension Benefits

U.S.

489

366

(597)

(5)

340

436

—

381

(776)

—

(94)

(46)

(13)

169

1,029

190

304

411

—

931

151

(715)

—

(2)

(62)

(13)

2019

Int’l.

$ 139

199

158

338

(24)

(30)

406

397

239

259

—

738

1,939

(498)

—

(2)

—

(28)

(3)

—

101

128

(1)

(28)

—

123

(248)

(15)

—

(28)

(5)

—

284

—

Recognized in Net Periodic Benefit Cost and Other

Comprehensive Income

$ 2,177

$ 471

365

129

639

259

$ (109) $ 411

1,439

313

(566)

(40)

(390)

(152)

158

(232)

317

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2019, 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 14

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 2020, the company estimates actuarial losses of $385, $46 and $3 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 $320 will be recognized from “Accumulated other comprehensive loss” during 2020

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, 2019, was approximately 3 and 6 years for U.S. and international pension plans,

respectively, and 8 years for OPEB plans. During 2020, the company estimates prior service (credits) costs of $2, $10 and

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 21

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. For the company’s main U.S. medical plan, 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 2019 and 2018 follows:

Pension Benefits

Other Benefits

2019

2018

U.S.

480

370

—

(1,051)

(1,653)

9,948

(566)

—

803

—

(1,653)

—

8,532

2018

Int’l.

141

206

(239)

(227)

(432)

(196)

—

4,766

(9)

(221)

232

(432)

(198)

4,142

11,726

4,820

—

125

(240)

(1)

—

2,520

—

168

(240)

—

(272)

(9)

(237)

(49)

—

2,430

—

166

(237)

—

Change in Benefit Obligation

Benefit obligation at January 1

Service cost

Interest cost

Plan participants’ contributions

Plan amendments

Actuarial (gain) loss

Foreign currency exchange rate changes

Benefits paid

Divestitures/Acquisitions

Curtailment

Benefit obligation at December 31

Change in Plan Assets

Fair value of plan assets at January 1

Actual return on plan assets

Foreign currency exchange rate changes

Employer contributions

Plan participants’ contributions

Benefits paid

Divestitures/Acquisitions

Fair value of plan assets at December 31

and 2018, include:

Deferred charges and other assets

Accrued liabilities

Noncurrent employee benefit plans

U.S.

406

397

—

2,922

(1,035)

—

14,465

8,532

1,548

1,096

—

(1,035)

10,177

2019

Int’l.

139

199

673

121

(302)

—

(3)

5,680

4,142

566

115

266

(302)

—

4,791

Funded status at December 31

(4,288)

(889)

(3,194)

(678)

(2,520)

(2,430)

U.S.

(239)

(4,072)

2019

Int’l.

413

(71)

(1,231)

Pension Benefits

U.S.

(180)

(3,031)

2018

Int’l.

412

(66)

(1,024)

Other Benefits

2018

—

(175)

(2,255)

(2,430)

2019

—

(174)

(2,346)

(2,520)

Net amount recognized at December 31

(4,288)

(889)

(3,194)

(678)

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB
plans were $6,357 and $4,448 at the end of 2019 and 2018, respectively. These amounts consisted of:

Net actuarial loss
Prior service (credit) costs

Total recognized at December 31

Pension Benefits

U.S.

5,135
5

5,140

2019

Int’l.

1,269
102

1,371

U.S.

3,694
7

3,701

2018

Int’l.

955
104

1,059

Other Benefits

2019

74
(228)

(154)

2018

(56)
(256)

(312)

The accumulated benefit obligations for all U.S. and international pension plans were $12,781 and $5,203, respectively, at
December 31, 2019, and $10,514 and $4,360, respectively, at December 31, 2018.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at
December 31, 2019 and 2018, was:

Projected benefit obligations
Accumulated benefit obligations
Fair value of plan assets

U.S.

14,401
12,718
10,091

2019

Int’l.

1,554
1,268
278

Pension Benefits

U.S.

11,667
10,456
8,456

2018

Int’l.

1,277
1,062
198

11,726

4,820

13,580

5,540

2,430

2,788

The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive
Income for 2019, 2018 and 2017 are shown in the table below:

Net Periodic Benefit Cost

Service cost
Interest cost
Expected return on plan assets
Amortization of prior service costs (credits)
Recognized actuarial losses
Settlement losses
Curtailment losses (gains)

2019

Int’l.

$ 139
199
(231)
11
21
3
16

U.S.

406
397
(565)
2
239
259
—

Total net periodic benefit cost

738

158

Changes Recognized in Comprehensive Income

Net actuarial (gain) loss during period
Amortization of actuarial loss
Prior service (credits) costs during period
Amortization of prior service (costs) credits

Total changes recognized in other

comprehensive income

Recognized in Net Periodic Benefit Cost and Other

1,939
(498)
—
(2)

338
(24)
29
(30)

2018

Int’l.

141
206
(253)
10
29
33
3

169

12
(62)
23
(13)

U.S.

480
370
(636)
2
304
411
—

931

151
(715)
—
(2)

Pension Benefits

2017

Int’l.

151
219
(239)
13
44
2
—

190

(94)
(46)
1
(13)

U.S.

489
366
(597)
(5)
340
436
—

1,029

381
(776)
—
5

Other Benefits

2019

2018

2017

36
96
—
(28)
(3)
—
—

101

128
3
(1)
28

42
94
—
(28)
15
—
—

123

(248)
(15)
3
28

32
95
—
(28)
(5)
—
—

284
5
—
28

1,439

313

(566)

(40)

(390)

(152)

158

(232)

317

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2019

Comprehensive Income

$ 2,177

$ 471

365

129

639

259

$ (109) $ 411

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2019, 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 14
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 2020, the company estimates actuarial losses of $385, $46 and $3 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 $320 will be recognized from “Accumulated other comprehensive loss” during 2020
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, 2019, was approximately 3 and 6 years for U.S. and international pension plans,
respectively, and 8 years for OPEB plans. During 2020, the company estimates prior service (credits) costs of $2, $10 and

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

$(28) 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:

2019

Int’l.

2018

Int’l.

2017

Int’l.

U.S.

Other Benefits

2019

2018

2017

Pension Benefits

Assumptions used to determine benefit obligations:

Discount rate
Rate of compensation increase

Assumptions used to determine net periodic benefit cost:

Discount rate for service cost
Discount rate for interest cost
Expected return on plan assets
Rate of compensation increase

3.1% 3.2%
4.5% 4.0%

4.2% 4.4% 3.5% 3.9%
4.5% 4.0% 4.5% 4.0%

4.4% 4.4%
3.7% 4.4%
6.8% 5.6%
4.5% 4.0%

3.7% 3.9% 4.2% 4.3%
3.0% 3.9% 3.0% 4.3%
6.8% 5.5% 6.8% 5.5%
4.5% 4.0% 4.5% 4.5%

3.2%
N/A

4.6%
4.2%
N/A
N/A

4.4%
N/A

3.9%
3.5%
N/A
N/A

3.8%
N/A

4.6%
3.8%
N/A
N/A

Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily
by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms
and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/
liability studies, and the company’s estimated long-term rates of return are consistent with these studies.

For 2019, the company used an expected long-term rate of return of 6.75 percent for U.S. pension plan assets, which account
for 68 percent of the company’s pension plan assets. In both 2018 and 2017, the company used a long-term rate of return of
6.75 percent for these plans.

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. 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 2019
were 3.1 percent for the main U.S. pension plan and 3.1 percent for the main U.S. OPEB plan. The discount rates for these
plans at the end of 2018 were 4.2 and 4.3 percent, respectively, while in 2017 they were 3.5 and 3.6 percent for these plans,
respectively.

Other Benefit Assumptions Assumed health care cost-trend rates can have a significant effect on the amounts reported for
retiree health care costs. For the measurement of accumulated postretirement benefit obligation at December 31, 2019, for
the main U.S. OPEB plan, the assumed health care cost-trend rates start with 6.8 percent in 2020 and gradually decline to
4.5 percent for 2025 and beyond. For this measurement at December 31, 2018, the assumed health care cost-trend rates
started with 7.2 percent in 2019 and gradually declined to 4.5 percent for 2025 and beyond. A 1-percentage-point change in
the assumed health care cost-trend rates would have the following effects on worldwide plans:

Effect on total service and interest cost components
Effect on postretirement benefit obligation

Plan Assets and Investment Strategy

1 Percent Increase

1 Percent Decrease

$
$

20
224

$
$

(15)
(176)

The fair value measurements of the company’s pension plans for 2019 and 2018 are on the following page:

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Total

Level 1

Level 2 Level 3

Total

Level 1 Level 2 Level 3

1,110 $

— $ — $ —

520 $

520 $ — $ — $ —

At December 31, 2018

Equities

U.S.1

International

Fixed Income

Government

Corporate

Bank Loans

Collective Trusts/Mutual Funds2

Mortgage/Asset Backed

Collective Trusts/Mutual Funds2

Mixed Funds3

Real Estate4

Alternative Investments5

Cash and Cash Equivalents

Other6

At December 31, 2019

Equities

U.S.1

International

Fixed Income

Government

Corporate

Bank Loans

Mortgage/Asset Backed

Collective Trusts/Mutual Funds2

Mixed Funds3

Real Estate4

Alternative Investments5

Cash and Cash Equivalents

Other6

1,631

893

225

1,382

119

1,065

877

—

941

212

1,958

1,079

523

1,444

120

1,089

963

—

924

235

1,630

208

(4)

1,958

—

228

(5)

225

1,382

114

—

523

1,444

113

U.S.

NAV

—

872

—

877

—

941

—

963

—

924

—

521

152

254

409

—

378

—

287

422

184

265

493

—

277

—

338

520

—

277

—

421

144

—

334

—

157

389

—

121

490

—

Total at December 31, 2018

8,532 $

2,965 $

1,758 $

49 $ 3,760

4,142 $

1,441 $

642 $

80 $ 1,979

1,769 $

— $ — $ —

471 $

471 $ — $ — $ —

Collective Trusts/Mutual Funds2

— 1,027

2,230

— 2,225

— 1,089

1,521

— 1,506

— 1,065

Total at December 31, 2019

$ 10,177 $

4,002 $

2,117 $

51 $ 4,007

4,791 $

1,388 $

715 $

61 $ 2,627

1 U.S. equities include investments in the company’s common stock in the amount of $6 at December 31, 2019, and $9 at December 31, 2018.

2 Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly unit trust and index funds.

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 third-party appraisals that occur at least once a year for each property in the portfolio.

5 Alternative investments focus on market-neutral strategies that have a low expected correlation to traditional asset classes.

6 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 (Level 3); and investments in private-equity limited partnerships (NAV).

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

below:

Total at December 31, 2017

Actual Return on Plan Assets:

Assets held at the reporting date

Assets sold during the period

Purchases, Sales and Settlements

Transfers in and/or out of Level 3

Total at December 31, 2018

Actual Return on Plan Assets:

Assets held at the reporting date

Assets sold during the period

Purchases, Sales and Settlements

Transfers in and/or out of Level 3

Total at December 31, 2019

Equity

Fixed Income

International

Corporate

Bank Loans

Real Estate

Other

—

(4)

—

(1)

—

(2)

—

(7)

—

(19)

—

(4)

(2)

—

(13)

—

(1)

—

(1)

—

Int’l.

NAV

—

143

—

322

—

178

—

222

—

Total

143

(4)

(24)

(1)

129

(1)

—

(19)

112

$(28) 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:

2019

Int’l.

Pension Benefits

2018

Int’l.

2017

Int’l.

U.S.

2019

2018

2017

Other Benefits

Assumptions used to determine benefit obligations:

Assumptions used to determine net periodic benefit cost:

Discount rate

Rate of compensation increase

Discount rate for service cost

Discount rate for interest cost

Expected return on plan assets

Rate of compensation increase

3.1% 3.2%

4.5% 4.0%

4.2% 4.4% 3.5% 3.9%

4.5% 4.0% 4.5% 4.0%

4.4% 4.4%

3.7% 4.4%

6.8% 5.6%

4.5% 4.0%

3.7% 3.9% 4.2% 4.3%

3.0% 3.9% 3.0% 4.3%

6.8% 5.5% 6.8% 5.5%

4.5% 4.0% 4.5% 4.5%

3.2%

N/A

4.6%

4.2%

N/A

4.4%

N/A

3.9%

3.5%

N/A

3.8%

N/A

4.6%

3.8%

N/A

Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily

by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms

and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/

liability studies, and the company’s estimated long-term rates of return are consistent with these studies.

For 2019, the company used an expected long-term rate of return of 6.75 percent for U.S. pension plan assets, which account

for 68 percent of the company’s pension plan assets. In both 2018 and 2017, the company used a long-term rate of return of

6.75 percent for these plans.

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. 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 2019

were 3.1 percent for the main U.S. pension plan and 3.1 percent for the main U.S. OPEB plan. The discount rates for these

plans at the end of 2018 were 4.2 and 4.3 percent, respectively, while in 2017 they were 3.5 and 3.6 percent for these plans,

respectively.

Other Benefit Assumptions Assumed health care cost-trend rates can have a significant effect on the amounts reported for

retiree health care costs. For the measurement of accumulated postretirement benefit obligation at December 31, 2019, for

the main U.S. OPEB plan, the assumed health care cost-trend rates start with 6.8 percent in 2020 and gradually decline to

4.5 percent for 2025 and beyond. For this measurement at December 31, 2018, the assumed health care cost-trend rates

started with 7.2 percent in 2019 and gradually declined to 4.5 percent for 2025 and beyond. A 1-percentage-point change in

the assumed health care cost-trend rates would have the following effects on worldwide plans:

1 Percent Increase

1 Percent Decrease

224

(15)

(176)

Effect on total service and interest cost components

Effect on postretirement benefit obligation

Plan Assets and Investment Strategy

The fair value measurements of the company’s pension plans for 2019 and 2018 are on the following page:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Total

Level 1

Level 2 Level 3

U.S.

NAV

Total

Level 1 Level 2 Level 3

Int’l.

NAV

At December 31, 2018
Equities
U.S.1
International
Collective Trusts/Mutual Funds2

Fixed Income
Government
Corporate
Bank Loans
Mortgage/Asset Backed
Collective Trusts/Mutual Funds2

Mixed Funds3
Real Estate4
Alternative Investments5
Cash and Cash Equivalents
Other6

1,110 $
1,631
893

1,110 $
1,630
21

— $ — $ —
—
—
1
872
—
—

225
1,382
119
1
877
—
1,065
941
212
76

—
—
—
—
—
—
—
—
208
(4)

225
1,382
114
1
—
—
—
—
4
31

—
—
—
—
—
5
—
—
877
—
—
—
— 1,065
941
—
—
—
5
44

Total at December 31, 2018

8,532 $

2,965 $

1,758 $

49 $ 3,760

At December 31, 2019
Equities
U.S.1
International
Collective Trusts/Mutual Funds2

Fixed Income
Government
Corporate
Bank Loans
Mortgage/Asset Backed
Collective Trusts/Mutual Funds2

Mixed Funds3
Real Estate4
Alternative Investments5
Cash and Cash Equivalents
Other6

1,769 $
1,958
1,079

1,769 $
1,958
52

— $ — $ —
—
—
—
— 1,027
—

523
1,444
120
1
963
—
1,089
924
235
72

—
—
—
—
—
—
—
—
228
(5)

523
1,444
113
1
—
—
—
—
7
29

—
—
—
—
—
7
—
—
963
—
—
—
— 1,089
924
—
—
—
4
44

520 $
521
152

254
409
—
6
1,521
74
378
—
287
20

520 $ — $ — $ —
520
—
143
9

1
—

—
—

97
—
—
—
15
3
—
—
277
—

157
389
—
6
—
71
—
—
2
17

—
—
—
20
—
—
—
—
— 1,506
—
—
322
56
—
—
8
—
—
3

4,142 $

1,441 $

642 $

80 $ 1,979

471 $
422
184

265
493
—
4
2,230
84
277
—
338
23

471 $ — $ — $ —
421
—
178
6

1
—

—
—

144
—
—
—
5
7
—
—
334
—

121
490
—
4
—
77
—
—
2
21

—
—
—
3
—
—
—
—
— 2,225
—
—
222
55
—
—
2
—
—
2

Total at December 31, 2019

$ 10,177 $

4,002 $

2,117 $

51 $ 4,007

4,791 $

1,388 $

715 $

61 $ 2,627

1 U.S. equities include investments in the company’s common stock in the amount of $6 at December 31, 2019, and $9 at December 31, 2018.
2 Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly unit trust and index funds.
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 third-party appraisals that occur at least once a year for each property in the portfolio.
5 Alternative investments focus on market-neutral strategies that have a low expected correlation to traditional asset classes.
6 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 (Level 3); and investments in private-equity limited partnerships (NAV).

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

Total at December 31, 2017
Actual Return on Plan Assets:

Assets held at the reporting date
Assets sold during the period
Purchases, Sales and Settlements
Transfers in and/or out of Level 3

Total at December 31, 2018

Actual Return on Plan Assets:

Assets held at the reporting date
Assets sold during the period
Purchases, Sales and Settlements
Transfers in and/or out of Level 3

Total at December 31, 2019

Equity

Fixed Income

International

Corporate

Bank Loans

Real Estate

Other

—

4
(4)
—
1

(1)
—
—
1

(2)
—
(7)
—

1
—
(19)
—

—
—
(4)
(2)

—
—
—
2

13
—
(13)
—

—
—
(1)
—

—
—
—
—

(1)
—
1
—

Total

143

15
(4)
(24)
(1)

129

(1)
—
(19)
3

112

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 92 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 Investment Committee has established the following approved asset
allocation ranges: Equities 30–60 percent, Fixed Income 20–40 percent, Real Estate 0–15 percent, Alternative Investments
0–15 percent and Cash 0–25 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following
asset allocation guidelines: Equities 10–30 percent, Fixed Income 55–85 percent, Real Estate 5–15 percent, and Cash 0–
5 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 2019, the company contributed $1,096 and $266 to its U.S. and international
pension plans, respectively. In 2020, the company expects contributions to be approximately $1,250 to its U.S. plans and
$250 to its international pension plans. Actual contribution amounts are dependent upon investment returns, changes in
tax law changes and other economic factors. Additional funding may
pension obligations, regulatory environments,
ultimately be required if investment returns are insufficient to offset increases in plan obligations.

The company anticipates paying OPEB benefits of approximately $174 in 2020; $168 was paid in 2019.

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

to the sale of the assets in 1997.

2020
2021
2022
2023
2024
2024-2028

Pension Benefits

U.S.

1,262
1,176
1,160
1,150
1,134
5,232

$
$
$
$
$
$

Int’l.

280
602
224
234
255
1,434

Other

Benefits

$
$
$
$
$
$

174
170
165
161
156
725

$
$
$
$
$
$

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 $284, $270 and $316 in 2019, 2018
and 2017, 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 2019, 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, 2019 and 2018, trust assets
of $35 and $34, 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
$826, $1,048 and $936 in 2019, 2018 and 2017, 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 20, beginning on page 80.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 22

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 15, beginning on page 74, 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 provisions have been made for all years under examination or subject to future examination.

Guarantees The company has two guarantees to equity affiliates totaling $704. Of this amount, $412 is associated with a

financing arrangement with an equity affiliate. Over the approximate 2-year remaining term of this guarantee, the maximum

amount will be reduced as payments are made by the affiliate. The remaining amount of $292 is associated with certain

payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 8-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

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 may relate to

suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage

capacity, 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: 2020 – $900; 2021 – $1,100;

2022 – $1,100; 2023 – $1,200; 2024 – $1,200; 2025 and after – $7,200. A portion of these commitments may ultimately be

shared with project partners. Total payments under the agreements were approximately $800 in 2019, $1,400 in 2018 and

$1,300 in 2017.

As part of the implementation of ASU 2016-02, the company assessed some contracts, previously incorporated into the

unconditional purchase obligations disclosure, as operating leases in 2019.

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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 92 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 Investment Committee has established the following approved asset

allocation ranges: Equities 30–60 percent, Fixed Income 20–40 percent, Real Estate 0–15 percent, Alternative Investments

0–15 percent and Cash 0–25 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following

asset allocation guidelines: Equities 10–30 percent, Fixed Income 55–85 percent, Real Estate 5–15 percent, and Cash 0–

5 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 2019, the company contributed $1,096 and $266 to its U.S. and international

pension plans, respectively. In 2020, the company expects contributions to be approximately $1,250 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 $174 in 2020; $168 was paid in 2019.

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

10 years:

2020

2021

2022

2023

2024

2024-2028

Pension Benefits

U.S.

1,262

1,176

1,160

1,150

1,134

5,232

Int’l.

280

602

224

234

255

1,434

Other

Benefits

174

170

165

161

156

725

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 $284, $270 and $316 in 2019, 2018

and 2017, 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 2019, 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, 2019 and 2018, trust assets

of $35 and $34, 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

$826, $1,048 and $936 in 2019, 2018 and 2017, 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 20, beginning on page 80.

Note 22
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 15, beginning on page 74, 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 provisions have been made for all years under examination or subject to future examination.

Guarantees The company has two guarantees to equity affiliates totaling $704. Of this amount, $412 is associated with a
financing arrangement with an equity affiliate. Over the approximate 2-year remaining term of this guarantee, the maximum
amount will be reduced as payments are made by the affiliate. The remaining amount of $292 is associated with certain
payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 8-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 may relate to
suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage
capacity, 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: 2020 – $900; 2021 – $1,100;
2022 – $1,100; 2023 – $1,200; 2024 – $1,200; 2025 and after – $7,200. A portion of these commitments may ultimately be
shared with project partners. Total payments under the agreements were approximately $800 in 2019, $1,400 in 2018 and
$1,300 in 2017.

As part of the implementation of ASU 2016-02, the company assessed some contracts, previously incorporated into the
unconditional purchase obligations disclosure, as operating leases in 2019.

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.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Chevron’s environmental reserve as of December 31, 2019, was $1,234. Included in this balance was $266 related to
remediation activities at approximately 145 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 2019 environmental reserves balance of $968, $667 is related to the company’s U.S. downstream
operations, $28 to its international downstream operations, $272 to upstream operations and $1 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 2019 had a recorded liability that was material to the company’s results of operations, consolidated financial
position or liquidity.

Refer to Note 23 on page 89 for a discussion of the company’s asset retirement obligations.

Other Contingencies Governmental and other entities in California and other jurisdictions have filed legal proceedings
against fossil fuel producing companies, including Chevron, purporting to seek legal and equitable relief to address alleged
impacts of climate change. Further such proceedings are likely to be filed by other parties. The unprecedented legal theories
set forth in these proceedings entail the possibility of damages liability and injunctions against the production of all fossil
fuels that, while we believe remote, could have a material adverse effect on the company’s results of operations and financial
condition. Management believes that these proceedings are legally and factually meritless and detract from constructive
efforts to address the important policy issues presented by climate change, and will vigorously defend against such
proceedings.

Chevron has interests in Venezuelan crude oil production assets operated by independent equity affiliates. During 2019, net
oil equivalent production in Venezuela averaged 35,000 barrels per day, 3,000 barrels per day of which was upgraded to
synthetic crude. Synthetic crude production in 2019 was impacted by operating conditions, including a shutdown of the
Petropiar heavy oil upgrader for part of the year. The operating environment in Venezuela has been deteriorating for some
time. In January 2019, the United States government issued sanctions against the Venezuelan national oil company, Petroleos
de Venezuela, S.A. (PdVSA), which is the company’s partner in the equity affiliates. The company is conducting its business
pursuant to general licenses and guidance issued coincident with the sanctions. In late July 2019, the United States
government renewed General License 8A with the issuance of General License 8B, subsequently superseded by General
License 8C issued on August 5, 2019. The authorization provided to Chevron under General License 8C was extended by
General License 8D on October 21, 2019 and General License 8E issued by the United States government on January 17,
2020. General License 8E enables the company to continue to meet its contractual obligations in Venezuela with PdVSA and
is effective until April 22, 2020.

At December 31, 2019, the carrying value of the company’s investments was approximately $2,650 and for the year ended
December 31, 2019, the company recognized losses of $54 for its share of net income from the equity affiliates, and for
demurrage, foreign exchange losses and other costs incurred in support of the company’s operations in Venezuela. Future
events could result in the environment in Venezuela becoming more challenged, which could lead to increased business
disruption and volatility in the associated financial results. The company continues to evaluate the carrying value of its
Venezuelan investments in line with its accounting policies. Future events related to the company’s activities in Venezuela
may result in significant impacts on the company’s results of operation in subsequent periods. Please see Note 13,
“Investments and Advances”, on page 71 for further information on the company’s investments in equity affiliates in
Venezuela.

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, retire, 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.

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Chevron Corporation 2019 Annual Report
88

obligation.

Balance at January 1

Liabilities incurred

Liabilities settled

Accretion expense

Revisions in estimated cash flows

Balance at December 31

$11,592.

Note 24

Revenue

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 23

Asset Retirement Obligations

The company records the fair value of a liability for an asset retirement obligation (ARO) both as an asset and a 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

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2019, 2018 and 2017:

14,050

14,214

2019

(1,694)

628

(184)

2018

(830)

654

(84)

2017

14,243

684

(1,721)

668

340

12,832

14,050

14,214

In the table above, the amount associated with “Revisions in estimated cash flows” in 2019 reflects decreased cost estimates

to decommission wells, equipment and facilities. The long-term portion of the $12,832 balance at the end of 2019 was

Revenue from contracts with customers is presented in “Sales and other operating revenue” along with some activity that is

accounted for outside the scope of Accounting Standard Codification (ASC) 606, which is not material to this line, on the

Consolidated Statement of Income. 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. Refer to Note 12 beginning on page 68 for

additional information on the company’s segmentation of revenue.

Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable, net” on the

Consolidated Balance Sheet, net of the allowance for doubtful accounts. The net balance of these receivables was $9,247 and

$10,046 at December 31, 2019 and December 31, 2018, respectively. Other items included in “Accounts and notes

receivable, net” represent amounts due from partners for their share of joint venture operating and project costs and amounts

due from others, primarily related to derivatives, leases, buy/sell arrangements and product exchanges, which are accounted

for outside the scope of ASC 606.

Contract assets and related costs are reflected in “Prepaid expenses and other current assets” and contract liabilities are

reflected in “Accrued liabilities” and “Deferred credits and other noncurrent obligations” on the Consolidated Balance Sheet.

Amounts for these items are not material to the company’s financial position.

Note 25

Other Financial Information

Earnings in 2019 included after-tax gains of approximately $1,500 relating to the sale of certain properties. Of this amount,

approximately $50 and $1,450 related to downstream and upstream, respectively. Earnings in 2018 included after-tax gains

of approximately $630 relating to the sale of certain properties, of which approximately $365 and $265 related to

downstream and upstream assets, respectively. Earnings in 2019 included after-tax charges of approximately $10,400 for

impairments and other asset write-offs related to upstream. Earnings in 2018 included after-tax charges of approximately

$2,000 for impairments and other asset write-offs related to upstream.

145363_10K.indd 88

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Chevron’s environmental reserve as of December 31, 2019, was $1,234. Included in this balance was $266 related to

remediation activities at approximately 145 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 2019 environmental reserves balance of $968, $667 is related to the company’s U.S. downstream

operations, $28 to its international downstream operations, $272 to upstream operations and $1 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.

position or liquidity.

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 2019 had a recorded liability that was material to the company’s results of operations, consolidated financial

Refer to Note 23 on page 89 for a discussion of the company’s asset retirement obligations.

Other Contingencies Governmental and other entities in California and other jurisdictions have filed legal proceedings

against fossil fuel producing companies, including Chevron, purporting to seek legal and equitable relief to address alleged

impacts of climate change. Further such proceedings are likely to be filed by other parties. The unprecedented legal theories

set forth in these proceedings entail the possibility of damages liability and injunctions against the production of all fossil

fuels that, while we believe remote, could have a material adverse effect on the company’s results of operations and financial

condition. Management believes that these proceedings are legally and factually meritless and detract from constructive

efforts to address the important policy issues presented by climate change, and will vigorously defend against such

proceedings.

Chevron has interests in Venezuelan crude oil production assets operated by independent equity affiliates. During 2019, net

oil equivalent production in Venezuela averaged 35,000 barrels per day, 3,000 barrels per day of which was upgraded to

synthetic crude. Synthetic crude production in 2019 was impacted by operating conditions, including a shutdown of the

Petropiar heavy oil upgrader for part of the year. The operating environment in Venezuela has been deteriorating for some

time. In January 2019, the United States government issued sanctions against the Venezuelan national oil company, Petroleos

de Venezuela, S.A. (PdVSA), which is the company’s partner in the equity affiliates. The company is conducting its business

pursuant to general licenses and guidance issued coincident with the sanctions. In late July 2019, the United States

government renewed General License 8A with the issuance of General License 8B, subsequently superseded by General

License 8C issued on August 5, 2019. The authorization provided to Chevron under General License 8C was extended by

General License 8D on October 21, 2019 and General License 8E issued by the United States government on January 17,

2020. General License 8E enables the company to continue to meet its contractual obligations in Venezuela with PdVSA and

is effective until April 22, 2020.

At December 31, 2019, the carrying value of the company’s investments was approximately $2,650 and for the year ended

December 31, 2019, the company recognized losses of $54 for its share of net income from the equity affiliates, and for

demurrage, foreign exchange losses and other costs incurred in support of the company’s operations in Venezuela. Future

events could result in the environment in Venezuela becoming more challenged, which could lead to increased business

disruption and volatility in the associated financial results. The company continues to evaluate the carrying value of its

Venezuelan investments in line with its accounting policies. Future events related to the company’s activities in Venezuela

may result in significant impacts on the company’s results of operation in subsequent periods. Please see Note 13,

“Investments and Advances”, on page 71 for further information on the company’s investments in equity affiliates in

Venezuela.

future periods.

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

The company and its affiliates also continue to review and analyze their operations and may close, retire, 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 23
Asset Retirement Obligations
The company records the fair value of a liability for an asset retirement obligation (ARO) both as an asset and a 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 2019, 2018 and 2017:

Balance at January 1
Liabilities incurred
Liabilities settled
Accretion expense
Revisions in estimated cash flows

Balance at December 31

2019

14,050
32
(1,694)
628
(184)

2018

14,214
96
(830)
654
(84)

2017

14,243
684
(1,721)
668
340

12,832

14,050

14,214

In the table above, the amount associated with “Revisions in estimated cash flows” in 2019 reflects decreased cost estimates
to decommission wells, equipment and facilities. The long-term portion of the $12,832 balance at the end of 2019 was
$11,592.

Note 24
Revenue
Revenue from contracts with customers is presented in “Sales and other operating revenue” along with some activity that is
accounted for outside the scope of Accounting Standard Codification (ASC) 606, which is not material to this line, on the
Consolidated Statement of Income. 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. Refer to Note 12 beginning on page 68 for
additional information on the company’s segmentation of revenue.

Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable, net” on the
Consolidated Balance Sheet, net of the allowance for doubtful accounts. The net balance of these receivables was $9,247 and
$10,046 at December 31, 2019 and December 31, 2018, respectively. Other items included in “Accounts and notes
receivable, net” represent amounts due from partners for their share of joint venture operating and project costs and amounts
due from others, primarily related to derivatives, leases, buy/sell arrangements and product exchanges, which are accounted
for outside the scope of ASC 606.

Contract assets and related costs are reflected in “Prepaid expenses and other current assets” and contract liabilities are
reflected in “Accrued liabilities” and “Deferred credits and other noncurrent obligations” on the Consolidated Balance Sheet.
Amounts for these items are not material to the company’s financial position.

Note 25
Other Financial Information
Earnings in 2019 included after-tax gains of approximately $1,500 relating to the sale of certain properties. Of this amount,
approximately $50 and $1,450 related to downstream and upstream, respectively. Earnings in 2018 included after-tax gains
of approximately $630 relating to the sale of certain properties, of which approximately $365 and $265 related to
downstream and upstream assets, respectively. Earnings in 2019 included after-tax charges of approximately $10,400 for
impairments and other asset write-offs related to upstream. Earnings in 2018 included after-tax charges of approximately
$2,000 for impairments and other asset write-offs related to upstream.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Other financial information is as follows:

Total financing interest and debt costs
Less: Capitalized interest

Interest and debt expense

Research and development expenses

Excess of replacement cost over the carrying value of inventories (LIFO method)
LIFO profits (losses) on inventory drawdowns included in earnings

Foreign currency effects*

2019

817
19

798

500

4,513
(9)

(304)

$
$

Year ended December 31

2018

921
173

748

453

5,134
26

611

$
$

2017

902
595

307

433

3,937
(5)

(446)

$
$

Includes $(28), $416 and $(45) in 2019, 2018 and 2017, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $4,463 in goodwill on the Consolidated Balance Sheet, all of which is in the upstream segment and
primarily related to the 2005 acquisition of Unocal. The company tested this goodwill for impairment during 2019, and no
impairment was required.

Note 26
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 13, on page 72, for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem
is presented in the table below:

Sales and other operating revenues
Costs and other deductions
Net income attributable to CPChem

Current assets
Other assets
Current liabilities
Other liabilities

Total CPChem net equity

2019

9,333
7,863
1,760

Year ended December 31

2018

11,310
9,812
2,069

2017

9,063
8,126
1,446

At December 31

2018

2,820
13,790
1,281
2,892

2019

2,554
14,314
1,247
3,174

12,447

12,437

Millions of dollars, except per-share amounts

2019

2018

2017

2016

2015

Net Income (Loss) Attributable to Chevron Corporation

2,924

14,824

9,195

(497) $

Five-Year Financial Summary

Unaudited

Statement of Income Data

Revenues and Other Income

Total sales and other operating revenues*

Income from equity affiliates and other income

Total Revenues and Other Income

Total Costs and Other Deductions

Income Before Income Tax Expense (Benefit)

Income Tax Expense (Benefit)

Net Income

Less: Net income attributable to noncontrolling interests

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron

– Basic

– Diluted

Cash Dividends Per Share

Balance Sheet Data (at December 31)

Current assets

Noncurrent assets

Total Assets

Short-term debt

Other current liabilities

Long-term debt

Other noncurrent liabilities

Total Liabilities

Noncontrolling interests

Total Equity

Total Chevron Corporation Stockholders’ Equity

139,865

158,902

134,674

110,215

129,925

6,651

146,516

140,980

5,536

2,691

2,845

(79)

1.55

1.54

4.76

28,329

209,099

237,428

3,282

23,248

23,691

41,999

92,220

144,213

995

145,208

7,437

166,339

145,764

20,575

5,715

14,860

7.81

7.74

4.48

34,021

219,842

253,863

5,726

21,445

28,733

42,317

98,221

154,554

1,088

155,642

7,048

141,722

132,501

9,221

(48)

9,269

4,257

114,472

116,632

(2,160)

(1,729)

(431)

4.88

4.85

4.32

28,560

225,246

253,806

5,192

22,545

33,571

43,179

104,487

148,124

1,195

149,319

(0.27) $

4.29

29,619

230,459

260,078

10,840

20,945

35,286

46,285

113,356

145,556

1,166

146,722

8,552

138,477

133,635

4,842

132

4,710

123

4,587

2.46

2.45

4.28

34,430

230,110

264,540

4,927

20,540

33,622

51,565

110,654

152,716

1,170

153,886

* Includes excise, value-added and similar taxes:

—

— $

7,189

6,905

7,359

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Five-Year Financial Summary
Unaudited

Millions of dollars, except per-share amounts

2019

2018

2017

2016

2015

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Other financial information is as follows:

Total financing interest and debt costs

Less: Capitalized interest

Interest and debt expense

Research and development expenses

impairment was required.

Note 26

is presented in the table below:

Sales and other operating revenues

Costs and other deductions

Net income attributable to CPChem

Current assets

Other assets

Current liabilities

Other liabilities

Total CPChem net equity

Excess of replacement cost over the carrying value of inventories (LIFO method)

LIFO profits (losses) on inventory drawdowns included in earnings

Foreign currency effects*

Includes $(28), $416 and $(45) in 2019, 2018 and 2017, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $4,463 in goodwill on the Consolidated Balance Sheet, all of which is in the upstream segment and

primarily related to the 2005 acquisition of Unocal. The company tested this goodwill for impairment during 2019, and no

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 13, on page 72, for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem

2019

817

798

500

4,513

(9)

(304)

2019

9,333

7,863

1,760

Year ended December 31

2018

921

173

748

453

5,134

611

2017

902

595

307

433

3,937

(5)

(446)

Year ended December 31

2018

11,310

9,812

2,069

2019

2,554

14,314

1,247

3,174

At December 31

2017

9,063

8,126

1,446

2018

2,820

13,790

1,281

2,892

12,447

12,437

Statement of Income Data
Revenues and Other Income

Total sales and other operating revenues*
Income from equity affiliates and other income

Total Revenues and Other Income
Total Costs and Other Deductions

Income Before Income Tax Expense (Benefit)
Income Tax Expense (Benefit)

Net Income

Less: Net income attributable to noncontrolling interests

Net Income (Loss) Attributable to Chevron Corporation

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron

– Basic
– Diluted

Cash Dividends Per Share

Balance Sheet Data (at December 31)

Current assets
Noncurrent assets

Total Assets

Short-term debt
Other current liabilities
Long-term debt
Other noncurrent liabilities

Total Liabilities

Total Chevron Corporation Stockholders’ Equity

Noncontrolling interests

Total Equity

* Includes excise, value-added and similar taxes:

$
$

139,865
6,651

146,516
140,980

5,536
2,691

2,845
(79)

158,902
7,437

166,339
145,764

20,575
5,715

14,860
36

$ 134,674
7,048

141,722
132,501

9,221
(48)

9,269
74

(2,160)
(1,729)

(431)
66

110,215
4,257

114,472
116,632

129,925
8,552

138,477
133,635

2,924

14,824

9,195

(497) $

1.55
1.54

4.76

28,329
209,099

237,428

3,282
23,248
23,691
41,999

92,220

144,213
995

145,208

—

$
$

7.81
7.74

4.48

34,021
219,842

253,863

5,726
21,445
28,733
42,317

98,221

$
$

4.88
4.85

4.32

28,560
225,246

253,806

5,192
22,545
33,571
43,179

104,487

154,554
1,088

$ 148,124
1,195

155,642

$ 149,319

— $

7,189

$
$

(0.27) $
(0.27) $

4.29

29,619
230,459

260,078

10,840
20,945
35,286
46,285

113,356

145,556
1,166

146,722

6,905

4,842
132

4,710
123

4,587

2.46
2.45

4.28

34,430
230,110

264,540

4,927
20,540
33,622
51,565

110,654

152,716
1,170

153,886

7,359

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides
supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I
through IV provide historical cost
information pertaining to costs incurred in exploration, property acquisitions and
development; capitalized costs; and results of operations. Tables V through VII present information on the company’s estimated
net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved 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 13, beginning on page 71, for a discussion of the company’s

major equity affiliates.

Table I - Costs Incurred in Exploration, Property Acquisitions and Development1

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

U.S.

Other
Americas

Africa

Asia

Australia/
Oceania

Europe

Total

TCO4

Other

Consolidated Companies

Affiliated Companies

Millions of dollars

U.S.

Americas

Africa

Asia

Europe

Total

TCO*

Other

Consolidated Companies

Affiliated Companies

4,620 $

2,492 $

151 $

1,081 $

1,986 $

— $

10,330

108 $

—

Millions of dollars

Year Ended December 31, 2019
Exploration
Wells
Geological and geophysical
Other

Total exploration

Property acquisitions2

Proved
Unproved

Total property acquisitions

571
82
140

793

81
68

149

44
118
52

214

34
150

184

Development3

7,072

1,216

Total Costs Incurred5

8,014

1,614

Year Ended December 31, 2018
Exploration
Wells
Geological and geophysical
Other

Total exploration

Property acquisitions2

Proved
Unproved

Total property acquisitions

Development3

508
84
190

782

160
52

212

6,245

74
41
46

161

—
494

494

856

Total Costs Incurred5

7,239

1,511

Year Ended December 31, 2017
Exploration
Wells
Geological and geophysical
Other

Total exploration

Property acquisitions2

Proved
Unproved

Total property acquisitions

479
93
157

729

64
77

141

3
46
32

—
—

—

9
21
35

—
—

—

279

344

25
4
35

7
2

711

784

1
4
52

—
40

518

578

199

210

10,304

5,112

11,926

5,112

4
11
44

—
1

4
1
6

—
—

—

634
238
306

1,178

208
236

444

— $
7
49

—
—

—

14
1
23

—
—

—

676
142
376

1,194

284
575

859

2
5
29

93
17

110

1,020

1,166

55
5
33

117
27

144

1,095

1,332

36
3
60

93
18

111

1,324

— $
33
46

—
1

2,580

534
184
475

1,193

157
136

293

15
5
128

148

—
—

—

121

269

— $ —
—
—
8
—

—

—
—

—

—
—

—

—
—

—

—
—

—

158

166

—

—
—

—

200

—

—
—

—

147

845

901

278

316

10,030

4,963

12,083

4,963

— $ —
—
—
—
—

Development3

4,346

944

1,136

Total Costs Incurred5

5,216

1,025

$ 1,233

1,534

2,660

10,451

3,683

11,937

3,683

— $ —
—
—
—
—

32,209 $

13,503 $

14,081 $

13,925 $

36,528 $

1,814 $

112,060

22,213 $

3,142

4,687 $

2,463 $

201 $

1,299 $

1,986 $

— $

10,636

108 $

—

At December 31, 2019

Unproved properties

Proved properties and related

producing assets

Support equipment

Deferred exploratory wells

Other uncompleted projects

Gross Capitalized Costs

Unproved properties valuation

Proved producing properties –

Depreciation and depletion

Support equipment depreciation

Accumulated provisions

Net Capitalized Costs

At December 31, 2018

Unproved properties

Proved properties and related

producing assets

Support equipment

Deferred exploratory wells

Other uncompleted projects

Gross Capitalized Costs

Unproved properties valuation

Proved producing properties –

Depreciation and depletion

Support equipment depreciation

Accumulated provisions

Net Capitalized Costs

At December 31, 2017

Unproved properties

Proved properties and

related producing assets

Support equipment

Deferred exploratory wells

Other uncompleted projects

Gross Capitalized Costs

Unproved properties valuation

Proved producing properties –

Depreciation and depletion

Support equipment depreciation

Accumulated provisions

82,199

2,287

533

5,080

94,719

3,964

56,911

1,635

62,510

75,013

2,216

782

4,730

87,428

820

45,712

1,466

47,998

66,390

2,248

969

8,333

84,406

977

43,286

1,359

45,622

2017 and 2018 conformed to 2019 presentation

Other

24,189

311

147

505

27,644

1,271

12,644

226

14,141

21,796

317

160

3,704

28,440

694

12,984

220

13,898

20,696

337

181

3,624

27,152

855

11,795

227

12,877

45,756

1,098

405

1,176

48,586

120

33,613

772

34,505

44,876

1,096

405

1,744

48,322

164

31,102

738

32,004

43,656

1,104

406

2,528

47,934

162

27,916

712

28,790

56,648

2,075

513

926

61,243

842

44,871

1,605

47,318

57,168

2,149

632

1,292

62,540

623

43,735

1,674

46,032

55,616

2,050

562

1,889

61,537

535

40,234

1,584

42,353

Australia/

Oceania

22,032

18,610

1,322

1,023

44,973

109

6,064

2,272

8,445

2,218

279,383

2,082

—

121

—

404

—

404

232,906

24,381

3,041

8,725

6,306

154,507

6,510

167,323

22,047

17,712

1,323

1,462

12,634

233,534

124

261

300

23,614

3,563

13,232

44,530

13,319

284,579

107

—

2,408

4,631

1,531

6,269

10,014

119

10,133

148,178

5,748

156,334

4,311

—

743

5,054

—

1,912

—

1,912

4,336

—

605

4,941

—

1,730

—

1,730

10,757

1,981

—

16,503

29,349

6,018

1,053

7,136

9,892

1,858

—

12,311

24,169

5,276

947

6,284

21,544

15,599

1,323

3,238

10,697

218,599

132

261

1,966

21,470

3,702

21,578

8,956

1,731

—

8,408

4,346

—

457

43,690

13,079

277,798

19,203

4,803

107

2,659

—

3,193

870

4,170

9,306

123

9,452

135,730

4,875

143,264

4,674

846

5,578

1,468

—

1,468

39,430 $

14,542 $

16,318 $

16,508 $

38,261 $

3,186 $

128,245

17,885 $

3,211

6,466 $

2,314 $

240 $

1,420 $

1,986 $

23 $

12,449

108 $

—

Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations.
See Note 23, “Asset Retirement Obligations,” on page 89.

2 Does not include properties acquired in nonmonetary transactions.
3

Includes $246, $114 and $84 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2019, 2018, and 2017,
respectively.
2017 and 2018 conformed to 2019 presentation

5 Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures—$ billions:

Net Capitalized Costs

38,784 $

14,275 $

19,144 $

19,184 $

39,520 $

3,627 $

134,534

13,625 $

3,335

2019

2018

2017

Total cost incurred

Non-oil and gas activities
ARO reduction/(build)

17.2
0.3
0.3

17.2
0.6
(0.1)

15.7
1.3
(0.6)

(Primarily; LNG and transportation activities.)

Upstream C&E

17.8

17.7

16.4

Reference page 39 Upstream total

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides

supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I

through IV provide historical cost

information pertaining to costs incurred in exploration, property acquisitions and

development; capitalized costs; and results of operations. Tables V through VII present information on the company’s estimated

net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved 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 13, beginning on page 71, for a discussion of the company’s
major equity affiliates.

Table I - Costs Incurred in Exploration, Property Acquisitions and Development1

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

Millions of dollars

At December 31, 2019
Unproved properties
Proved properties and related

producing assets
Support equipment
Deferred exploratory wells
Other uncompleted projects

Gross Capitalized Costs

Unproved properties valuation
Proved producing properties –
Depreciation and depletion
Support equipment depreciation

Accumulated provisions

Net Capitalized Costs

At December 31, 2018
Unproved properties
Proved properties and related

producing assets
Support equipment
Deferred exploratory wells
Other uncompleted projects

Gross Capitalized Costs

Unproved properties valuation
Proved producing properties –
Depreciation and depletion
Support equipment depreciation

Accumulated provisions

Net Capitalized Costs

At December 31, 2017
Unproved properties
Proved properties and

related producing assets

Support equipment
Deferred exploratory wells
Other uncompleted projects

Gross Capitalized Costs

Unproved properties valuation
Proved producing properties –
Depreciation and depletion
Support equipment depreciation

Accumulated provisions

U.S.

Other
Americas

Africa

Asia

Australia/
Oceania

Europe

Total

TCO*

Other

Consolidated Companies

Affiliated Companies

4,620 $

2,492 $

151 $

1,081 $

1,986 $

— $

10,330

108 $

—

82,199
2,287
533
5,080

94,719

3,964

56,911
1,635

62,510

24,189
311
147
505

27,644

1,271

12,644
226

14,141

45,756
1,098
405
1,176

48,586

120

33,613
772

34,505

56,648
2,075
513
926

61,243

842

44,871
1,605

47,318

22,032
18,610
1,322
1,023

44,973

109

6,064
2,272

8,445

2,082
—
121
15

2,218

—

404
—

404

232,906
24,381
3,041
8,725

279,383

6,306

154,507
6,510

167,323

32,209 $

13,503 $

14,081 $

13,925 $

36,528 $

1,814 $

112,060

4,687 $

2,463 $

201 $

1,299 $

1,986 $

— $

10,636

75,013
2,216
782
4,730

87,428

820

45,712
1,466

47,998

21,796
317
160
3,704

28,440

694

12,984
220

13,898

44,876
1,096
405
1,744

48,322

164

31,102
738

32,004

57,168
2,149
632
1,292

62,540

623

43,735
1,674

46,032

22,047
17,712
1,323
1,462

12,634
124
261
300

233,534
23,614
3,563
13,232

44,530

13,319

284,579

107

—

2,408

4,631
1,531

6,269

10,014
119

10,133

148,178
5,748

156,334

39,430 $

14,542 $

16,318 $

16,508 $

38,261 $

3,186 $

128,245

6,466 $

2,314 $

240 $

1,420 $

1,986 $

23 $

12,449

10,757
1,981
—
16,503

29,349

6,018
1,053

7,136

4,311
—
—
743

5,054

—

1,912
—

1,912

22,213 $

3,142

108 $

—

9,892
1,858
—
12,311

24,169

5,276
947

6,284

4,336
—
—
605

4,941

—

1,730
—

1,730

17,885 $

3,211

108 $

—

66,390
2,248
969
8,333

84,406

977

43,286
1,359

45,622

20,696
337
181
3,624

27,152

855

11,795
227

12,877

43,656
1,104
406
2,528

47,934

162

27,916
712

28,790

55,616
2,050
562
1,889

61,537

535

40,234
1,584

42,353

21,544
15,599
1,323
3,238

10,697
132
261
1,966

218,599
21,470
3,702
21,578

8,956
1,731
—
8,408

43,690

13,079

277,798

19,203

107

2,659

3,193
870

4,170

9,306
123

9,452

135,730
4,875

143,264

4,674
846

5,578

4,346
—
—
457

4,803

—

1,468
—

1,468

5 Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures—$ billions:

Net Capitalized Costs

38,784 $

14,275 $

19,144 $

19,184 $

39,520 $

3,627 $

134,534

13,625 $

3,335

2017 and 2018 conformed to 2019 presentation

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Millions of dollars

U.S.

Americas

Africa

Asia

Europe

Total

TCO4

Other

Australia/

Oceania

Consolidated Companies

Affiliated Companies

— $ —

Year Ended December 31, 2019

Exploration

Wells

Other

Geological and geophysical

Total exploration

Property acquisitions2

Proved

Unproved

Total property acquisitions

Year Ended December 31, 2018

Exploration

Wells

Other

Geological and geophysical

Total exploration

Property acquisitions2

Proved

Unproved

Year Ended December 31, 2017

Exploration

Wells

Other

Geological and geophysical

Total exploration

Property acquisitions2

Proved

Unproved

Total property acquisitions

Development3

7,072

1,216

10,304

5,112

Total Costs Incurred5

8,014

1,614

1,166

11,926

5,112

110

1,020

279

344

518

578

199

210

— $

— $ —

571

140

793

149

508

190

782

160

212

479

157

729

141

118

214

150

184

161

—

494

856

—

711

784

117

144

1,095

111

1,324

634

238

306

1,178

208

236

444

676

142

376

1,194

284

575

859

534

184

475

1,193

157

136

293

—

128

148

—

121

269

—

158

166

—

200

—

147

Total property acquisitions

Development3

6,245

Total Costs Incurred5

7,239

1,511

1,332

12,083

4,963

845

901

278

316

10,030

4,963

— $

— $ —

Development3

4,346

944

1,136

2,580

10,451

3,683

Total Costs Incurred5

5,216

1,025

$ 1,233

1,534

2,660

11,937

3,683

Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations.

Includes $246, $114 and $84 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2019, 2018, and 2017,

See Note 23, “Asset Retirement Obligations,” on page 89.

2 Does not include properties acquired in nonmonetary transactions.

respectively.

2017 and 2018 conformed to 2019 presentation

2019

2018

2017

Total cost incurred

17.2

Non-oil and gas activities

ARO reduction/(build)

0.3

17.2

0.6

(0.1)

15.7

1.3

(0.6)

Upstream C&E

17.8

17.7

16.4

Reference page 39 Upstream total

(Primarily; LNG and transportation activities.)

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table III - Results of Operations for Oil and Gas Producing Activities1

Table III - Results of Operations for Oil and Gas Producing Activities1, continued

The company’s results of operations from oil and gas producing activities for the years 2019, 2018 and 2017 are shown in the
following table. Net income (loss) from exploration and production activities as reported on page 69 reflects income taxes
computed on an effective rate basis.

Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and
expense are excluded from the results reported in Table III and from the net income amounts on page 69.

Millions of dollars

Year Ended December 31, 2019
Revenues from net production

Sales
Transfers

Total

Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion

Accretion expense3
Exploration expenses
Unproved properties valuation
Other income (expense)4

Results before income taxes

Income tax (expense) benefit

Other
Americas

U.S.

Africa

Asia

Australia/
Oceania

Europe

Total

TCO2

Other

Consolidated Companies

Affiliated Companies

2,259 $
11,043

863 $

668 $

2,160

6,534

7,410 $
1,311

4,332 $
2,596

592 $
655

13,302
(3,567)
(595)

(11,659)
(191)
(293)
(3,268)
(51)

(6,322)
1,311

3,023
(1,020)
(64)

(1,380)
(21)
(211)
(591)
(44)

(308)
(27)

7,202
(1,460)
(101)

(2,548)
(148)
(73)
(2)
(121)

2,749
(1,731)

8,721
(2,703)
(16)

(3,165)
(133)
(93)
(388)
413

2,636
(1,212)

6,928
(616)
(221)

(2,192)
(53)
(60)
(2)
53

3,837
(1,161)

1,247
(343)
(2)

(85)
(37)
(10)
—
1,373

2,143
(311)

16,124
24,299

40,423
(9,709)
(999)

(21,029)
(583)
(740)
(4,251)
1,623

4,735
(3,131)

5,603 $
—

5,603
(475)
(57)

(870)
(5)
—
(4)
1

4,193
(1,261)

Results of Producing Operations

(5,011) $

(335) $

1,018 $

1,424 $

2,676 $

1,832 $

1,604

2,932 $

Year Ended December 31, 2018
Revenues from net production

Sales
Transfers

Total

Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion

Accretion expense3
Exploration expenses
Unproved properties valuation
Other income (expense)4

Results before income taxes

Income tax (expense) benefit

2,162 $
11,645

1,008 $
1,808

13,807
(3,203)
(540)

2,816
(1,009)
(70)

(4,583)
(186)
(777)
(516)
336

4,338
(886)

(998)
(26)
(191)
(42)
4

484
(400)

829 $

7,829

8,658
(1,564)
(112)

(3,368)
(149)
(52)
(3)
97

3,507
(2,131)

5,880 $
3,206

4,229 $
3,413

9,086
(2,653)
(22)

(3,714)
(146)
(58)
(135)
(33)

2,325
(1,088)

7,642
(557)
(250)

(2,103)
(50)
(56)
—
31

4,657
(1,415)

619 $

1,071

1,690
(424)
(2)

(411)
(52)
(41)
—
(161)

599
(233)

14,727
28,972

43,699
(9,410)
(996)

(15,177)
(609)
(1,175)
(696)
274

15,910
(6,153)

5,987 $
—

5,987
(447)
160

(711)
(4)
(3)
—
70

5,052
(1,519)

Results of Producing Operations

3,452 $

84 $

1,376 $

1,237 $

3,242 $

366 $

9,757

3,533 $

780
—

780
(247)
(10)

(211)
(8)
(8)
—
(157)

139
(73)

1,369
—

1,369
(295)
(210)

(306)
(3)
(6)
—
(280)

269
341

610

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.
2017 and 2018 conformed to 2019 presentation.

3 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 89.
4

Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

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Millions of dollars

U.S.

Americas

Africa

Asia

Europe

Total

TCO2

Other

Australia/

Oceania

Consolidated Companies

Affiliated Companies

Year Ended December 31, 2017

Revenues from net production

Sales

Transfers

Total

Production expenses excluding taxes

Taxes other than on income

Proved producing properties:

Depreciation and depletion

Accretion expense3

Exploration expenses

Unproved properties valuation

Other income (expense)4

Results before income taxes

Income tax (expense) benefit

1,548 $

999 $

487 $

5,381 $

2,061 $

372 $

4,509 $

1,218

(5,092)

(1,046)

(4,134)

(1,176)

(15,647)

(645)

7,610

1,371

6,533

2,966

9,158

(3,160)

(403)

2,370

(1,021)

(85)

(212)

(299)

(204)

580

368

(88)

(23)

(126)

(259)

(87)

(277)

(64)

7,020

(1,521)

(115)

(3,531)

(144)

(65)

(3)

259

1,900

(1,199)

8,347

(2,670)

(11)

(155)

(108)

(52)

273

1,490

(616)

937

2,998

(304)

(183)

(40)

(85)

—

170

1,380

(413)

1,246

1,618

(415)

(3)

(668)

(60)

(149)

—

(170)

153

(174)

10,848

20,663

31,511

(9,091)

(800)

(634)

(832)

(518)

1,025

5,014

(2,554)

—

4,509

(425)

118

(3)

—

(3)

3,576

(1,076)

—

1,218

(306)

(121)

(365)

(16)

—

(14)

396

416

Results of Producing Operations

280 $

(341) $

701 $

874 $

967 $

(21) $

2,460

2,500 $

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.

2017 and 2018 conformed to 2019 presentation.

3 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 89.

Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs1

U.S.

Americas

Africa

Asia

Europe

Total

TCO

Other

Australia/

Oceania

Consolidated Companies

Affiliated Companies

Natural gas, per thousand cubic feet

Average production costs, per barrel2

1.07

10.48

2.24

15.97

1.84

11.90

4.73

12.74

7.54

4.08

4.43

14.28

0.79

3.53

0.99

7.93

48.54 $

54.85 $

62.27 $

59.53 $

60.15 $

61.80 $

49.14 $

45.25

Natural gas, per thousand cubic feet

Average production costs, per barrel2

1.86

11.18

2.62

17.32

2.55

11.29

4.48

12.15

8.78

3.95

7.54

14.21

0.77

3.59

3.19

9.29

58.17 $

58.27 $

69.75 $

63.55 $

68.78 $

66.31 $

56.20 $

56.41

Year Ended December 31, 2019

Average sales prices

Liquids, per barrel

Year Ended December 31, 2018

Average sales prices

Liquids, per barrel

Year Ended December 31, 2017

Average sales prices

Liquids, per barrel

Natural gas, per thousand cubic feet

Average production costs, per barrel2

2.11

12.83

3.15

18.64

1.77

10.88

4.12

11.30

5.75

3.60

5.55

11.95

0.88

3.34

2.38

8.51

44.53 $

51.26 $

52.12 $

48.45 $

52.32 $

51.15 $

41.47 $

48.68

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.

54.47

4.86

10.62

62.45

5.54

10.78

48.61

4.07

11.41

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table III - Results of Operations for Oil and Gas Producing Activities1

Table III - Results of Operations for Oil and Gas Producing Activities1, continued

1,218
—

1,218
(306)
(121)

(365)
(16)
—
—
(14)

396
20

416

Other
Americas

U.S.

Africa

Asia

Australia/
Oceania

Europe

Total

TCO2

Other

Consolidated Companies

Affiliated Companies

(11,659)

(1,380)

(3,165)

(2,192)

(21,029)

(870)

(211)

Results of Producing Operations

280 $

(341) $

701 $

874 $

967 $

(21) $

2,460

2,500 $

Millions of dollars

Year Ended December 31, 2017
Revenues from net production

Sales
Transfers

Total

Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion

Accretion expense3
Exploration expenses
Unproved properties valuation
Other income (expense)4

Results before income taxes

Income tax (expense) benefit

1,548 $
7,610

999 $

487 $

1,371

6,533

5,381 $
2,966

2,061 $
937

9,158
(3,160)
(403)

(5,092)
(212)
(299)
(204)
580

368
(88)

2,370
(1,021)
(85)

(1,046)
(23)
(126)
(259)
(87)

(277)
(64)

7,020
(1,521)
(115)

(3,531)
(144)
(65)
(3)
259

1,900
(1,199)

8,347
(2,670)
(11)

(4,134)
(155)
(108)
(52)
273

1,490
(616)

2,998
(304)
(183)

(1,176)
(40)
(85)
—
170

1,380
(413)

372 $

1,246

1,618
(415)
(3)

(668)
(60)
(149)
—
(170)

153
(174)

10,848
20,663

31,511
(9,091)
(800)

(15,647)
(634)
(832)
(518)
1,025

5,014
(2,554)

4,509 $
—

4,509
(425)
118

(645)
(3)
—
(3)
25

3,576
(1,076)

The company’s results of operations from oil and gas producing activities for the years 2019, 2018 and 2017 are shown in the

following table. Net income (loss) from exploration and production activities as reported on page 69 reflects income taxes

computed on an effective rate basis.

Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and

expense are excluded from the results reported in Table III and from the net income amounts on page 69.

Millions of dollars

U.S.

Americas

Africa

Asia

Europe

Total

TCO2

Other

Australia/

Oceania

Consolidated Companies

Affiliated Companies

Year Ended December 31, 2019

Revenues from net production

Sales

Transfers

Total

Production expenses excluding taxes

Taxes other than on income

Proved producing properties:

Depreciation and depletion

Accretion expense3

Exploration expenses

Unproved properties valuation

Other income (expense)4

Results before income taxes

Income tax (expense) benefit

Year Ended December 31, 2018

Revenues from net production

Sales

Transfers

Total

Production expenses excluding taxes

Taxes other than on income

Proved producing properties:

Depreciation and depletion

Accretion expense3

Exploration expenses

Unproved properties valuation

Other income (expense)4

Results before income taxes

Income tax (expense) benefit

2,259 $

863 $

668 $

7,410 $

4,332 $

592 $

5,603 $

11,043

2,160

6,534

1,311

13,302

(3,567)

(595)

3,023

(1,020)

(64)

(191)

(293)

(3,268)

(51)

(6,322)

1,311

(21)

(211)

(591)

(44)

(308)

(27)

7,202

(1,460)

(101)

(2,548)

(148)

(73)

(2)

(121)

2,749

(1,731)

8,721

(2,703)

(16)

(133)

(93)

(388)

413

2,636

(1,212)

3,837

(1,161)

11,645

1,808

7,829

3,206

13,807

(3,203)

(540)

2,816

(1,009)

(70)

8,658

(1,564)

(112)

9,086

(2,653)

(22)

(4,583)

(186)

(777)

(516)

336

4,338

(886)

(998)

(26)

(191)

(42)

484

(400)

(149)

(52)

(3)

(146)

(58)

(135)

(33)

3,507

(2,131)

2,325

(1,088)

4,657

(1,415)

2,596

6,928

(616)

(221)

(53)

(60)

(2)

3,413

7,642

(557)

(250)

(50)

(56)

—

655

1,247

(343)

(2)

(85)

(37)

(10)

—

1,373

2,143

(311)

1,071

1,690

(424)

(2)

(411)

(52)

(41)

—

(161)

599

(233)

16,124

24,299

40,423

(9,709)

(999)

(583)

(740)

(4,251)

1,623

4,735

(3,131)

14,727

28,972

43,699

(9,410)

(996)

(15,177)

(609)

(1,175)

(696)

274

15,910

(6,153)

—

5,603

(475)

(57)

(5)

—

(4)

4,193

(1,261)

—

5,987

(447)

160

(4)

(3)

—

5,052

(1,519)

780

—

780

(247)

(10)

(8)

—

(157)

139

(73)

—

1,369

(295)

(210)

(3)

(6)

—

(280)

269

341

610

(3,368)

(3,714)

(2,103)

(711)

(306)

2,162 $

1,008 $

829 $

5,880 $

4,229 $

619 $

5,987 $

1,369

Results of Producing Operations

3,452 $

84 $

1,376 $

1,237 $

3,242 $

366 $

9,757

3,533 $

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.

2017 and 2018 conformed to 2019 presentation.

3 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 89.

Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

Results of Producing Operations

(5,011) $

(335) $

1,018 $

1,424 $

2,676 $

1,832 $

1,604

2,932 $

Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs1

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.
2017 and 2018 conformed to 2019 presentation.

3 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 89.
4

Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

Other
Americas

U.S.

Africa

Asia

Australia/
Oceania

Europe

Total

TCO

Other

Consolidated Companies

Affiliated Companies

Year Ended December 31, 2019
Average sales prices
Liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel2

Year Ended December 31, 2018
Average sales prices
Liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel2

Year Ended December 31, 2017
Average sales prices
Liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel2

48.54 $
1.07
10.48

54.85 $
2.24
15.97

62.27 $
1.84
11.90

59.53 $
4.73
12.74

60.15 $
7.54
4.08

61.80 $
4.43
14.28

54.47
4.86
10.62

58.17 $
1.86
11.18

58.27 $
2.62
17.32

69.75 $
2.55
11.29

63.55 $
4.48
12.15

68.78 $
8.78
3.95

66.31 $
7.54
14.21

62.45
5.54
10.78

44.53 $
2.11
12.83

51.26 $
3.15
18.64

52.12 $
1.77
10.88

48.45 $
4.12
11.30

52.32 $
5.75
3.60

51.15 $
5.55
11.95

48.61
4.07
11.41

49.14 $
0.79
3.53

45.25
0.99
7.93

56.20 $
0.77
3.59

56.41
3.19
9.29

41.47 $
0.88
3.34

48.68
2.38
8.51

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.

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Table V Reserve Quantity Information

Summary of Net Oil and Gas Reserves

Liquids in Millions of Barrels
Natural Gas in Billions of
Cubic Feet

Proved Developed

Consolidated Companies

U.S.
Other Americas
Africa
Asia
Australia/Oceania
Europe

Total Consolidated

Affiliated Companies

TCO
Other

Total Consolidated and
Affiliated Companies

Proved Undeveloped

Consolidated Companies

U.S.
Other Americas
Africa
Asia
Australia/Oceania
Europe

Total Consolidated

Affiliated Companies

TCO
Other

Total Consolidated and
Affiliated Companies

Total Proved Reserves

2019

2018

2017

Crude Oil
Condensate

Synthetic

Oil NGL

Natural
Gas

Crude Oil
Condensate

Synthetic

Oil NGL

Natural
Gas

Crude Oil
Condensate

Synthetic

Oil NGL

Natural
Gas

1,121
174
525
406
136
21

2,383

584
114

2,998
— 258
397
540
5
— 67
1,472
— — 3,382
10,697
—
4
8
— —

540

334

18,954

— 59
— 10

1,135
308

1,061
156
568
470
127
81

2,463

638
65

2,396
— 179
393
545
3
— 60
1,316
— — 4,021
10,084
5
—
205
3
—

909
99
610
529
121
80

2,096
— 122
398
543
2
— 54
1,276
— — 4,463
9,907
—
215
—

5
3

545

250

18,415

2,348

543

186

18,355

— 62
11
55

1,179
308

716
74

— 71
10
66

1,300
270

reserves.

3,081

540

403

20,397

3,166

600

323

19,902

3,138

609

267

19,925

807
146
88
107
30
48

1,730
— 244
339
— 11
1,286
— 33
— —
299
— — 3,961
18
— —

813
185
110
109
29
65

4,313
— 349
470
— 19
1,499
— 38
— —
289
— — 3,647
100
— —

664
181
133
102
32
62

1,226

— 288

7,633

1,311

— 406

10,318

1,174

889
45

2,160

5,241

— 44
5
—

869
558

— 337

9,060

540

740

29,457

866
2

2,179

5,345

— 39
5
72

755
601

672

450

773

11,674

31,576

914
9

2,097

5,235

— 221
— 15
— 42
— —
—
1
— —

— 279

3,084
397
1,630
310
3,652
86

9,159

— 48
11
93

883
769

702

338

605

10,811

30,736

Reserves Governance The company has adopted a comprehensive reserves and resource classification system modeled after
a system developed and approved by a number of organizations including the Society of Petroleum Engineers, the World
Petroleum Congress and the American Association of Petroleum Geologists. The company classifies recoverable
hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three
potentially recoverable. Within the commercial classification are proved reserves and two categories of unproved reserves:
probable and possible. The potentially recoverable categories are also referred to as contingent resources. For reserves
estimates to be classified as proved, they must meet all SEC and company standards.

Proved oil and gas reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable
certainty to be economically producible in the future from known reservoirs under existing economic conditions, operating
methods and government regulations. Net proved reserves exclude royalties and interests owned by others and reflect
contractual arrangements and royalty obligations in effect at the time of the estimate.

Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to
be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are the
quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion.

Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as
additional information becomes available.

Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal
control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired
by the Manager of Global Reserves, an organization that is separate from the Upstream operating organization. The Manager

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of Global Reserves has more than 30 years’ experience working in the oil and gas industry and holds both undergraduate and

graduate degrees in geoscience. His experience includes various technical and management roles in providing reserve and

resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas

reserves processes. He has been named a Distinguished Lecturer by the American Association of Petroleum Geologists and is

an active member of 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 Chevron Corporation

Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon

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

senior leadership team including 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

Chevron Corporation Reserves Manual.

Technologies Used in Establishing Proved Reserves Additions In 2019, 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 2019, proved undeveloped reserves totaled 4.0 billion barrels of oil-equivalent

(BOE), a decrease of 641 million BOE from year-end 2018. The decrease was due to 685 million BOE in revisions, the

transfer of 593 million BOE to proved developed and 31 million BOE in sales, partially offset by 635 million BOE in

extensions and discoveries, 26 million BOE in acquisitions and 7 million BOE in improved recovery. A major portion of the

reserves revisions are attributed to the company’s decision to reduce planned developments and evaluate strategic

alternatives, including divestment scenarios for its acreage in the Appalachian region.

During 2019, investments totaling approximately $10.5 billion in oil and gas producing activities and about $0.1 billion in

non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. In Asia,

expenditures during the year totaled approximately $5.3 billion, primarily related to development projects of the TCO

affiliate in Kazakhstan. The United States accounted for about $3.3 billion related primarily to various development activities

in the Gulf of Mexico and the Midland and Delaware basins. In Africa, about $0.5 billion was expended on various offshore

development and natural gas projects in Nigeria, Angola and Republic of Congo. Development activities in Canada, Brazil

and Argentina were primarily responsible for about $1.0 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 2019, the company held approximately 2.1 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 700 million BOE have remained undeveloped for five

years or more related to the Gorgon and Wheatstone projects. Further field development to convert the remaining proved

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Table V Reserve Quantity Information

Summary of Net Oil and Gas Reserves

2019

2018

2017

Crude Oil

Synthetic

Condensate

Oil NGL

Natural

Gas

Crude Oil

Synthetic

Condensate

Oil NGL

Natural

Gas

Crude Oil

Synthetic

Condensate

Oil NGL

Natural

Gas

Liquids in Millions of Barrels

Natural Gas in Billions of

Cubic Feet

Proved Developed

Consolidated Companies

Other Americas

U.S.

Africa

Asia

Europe

TCO

Other

U.S.

Africa

Asia

Europe

TCO

Other

Australia/Oceania

Total Consolidated

Affiliated Companies

Total Consolidated and

Affiliated Companies

Proved Undeveloped

Consolidated Companies

Other Americas

Australia/Oceania

Total Consolidated

Affiliated Companies

Total Consolidated and

Affiliated Companies

Total Proved Reserves

1,121

174

525

406

136

— 258

540

— 67

2,998

397

1,472

— — 3,382

—

10,697

— —

1,061

— 179

545

— 60

—

2,396

393

1,316

10,084

205

— 122

543

— 54

—

2,096

398

1,276

9,907

215

— — 4,021

— — 4,463

2,383

540

334

18,954

2,463

545

250

18,415

2,348

543

186

18,355

584

114

— 59

— 10

1,135

308

— 62

1,179

308

— 71

1,300

270

3,081

540

403

20,397

3,166

600

323

19,902

3,138

609

267

19,925

807

146

107

889

— 244

— 11

— 33

— —

1,730

339

1,286

299

— — 3,961

— —

— 349

— 19

— 38

— —

4,313

470

1,499

289

— — 3,647

— —

100

— 44

—

869

558

— 39

755

601

1,226

— 288

7,633

1,311

— 406

10,318

1,174

— 221

— 15

— 42

— —

—

— —

— 279

3,084

397

1,630

310

3,652

9,159

— 48

883

769

2,160

5,241

— 337

9,060

540

740

29,457

2,179

5,345

672

450

773

11,674

31,576

2,097

5,235

702

338

605

10,811

30,736

909

610

529

121

716

664

181

133

102

914

156

568

470

127

638

813

185

110

109

866

Reserves Governance The company has adopted a comprehensive reserves and resource classification system modeled after

a system developed and approved by a number of organizations including the Society of Petroleum Engineers, the World

Petroleum Congress and the American Association of Petroleum Geologists. The company classifies recoverable

hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three

potentially recoverable. Within the commercial classification are proved reserves and two categories of unproved reserves:

probable and possible. The potentially recoverable categories are also referred to as contingent resources. For reserves

estimates to be classified as proved, they must meet all SEC and company standards.

Proved oil and gas reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable

certainty to be economically producible in the future from known reservoirs under existing economic conditions, operating

methods and government regulations. Net proved reserves exclude royalties and interests owned by others and reflect

contractual arrangements and royalty obligations in effect at the time of the estimate.

Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to

be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are the

quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major

expenditure is required for recompletion.

additional information becomes available.

Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as

Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal

control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired

by the Manager of Global Reserves, an organization that is separate from the Upstream operating organization. The Manager

of Global Reserves has more than 30 years’ experience working in the oil and gas industry and holds both undergraduate and
graduate degrees in geoscience. His experience includes various technical and management roles in providing reserve and
resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas
reserves processes. He has been named a Distinguished Lecturer by the American Association of Petroleum Geologists and is
an active member of 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 Chevron Corporation
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
senior leadership team including 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
Chevron Corporation Reserves Manual.
Technologies Used in Establishing Proved Reserves Additions In 2019, 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 2019, proved undeveloped reserves totaled 4.0 billion barrels of oil-equivalent
(BOE), a decrease of 641 million BOE from year-end 2018. The decrease was due to 685 million BOE in revisions, the
transfer of 593 million BOE to proved developed and 31 million BOE in sales, partially offset by 635 million BOE in
extensions and discoveries, 26 million BOE in acquisitions and 7 million BOE in improved recovery. A major portion of the
reserves revisions are attributed to the company’s decision to reduce planned developments and evaluate strategic
alternatives, including divestment scenarios for its acreage in the Appalachian region.
During 2019, investments totaling approximately $10.5 billion in oil and gas producing activities and about $0.1 billion in
non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. In Asia,
expenditures during the year totaled approximately $5.3 billion, primarily related to development projects of the TCO
affiliate in Kazakhstan. The United States accounted for about $3.3 billion related primarily to various development activities
in the Gulf of Mexico and the Midland and Delaware basins. In Africa, about $0.5 billion was expended on various offshore
development and natural gas projects in Nigeria, Angola and Republic of Congo. Development activities in Canada, Brazil
and Argentina were primarily responsible for about $1.0 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 2019, the company held approximately 2.1 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 700 million BOE have remained undeveloped for five
years or more related to the Gorgon and Wheatstone projects. Further field development to convert the remaining proved

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undeveloped reserves is scheduled to occur in line with operating constraints and infrastructure optimization. In Africa,
approximately 300 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 1.2 billion
BOE of proved undeveloped reserves with about 900 million 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 and facility constraints.

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 2019, decreases
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 quantities have been updated for
these circumstances and significant changes have been discussed in the appropriate reserves sections. Over the past three
years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 35 percent and 38 percent.

Proved Reserve Quantities For the three years ending December 31, 2019, 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, 2019, proved reserves for the company were 11.4 billion BOE. The company’s estimated net proved
reserves of liquids including crude oil, condensate and synthetic oil for the years 2017, 2018 and 2019 are shown in the table
on page 99. The company’s estimated net proved reserves of natural gas liquids are shown on page 100 and the company’s
estimated net proved reserves of natural gas are shown on page 101.

Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2017 through 2019 are discussed below
and shown in the table on the following page:

Revisions In 2017, improved field performance at various Gulf of Mexico fields, including Jack/St Malo and Tahiti, and in
the Midland and Delaware basins were primarily responsible for the 209 million barrel increase in the United States.
Improved field performance at various fields, including Agbami and Sonam in Nigeria, were responsible for the 73 million
barrel increase in Africa. Synthetic oil reserves in Canada decreased by 42 million barrels, primarily due to entitlement
effects. In the TCO affiliate in Kazakhstan, entitlement effects were mainly responsible for the 52 million barrel decrease.

In 2018, improved field performance at various Gulf of Mexico fields and in the Midland and Delaware basins were
primarily responsible for the 121 million barrel increase in the United States. Improved field performance at various fields,
including Agbami in Nigeria and Moho-Bilondo in the Republic of Congo, were responsible for the 61 million barrel
increase in Africa. Reserves in Other Americas increased by 59 million barrels, primarily due to improved field performance
at the Hebron field in Canada. In Asia, improved performance across numerous assets resulted in the 37 million barrel
increase.

In 2019, portfolio optimizations, where future drilling in various fields in the Midland and Delaware basins is being targeted
away from reservoirs with higher gas-to-oil ratios and lower execution efficiencies, and planned divestments in the
Appalachian basin, were primarily responsible for the 153 million barrel decrease in the United States. Operational issues
with the Petropiar upgrader in Venezuela resulted in a decrease in reserves of synthetic oil of 126 million barrels and an
increase of crude oil and condensate reserves of 105 million barrels. Reservoir management and entitlement effects were
mainly responsible for 75 million barrels increase in the TCO affiliate in Kazakhstan. Improved field performance at various
fields, including Moho-Bilondo in the Republic of Congo, Mafumeria in Angola, and Sonam in Nigeria, were responsible for
the 42 million barrel increase in Africa.

Extensions and Discoveries In 2017, extensions and discoveries in the Midland and Delaware basins and the Gulf of
Mexico were primarily responsible for the 323 million barrel increase in the United States. Extensions and discoveries in the
Duvernay Shale in Canada were primarily responsible for the 63 million barrel increase in Other Americas.

In 2018, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 359 million barrel
increase in the United States. Extensions and discoveries in the Duvernay Shale in Canada and Loma Campana in Argentina
were primarily responsible for the 31 million barrel increase in Other Americas.

In 2019, portfolio optimizations, where future drilling in various fields in the Midland and Delaware basins is being targeted

towards liquids-rich reservoirs with higher execution efficiencies, and extensions and discoveries in the deepwater fields in the

Gulf of Mexico, were primarily responsible for the 394 million barrel increase in the United States. Extensions and discoveries

in Loma Campana in Argentina were primarily responsible for the 39 million barrel increase in Other Americas.

Purchases In 2017, purchases of 33 million barrels in Asia were due to contract extension in the Azeri-Chirag-Gunashli

In 2018, purchases of 31 million barrels in the United States were primarily in the Midland and Delaware basins.

Sales In 2017, sales of 51 million barrels in the United States were primarily in the Gulf of Mexico shelf and in the Midland

fields in Azerbaijan.

and Delaware basins.

In 2019, sales of 69 million barrels in Europe were in the United Kingdom and Denmark.

Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil

Millions of barrels

U.S.

Americas1 Africa Asia

Oceania Europe

Oil2 Total

TCO

Oil Other3

Other

Australia/

Synthetic

Reserves at January 1, 2017

1,244

219

782

720

152

135

604 3,856

1,781

170

Consolidated Companies

Affiliated Companies

Consolidated

Total

and Affiliated

Companies

Reserves at December 31, 20174

1,573

280

743

631

543 4,065

1,630

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Purchases

Sales

Production

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Purchases

Sales

Production

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Purchases

Sales

Production

209

323

(51)

(165)

121

359

(26)

(189)

(153)

394

—

(213)

—

(17)

4 —

(1) — (2)

(23)

(125) (104)

—

1 —

— —

(5) —

(29)

(122)

(90)

(25)

—

— —

(4) — —

(33)

(108)

(86)

(9)

153

(22)

142

—

(14)

156

(16)

166

—

(19)

146

—

(69)

(16)

(4)

—

(9)

(7)

—

(9)

—

(11)

159

(23)

—

(9)

127

—

(126)

105

(106)

(1)

(13)

(42)

—

284

— 390

—

— (54)

(19)

(467)

335

— 391

— (31)

(19)

(482)

(72)

— 438

— (73)

(19)

(491)

—

(52)

—

(99)

(28)

—

(98)

—

5,900

228

390

(54)

(586)

5,937

277

391

(31)

(598)

6,017

(18)

438

(73)

(611)

Reserves at December 31, 20184

1,874

341

678

579

545 4,319

1,504

Reserves at December 31, 20194

1,928

320

613

513

540 4,149

1,473

— 159

5,781

1 Ending reserve balances in North America were 230, 269 and 217 and in South America were 90, 72 and 63 in 2019, 2018 and 2017, respectively.

2 Reserves associated with Canada.

3 Ending reserve balances in Africa were 3, 3 and 5 and in South America were 156, 64 and 78 in 2019, 2018 and 2017, respectively.

Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to glossary of energy and financial terms for the definition of a PSC). PSC-related

reserve quantities are 11 percent, 14 percent and 16 percent for consolidated companies for 2019, 2018 and 2017, respectively.

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undeveloped reserves is scheduled to occur in line with operating constraints and infrastructure optimization. In Africa,

approximately 300 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 1.2 billion

BOE of proved undeveloped reserves with about 900 million 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 and facility constraints.

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 2019, decreases

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 quantities have been updated for

these circumstances and significant changes have been discussed in the appropriate reserves sections. Over the past three

years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 35 percent and 38 percent.

Proved Reserve Quantities For the three years ending December 31, 2019, 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, 2019, proved reserves for the company were 11.4 billion BOE. The company’s estimated net proved

reserves of liquids including crude oil, condensate and synthetic oil for the years 2017, 2018 and 2019 are shown in the table

on page 99. The company’s estimated net proved reserves of natural gas liquids are shown on page 100 and the company’s

estimated net proved reserves of natural gas are shown on page 101.

Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2017 through 2019 are discussed below

and shown in the table on the following page:

Revisions In 2017, improved field performance at various Gulf of Mexico fields, including Jack/St Malo and Tahiti, and in

the Midland and Delaware basins were primarily responsible for the 209 million barrel increase in the United States.

Improved field performance at various fields, including Agbami and Sonam in Nigeria, were responsible for the 73 million

barrel increase in Africa. Synthetic oil reserves in Canada decreased by 42 million barrels, primarily due to entitlement

effects. In the TCO affiliate in Kazakhstan, entitlement effects were mainly responsible for the 52 million barrel decrease.

In 2018, improved field performance at various Gulf of Mexico fields and in the Midland and Delaware basins were

primarily responsible for the 121 million barrel increase in the United States. Improved field performance at various fields,

including Agbami in Nigeria and Moho-Bilondo in the Republic of Congo, were responsible for the 61 million barrel

increase in Africa. Reserves in Other Americas increased by 59 million barrels, primarily due to improved field performance

at the Hebron field in Canada. In Asia, improved performance across numerous assets resulted in the 37 million barrel

increase.

In 2019, portfolio optimizations, where future drilling in various fields in the Midland and Delaware basins is being targeted

away from reservoirs with higher gas-to-oil ratios and lower execution efficiencies, and planned divestments in the

Appalachian basin, were primarily responsible for the 153 million barrel decrease in the United States. Operational issues

with the Petropiar upgrader in Venezuela resulted in a decrease in reserves of synthetic oil of 126 million barrels and an

increase of crude oil and condensate reserves of 105 million barrels. Reservoir management and entitlement effects were

mainly responsible for 75 million barrels increase in the TCO affiliate in Kazakhstan. Improved field performance at various

fields, including Moho-Bilondo in the Republic of Congo, Mafumeria in Angola, and Sonam in Nigeria, were responsible for

the 42 million barrel increase in Africa.

Extensions and Discoveries In 2017, extensions and discoveries in the Midland and Delaware basins and the Gulf of

Mexico were primarily responsible for the 323 million barrel increase in the United States. Extensions and discoveries in the

Duvernay Shale in Canada were primarily responsible for the 63 million barrel increase in Other Americas.

In 2018, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 359 million barrel

increase in the United States. Extensions and discoveries in the Duvernay Shale in Canada and Loma Campana in Argentina

were primarily responsible for the 31 million barrel increase in Other Americas.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

In 2019, portfolio optimizations, where future drilling in various fields in the Midland and Delaware basins is being targeted
towards liquids-rich reservoirs with higher execution efficiencies, and extensions and discoveries in the deepwater fields in the
Gulf of Mexico, were primarily responsible for the 394 million barrel increase in the United States. Extensions and discoveries
in Loma Campana in Argentina were primarily responsible for the 39 million barrel increase in Other Americas.

Purchases In 2017, purchases of 33 million barrels in Asia were due to contract extension in the Azeri-Chirag-Gunashli
fields in Azerbaijan.

In 2018, purchases of 31 million barrels in the United States were primarily in the Midland and Delaware basins.

Sales In 2017, sales of 51 million barrels in the United States were primarily in the Gulf of Mexico shelf and in the Midland
and Delaware basins.

In 2019, sales of 69 million barrels in Europe were in the United Kingdom and Denmark.

Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil

Millions of barrels

U.S.

Americas1 Africa Asia

Oceania Europe

Oil2 Total

TCO

Oil Other3

Other

Australia/

Consolidated Companies
Synthetic

Affiliated Companies

Synthetic

Total
Consolidated
and Affiliated
Companies

1,244

219

782

720

152

135

604 3,856

1,781

170

Reserves at January 1, 2017
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Reserves at December 31, 20174
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Reserves at December 31, 20184
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

209
9
323
4
(51)
(165)

(17)
73
22
1
7
—
4 —
63
—
33
2
(1) — (2)
(125) (104)
(23)

10
—
—
—
—
(9)

29
—
—
—
—
(22)

284
(42)
17
—
— 390
—
39
— (54)
(467)
(19)

(52)
—
—
—
—
(99)

1,573

280

743

631

153

142

543 4,065

1,630

121
5
359
31
(26)
(189)

59
—
31
—
—
(29)

37
61
—
1
1 —
— —
(5) —
(90)

(122)

17
—
—
—
—
(14)

19
4
—
—
—
(19)

335
21
—
10
— 391
31
—
— (31)
(482)
(19)

(28)
—
—
—
—
(98)

1,874

341

678

579

156

146

545 4,319

1,504

(153)
7
394
19
—
(213)

42
19
(25)
— —
—
1
1
39
2
— —
(4) — —
(86)
(108)

(33)

25
—
1
—
—
(16)

(72)
14
—
7
— 438
—
21
— (73)
(491)
(19)

75
—
—
—
—
(106)

6
—
2
—
(69)
(16)

(4)
3
—
—
—
(9)

(7)
—
—
—
—
(9)

105
—
—
—
—
(13)

5,900

228
20
390
39
(54)
(586)

5,937

277
10
391
31
(31)
(598)

6,017

(18)
7
438
21
(73)
(611)

—
—
—
—
—
(11)

159

(23)
—
—
—
—
(9)

127

(126)
—
—
—
—
(1)

Reserves at December 31, 20194

1,928

320

613

513

166

540 4,149

1,473

— 159

5,781

1 Ending reserve balances in North America were 230, 269 and 217 and in South America were 90, 72 and 63 in 2019, 2018 and 2017, respectively.
2 Reserves associated with Canada.
3 Ending reserve balances in Africa were 3, 3 and 5 and in South America were 156, 64 and 78 in 2019, 2018 and 2017, respectively.
4

Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to glossary of energy and financial terms for the definition of a PSC). PSC-related
reserve quantities are 11 percent, 14 percent and 16 percent for consolidated companies for 2019, 2018 and 2017, respectively.

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Noteworthy changes in natural gas liquids proved reserves for 2017 through 2019 are discussed and shown in the table
below:

Revisions In 2017, improved field performance in the Midland and Delaware basins and at various Gulf of Mexico fields
were primarily responsible for the 71 million barrel increase in the United States.

In 2018, improved field performance in the Midland and Delaware basins were primarily responsible for the 34 million barrel
increase in the United States.

In 2019, portfolio optimizations and low price realizations in various fields in the Midland and Delaware basins and planned
divestments in the Appalachian basin were mainly responsible for the 120 million barrel decrease in the United States.

Extensions and Discoveries In 2017, extensions and discoveries in the Midland and Delaware basins and the Appalachian
region were primarily responsible for the 135 million barrel increase in the United States.

In 2018, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 173 million barrel
increase in the United States.

In 2019, extensions and discoveries in the Midland and Delaware basins and deepwater fields in the Gulf of Mexico were
primarily responsible for the 140 million barrel increase in the United States.

Net Proved Reserves of Natural Gas Liquids

Millions of barrels

Reserves at January 1, 2017
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Reserves at December 31, 20173
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Reserves at December 31, 20183
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Reserves at December 31, 20193

Other

Australia/

U.S.

Americas1 Africa Asia

Oceania Europe Total

TCO Other2

Consolidated Companies

Affiliated
Companies

Total
Consolidated
and Affiliated
Companies

168

71
—
135
—
(6)
(25)

343

34
—
173
19
(6)
(35)

528

(120)
—
140
5
—
(51)

502

94 —

3
—
11
—
—
(1)

1
—
5
—
—
(1)

(4)
—
—
—
—
(2)

6 —
— —
— —
— —
— —
(4) —

96 —

7 —
— —
— —
— —
— —
(5) —

98 —

6 —
— —
— —
— —
— —
(4) —

100 —

1
—
—
—
—
(1)

—
—
—
—
—
(1)

275

128

82
1
—
—
— 146
—
—
(6)
—
(32)
(1)

(1)
—
—
—
—
(8)

465

119

43
1
—
—
— 178
19
—
(6)
—
(43)
(1)

(11)
—
—
—
—
(7)

656

101

— (118)
—
—
— 140
5
—
(2)
(2)
(59)
(1)

10
—
—
—
—
(8)

— 622

103

(1)
—
—
—
—
(3)

(3)
—
—
—
—
(2)

2
—
—
—
—
(3)

428

80
—
146
—
(6)
(43)

605

29
—
178
19
(6)
(52)

773

(106)
—
140
5
(2)
(70)

740

1 Reserves associated with North America.
2 Reserves associated with Africa.
3 Year-end reserve quantities related to production-sharing contracts (PSC) (refer to glossary of energy and financial terms for the definition of a PSC) are not material for 2019,

2018 and 2017, respectively.

28,760

2,781

1,682

(337)

(2,202)

30,736

1,561

1,774

145

(130)

(2,515)

31,576

(464)

1,176

—

(243)

(2,612)

29,457

Net Proved Reserves of Natural Gas

Billions of cubic feet (BCF)

U.S.

Americas1 Africa

Asia

Europe

Total

TCO Other2

3,676

647

2,827

5,533

12,515

234

25,432

2,242

1,086

Consolidated Companies

Affiliated

Companies

Total

Consolidated

and Affiliated

Companies

Australia/

Oceania

1,545

Reserves at December 31, 20174

795

2,906

4,773

13,559

301

27,514

2,183

1,039

(501)

(76)

(1,961)

(146)

(95)

347

1,012

(108)

(38)

Reserves at January 1, 2017

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Purchases

Sales

Production3

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Purchases

Sales

Production3

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Purchases

Sales

Production3

Other

—

319

—

(129)

(81)

(3)

138

—

(107)

—

(2)

(67)

184

—

(107)

—

(31)

(842)

—

(5)

—

670

1,361

(177)

(354)

5,180

258

1,627

144

(125)

(377)

6,709

(2,565)

—

1,008

(1)

(447)

4,728

Reserves at December 31, 20184

863

2,815

4,310

13,731

305

28,733

(69)

(112)

(815)

(841)

(65)

(2,279)

165

1,732

—

143

—

2,646

(337)

— 1,682

—

(240)

(43)

1,707

1,771

145

(130)

(726)

1,156

—

(243)

(2,357)

—

(141)

1,934

223

—

(95)

909

—

(103)

(799)

(898)

(153)

(102)

Reserves at December 31, 20194

736

2,758

3,681

14,658

26,587

2,004

866

1 Ending reserve balances in North America and South America were 462, 582, 478 and 274, 281, 317 in 2019, 2018 and 2017, respectively.

2 Ending reserve balances in Africa and South America were 802, 799, 899 and 64, 110, 140 in 2019, 2018 and 2017, respectively.

3 Total “as sold” volumes are 2,379, 2,289 and 1,995 for 2019, 2018 and 2017, respectively.

Includes reserve quantities related to production-sharing contracts (PSC) (refer to glossary of energy and financial terms for the definition of a PSC). PSC-related reserve

quantities are 10 percent, 10 percent and 12 percent for consolidated companies for 2019, 2018 and 2017, respectively.

Noteworthy changes in natural gas proved reserves for 2017 through 2019 are discussed below and shown in the table above:

Revisions In 2017, reservoir performance and new seismic data in the greater Gorgon area were primarily responsible for the

1.5 TCF increase in Australia. Improved performance in the Midland and Delaware basins were primarily responsible for the

670 BCF increase in the United States. The Sonam Field in Nigeria was primarily responsible for the 184 BCF increase in

Africa.

In 2018, reservoir performance, well test and surveillance data at Wheatstone and the greater Gorgon area were responsible

for the 1.0 TCF increase in Australia. The Bibiyana Field in Bangladesh and the Pattani Field in Thailand were primarily

responsible for the 347 BCF increase in Asia. Improved performance in the Midland and Delaware basins were primarily

responsible for the 258 BCF increase in the United States.

In 2019, strong performances at Wheatstone and the greater Gorgon areas were mainly responsible for 1.7 TCF increase in

Australia. In the TCO affiliate in Kazakhstan, reservoir management and entitlement effects were mainly responsible for 223

BCF increase. Portfolio optimizations and low price realizations in various fields of the Midland and Delaware basins and

planned divestments in the Appalachian basin, were mainly responsible for the 2.6 TCF decrease in the United States.

Extensions and Discoveries In 2017, extensions and discoveries of 1.4 TCF in the United States were primarily in the

Appalachian region and the Midland and Delaware basins. Extensions and discoveries in the Duvernay Shale in Canada were

primarily responsible for the 319 BCF increase in Other Americas.

In 2018, extensions and discoveries of 1.6 TCF in the United States were primarily in the Appalachian region and the

Midland and Delaware basins.

In 2019, extensions and discoveries of 1.0 TCF in the United States were primarily in the Midland and Delaware basins.

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Noteworthy changes in natural gas liquids proved reserves for 2017 through 2019 are discussed and shown in the table

Net Proved Reserves of Natural Gas

below:

Revisions In 2017, improved field performance in the Midland and Delaware basins and at various Gulf of Mexico fields

were primarily responsible for the 71 million barrel increase in the United States.

Billions of cubic feet (BCF)

U.S.

Americas1 Africa

Asia

Other

Consolidated Companies

Affiliated
Companies

Australia/
Oceania

Europe

Total

TCO Other2

Total
Consolidated
and Affiliated
Companies

In 2018, improved field performance in the Midland and Delaware basins were primarily responsible for the 34 million barrel

increase in the United States.

In 2019, portfolio optimizations and low price realizations in various fields in the Midland and Delaware basins and planned

divestments in the Appalachian basin were mainly responsible for the 120 million barrel decrease in the United States.

Extensions and Discoveries In 2017, extensions and discoveries in the Midland and Delaware basins and the Appalachian

region were primarily responsible for the 135 million barrel increase in the United States.

In 2018, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 173 million barrel

increase in the United States.

In 2019, extensions and discoveries in the Midland and Delaware basins and deepwater fields in the Gulf of Mexico were

primarily responsible for the 140 million barrel increase in the United States.

Net Proved Reserves of Natural Gas Liquids

Other

Australia/

U.S.

Americas1 Africa Asia

Oceania Europe Total

TCO Other2

Consolidated Companies

Affiliated

Companies

Total

Consolidated

and Affiliated

Companies

168

—

135

—

(6)

(25)

343

—

173

(6)

(35)

528

(120)

—

140

—

(51)

502

(1)

—

(1)

(4)

—

(2)

94 —

6 —

— —

(4) —

96 —

7 —

— —

(5) —

98 —

6 —

— —

(4) —

100 —

—

(1)

—

(1)

—

(1)

275

128

465

119

— 146

—

(1)

—

(1)

—

(6)

(32)

—

(6)

(43)

— 178

— (118)

—

— 140

—

(2)

(1)

(2)

(59)

— 622

(1)

—

(8)

(11)

—

(7)

—

(8)

103

656

101

(1)

—

(3)

—

(2)

—

(3)

428

—

146

—

(6)

(43)

605

—

178

(6)

(52)

773

(106)

—

140

(2)

(70)

740

Millions of barrels

Reserves at January 1, 2017

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Purchases

Sales

Production

Reserves at December 31, 20173

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Purchases

Sales

Production

Purchases

Sales

Production

Reserves at December 31, 20183

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Reserves at December 31, 20193

1 Reserves associated with North America.

2 Reserves associated with Africa.

2018 and 2017, respectively.

3 Year-end reserve quantities related to production-sharing contracts (PSC) (refer to glossary of energy and financial terms for the definition of a PSC) are not material for 2019,

Reserves at January 1, 2017
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production3

Reserves at December 31, 20174
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production3

Reserves at December 31, 20184
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production3

Reserves at December 31, 20194

3,676

647

2,827

5,533

12,515

234

25,432

2,242

1,086

670
3
1,361
1
(177)
(354)

5,180

258
2
1,627
144
(125)
(377)

6,709

(2,565)
—
1,008
24
(1)
(447)

4,728

39
—
319
—
(129)
(81)

184
—
—
2
—
(107)

65
—
2
46
(31)
(842)

1,545
—
—
—
—
(501)

2,646
143
—
3
— 1,682
49
—
—
(337)
(1,961)
(76)

87
—
—
—
—
(146)

48
—
—
—
—
(95)

795

2,906

4,773

13,559

301

27,514

2,183

1,039

(3)
2
138
—
—
(69)

25
—
—
1
(5)
(112)

347
—
5
—
—
(815)

1,012
1
—
—
—
(841)

68
—
1
—
—
(65)

1,707
5
1,771
145
(130)
(2,279)

(108)
—
—
—
—
(141)

(38)
—
3
—
—
(95)

863

2,815

4,310

13,731

305

28,733

1,934

909

(107)
—
49
—
(2)
(67)

46
—
—
—
—
(103)

165
—
5
—
—
(799)

1,732
—
93
—
—
(898)

3
—
1
—
(240)
(43)

(726)
—
1,156
24
(243)
(2,357)

223
—
—
—
—
(153)

736

2,758

3,681

14,658

26,587

2,004

39
—
20
—
—
(102)

866

28,760

2,781
3
1,682
49
(337)
(2,202)

30,736

1,561
5
1,774
145
(130)
(2,515)

31,576

(464)
—
1,176
24
(243)
(2,612)

29,457

1 Ending reserve balances in North America and South America were 462, 582, 478 and 274, 281, 317 in 2019, 2018 and 2017, respectively.
2 Ending reserve balances in Africa and South America were 802, 799, 899 and 64, 110, 140 in 2019, 2018 and 2017, respectively.
3 Total “as sold” volumes are 2,379, 2,289 and 1,995 for 2019, 2018 and 2017, respectively.
4

Includes reserve quantities related to production-sharing contracts (PSC) (refer to glossary of energy and financial terms for the definition of a PSC). PSC-related reserve
quantities are 10 percent, 10 percent and 12 percent for consolidated companies for 2019, 2018 and 2017, respectively.

Noteworthy changes in natural gas proved reserves for 2017 through 2019 are discussed below and shown in the table above:

Revisions In 2017, reservoir performance and new seismic data in the greater Gorgon area were primarily responsible for the
1.5 TCF increase in Australia. Improved performance in the Midland and Delaware basins were primarily responsible for the
670 BCF increase in the United States. The Sonam Field in Nigeria was primarily responsible for the 184 BCF increase in
Africa.

In 2018, reservoir performance, well test and surveillance data at Wheatstone and the greater Gorgon area were responsible
for the 1.0 TCF increase in Australia. The Bibiyana Field in Bangladesh and the Pattani Field in Thailand were primarily
responsible for the 347 BCF increase in Asia. Improved performance in the Midland and Delaware basins were primarily
responsible for the 258 BCF increase in the United States.

In 2019, strong performances at Wheatstone and the greater Gorgon areas were mainly responsible for 1.7 TCF increase in
Australia. In the TCO affiliate in Kazakhstan, reservoir management and entitlement effects were mainly responsible for 223
BCF increase. Portfolio optimizations and low price realizations in various fields of the Midland and Delaware basins and
planned divestments in the Appalachian basin, were mainly responsible for the 2.6 TCF decrease in the United States.

Extensions and Discoveries In 2017, extensions and discoveries of 1.4 TCF in the United States were primarily in the
Appalachian region and the Midland and Delaware basins. Extensions and discoveries in the Duvernay Shale in Canada were
primarily responsible for the 319 BCF increase in Other Americas.

In 2018, extensions and discoveries of 1.6 TCF in the United States were primarily in the Appalachian region and the
Midland and Delaware basins.

In 2019, extensions and discoveries of 1.0 TCF in the United States were primarily in the Midland and Delaware basins.

100

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Sales In 2017, sales of 177 BCF in the United States were primarily from the Midland and Delaware basins. Sale of the
company’s interests in Trinidad and Tobago was primarily responsible for the 129 BCF decrease in Other Americas.

In 2019, sales of 240 BCF in Europe were in the United Kingdom and Denmark.

Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows is calculated in accordance with SEC and FASB requirements.
This includes using the average of first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the
reporting period, estimated future development and production costs assuming the continuation of existing economic
conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to
those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based
on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount
factors. Estimates of proved-reserve quantities are imprecise and change over time as new information becomes available.
Probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation
requires assumptions as to the timing and amount of future development and production costs. The calculations are made as
of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil
and gas reserves. In the following table, the caption “Standardized Measure Net Cash Flows” refers to the standardized
measure of discounted future net cash flows.

Millions of dollars

At December 31, 2019
Future cash inflows from production
Future production costs
Future development costs
Future income taxes

Undiscounted future net cash flows
10 percent midyear annual discount for

Other
Americas

U.S.

Consolidated Companies

Australia/

Affiliated
Companies

Africa

Asia

Oceania Europe

Total

TCO

Other

Total
Consolidated
and Affiliated
Companies

$ 122,012 $ 45,701 $ 45,706 $ 43,386 $ 95,845 $ 4,466 $ 357,116 $
(14,646)
(5,070)
(11,147)

(18,324)
(4,219)
(6,491)

(32,349)
(15,987)
(15,780)

(98,870)
(34,718)
(74,932)

(14,141)
(5,458)
(22,874)

(17,982)
(3,643)
(17,562)

(1,428)
(341)
(1,078)

85,179 $ 12,309 $
(22,302)
(14,340)
(14,561)

(2,487)
(705)
(3,855)

454,604
(123,659)
(49,763)
(93,348)

57,896

16,667

6,519

12,523

53,372

1,619

148,596

33,976

5,262

187,834

Present Value at December 31, 2018

Sales and transfers of oil and gas produced net of production costs

timing of estimated cash flows

(26,422)

(9,312)

(1,629)

(3,652)

(26,536)

(650)

(68,201)

(16,990)

(2,096)

(87,287)

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.”

Consolidated Companies

Affiliated Companies

Total Consolidated and

Affiliated Companies

Sales and transfers of oil and gas produced net of production costs

Millions of dollars

Present Value at January 1, 2017

Development costs incurred

Purchases of reserves

Sales of reserves

Extensions, discoveries and improved recovery less related costs

Revisions of previous quantity estimates

Net changes in prices, development and production costs

Present Value at December 31, 2017

Sales and transfers of oil and gas produced net of production costs

Extensions, discoveries and improved recovery less related costs

Revisions of previous quantity estimates

Net changes in prices, development and production costs

Accretion of discount

Net change in income tax

Net Change for 2017

Development costs incurred

Purchases of reserves

Sales of reserves

Accretion of discount

Net change in income tax

Net Change for 2018

Development costs incurred

Purchases of reserves

Sales of reserves

Extensions, discoveries and improved recovery less related costs

Revisions of previous quantity estimates

Net changes in prices, development and production costs

Accretion of discount

Net change in income tax

Net Change for 2019

Present Value at December 31, 2019

$ 42,355

(21,505)

9,417

105

(1,148)

3,716

11,132

28,754

6,116

(13,095)

23,492

$ 65,847

(33,535)

9,723

(622)

5,503

15,480

39,241

9,413

(16,518)

28,784

$ 94,631

(29,436)

10,497

406

(579)

5,697

621

(25,056)

13,538

10,077

(14,235)

$ 80,396

$ 9,714

(5,234)

3,721

—

(1,085)

8,013

1,398

(2,361)

4,452

$ 14,166

(6,813)

5,044

—

(2,255)

17,251

2,084

(4,795)

10,530

$ 24,696

(5,823)

5,120

—

2,122

(11,637)

3,584

2,046

(4,545)

$ 20,151

$ 52,069

(26,739)

13,138

105

(1,148)

3,716

10,047

36,767

7,514

(15,456)

27,944

$ 80,013

(40,348)

14,767

(622)

5,517

13,225

56,492

11,497

(21,313)

39,314

$119,327

(35,259)

15,617

406

(579)

5,740

2,743

(36,693)

17,122

12,123

(18,780)

$100,547

$ 132,512 $ 52,470 $ 56,856 $ 54,012 $ 109,116 $ 11,959 $ 416,925
(6,609) (114,484)
(41,184)
(1,393)
(90,224)
(1,676)

(20,691)
(5,106)
(7,553)

$ 100,518 $ 16,928 $

(24,580)
(14,069)
(18,561)

(4,665)
(1,692)
(4,496)

534,371
(143,729)
(56,945)
(113,281)

31,474 $

7,355 $

4,890 $

8,871 $ 26,836 $

969 $ 80,395 $

16,986 $ 3,166 $

100,547

(34,679)
(17,322)
(17,369)

(18,850)
(4,112)
(23,593)

(17,359)
(5,494)
(14,514)

(16,296)
(7,757)
(25,519)

63,142

19,120

10,301

16,645

59,544

2,281

171,033

43,308

6,075

220,416

(29,103)

(11,136)

(2,646)

(4,822)

(28,276)

(419)

(76,402)

(22,025)

(2,662)

(101,089)

34,039 $

7,984 $

7,655 $ 11,823 $ 31,268 $ 1,862 $ 94,631 $

21,283 $ 3,413 $

119,327

Standardized Measure

Net Cash Flows

At December 31, 2018
Future cash inflows from production
Future production costs
Future development costs
Future income taxes

Undiscounted future net cash flows
10 percent midyear annual discount
for timing of estimated cash flows

Standardized Measure

Net Cash Flows

At December 31, 2017
Future cash inflows from production
Future production costs
Future development costs
Future income taxes

Undiscounted future net cash flows
10 percent midyear annual discount
for timing of estimated cash flows

94,086 $ 43,175 $ 47,828 $ 47,809 $ 77,557 $ 8,800 $ 319,255
(6,345) (104,517)
(18,640)
(29,049)
(32,310)
(1,114)
(10,849)
(4,755)
(62,890)
(615)
(10,901)
(10,803)

(20,044)
(5,102)
(5,158)

(18,124)
(3,808)
(17,845)

(12,315)
(6,682)
(17,568)

80,090 $ 13,632 $
(22,050)
(17,564)
(12,143)

(4,635)
(1,760)
(3,250)

412,977
(131,202)
(51,634)
(78,283)

43,385

12,871

8,051

13,513

40,992

726

119,538

28,333

3,987

151,858

(19,781)

(8,483)

(2,058)

(3,846)

(19,730)

207

(53,691)

(16,310)

(1,844)

(71,845)

Standardized Measure

Net Cash Flows

23,604 $

4,388 $

5,993 $

9,667 $ 21,262 $

933 $ 65,847 $

12,023 $ 2,143 $

80,013

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Sales In 2017, sales of 177 BCF in the United States were primarily from the Midland and Delaware basins. Sale of the

company’s interests in Trinidad and Tobago was primarily responsible for the 129 BCF decrease in Other Americas.

In 2019, sales of 240 BCF in Europe were in the United Kingdom and Denmark.

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.

Other

Australia/

U.S.

Americas

Africa

Asia

Oceania Europe

Total

TCO

Other

Consolidated Companies

Affiliated

Companies

Total

Consolidated

and Affiliated

Companies

Future cash inflows from production

$ 122,012 $ 45,701 $ 45,706 $ 43,386 $ 95,845 $ 4,466 $ 357,116 $

85,179 $ 12,309 $

(32,349)

(15,987)

(15,780)

(18,324)

(17,982)

(14,646)

(14,141)

(1,428)

(4,219)

(6,491)

(3,643)

(5,070)

(5,458)

(341)

(17,562)

(11,147)

(22,874)

(1,078)

(98,870)

(34,718)

(74,932)

(22,302)

(14,340)

(14,561)

(2,487)

(705)

(3,855)

Undiscounted future net cash flows

57,896

16,667

6,519

12,523

53,372

1,619

148,596

33,976

5,262

187,834

10 percent midyear annual discount for

timing of estimated cash flows

(26,422)

(9,312)

(1,629)

(3,652)

(26,536)

(650)

(68,201)

(16,990)

(2,096)

(87,287)

31,474 $

7,355 $

4,890 $

8,871 $ 26,836 $

969 $ 80,395 $

16,986 $ 3,166 $

100,547

Future cash inflows from production

$ 132,512 $ 52,470 $ 56,856 $ 54,012 $ 109,116 $ 11,959 $ 416,925

$ 100,518 $ 16,928 $

(34,679)

(17,322)

(17,369)

(20,691)

(18,850)

(17,359)

(16,296)

(6,609) (114,484)

(5,106)

(7,553)

(4,112)

(5,494)

(7,757)

(23,593)

(14,514)

(25,519)

(1,393)

(1,676)

(41,184)

(90,224)

(24,580)

(14,069)

(18,561)

(4,665)

(1,692)

(4,496)

Undiscounted future net cash flows

63,142

19,120

10,301

16,645

59,544

2,281

171,033

43,308

6,075

220,416

10 percent midyear annual discount

for timing of estimated cash flows

(29,103)

(11,136)

(2,646)

(4,822)

(28,276)

(419)

(76,402)

(22,025)

(2,662)

(101,089)

34,039 $

7,984 $

7,655 $ 11,823 $ 31,268 $ 1,862 $ 94,631 $

21,283 $ 3,413 $

119,327

Future cash inflows from production

94,086 $ 43,175 $ 47,828 $ 47,809 $ 77,557 $ 8,800 $ 319,255

80,090 $ 13,632 $

(29,049)

(10,849)

(10,803)

(20,044)

(18,124)

(18,640)

(12,315)

(6,345) (104,517)

(5,102)

(5,158)

(3,808)

(4,755)

(6,682)

(1,114)

(17,845)

(10,901)

(17,568)

(615)

(32,310)

(62,890)

(22,050)

(17,564)

(12,143)

(4,635)

(1,760)

(3,250)

Undiscounted future net cash flows

43,385

12,871

8,051

13,513

40,992

726

119,538

28,333

3,987

151,858

for timing of estimated cash flows

(19,781)

(8,483)

(2,058)

(3,846)

(19,730)

207

(53,691)

(16,310)

(1,844)

(71,845)

10 percent midyear annual discount

Standardized Measure

Net Cash Flows

23,604 $

4,388 $

5,993 $

9,667 $ 21,262 $

933 $ 65,847 $

12,023 $ 2,143 $

80,013

Millions of dollars

At December 31, 2019

Future production costs

Future development costs

Future income taxes

Standardized Measure

Net Cash Flows

At December 31, 2018

Future production costs

Future development costs

Future income taxes

Standardized Measure

Net Cash Flows

At December 31, 2017

Future production costs

Future development costs

Future income taxes

454,604

(123,659)

(49,763)

(93,348)

534,371

(143,729)

(56,945)

(113,281)

412,977

(131,202)

(51,634)

(78,283)

Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

The changes in present values between years, which can be significant, reflect changes in estimated proved-reserve quantities
and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are
included with “Revisions of previous quantity estimates.”

Millions of dollars

Consolidated Companies

Affiliated Companies

Total Consolidated and
Affiliated Companies

Present Value at January 1, 2017
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax

Net Change for 2017

Present Value at December 31, 2017
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax

Net Change for 2018

Present Value at December 31, 2018
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax

Net Change for 2019

Present Value at December 31, 2019

$ 42,355
(21,505)
9,417
105
(1,148)
3,716
11,132
28,754
6,116
(13,095)

23,492

$ 65,847
(33,535)
9,723
99
(622)
5,503
15,480
39,241
9,413
(16,518)

28,784

$ 94,631
(29,436)
10,497
406
(579)
5,697
621
(25,056)
13,538
10,077

(14,235)

$ 80,396

$ 9,714
(5,234)
3,721
—
—
—
(1,085)
8,013
1,398
(2,361)

4,452

$ 14,166
(6,813)
5,044
—
—
14
(2,255)
17,251
2,084
(4,795)

10,530

$ 24,696
(5,823)
5,120
—
—
43
2,122
(11,637)
3,584
2,046

(4,545)

$ 20,151

$ 52,069
(26,739)
13,138
105
(1,148)
3,716
10,047
36,767
7,514
(15,456)

27,944

$ 80,013
(40,348)
14,767
99
(622)
5,517
13,225
56,492
11,497
(21,313)

39,314

$119,327
(35,259)
15,617
406
(579)
5,740
2,743
(36,693)
17,122
12,123

(18,780)

$100,547

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our history
We are proud of chevron’s 140-year history and are committed to upholding our legacy by
providing the affordable, reliable, ever-cleaner energy that enables human progress.

1999
Acquired Rutherford-Moran Oil
Corporation. This acquisition provided
inroads to Asian natural gas markets.

2001
Merged with Texaco Inc. and changed
name to ChevronTexaco Corporation.
Became the second-largest U.S.-based
energy company.

2002
Relocated corporate headquarters from
San Francisco, California, to San Ramon,
California.

2005
Acquired Unocal Corporation, an
independent crude oil and natural gas
exploration and production company.
Unocal’s upstream assets bolstered
Chevron’s already-strong position in
the Asia-Pacific, U.S. Gulf of Mexico
and Caspian regions. Changed name to
Chevron Corporation to convey a clearer,
stronger and more unified presence
in the global marketplace.

1879
Incorporated in San Francisco, California,
as the Pacific Coast Oil Company.

1900

Acquired by the West Coast operations
of John D. Rockefeller’s original Standard
Oil Company.

1961
Acquired Standard Oil Company
(Kentucky), a major petroleum products
marketer in five southeastern states,
to provide outlets for crude oil from
southern Louisiana and the U.S. Gulf
of Mexico, where the company was a
major producer.

1984
Acquired Gulf Corporation — nearly
doubling the company’s crude oil and
natural gas activities — and gained a
significant presence in industrial
chemicals, natural gas liquids and coal.
Changed name to Chevron Corporation
to identify with the name under which
most products were marketed.

1988
Purchased Tenneco Inc.’s U.S. Gulf of
Mexico crude oil and natural gas
properties, becoming one of the
largest U.S. natural gas producers.

1993
Formed Tengizchevroil, a joint venture
with the Republic of Kazakhstan, to
develop and produce the giant Tengiz
Field, becoming the first major Western
oil company to enter newly independent
Kazakhstan.

1911
Emerged as an autonomous entity —
Standard Oil Company (California) —
following U.S. Supreme Court decision
to divide the Standard Oil conglomerate
into 34 independent companies.

1926
Acquired Pacific Oil Company to
become Standard Oil Company of
California (Socal).

1936
Formed the Caltex Group of Companies,
jointly owned by Socal and The Texas
Company (later became Texaco), to
combine Socal’s exploration and
production interests in the Middle East
and Indonesia and provide an outlet for
crude oil through The Texas Company’s
marketing network in Africa and Asia.

1947
Acquired Signal Oil Company,
obtaining the Signal brand name
and adding 2,000 retail stations
in the western United States.

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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 spending 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 may also 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, coalbeds and other nonrenewable
natural resources that are intended to be upgraded
into synthetic oil or gas. Net proved reserves are
the estimated quantities that geoscience and
engineering data demonstrate with reasonable
certainty to be economically producible in the
future from known reservoirs under existing
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, 2019.

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 commerciality.
Unrisked resources, unrisked resource base
and similar terms represent the arithmetic sum
of the amounts recorded under each of these
classifications. Recoverable resources, potentially
recoverable volumes and 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,

Chevron Corporation 2019 Annual Report
105

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 and
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 finance 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.

Free cash flow The cash provided by operating
activities less cash capital expenditures.

Margin The difference between the cost of
purchasing, producing and/or marketing a product
and its sales price.

Net debt ratio Total debt less the sum of cash and
cash equivalents, time deposits and marketable
securities as a percentage of total debt less the sum
of cash and cash equivalents, time deposits and
marketable securities plus Chevron Corporation’s
total stockholder’s equity.

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 (ROSE) 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.

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stockholder and investor information

Stock exchange listing
Chevron common stock is listed on the
New York Stock Exchange. The symbol
is “CVX.”

Stockholder information
As of February 10, 2020, stockholders
of record numbered approximately
118,000.

For questions about stock ownership,
changes of address and dividend
reinvestment programs, please contact
Chevron’s Stock Transfer Agent:

Computershare
P.O. Box 505000
Louisville, KY 40233-5000
800 368 8357 (U.S. and Canada)
201 680 6578 (outside the U.S.
and Canada)
www.computershare.com/investor

Overnight correspondence should
be sent to:

Computershare
462 South 4th 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 a.m. PDT, Wednesday,
May 27, 2020, at:

Chevron Corporation
6001 Bollinger Canyon Road
San Ramon, CA 94583

unless we disclose by news release that
the meeting will instead be conducted
online or by phone.

Investor information
Securities analysts, portfolio managers
and representatives of financial
institutions may contact:
Investor Relations
Chevron Corporation
6001 Bollinger Canyon Road
San Ramon, CA 94583-2324
925 842 5690
Email: invest@chevron.com

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 by email
and vote their shares on the Internet.
Stockholders of record may sign up
for electronic access (and beneficial
stockholders may be able to request
electronic access by contacting their
broker or bank or Broadridge Financial
Solutions) on this website:
www.icsdelivery.com/cvx/.
Enrollment is revocable until each year’s
Annual Meeting record date.

Notice
As used in this report, the term
“Chevron” and such terms as “the
company,” “the corporation,” “our,”
“we,” “us” and “its” 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

Chevron Soccer Academy
Chevron has proudly partnered
with Open Goal Project to launch
the Chevron Soccer Academy. The
Academy strives to create accessible
soccer opportunities for youth and
to provide the proper resources,
knowledge, and support system
for players to learn and grow. As an
integral part of the community for
over a century, Chevron is committed
to building lasting partnerships that
help community members thrive
both on and off the pitch.

Chevron Corporation 2019 Annual Report
106

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whale shark rescue
A whale shark in distress was spotted
by our team on the Erawan platform,
offshore Thailand. The team found
a rope tied to the whale shark’s
tail. A plan was devised to ensure
worker safety, and then a team
spent approximately 30 minutes
helping to free the whale shark. They
believe it became entangled in the
rope from a nearby fishing net. Our
actions helped protect the life of an
endangered species and demonstrate
Chevron’s commitment to conserving
biodiversity and protecting the
environment and wildlife that live
around our operations.

Details of the company’s political
contributions for 2019 are available
on the company’s website,
www.chevron.com, or by writing to:

Corporate Affairs
Chevron Corporation
6001 Bollinger Canyon Road, Bldg., G
San Ramon, CA 94583-2324

For additional information about the
company and the energy industry, visit
Chevron’s website, www.chevron.com.
It includes articles, news releases,
speeches, quarterly earnings
information, the Proxy Statement and
the complete text of this Annual Report.

Publications and other news sources
The Annual Report, distributed in April,
summarizes the company’s financial
performance in the preced ing year and
provides an overview of the company’s
major activities.

Chevron’s Annual Report on Form
10-K filed with the U.S. Securities
and Exchange Commission and the
Supplement to the Annual Report,
containing additional financial and
operating data, are available on the
company’s website, www.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 2019 Sustainability Report will
be available in May on the company’s
website, www.chevron.com/sustainability,
where a guide to Chevron’s sustainability
efforts and approach to our environment,
social and governance (ESG) priorities
can be found.

Highlights include: the innovative and
responsible actions Chevron is taking to
advance environmental performance; our
investment in people and partnership;
and Chevron’s commitment to delivering
results the right and responsible way, with
safety and health as operating priorities.

Printed copies may be requested by
writing to:

Corporate Affairs: Corporate
Sustainability Communications
Chevron Corporation
6001 Bollinger Canyon Road, Bldg., G
San Ramon, CA 94583-2324

connect with us

This Annual Report contains forward-looking statements — identified by words such as “believe,” “expect,” “may,” “will,” “commit,” “position,” “focus,” “goal,” “target,” “schedule,” “budget,”
“plan,” “opportunity,” “strategy,” “project,” “forecast,” “on track” and similar phrases — that reflect management’s current estimates and beliefs, but are not guarantees of future results.
Please see “Cautionary Statements Relevant to Forward-Looking Information for the Purpose of ‘Safe Harbor’ Provisions of the Private Securities Litigation
Reform Act of 1995” on page 27 for a discussion of some of the factors that could cause actual results to differ materially.

PRODUCED BY Corporate Affairs and Comptroller’s Departments, Chevron Corporation
DESIGN Information Design & Communications, Chevron Corporation PRINTING ColorGraphics — Anaheim, California

www.chevron.com/annualreport2019

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