Chevron Annual Report 2020

FY2020 Annual Report · Chevron

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2020 annual report

noble energy enhances
chevron’s performance

The acquisition of Noble Energy, Inc. in October 2020 is expected to deliver strong ﬁnancial beneﬁts. Noble’s high-quality
assets in the Denver-Julesburg (DJ) Basin, Permian Basin and Eagle Ford in the United States, along with those in the Eastern
Mediterranean and West Africa, complement Chevron’s advantaged Upstream portfolio. The acquired low-cost resources
strengthen our global portfolio, adding approximately 1.7 billion oil-equivalent barrels of proved reserves at year-end 2020. The
transaction aligns with our goal of generating industry-leading returns from our existing portfolio by adding advantaged assets
with a low breakeven point.

Photo: The DJ Basin is a large geological formation in northwestern Colorado and southeastern Wyoming. Our newest facilities enable us to
eliminate more than 90 percent of greenhouse gas emissions and reduce our surface footprint by more than 95 percent by combining facility
locations with innovative processes and the latest technology.

~330,000

net acres

DJ basin
148,000

average net barrels of
oil-equivalent production
per day in 2020

90%

less greenhouse
gas emissions with
newest facilities

On the cover: An earth scientist in our reservoir modeling
group in Houston, Texas, analyzes subsurface data in search
of natural gas.

A digital version of this report is available at www.chevron.com/annualreport2020

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The way companies respond to challenging
events tests the strength of their people,
their culture and their plans. Faced with such
conditions, some change their strategies,
alter their priorities or revise their fnancial
commitments to stockholders. At Chevron,
we responded to the events of 2020 with
resilience – afrming our strategy, maintaining
our priorities and honoring our commitments.

higher returns in a lower-carbon future
Our approach to delivering higher returns in
a lower-carbon world is grounded in a set of
beliefs. We know afordable, reliable, ever-
cleaner energy enables modern life, and we
believe energy transitions must work for all.
We set ambitions and favor results, striving
for actions that deliver measurable progress.
We believe in the power of people to deliver
innovative solutions to the world’s biggest
challenges. We support innovation, competitive
markets, partnerships and smart, inclusive
policy as the most efective ways to deliver the
progress needed to achieve shared goals.

We articulate our goal in four words – “higher
returns, lower carbon” – a simple statement that
captures our view of what it takes to succeed
in the future of energy and our commitment to
all stakeholders.

“Higher returns, lower carbon” starts with
fnancial strength. This is underpinned by an
advantaged portfolio, a strong balance sheet,
strict capital discipline, a dividend that is our frst
fnancial priority, and the transformation of our
business to work more efciently and efectively.
It recognizes the need to deliver value for our
stockholders and to work with all stakeholders
in a world moving toward a lower-carbon energy
system. We embrace this future and are aligning
our strategy to advance these goals.

Our strategy also requires unwavering
commitment to the values that have sustained
us: being an industry leader in health, safety
and environmental performance; continuing
to build an inclusive workforce where diversity
is valued and celebrated; and ensuring that
our emphasis on performance, integrity and
accountability guides everything we do.

We believe this is how leaders perform and how
long-term value is generated – for stockholders,
stakeholders and society as a whole.

Contents

higher returns in a lower-carbon future ����������������������������������I

chevron at a glance

��������������������������������������������������������������

XIII

chairman’s letter ��������������������������������������������������������������������� II

chevron stock performance�������������������������������������������������XIV

higher returns, lower carbon ������������������������������������������������� VI

fnancial and operating highlights

���������������������������������������

our beliefs �����������������������������������������������������������������������������VIII

protecting people and the environment ����������������������������XVI

lead director: one-on-one ����������������������������������������������������� IX

fnancials ������������������������������������������������������������������������������� 30

board of directors ������������������������������������������������������������������� X

glossary of energy and fnancial terms ��������������������������������112

corporate ofcers ������������������������������������������������������������������ XI

stockholder and investor information

���������������������������������

113

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To our stockholders:

The COVID-19 pandemic and resulting disruption
to world energy markets tested the resilience of
Chevron and our strategies like never before. As
we look toward economic recovery, we are grateful
for our people and our partners. They have risen to
the challenge, keeping global supply chains moving,
powering manufacturing and transportation systems
to deliver equipment and supplies to frontline workers,
and ensuring essential products are available to those
in need. The opportunity to leverage our assets and
global relationships to give aid to others has been an
honor for all of us at Chevron.

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building on strengths

Even before COVID-19, we were preparing to lead in a future marked by change. Our actions were proactive and disciplined –
simplifying and modernizing work; integrating teams, processes and value chains across business units and geographies; elevating
leadership capabilities; advancing digital solutions; and empowering our workforce to make decisions quickly, safely and with
greater accountability.

We leveraged our strengths to design a better company for the long term – one that can act deliberately, seize opportunity and
generate stronger returns. And we remained true to our values, prepared to succeed in any environment, and adaptive in a dynamic
world where disruption is routine.

Our fnancial priorities have not changed:

growing
the dividend

While others are lowering dividends, we have maintained ours
as we know it is a vital source of stockholder income. In 2020, we
increased our payout 8 percent, the 33rd consecutive annual
increase in per-share dividend payout.

maintaining a strong
balance sheet

Financial strength – demonstrated by our industry-leading
net debt ratio – gives us the fexibility to navigate uncertain
market conditions and address emerging opportunities.

reinvesting to
grow future cash fows

Improving capital efciency allows us to sustain our future
at a lower reinvestment rate. The Noble Energy acquisition is
expected to generate free cash fow and added $13 billion in
enterprise value.

returning excess
cash to stockholders
After meeting the frst three priorities, we return excess cash
to stockholders through buybacks. We have repurchased
shares in 13 of the last 17 years, including returning $1.75 billion
to stockholders in 2020.

Our priorities anchor our commitment to deliver higher returns. They guide us in good times – and we stand by them in difcult
times. They dictate a disciplined approach to capital allocation. They inform actions to strengthen our already advantaged
portfolio through smart acquisitions and prudent divestments – focusing on assets that deliver higher returns. Our success in
reliably delivering value for stockholders will be commemorated this year when we celebrate a full century on the New York Stock
Exchange – one of only 29 companies to reach this milestone.

operating with resilience

During 2020, global oil demand fell by some 9 percent, while
natural gas demand fell by a more modest 3 percent. Stress
in energy markets was compounded by intense competition
for market share among the world’s key oil producers. These
disruptions occurred against the backdrop of geopolitical
uncertainty and growing economic distress.

We demonstrated both resilience and agility in adjusting to
extreme market conditions, balancing short-term cash fow
and long-term value. Our portfolio is anchored in businesses
that are low cost, large scale and long-lived – from our royalty-
advantaged position in the Permian and growing natural
gas business in the Eastern Mediterranean to our feedstock-
advantaged chemicals business and leading fuels brands on
the U.S. West Coast. We expect to deliver results through the
business cycle, creating greater value for our stockholders and
stronger cash fow for decades.

When market conditions deteriorated in 2020, we swiftly
reduced capital spending by 35 percent from 2019. We also
reduced operating costs, refecting our commitment to

both capital and cost discipline. In the Permian Basin, we
demonstrated our fexibility to cut short-cycle capital. At the
same time, we redoubled internal transformation eforts to
become more agile, cost efcient and streamlined.

In our Upstream business, the acquisition of Noble Energy
added complementary high-quality assets in Texas’s
Permian Basin, Colorado’s DJ Basin and the Eastern
Mediterranean. Portfolio additions in 2020 included
approximately 5.67 million net exploration acres. We added
832 million barrels of net oil-equivalent proved reserves
in 2020, with the largest net additions coming from the
Noble Energy acquisition.

Despite the challenges presented by the COVID-19 pandemic,
we advanced construction of the Future Growth Project-
Wellhead Pressure Management Project at Tengizchevroil
in Kazakhstan. Over three years, we safely delivered by sea
408 modules, many of which weighed between 500 and
1,800 tons, to the Tengiz Field from fabrication sites in Italy,
Kazakhstan and South Korea.

Chevron Corporation 2020 Annual Report
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In our Downstream business, we completed the acquisition
of Puma Energy (Australia) Holdings Pty Ltd., adding a
network of more than 360 company- and retailer-owned
service stations, a commercial and industrial fuels business,
owned and leased seaboard import terminals and fuel
distribution depots. And we made excellent progress on
GS Caltex’s olefns mixed-feed cracker project at the Yeosu
Refnery in South Korea.

In 2020, we also increased production of renewable products
and investments in low-carbon technologies, consistent
with our energy transition strategy to help advance a lower-
carbon future. During the year, Chevron announced frst gas
production at our CalBioGas renewable natural gas (RNG)
joint venture in California, formed a new RNG partnership with
Brightmark and announced frst production of renewable base
oil through a joint venture with Novvi.

During a year of unprecedented challenges, we also delivered
one of our safest years ever. This refects our commitment to
protecting people and the environment – and our unwavering
determination to keep getting better.

advancing a lower-carbon future

Helping advance a lower-carbon future requires actions that
drive measurable progress, demonstrating the improvements
we are making today and our intention to do more tomorrow.
Our energy transition strategy focuses on three action areas:

y We are reducing the carbon intensity of our operations

and assets, prioritizing the projects that return the largest
reduction in carbon emissions at the lowest cost to
customers and society.

y We are increasing renewables and ofsets in support of

our business.

y And we are investing in low-carbon technologies to enable
commercial solutions while leveraging our capabilities
and operations to advance technologies such as carbon
capture and hydrogen.

great challenges – eliminating poverty, creating prosperity for
all and delivering the sustainable environment everyone desires.
On this foundation of hope, optimism and confdence, we can
work together to achieve an even brighter future.

At Chevron, our people are helping to build this future,
providing the afordable, reliable, ever-cleaner energy that
billions of people rely on every day. We take great pride in
enabling human progress around the world. And we are deeply
grateful to all our employees, partners and stockholders who
make this work possible.

Thank you for your support and the trust you place in us.

These actions will help make energy and global supply chains
more sustainable – so industries and customers who use our
products can work toward building a lower-carbon world.

Sincerely,

looking ahead

We are coming out of a year like none other: a global pandemic;
a historic lockdown of economic activity; and unprecedented
disruption in energy markets.

Yet the greatest challenges can call forth the greatest responses.

Through the power of innovation, markets and partnership,
scientists developed multiple COVID-19 vaccines in record time.
The tide is beginning to turn, and the pandemic will eventually
recede. This inspiring example points the way to meeting other

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

Chevron Corporation 2020 Annual Report
IV

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“During a year of unprecedented
challenges, we also delivered one of
our safest years ever. This refects our
commitment to protecting people and
the environment – and our unwavering
determination to keep getting better.”

– Mike Wirth

Photo: An operator aboard the Agbami floating production, storage
and offloading vessel at the deepwater field 70 miles off the coast of
central Nigeria.

Chevron Corporation 2020 Annual Report
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higher returns, lower carbon

We are focused on earning higher returns in a lower-carbon future. We recognize the need
both to deliver for our stockholders and to work with all stakeholders in a world moving toward
a lower-carbon energy system.

higher returns

We plan to deliver higher returns on capital employed and create superior value for our stockholders
by maintaining capital and cost discipline and staying anchored to our four financial priorities:

growing the dividend

Increased dividend 8% in 2020

reinvesting in our business
to grow future cash flows

$13

billion

maintaining a
strong balance sheet

22.7%

Achieved industry-leading 22.7% net debt ratio
See page 46 for additional information

returning excess
cash to stockholders

$1.75

billion

Added $13 billion in enterprise value
with Noble Energy acquisition

Repurchased shares in 13 of the last 17
years, including $1.75 billion in 2020

Helping to advance a lower-carbon future means striving for actions that drive measurable
progress. Our energy transition strategy focuses on three action areas:

lower carbon

lower
carbon intensity
cost efficiently

increase renewables
and offsets
in support of our business

invest in low‑
carbon technologies
to enable commercial solutions

We prioritize projects that return
the largest reduction in carbon
emissions at the lowest cost, and
we hold ourselves accountable
with transparent metrics.

We are increasing the use of
renewables in a number of our
products, with the goal of reducing
life-cycle emissions, in an effort to help
our customers achieve their own
lower-carbon goals.

Chevron Corporation 2020 Annual Report
VI

We identify promising technologies
with the goal of bringing down
their cost and helping them
compete effectively in the market
to achieve global scale.

“Helping advance a lower-carbon future requires actions that
drive measurable progress, demonstrating the improvements
we are making today and our intention to do more tomorrow.”

– Mike Wirth

Photo: With our Australian headquarters in Perth, Chevron has been present
in the country for more than 60 years. At Chevron, we believe our business
succeeds best when the people we work with and the communities in which
we operate succeed too.

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our beliefs

We strive to achieve results the right way. Our actions and investments are guided by a set of
beliefs, which shape our culture and underpin our commitment to deliver for our stockholders,
partners and all our stakeholders.

energy is essential
to modern life
We work to provide the energy that enables human progress
around the world. We live this purpose every day.

human ingenuity
fuels innovation
The imagination and perseverance of people will
deliver solutions to energy’s greatest challenges.

the future
is lower carbon
Our actions will help make energy and global supply chains
more sustainable – so industries and customers who use our
products can work toward building a lower-carbon world.

leadership carries
great responsibility
Meeting rising stakeholder expectations demands
performance and accountability at the highest
level. We aim to deliver industry-leading results.

Photo: Chevron’s joint venture CalBioGas LLC successfully achieved first renewable natural gas production from dairy farms in Kern County,
California, in 2020. CalBio brings technology and operational experience to help capture dairy biomethane as a fuel for heavy-duty vehicles.

Chevron Corporation 2020 Annual Report
VIII

lead director: one-on-one

Chevron’s lead independent Director, Ronald Sugar, talks with Director
Enrique Hernandez Jr. about the link between strong fnancial results
and environmental, social and governance (ESG) performance.

Sugar: As the two longest-serving Directors on
Chevron’s Board, we know strong ESG performance goes
hand-in-hand with strong fnancial performance. The
company’s resilient strategy and capital discipline enable
us to continually strengthen our commitment to building a
more sustainable future in any business environment.

Our role as Directors is to help position the company
to achieve higher returns in a world transitioning to a
lower-carbon economy. In this environment, delivering on
our ESG commitments will increasingly defne our success
as a company and earn support from stockholders and our
other stakeholders.

Hernandez: That’s right, Ron. To maintain our fnancial
strength and deliver on our ESG goals, we prioritize
projects that we believe will return the largest reduction
in carbon emissions at the lowest costs, and we hold
ourselves accountable with transparent metrics. We also
partner with those who have shared aspirations and where
our combined strengths can have a tangible impact on
advancing a lower-carbon future.

Sugar: You and I have both met with groups of Chevron
stockholders over the years, and we hear their expectations
directly, particularly on accountability for ESG matters.
We are actively working to lower the carbon intensity of
our assets and operations by investing in technologies like
carbon capture, utilization and storage and increasing the
use of renewables and ofsets in our operations. These
actions help lower our operating costs, and they help us
meet the increasing expectations of society.

For example, Chevron is co-developing up to
500 megawatts of renewable power to provide electricity
to strategic assets across Chevron’s global portfolio. In
2020, Chevron also announced the frst production of 100
percent renewable base oil, and one of our joint ventures
produced its frst renewable natural gas. Our goal is to
help scale innovations like these both to use them across
our global platform and to help our customers achieve
their lower-carbon goals. These actions will make energy
and global supply chains more sustainable. No company
can do it alone, but we can all play our constructive part.

Hernandez: As a member of the Board’s Public Policy and
Sustainability Committee, I know that smart, inclusive public
policy is an important part of this efort. We are committed
to engaging with governments and stakeholders to create
incentives for market-based solutions like carbon pricing
and other policies that support the innovations needed to
build a lower-carbon economy. These tools are critical to
achieving progress on a global basis.

Sugar: Rick, you mentioned metrics. You and I both serve
on the Board’s Management Compensation Committee,
where we set the metrics and monitor the company’s
progress toward them. To hold ourselves accountable
and allow stakeholders to measure our progress, Chevron
has set equity greenhouse gas intensity reduction metrics
that are communicated broadly and shared online. These
metrics align with the Paris Agreement. To further build
environmental progress into our company’s culture, we have
tied our compensation plans for executives and employees
directly to these metrics.

Hernandez: As Board members, we know that
transparency is critical to all our ESG eforts, and we aim
to be an industry leader on carbon emissions reporting.
Our reporting aligns with the recommendations of the
Financial Stability Board’s Task Force on Climate-related
Financial Disclosures. Our 2020 Sustainability Report
provides a detailed look at our performance on our
ESG priorities such as global employee diversity, social
investments in communities around the world, our
stewardship on protecting the environments where we
operate and strong governance.

Sugar: As you and I well know, Chevron is in a long-cycle,
complex global business, which means the Board must think
about the future beyond current business conditions. It’s
our job, working with Chevron’s diverse and engaged Board,
to review, test, debate and, where necessary, work with
management to adjust the company’s business strategy.
The goal: to most efectively deploy Chevron’s capital and
human talent to meet rising stockholder and stakeholder
expectations in a world where fnancial results and ESG
performance are inextricably linked.

Learn more about our ESG eforts at www.chevron.com/sustainability

Chevron Corporation 2020 Annual Report
IX

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, 60
Chairman of the Board and Chief Executive Officer since February 2018. Prior to his current role, Wirth served as vice
chairman of the Board in 2017 and executive vice president of Midstream & Development 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, 66
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 ofcer 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, 64
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 frm’s principal executive ofcer.
He is a director of Oaktree Capital Group LLC and its subsidiaries:
Oaktree Acquisition Corporation II, Oaktree Acquisition
Corporation III and Oaktree Specialty Lending Corporation. (1)

Alice P� Gast, 62
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�, 65
Director since 2008. He is chairman and chief executive ofcer
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)

Marillyn A� Hewson, 67
Director since 2021. She has been strategic advisor to the chief
executive ofcer of Lockheed Martin Corporation, a security
and aerospace company, since March 2021. Previously, she was
executive chairman, chairman, president and chief executive
ofcer of Lockheed Martin Corporation. She is a director of
Johnson & Johnson. (1)

Jon M� Huntsman Jr�, 60
Director since 2020 and from 2014 to 2017 when he resigned
to serve as the U.S. Ambassador to Russia. He served as
U.S. Ambassador to China and was governor of Utah for two
consecutive terms. He is a director of Ford Motor Company. (3,4)

Charles W� Moorman IV, 69
Director since 2012. He is a retired chairman of the board, chief
executive ofcer and president 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 ofcer. He is a
director of Oracle Corporation. (1)

Dambisa F� Moyo, 52
Director since 2016. She is chief executive ofcer of Mildstorm
LLC, focusing on the global economy and international afairs.
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, 64
Director since 2018. She is a retired chairman, chief executive
ofcer and president of Sempra Energy, an energy services
holding company. Previously, she was executive vice president
of Sempra Energy and president and chief executive ofcer of
San Diego Gas & Electric and Southern California Gas Co. She is a
director of Caterpillar Inc. and Lockheed Martin Corporation. (1)

Ronald D� Sugar, 72
Lead Director since 2015 and a Director since 2005. He is an
advisor and retired chairman and chief executive ofcer 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.
and Uber Technologies Inc. (2,3)

D� James Umpleby III, 63
Director since 2018. He is chairman and chief executive ofcer
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)Nominating and Governance: Ronald D. Sugar, Chair
3)Management Compensation: Enrique Hernandez Jr., Chair
4) Public Policy and Sustainability: Wanda M. Austin, Chair

Chevron Corporation 2020 Annual Report
X

corporate officers

Paul R� Antebi, 49
Vice President since 2021 and General Tax Counsel since 2021.
Responsible for directing Chevron’s worldwide tax activities.
Previously, the company’s Deputy General Tax Counsel. Joined
the company in 1998.

Pierre R� Breber, 56
Vice President and Chief Financial Officer since 2019.
Responsible for controller, tax, treasury, audit and investor
relations activities worldwide. Previously, Executive Vice
President of Downstream and Chemicals. Joined the company
in 1989.

Mary A� Francis, 56
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, 61
Executive Vice President, Technology, Projects and Services
since 2015. Responsible for the Chevron Technical Center,
including energy technology and innovation; capital projects
delivery; IT; asset performance and process safety; and HSE. He
is also responsible for environmental management; real estate;
procurement; and talent selection. Previously Senior Vice President,
Technology, Projects and Services. Joined the company in 1982.

David A� Inchausti, 57
Vice President and Controller since 2019. Responsible for
corporatewide accounting, fnancial reporting and analysis,
internal controls, accounting policy, and digital fnance.
Previously, Deputy Comptroller and Upstream Comptroller. Prior
to that, 20 years abroad in multiple business units. Joined the
company in 1988.

James W� Johnson, 62
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.

Navin K� Mahajan, 54
Vice President and Treasurer since 2019. Responsible for
Chevron’s banking, fnancing, 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 Ofcer. Joined the company in 1996.

Rhonda J� Morris, 55
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, 57
Executive Vice President, Downstream & Chemicals since 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, 59
Vice President, Strategy & Sustainability since 2018.
Responsible for guiding development of the company’s key
strategies, including capital allocation and sustainability eforts.
Previously, Vice President of Chevron’s Mid-Continent Business
Unit; Vice President of the Appalachian/Michigan Business Unit;
and General Manager of Strategy and Planning for Chevron North
America Exploration & Production. Joined the company in 2000.

Colin E� Parftt, 57
Vice President, Midstream since 2019. Responsible for Chevron’s
Midstream business, including supply and trading activities,
shipping, pipeline, and power and energy management.
Appointed Chairman of the Board, Noble Midstream Partners GP
LLC, in October 2020. Previously, President, Supply and Trading.
Joined the company in 1995.

R� Hewitt Pate, 58
Vice President and General Counsel since 2009. Responsible
for directing the company’s worldwide legal afairs. 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 Payne, 60
Vice President, Health, Safety and Environment (HSE)
since 2018. Responsible for HSE 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, 63
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
Ofshore (Thailand) Ltd. Joined the company in 1979.

Albert J� Williams, 52
Vice President, Corporate Afairs since 2021. Responsible
for overseeing government afairs, public afairs, social
investment and performance, and the company’s worldwide
eforts to protect and enhance its reputation. Previously,
Managing Director of Chevron Australia and head of the
Australasia business unit. Joined the company in 1991.

Retiring Ofcers
Charles N� Macfarlane, retired efective February 2021; vice president, since 2013, and
general tax counsel, since 2010; joined the company in 1986.

Dale A� Walsh, retires efective May 2021; vice president, Corporate Afairs, since 2019;
joined the company in 1983.

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

Chevron Corporation 2020 Annual Report
XI

Photo: Workers at a drill site in the Permian Basin, where Chevron
maintains one of the lowest venting and flaring rates of any
company. Chevron s midcontinent business also has a dedicated
water team, which implements strategies to reduce the amount of
fresh water used for well completions.

’

Chevron Corporation 2020 Annual Report
XII

X-over .000

1149230_Annual_Report_v8.3_r2.indd 12

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chevron at a glance

Chevron is one of the world’s leading integrated energy companies� We believe
afordable, reliable and ever-cleaner energy is essential to achieving a more
prosperous and sustainable world� Chevron produces crude oil and natural gas;
manufactures transportation fuels, lubricants, petrochemicals and additives; and
develops technologies that enhance our business and the industry� To advance
a lower-carbon future, we are focused on cost efciently lowering our carbon
intensity, increasing renewables and ofsets in support of our business, and
investing in low-carbon technologies that enable commercial solutions�

Our success is driven by a dedicated,
diverse and highly skilled global workforce
united by The Chevron Way, our enduring
statement of culture and our commitment
to delivering industry-leading results
and superior stockholder value – in any
operating environment.

We operate responsibly, applying advanced
technologies and capturing high-return, lower-
carbon opportunities that create stockholder
value in a socially and environmentally
responsible manner.

3.08
million barrels

net oil equivalent
daily production1

$239.8
billion

total assets2

11.1
billion barrels

net oil -equivalent
proved reserves2, 3

$94.5
billion

sales and other
operating revenues1

1 Year ended December 31, 2020
2 At December 31, 2020
3 For defnition of “reserves,” see glossary of energy and fnancial terms, page 112

Chevron Corporation 2020 Annual Report
XIII

chevron stock performance

2020 marked the 33rd consecutive year we increased
the annual per-share dividend payout

Indexed dividend growth
Basis 2005 = 100

7.5%
CVX compound
annual growth rate

300

250

200

150

100

˜°°˛

Chevron

S&P 500

Total stockholder returns*
(as of 12/31/2020)

1-year

-25.7%

20%

10%

-10%

-20%

-30%

-40%

-50%

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.

˜°˜°

5-year

3.1%

ii ••

10%

-5%

-10%

10-year

3.2%

10%

-5%

-10%

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 12/31/2020. 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 fve-year period
beginning December 31, 2015, and ending December 31, 2020,
and for the peer group is weighted by market capitalization as
of the beginning of each year. It includes the reinvestment of all
dividends that an investor would be entitled to receive and is
adjusted for stock splits. The interim measurement points show
the value of $100 invested on December 31, 2015, as of the end
of each year between 2016 and 2020.

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

$200

$175

$150

$125

$100

$203

$116
$93

$75

$50

...

˜°˛˝

...

˜°˛˙

Chevron

S&P 500

...

˜°˛ˆ

˜°˛ˇ

˜°˛˘

˜°˜°

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

Chevron Corporation 2020 Annual Report
XIV

financial and operating highlights

Financial highlights1

Net income (loss) attributable to Chevron Corporation
Sales and other operating revenues
Cash fow from operating activities
Capital and exploratory expenditures2
Total assets at year-end
Total debt and fnance 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
Net debt ratio3
Return on stockholders’ equity3
Return on average capital employed3

1 Millions of dollars, except per-share amounts
2 Includes equity in afliates
3 See pages 45-46 for additional information

$
$
$
$
$
$
$

$
$
$

2020

(5,543)
94,471
10,576
13,499
239,790
44,315
131,688
1,911,018

(2.96)
5.16
68.91

25.2%
22.7%
(4.0)%
(2.8)%

2019

2018

$
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%
12.8%
2.0%
2.0%

$
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%
13.5%
9.8%
8.2%

Total capital and exploratory expenditures 4
($ – Billions)

Operating expense5
($ – Billions)

$50

$40

$30

$20

$10

~$20�5 billion reduction
(2015–2020)

˜ˆˇ

˜˝˝

˜°˛

˜˝˙

˜˝°

˜°ˆ˘

˝˙˝˙

$35

$30

$25

$20

$15

$10

~$2 billion reduction
(2015–2020)

˛˜ˇ

˛˜˙

˛˜˝

˛˜˙

˛˜ˆ

˛˜˙

ˇ˘

˜°˜°

4 Includes expenditures by equity afliates. 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 beneft 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

2020

2019

2018

1,868
7,290
3,083
6,147
29,922
11,134
1,377
2,224
42,628

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

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

Chevron Corporation 2020 Annual Report
XV

protecting people and the environment
The Chevron Way’s emphasis on protecting people and the environment guides our
commitment to operating safely and reliably. Our leaders drive a culture of Operational
Excellence (OE) at Chevron, managing risk and learning from one another. We maintain a
system of efective safeguards to keep our workforce, communities and environment safe.

2020 was our second-best year ever in overall OE
performance. In personal safety, we set record lows in serious
injuries and motor vehicle crashes. Our Total Recordable
Injury Rate is the best in the industry. In process safety, we
recorded for the frst time ever no Severe Tier 1 Loss of
Containment (LOC) incidents.

This success is due to the Operational Excellence Management
System (OEMS), followed by our workforce since 2004 to
manage health, safety and environmental risks. The OEMS
enables us to assess risks, identify safeguards and implement
programs to assure the efectiveness of those safeguards.

how we maintain safe operations
comprehensive risk management based on data and science

Preventing high-consequence incidents and impacts
starts with understanding and mitigating risks.

We manage risk across our six focus areas
through a system of safeguards. Learn more
at www.chevron.com/oems

assess

risk

manage
safeguards

verify

assurance

our COVID-19 pandemic response

maintaining a sense of vulnerability

Our successful response to the COVID-19 pandemic has been
enabled by our safety culture and tools, emphasizing “people
frst and work second,” consistent with how we run our
business using the OEMS.

Everything we do comes with some level of risk. We routinely
assess risk in our business, develop safeguards to mitigate it,
and create an assurance process to verify an efective layer of
safeguards is in place and functioning.

COVID-19 posed a new risk, but one akin to occupational
hygiene risks and potential exposures regularly addressed
by our workforce. After adapting medical terminology to
the language of our safety culture, we applied the same
risk-based system to manage COVID-19, ensuring that both
new and existing safeguards were not compromised by the
pandemic. We remain consistent with the terms, principles
and practices employed in our operations, continually looking
at risk as we manage operations through the pandemic.

Throughout the pandemic, we have relied on a key component
of our process safety culture, the concept of maintaining
a sense of vulnerability. To do this, we frst develop an
awareness of the hazards inherent in our work. We then must
remain vigilant for signs of complacency and indicators of
weakness in our safeguards, including minor incidents that
may foreshadow more serious consequences.

In 2020, we again led the industry in process safety. We
reduced the frequency and severity of LOC incidents through
disciplined adherence to process safety standards while also
building fuency and competency across our workforce.

Despite a challenging business environment, we
collaborated closely with industry partners to strengthen our
approach to identifying and mitigating weaknesses in our
process safety systems.

More on our safety performance at www.chevron.com/sustainability.

Chevron Corporation 2020 Annual Report
XVI

Financial Table of Contents

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

. . . . . . . . . . . . . . .

. . . . .

Earnings by Major Operating Area

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . .

Business Environment and Outlook

. . . . . . . . . . . . . . . . . . . .

. .

. . . . . . . .

Operating Developments

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . .

. . .

Results of Operations

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . .

. .

. . . . .

Consolidated Statement of Income

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . .

Selected Operating Data

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . .

. . .

Liquidity and Capital Resources

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . .

Financial Ratios and Metrics

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. .

Off-Balance-Sheet Arrangements, Contractual Obligations,

Guarantees and Other Contingencies

. . . . . . . . . . . . . . . . . .

. . . . . . . .

Financial and Derivative Instrument Market Risk

. . . . . . . . . . . . . . . . . . .

Transactions With Related Parties

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . .

Litigation and Other Contingencies

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . .

Environmental Matters

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . .

Critical Accounting Estimates and Assumptions

. . . . . . . . . . . . . . . . . . . .

New Accounting Standards

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . .

Quarterly Results

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. . . . . . . . . . .

Consolidated Financial Statements
Reports of Management . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . .

. . .

Report of Independent Registered Public Accounting Firm

. . . . . . . . . . .

Consolidated Statement of Income

. . . . . . . . . . . . . . . . . . . .

. .

. . . . . . . .

Consolidated Statement of Comprehensive Income

. . . . . . . . . . . . . . . . .

Consolidated Balance Sheet

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . .

. .

Consolidated Statement of Cash Flows

. . . . . . . . . . . . . . . . . . . .

. . . . . . .

Consolidated Statement of Equity

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . .

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

64
67

. . . . . . . . . . . . . . . . . . . . .

Notes to the Consolidated Financial Statements
Note 1
Note 2
Note 3

Summary of Significant Accounting Policies . . . . . . . . . . . . . .
Changes in Accumulated Other Comprehensive Losses
. . .
Information Relating to the Consolidated Statement of
Cash Flows
. . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . .
New Accounting Standards
Lease Commitments
Summarized Financial Data – Chevron U.S.A. Inc.
Fair Value Measurements
Financial and Derivative Instruments
Assets Held for Sale

. . . . .
Note 4
. . . . . .
Note 5
. . . . . . . . . . . .
Note 6
. . . . . . . .
Note 7
. . . . . . .
Note 8
. . . . . . . . . . . . . . . . . . .
Note 9
. . . . . . . . . . . .
Note 10 Equity
. . . . . . . . .
. . . . . . . . . . . . . . .
Note 11 Earnings Per Share
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Note 12 Operating Segments and Geographic Data
. . . . . . . . . . . . . .
Note 13
. . . . . .
Note 14
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Note 15
. . . . . . . . . . .
Note 16 Properties, Plant and Equipment
. . .
Note 17 Short-Term Debt . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . .
Note 18
. . . . . . . . . . . . . . . . . . . . .
. .
. . . . . . . . . . . . .
. . . . . . . . . . . . .
Note 19 Accounting for Suspended Exploratory Wells
. . . . .
Note 20 Stock Options and Other Share-Based Compensation
. . . . . . . . . .
Note 21 Employee Benefit Plans
. . . . . . . . . . . . . . . . .
Note 22 Other Contingencies and Commitments
. . . . . . . . . . . . . . . . . . . . . . . . . .
Note 23 Asset Retirement Obligations
Note 24 Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Note 25 Other Financial Information
. . . . . .
Note 26 Summarized Financial Data – Chevron Phillips Chemical
. . . . . . . . . . . . .

Investments and Advances
Litigation
Taxes

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . .

Long-Term Debt

. . . . . . . . . . . . . .

Company LLC

68
69
69
71
71
72
74
74
74
74
77
78
79
82
83
84
85
86
87
92
94
94
95

Note 27 Restructuring and Reorganization Costs
Note 28
Note 29 Acquisition of Noble Energy, Inc.

Financial Instruments – Credit Losses

. .

.
. . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . .
. .

95
95
96
96

. . . . . . . . . . . . . . . . . . . . .

Five-Year Financial Summary . . . . . . . . . . . . . . . . . . . . .
Supplemental Information on Oil and Gas Producing Activities

. . . . . . . . . . . . . .
. . . . . . . .

98
99

Refer to the “Results of Operations” section beginning on page 37 for a discussion of financial results by major operating

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,” “potential”] and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees
of future performance and are subject to certain risks, uncertainties and other factors, many of which are beyond the company’s control and are difficult to
predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader
should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron
undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and
natural gas prices and demand for our products, and production curtailments due to market conditions; crude oil production quotas or other actions that might
be imposed by the Organization of Petroleum Exporting Countries (OPEC) and other producing countries; public health crises, such as pandemics (including
coronavirus (COVID-19)) and epidemics, and any related government policies and actions; changing economic, regulatory and political environments in the
various countries in which the company operates; general domestic and international economic and political conditions; changing refining, marketing and
chemicals margins; the company’s ability to realize anticipated cost savings, expenditure reductions 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 during the COVID-19 pandemic; 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, or other natural or human causes beyond the company’s control; 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 ability to achieve the anticipated benefits from the
acquisition of Noble Energy, Inc.; 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 receipt of required Board authorizations
to pay future dividends; 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 23 in the 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.

30
Chevron Corporation 2020 Annual Report
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3/5/21 6:04 PM

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, 2020.

Business Environment and Outlook

2020

(5,543)

(2.96)

5.16

94,471

(2.8)%

(4.0)%

2019

2018

2,924

14,824

139,865

158,902

1.55

1.54

4.76

2.0%

7.81

7.74

4.48

8.2%

9.8%

2020

2019

2018

(5,094) $

(1,608)

(825)

(2,433)

(571)

618

(3,157)

(5,543)

(645)

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

(2,290)

14,824

611

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

Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Indonesia, Israel, Kazakhstan, Kurdistan Region of

Iraq, 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.

The company’s objective is to deliver higher returns, lower carbon and superior shareholder value in any business

environment. 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. 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, including employee reductions, and capital and

exploratory expenditures, along with other measures intended to improve financial performance. Similarly, impairments or

write-offs have occurred, and may occur in the future, as a result of managerial decisions not to progress certain projects in

the company’s portfolio.

With ongoing global interest in addressing the risks of climate change, support for policies and advancements in lower

carbon technologies is expected. In seeking to help advance a lower carbon future, Chevron is focused on lowering its carbon

intensity cost efficiently,

increasing renewables and offsets in support of its business, and investing in low-carbon

technologies to enable commercial solutions.

Response to Market Conditions and COVID-19 During most of 2020, travel restrictions and other constraints on economic

activity designed to limit the spread of the COVID-19 virus were implemented in many locations around the world. These

constraints reduced demand for our products, and commodity prices fell, negatively impacting the company’s 2020 financial

and operating results. While demand and commodity prices have shown signs of recovery, demand is not back to

pre-pandemic levels, and financial results will likely continue to be challenged in future quarters. Due to the rapidly

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.

2020

2019

2018

(5,543)

$
$
$
$

(2.96)
(2.96)
5.16
94,471

$
$
$
$

2,924 $

14,824

1.55
1.54
4.76
139,865

$
$
$
$

7.81
7.74
4.48
158,902

(2.8)%
(4.0)%

2.0%
2.0%

8.2%
9.8%

2020

2019

2018

(1,608)
(825)

(2,433)

(571)
618

(3,157)
(5,543)

(645)

(5,094) $
7,670

2,576

1,559
922

2,481

3,278
10,038

13,316

2,103
1,695

3,798

(2,133)
2,924

(2,290)
14,824

(304) $

611

Refer to the “Results of Operations” section beginning on page 37 for a discussion of financial results by major operating
area for the three years ended December 31, 2020.

Business Environment and Outlook

Chevron is a global energy company with substantial business activities in the following countries: Angola, Argentina,
Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Indonesia, Israel, Kazakhstan, Kurdistan Region of
Iraq, 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.

The company’s objective is to deliver higher returns, lower carbon and superior shareholder value in any business
environment. 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. 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, including employee reductions, and capital and
exploratory expenditures, along with other measures intended to improve financial performance. Similarly, impairments or
write-offs have occurred, and may occur in the future, as a result of managerial decisions not to progress certain projects in
the company’s portfolio.

With ongoing global interest in addressing the risks of climate change, support for policies and advancements in lower
carbon technologies is expected. In seeking to help advance a lower carbon future, Chevron is focused on lowering its carbon
intensity cost efficiently, increasing renewables and offsets in support of its business, and investing in low-carbon
technologies to enable commercial solutions.

Response to Market Conditions and COVID-19 During most of 2020, travel restrictions and other constraints on economic
activity designed to limit the spread of the COVID-19 virus were implemented in many locations around the world. These
constraints reduced demand for our products, and commodity prices fell, negatively impacting the company’s 2020 financial
and operating results. While demand and commodity prices have shown signs of recovery, demand is not back to
pre-pandemic levels, and financial results will likely continue to be challenged in future quarters. Due to the rapidly

Chevron Corporation 2020 Annual Report
31

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

changing environment, there continues to be uncertainty and unpredictability around the extent to which the COVID-19
pandemic will impact our future results, which could be material.

Chevron entered this crisis well positioned with a strong balance sheet, flexible capital program and low cash flow breakeven
price. To protect its long-term health and value, the company took swift action, adjusting the items it can control. The
company lowered its capital expenditures 35 percent and lowered its operating expense, excluding non-recurring severance
costs, by $1.4 billion compared to 2019. The company completed an enterprise-wide transformation that is expected to
capture additional cost efficiencies. Additionally, the company suspended its stock repurchase program in March 2020.
Taken together, these actions are consistent with our financial priorities: to protect the dividend, to prioritize capital spend
that drives long-term value, and to maintain a strong balance sheet. The company expects to continue to have sufficient
liquidity and access to both commercial paper and debt capital markets due to its strong balance sheet and investment grade
credit ratings. Additionally, the company has access to nearly $10 billion in committed credit facilities.

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 23 of the company’s Annual Report on Form 10-K for a discussion of some of the inherent
risks that could materially impact the company’s results of operations or financial condition.

The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term
value or to acquire assets or operations complementary to its asset base to help augment the company’s financial
performance and value growth. Asset dispositions and restructurings may result in significant gains or losses in future
periods. The company’s asset sale program for 2018 through 2020 targeted before-tax proceeds of $5-10 billion. For the
three year period ending December 31, 2020, assets sales proceeds totaled $7.7 billion, in the middle of the guidance range.

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, natural and human causes beyond the company’s
control such as the COVID-19 pandemic, 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 is actively managing its schedule of work, contracting, procurement, and supply chain activities to effectively
manage costs and ensure supply chain resiliency and continuity in support of operational goals. Third party costs for capital,
exploration, and operating expenses 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 market based prices charged
by the industry’s material and service providers. Chevron utilizes contracts with various pricing mechanisms, so there may be
a lag before the company’s costs reflect the changes in market trends.

The spot markets and some of the current cost indexes for many materials and services have stabilized. Crude oil and natural
gas prices and demand have rebounded from lows of the early pandemic though demand still has not returned to
pre-pandemic levels. Drilling activity in the U.S. has risen slowly but steadily through the end of the year. The timing and

32
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32

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3/5/21 6:04 PM

trajectory of any increase in the cost of materials and services going forward will depend on the extent of the oil and gas

industry recovery. Correlated with these initial signs of industry recovery and cost stabilization was a noticeable

improvement in the risk of default for key suppliers. To date, there have been no material impacts to operations due to

supplier defaults. Chevron is actively monitoring and engaging key suppliers to mitigate any potential business impacts.

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

Brent

WTI

Henry Hub

Oil

$/bbl

$/mcf

15.00

12.50

10.00

7.50

5.00

2.50

0.00

2018

2019

2020

The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S.

Henry Hub natural gas. The Brent price averaged $42 per barrel for the full-year 2020, compared to $64 in 2019. As of

mid-February 2021, the Brent price was $64 per barrel. The WTI price averaged $39 per barrel for the full-year 2020,

compared to $57 in 2019. As of mid-February 2021, the WTI price was $60 per barrel. The majority of the company’s equity

crude production is priced based on the Brent benchmark.

Crude prices sharply declined at the end of the first and into the second quarter 2020 due to surplus supply as demand

decreased following government-imposed travel restrictions and other constraints on economic activity. In the second half of

2020, the supply/demand balance slowly improved, primarily due to production cuts and demand growth, allowing prices to

somewhat recover. The company’s average realization for U.S. crude oil and natural gas liquids in 2020 was $31 per barrel,

down 37 percent from 2019. The company’s average realization for international crude oil and natural gas liquids in 2020

was $36 per barrel, down 38 percent from 2019.

Prices 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 $1.98 per thousand cubic feet (MCF) during 2020, compared

with $2.53 per MCF during 2019. As of mid-February 2021, the Henry Hub spot price increased to $6.00 per MCF amid

freezing temperatures across much of the United States.

Outside the United States, prices for natural gas depend on a wide range of supply, demand and regulatory circumstances.

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. International natural gas realizations averaged $4.59 per MCF during

2020, compared with $5.83 per MCF during 2019. (See page 41 for the company’s average natural gas realizations for the

U.S. and international regions.)

The company’s worldwide net oil-equivalent production in 2020 averaged 3.083 million barrels per day. About 14 percent of

the company’s net oil-equivalent production in 2020 occurred in the OPEC-member countries of Angola, Equatorial Guinea,

Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, Republic of Congo and Venezuela.

The company estimates that net oil-equivalent production in 2021 will grow up to 3 percent compared to 2020, assuming a

Brent crude oil price of $50 per barrel and excluding the impact of anticipated 2021 asset sales. This estimate is subject to

many factors and uncertainties, including quotas or other actions that may be imposed by OPEC+; price effects on

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

reservoir performance; greater-than-expected declines in production from mature fields; start-up or ramp-up of projects;

fluctuations in demand for crude oil and natural gas in various markets; weather conditions that may shut in production; civil

unrest; changing geopolitics; delays in completion of maintenance turnarounds; storage constraints or economic

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

changing environment, there continues to be uncertainty and unpredictability around the extent to which the COVID-19

pandemic will impact our future results, which could be material.

Chevron entered this crisis well positioned with a strong balance sheet, flexible capital program and low cash flow breakeven

price. To protect its long-term health and value, the company took swift action, adjusting the items it can control. The

company lowered its capital expenditures 35 percent and lowered its operating expense, excluding non-recurring severance

costs, by $1.4 billion compared to 2019. The company completed an enterprise-wide transformation that is expected to

capture additional cost efficiencies. Additionally, the company suspended its stock repurchase program in March 2020.

Taken together, these actions are consistent with our financial priorities: to protect the dividend, to prioritize capital spend

that drives long-term value, and to maintain a strong balance sheet. The company expects to continue to have sufficient

liquidity and access to both commercial paper and debt capital markets due to its strong balance sheet and investment grade

credit ratings. Additionally, the company has access to nearly $10 billion in committed credit facilities.

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 23 of the company’s Annual Report on Form 10-K for a discussion of some of the inherent

risks that could materially impact the company’s results of operations or financial condition.

The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term

value or to acquire assets or operations complementary to its asset base to help augment

the company’s financial

performance and value growth. Asset dispositions and restructurings may result in significant gains or losses in future

periods. The company’s asset sale program for 2018 through 2020 targeted before-tax proceeds of $5-10 billion. For the

three year period ending December 31, 2020, assets sales proceeds totaled $7.7 billion, in the middle of the guidance range.

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, natural and human causes beyond the company’s

control such as the COVID-19 pandemic, 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 is actively managing its schedule of work, contracting, procurement, and supply chain activities to effectively

manage costs and ensure supply chain resiliency and continuity in support of operational goals. Third party costs for capital,

exploration, and operating expenses 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 market based prices charged

by the industry’s material and service providers. Chevron utilizes contracts with various pricing mechanisms, so there may be

a lag before the company’s costs reflect the changes in market trends.

The spot markets and some of the current cost indexes for many materials and services have stabilized. Crude oil and natural

gas prices and demand have rebounded from lows of the early pandemic though demand still has not returned to

pre-pandemic levels. Drilling activity in the U.S. has risen slowly but steadily through the end of the year. The timing and

trajectory of any increase in the cost of materials and services going forward will depend on the extent of the oil and gas
industry recovery. Correlated with these initial signs of industry recovery and cost stabilization was a noticeable
improvement in the risk of default for key suppliers. To date, there have been no material impacts to operations due to
supplier defaults. Chevron is actively monitoring and engaging key suppliers to mitigate any potential business impacts.

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

Brent
WTI
Henry Hub

Oil
$/bbl

HH
$/mcf
15.00

12.50

10.00

7.50

5.00

2.50

0.00

2018

2019

2020

The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S.
Henry Hub natural gas. The Brent price averaged $42 per barrel for the full-year 2020, compared to $64 in 2019. As of
mid-February 2021, the Brent price was $64 per barrel. The WTI price averaged $39 per barrel for the full-year 2020,
compared to $57 in 2019. As of mid-February 2021, the WTI price was $60 per barrel. The majority of the company’s equity
crude production is priced based on the Brent benchmark.

Crude prices sharply declined at the end of the first and into the second quarter 2020 due to surplus supply as demand
decreased following government-imposed travel restrictions and other constraints on economic activity. In the second half of
2020, the supply/demand balance slowly improved, primarily due to production cuts and demand growth, allowing prices to
somewhat recover. The company’s average realization for U.S. crude oil and natural gas liquids in 2020 was $31 per barrel,
down 37 percent from 2019. The company’s average realization for international crude oil and natural gas liquids in 2020
was $36 per barrel, down 38 percent from 2019.

Prices 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 $1.98 per thousand cubic feet (MCF) during 2020, compared
with $2.53 per MCF during 2019. As of mid-February 2021, the Henry Hub spot price increased to $6.00 per MCF amid
freezing temperatures across much of the United States.

Outside the United States, prices for natural gas depend on a wide range of supply, demand and regulatory circumstances.
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. International natural gas realizations averaged $4.59 per MCF during
2020, compared with $5.83 per MCF during 2019. (See page 41 for the company’s average natural gas realizations for the
U.S. and international regions.)

The company’s worldwide net oil-equivalent production in 2020 averaged 3.083 million barrels per day. About 14 percent of
the company’s net oil-equivalent production in 2020 occurred in the OPEC-member countries of Angola, Equatorial Guinea,
Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, Republic of Congo and Venezuela.

The company estimates that net oil-equivalent production in 2021 will grow up to 3 percent compared to 2020, assuming a
Brent crude oil price of $50 per barrel and excluding the impact of anticipated 2021 asset sales. This estimate is subject to
many factors and uncertainties, including quotas or other actions that may be imposed by OPEC+; price effects on
entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction;
reservoir performance; greater-than-expected declines in production from mature fields; start-up or ramp-up of projects;
fluctuations in demand for crude oil and natural gas in various markets; weather conditions that may shut in production; civil
unrest; changing geopolitics; delays in completion of maintenance turnarounds; storage constraints or economic

33
Chevron Corporation 2020 Annual Report
33

173155_Annual_Report_10-K.indd 33

3/5/21 6:04 PM

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

conditions that could lead to shut-in production; 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, but these too are
under pressure in the current market environment.

In the Partitioned Zone between Saudi Arabia and Kuwait, production was shut-in beginning in May 2015. In December
2019, the governments of Saudi Arabia and Kuwait signed a memorandum of understanding to allow production to restart in
the Partitioned Zone. In mid-February 2020, pre-startup activities commenced, and production resumed in July 2020. The
financial effects from the loss of production in 2019 and first half 2020 were not significant. During the fourth quarter 2020,
oil equivalent production in the Partitioned Zone averaged 40 thousand barrels per day.

Chevron has interests in Venezuelan crude oil assets, including those operated by Petropiar, Petroboscan and
Petroindependiente. While the operating environment in Venezuela has been deteriorating for some time, Petropiar,
Petroboscan, and Petroindependiente have conducted activities consistent with the authorization provided pursuant to general
licenses issued by the United States government. During the second quarter 2020, the company completed its evaluation of
the carrying value of its Venezuelan investments in line with its accounting policies and concluded that given the current
operating environment and overall outlook, which created significant uncertainties regarding the recovery of the company’s
investment, an other than temporary loss of value had occurred, which resulted in a full impairment of its investment in the
country totaling $2.6 billion and change in accounting treatment from equity method to non-equity method of accounting. As
a result, the company also removed approximately 160 million barrels of proved reserves and stopped reporting production in
the country effective July 2020. The company remains committed to its people, assets and operations in Venezuela.

Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil-equivalent at
year-end 2020, a decrease of 3 percent from year-end 2019. The reserve replacement ratio in 2020 was 74 percent. The 5 and
10 year reserve replacement ratios were 99 percent and 106 percent, respectively. Refer to Table V beginning on page 103
for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2018 and each
year-end from 2018 through 2020, and an accompanying discussion of major changes to proved reserves by geographic area
for the three-year period ending December 31, 2020.

Response to Market Conditions and COVID-19: Upstream Travel restrictions and other constraints on global economic
activity in 2020 in response to COVID-19 caused a significant decrease in demand for oil and gas. This led to lower price
realizations across all commodities. While critical asset integrity and reliability activities progressed throughout the year,

34
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34

173155_Annual_Report_10-K.indd 34

3/5/21 6:04 PM

locations with high COVID-19 infection rates deferred non-essential work and demobilized non-essential personnel to reduce

the COVID-19 exposure risk to our workforce.

Despite the challenges posed by the pandemic, progress continues on the FGP/WPMP project at Tengiz. In the second

quarter the project construction workforce was demobilized to 20 percent of planned levels, which slowed the overall

construction pace. In the third quarter, the rate of infections in Kazakhstan slowed, allowing remobilization of the FGP/

WPMP construction workforce to begin. In the fourth quarter, staffing levels at FGP/WPMP returned to 95 percent of desired

fourth quarter remobilization levels, however a worldwide resurgence of infections prevented the remaining 5 percent of the

workforce from returning to work and slowed progress on the project. Extended rotations, COVID testing and isolation

protocols are in place to minimize the spread of the virus. Given the uncertain timeline for remobilizing all personnel and

safely sustaining activity levels, it is too early to provide meaningful information regarding impacts on project cost and

schedule.

Facility maintenance turnarounds are being adjusted and, in certain cases, deferred into 2021. In some cases, turnarounds

have been extended in duration and/or reduced in scope in response to the pandemic. As a result of the reduction in capital

expenditures, new production is expected to be lower in the near term as drilling and completion activities are scaled back,

most notably in the Permian Basin, Gulf of Mexico, and Argentina. Exploration activities and projects not yet in execution

phase have been deferred, which may impact production in future years.

Production levels were curtailed in 2020 largely because of reductions imposed by OPEC+ nations in Kazakhstan, Nigeria

and Angola. In the fourth quarter, OPEC+ curtailments eased slightly relative to the third quarter. Production has also been

curtailed due to market conditions, most notably in Thailand. Additionally, operators of assets where the company has

non-operated interests also curtailed production. Production curtailments of approximately 106 thousand barrels of oil

equivalent per day were recorded in 2020. In the first quarter of 2021, we expect curtailments to be approximately

40 thousand barrels of oil equivalent per day, predominately related to OPEC+ restrictions.

Decreased capital expenditures, lower activity levels, delays in future development timing, and lower commodity prices have

resulted in reductions to Chevron’s proved reserve quantities for 2020. For more information on reserves, refer to Table V

beginning on page 103.

As some countries face a resurgence of the virus, regulatory and in-country conditions could impact logistics and material

movement and pose a risk to business continuity. We are taking precautionary measures to reduce the risk of exposure to and

spread of the COVID-19 virus through screening, testing and, when appropriate, quarantining workforce and visitors upon

arrival to our operated facilities.

business.

Refer to the “Results of Operations” section on pages 37 and 38 for additional discussion of the company’s upstream

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.

Response to Market Conditions and COVID-19: Downstream Beginning in March 2020 and continuing into the first quarter

2021, demand for refined products (primarily jet fuel and motor gasoline) has been below prior year levels as a result of

travel restrictions and other constraints on economic activity implemented in many countries to combat the spread of the

COVID-19 virus. Product prices also fell sharply, and although economic activity has somewhat rebounded from lows

experienced in April, refining margins continued to be at or near historic lows due to lower demand and pressure from

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

conditions that could lead to shut-in production; 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, but these too are

under pressure in the current market environment.

In the Partitioned Zone between Saudi Arabia and Kuwait, production was shut-in beginning in May 2015. In December

2019, the governments of Saudi Arabia and Kuwait signed a memorandum of understanding to allow production to restart in

the Partitioned Zone. In mid-February 2020, pre-startup activities commenced, and production resumed in July 2020. The

financial effects from the loss of production in 2019 and first half 2020 were not significant. During the fourth quarter 2020,

oil equivalent production in the Partitioned Zone averaged 40 thousand barrels per day.

Chevron has interests in Venezuelan crude oil assets,

including those operated by Petropiar, Petroboscan and

Petroindependiente. While the operating environment

in Venezuela has been deteriorating for some time, Petropiar,

Petroboscan, and Petroindependiente have conducted activities consistent with the authorization provided pursuant to general

licenses issued by the United States government. During the second quarter 2020, the company completed its evaluation of

the carrying value of its Venezuelan investments in line with its accounting policies and concluded that given the current

operating environment and overall outlook, which created significant uncertainties regarding the recovery of the company’s

investment, an other than temporary loss of value had occurred, which resulted in a full impairment of its investment in the

country totaling $2.6 billion and change in accounting treatment from equity method to non-equity method of accounting. As

a result, the company also removed approximately 160 million barrels of proved reserves and stopped reporting production in

the country effective July 2020. The company remains committed to its people, assets and operations in Venezuela.

Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil-equivalent at

year-end 2020, a decrease of 3 percent from year-end 2019. The reserve replacement ratio in 2020 was 74 percent. The 5 and

10 year reserve replacement ratios were 99 percent and 106 percent, respectively. Refer to Table V beginning on page 103

for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2018 and each

year-end from 2018 through 2020, and an accompanying discussion of major changes to proved reserves by geographic area

for the three-year period ending December 31, 2020.

Response to Market Conditions and COVID-19: Upstream Travel restrictions and other constraints on global economic

activity in 2020 in response to COVID-19 caused a significant decrease in demand for oil and gas. This led to lower price

realizations across all commodities. While critical asset integrity and reliability activities progressed throughout the year,

locations with high COVID-19 infection rates deferred non-essential work and demobilized non-essential personnel to reduce
the COVID-19 exposure risk to our workforce.

Despite the challenges posed by the pandemic, progress continues on the FGP/WPMP project at Tengiz. In the second
quarter the project construction workforce was demobilized to 20 percent of planned levels, which slowed the overall
construction pace. In the third quarter, the rate of infections in Kazakhstan slowed, allowing remobilization of the FGP/
WPMP construction workforce to begin. In the fourth quarter, staffing levels at FGP/WPMP returned to 95 percent of desired
fourth quarter remobilization levels, however a worldwide resurgence of infections prevented the remaining 5 percent of the
workforce from returning to work and slowed progress on the project. Extended rotations, COVID testing and isolation
protocols are in place to minimize the spread of the virus. Given the uncertain timeline for remobilizing all personnel and
safely sustaining activity levels, it is too early to provide meaningful information regarding impacts on project cost and
schedule.

Facility maintenance turnarounds are being adjusted and, in certain cases, deferred into 2021. In some cases, turnarounds
have been extended in duration and/or reduced in scope in response to the pandemic. As a result of the reduction in capital
expenditures, new production is expected to be lower in the near term as drilling and completion activities are scaled back,
most notably in the Permian Basin, Gulf of Mexico, and Argentina. Exploration activities and projects not yet in execution
phase have been deferred, which may impact production in future years.

Production levels were curtailed in 2020 largely because of reductions imposed by OPEC+ nations in Kazakhstan, Nigeria
and Angola. In the fourth quarter, OPEC+ curtailments eased slightly relative to the third quarter. Production has also been
curtailed due to market conditions, most notably in Thailand. Additionally, operators of assets where the company has
non-operated interests also curtailed production. Production curtailments of approximately 106 thousand barrels of oil
equivalent per day were recorded in 2020. In the first quarter of 2021, we expect curtailments to be approximately
40 thousand barrels of oil equivalent per day, predominately related to OPEC+ restrictions.

Decreased capital expenditures, lower activity levels, delays in future development timing, and lower commodity prices have
resulted in reductions to Chevron’s proved reserve quantities for 2020. For more information on reserves, refer to Table V
beginning on page 103.

As some countries face a resurgence of the virus, regulatory and in-country conditions could impact logistics and material
movement and pose a risk to business continuity. We are taking precautionary measures to reduce the risk of exposure to and
spread of the COVID-19 virus through screening, testing and, when appropriate, quarantining workforce and visitors upon
arrival to our operated facilities.

Refer to the “Results of Operations” section on pages 37 and 38 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.

Response to Market Conditions and COVID-19: Downstream Beginning in March 2020 and continuing into the first quarter
2021, demand for refined products (primarily jet fuel and motor gasoline) has been below prior year levels as a result of
travel restrictions and other constraints on economic activity implemented in many countries to combat the spread of the
COVID-19 virus. Product prices also fell sharply, and although economic activity has somewhat rebounded from lows
experienced in April, refining margins continued to be at or near historic lows due to lower demand and pressure from

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

a global oil product surplus. Chevron continued to take steps to maximize diesel production, given the decline in jet fuel and
motor gasoline demand, to fuel transportation that keeps global supply chains moving. The company is actively monitoring
supply and demand dynamics as every region is experiencing different recovery trends. The company is adjusting the
schedule for planned maintenance activity across its refining network and idling certain processing units to adjust for lower
demand, reduce costs, manage inventories and, most importantly, protect the safety of employees and contractors.

As of mid-February 2021, Chevron’s refining crude utilization was approximately 80 to 85 percent and sales were down
year-over-year approximately 50 percent for jet fuel, approximately 5 percent for motor gasoline, while diesel sales were
relatively flat. It is unclear how long these conditions will persist, but the company will continue to take actions necessary to
protect the health and well-being of people, the environment and its operations as conditions evolve. Refer to the “Results of
Operations” section on page 38 for additional discussion of the company’s downstream operations.

All Other consists of worldwide cash management and debt financing activities, corporate administrative functions,
insurance operations, real estate activities and technology companies.

Operating Developments

Key operating developments and other events during 2020 and early 2021 included the following:

Upstream

Azerbaijan Completed the sale of the company’s interest in the Azeri-Chirag-Gunashli fields and Baku-Tbilisi-Ceyhan
pipeline.

Colombia Completed the sale of the company’s interest in the offshore Chuchupa and onshore Ballena natural gas fields.

Philippines Completed the sale of the company’s interest in the Malampaya field in March.

United States Completed the acquisition of Noble Energy, Inc.

United States Completed the sale of the Appalachia natural gas business.

Downstream

Australia Completed the acquisition of Puma Energy (Australia) Holdings Pty Ltd.

Other

United States Chevron’s joint venture, CalBioGas LLC, successfully achieved first renewable natural gas production from
dairy farms in California and marketed it as an alternative fuel for heavy-duty trucks and buses.

United States Announced the formation of a joint venture with Brightmark LLC to produce and market renewable natural
gas.

United States Announced an investment in Zap Energy Inc., a start-up company developing a next-generation modular
nuclear reactor.

United States Announced an investment in Blue Planet Systems Corporation, a startup that manufactures and develops
carbonate aggregates and carbon capture technology intended to reduce the carbon intensity of industrial operations.

United States Announced an agreement with Algonquin Power & Utilities Corp. seeking to co-develop renewable power
projects that will provide electricity to strategic assets across Chevron’s global portfolio. Under the four-year agreement,
Chevron plans to generate more than 500 megawatts of its energy demand from renewable sources.

United States Announced a non-binding offer in February 2021 to acquire the outstanding common units of Noble
Midstream Partners LP not already owned by Chevron.

Common Stock Dividends The 2020 annual dividend was $5.16 per share, making 2020 the 33rd consecutive year that the
company increased its annual per share dividend payout. In January 2021, the company’s Board of Directors declared a
quarterly dividend of $1.29 per share.

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 74, 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 31 through 36. Refer to the “Selected Operating Data” table on page 41 for a

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

between 2019 and 2018 can be found in the “Results of Operations” section on pages 33 through 34 of the company’s 2019

Annual Report on Form 10-K filed with the SEC on February 22, 2020.

U.S. Upstream

Millions of dollars

Earnings (Loss)

2020

2019

(1,608)

(5,094) $

2018

3,278

U.S. upstream reported a loss of $1.61 billion in 2020, compared with a loss of $5.09 billion in 2019. The smaller loss was

largely due to the absence of fourth quarter 2019 impairment charges of $8.17 billion, primarily associated with Appalachia

shale and Big Foot, partially offset by lower crude oil realizations of $3.36 billion and second quarter 2020 impairments and

write-offs of $1.20 billion.

The company’s average realization for U.S. crude oil and natural gas liquids in 2020 was $30.53 per barrel compared with

$48.54 in 2019. The average natural gas realization was $0.98 per thousand cubic feet in 2020, compared with $1.09 in 2019.

Net oil-equivalent production in 2020 averaged 1.06 million barrels per day, up 14 percent from 2019. Production increases

from shale and tight properties in the Permian Basin and 58,000 barrels per day of production from the Noble acquisition

were partially offset by normal field declines.

The net liquids component of oil-equivalent production for 2020 averaged 790,000 barrels per day, up 9 percent from 2019.

Net natural gas production averaged 1.61 billion cubic feet per day in 2020, up 31 percent from 2019.

International Upstream

Millions of dollars

Earnings (Loss)*

*Includes foreign currency effects:

2020

(825)

(285)

2019

2018

7,670

10,038

(323) $

545

Common Stock Repurchase Program The company purchased $1.75 billion of its common stock in 2020 under its stock
repurchase programs. The stock repurchase program was suspended in March 2020.

International upstream reported a loss of $825 million in 2020, compared with earnings of $7.67 billion in 2019. The

decrease was primarily due to lower crude oil and natural gas realizations of $4.6 billion and $1.2 billion, respectively,

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a global oil product surplus. Chevron continued to take steps to maximize diesel production, given the decline in jet fuel and

motor gasoline demand, to fuel transportation that keeps global supply chains moving. The company is actively monitoring

supply and demand dynamics as every region is experiencing different recovery trends. The company is adjusting the

schedule for planned maintenance activity across its refining network and idling certain processing units to adjust for lower

demand, reduce costs, manage inventories and, most importantly, protect the safety of employees and contractors.

As of mid-February 2021, Chevron’s refining crude utilization was approximately 80 to 85 percent and sales were down

year-over-year approximately 50 percent for jet fuel, approximately 5 percent for motor gasoline, while diesel sales were

relatively flat. It is unclear how long these conditions will persist, but the company will continue to take actions necessary to

protect the health and well-being of people, the environment and its operations as conditions evolve. Refer to the “Results of

Operations” section on page 38 for additional discussion of the company’s downstream operations.

All Other consists of worldwide cash management and debt financing activities, corporate administrative functions,

insurance operations, real estate activities and technology companies.

Operating Developments

Key operating developments and other events during 2020 and early 2021 included the following:

Azerbaijan Completed the sale of the company’s interest in the Azeri-Chirag-Gunashli fields and Baku-Tbilisi-Ceyhan

Colombia Completed the sale of the company’s interest in the offshore Chuchupa and onshore Ballena natural gas fields.

Philippines Completed the sale of the company’s interest in the Malampaya field in March.

United States Completed the acquisition of Noble Energy, Inc.

United States Completed the sale of the Appalachia natural gas business.

Australia Completed the acquisition of Puma Energy (Australia) Holdings Pty Ltd.

United States Chevron’s joint venture, CalBioGas LLC, successfully achieved first renewable natural gas production from

dairy farms in California and marketed it as an alternative fuel for heavy-duty trucks and buses.

United States Announced the formation of a joint venture with Brightmark LLC to produce and market renewable natural

United States Announced an investment in Zap Energy Inc., a start-up company developing a next-generation modular

United States Announced an investment in Blue Planet Systems Corporation, a startup that manufactures and develops

carbonate aggregates and carbon capture technology intended to reduce the carbon intensity of industrial operations.

United States Announced an agreement with Algonquin Power & Utilities Corp. seeking to co-develop renewable power

projects that will provide electricity to strategic assets across Chevron’s global portfolio. Under the four-year agreement,

Chevron plans to generate more than 500 megawatts of its energy demand from renewable sources.

United States Announced a non-binding offer in February 2021 to acquire the outstanding common units of Noble

Midstream Partners LP not already owned by Chevron.

Common Stock Dividends The 2020 annual dividend was $5.16 per share, making 2020 the 33rd consecutive year that the

company increased its annual per share dividend payout. In January 2021, the company’s Board of Directors declared a

quarterly dividend of $1.29 per share.

Upstream

pipeline.

Downstream

Other

gas.

nuclear reactor.

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

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 74, 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 31 through 36. Refer to the “Selected Operating Data” table on page 41 for a
three-year comparison of production volumes, refined product sales volumes, and refinery inputs. A discussion of variances
between 2019 and 2018 can be found in the “Results of Operations” section on pages 33 through 34 of the company’s 2019
Annual Report on Form 10-K filed with the SEC on February 22, 2020.

U.S. Upstream

Millions of dollars

Earnings (Loss)

2020

2019

2018

(1,608)

(5,094) $

3,278

U.S. upstream reported a loss of $1.61 billion in 2020, compared with a loss of $5.09 billion in 2019. The smaller loss was
largely due to the absence of fourth quarter 2019 impairment charges of $8.17 billion, primarily associated with Appalachia
shale and Big Foot, partially offset by lower crude oil realizations of $3.36 billion and second quarter 2020 impairments and
write-offs of $1.20 billion.

The company’s average realization for U.S. crude oil and natural gas liquids in 2020 was $30.53 per barrel compared with
$48.54 in 2019. The average natural gas realization was $0.98 per thousand cubic feet in 2020, compared with $1.09 in 2019.

Net oil-equivalent production in 2020 averaged 1.06 million barrels per day, up 14 percent from 2019. Production increases
from shale and tight properties in the Permian Basin and 58,000 barrels per day of production from the Noble acquisition
were partially offset by normal field declines.

The net liquids component of oil-equivalent production for 2020 averaged 790,000 barrels per day, up 9 percent from 2019.
Net natural gas production averaged 1.61 billion cubic feet per day in 2020, up 31 percent from 2019.

International Upstream

Millions of dollars

Earnings (Loss)*

*Includes foreign currency effects:

2020

(825)

(285)

2019

2018

7,670

10,038

(323) $

545

Common Stock Repurchase Program The company purchased $1.75 billion of its common stock in 2020 under its stock

repurchase programs. The stock repurchase program was suspended in March 2020.

International upstream reported a loss of $825 million in 2020, compared with earnings of $7.67 billion in 2019. The
decrease was primarily due to lower crude oil and natural gas realizations of $4.6 billion and $1.2 billion, respectively,

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

higher charges of $1.4 billion for impairments and write-offs (charges of $3.6 billion in 2020 compared to $2.2 billion in
2019), and lower crude oil sales volumes of $1.1 billion. Lower gains on asset sales of $730 million also contributed to the
decrease and were largely offset by lower operating expenses of $710 million. Foreign currency effects had a favorable
impact on earnings of $38 million between periods.

The company’s average realization for international crude oil and natural gas liquids in 2020 was $36.07 per barrel compared
with $58.14 in 2019. The average natural gas realization was $4.59 per thousand cubic feet in 2020 compared with $5.83 in
2019.

International net oil-equivalent production was 2.03 million barrels per day in 2020, down 5 percent from 2019. The decrease
was due to production curtailments associated with OPEC+ restrictions and market conditions, and asset sale related
decreases of 94,000 barrels per day, partially offset by higher production entitlement effects and volumes associated with the
Noble acquisition.

The net liquids component of international oil-equivalent production was 1.08 million barrels per day in 2020, down
6 percent from 2019. International net natural gas production of 5.68 billion cubic feet per day in 2020 decreased 4 percent
from 2019.

U.S. Downstream

Millions of dollars

Earnings (Loss)

2020

2019

2018

(571)

1,559

2,103

U.S. downstream reported a loss of $571 million in 2020, compared with earnings of $1.56 billion in 2019. The decrease was
primarily due to lower margins on refined product sales of $1.08 billion and lower sales volumes of $1.00 billion. Lower
equity earnings from the 50 percent-owned CPChem of $220 million also contributed to the decrease. These were partially
offset by lower operating expenses of $220 million.

Total refined product sales of 1.00 million barrels per day in 2020 were down 20 percent from 2019, mainly due to lower jet
fuel, gasoline, and diesel demand associated with the COVID-19 pandemic.

Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2019 and

2018 can be found in the “Consolidated Statement of Income” section on pages 34 through 36 of the company’s 2019 Annual

Consolidated Statement of Income

Report on Form 10-K.

Millions of dollars

Sales and other operating revenues

and lower refined product volumes.

Millions of dollars

Income (loss) from equity affiliates

Sales and other operating revenues decreased in 2020 mainly due to lower refined product, crude oil and natural gas prices,

2020

2019

2018

94,471

139,865

158,902

2020

2019

(472)

3,968

2018

6,327

Income from equity affiliates decreased in 2020 mainly due to the full impairment of Petropiar and Petroboscan in Venezuela

and lower upstream-related earnings from Tengizchevroil in Kazakhstan.

Refer to Note 13, beginning on page 77, for a discussion of Chevron’s investments in affiliated companies.

Millions of dollars

Other income

2020

2019

693

2,683

2018

1,110

Other income decreased in 2020 mainly due to the absence of the receipt of the 2019 Anadarko merger termination fee, lower

gains on asset sales and unfavorable swings in foreign currency effects.

Millions of dollars

Purchased crude oil and products

2020

2019

2018

50,488

80,113

94,578

Crude oil and product purchases decreased $29.6 billion in 2020, primarily due to lower crude oil and refined product prices

and lower refined product and crude oil volumes.

Millions of dollars

Operating, selling, general and administrative expenses

International Downstream

Millions of dollars

Earnings*

*Includes foreign currency effects:

2020

618

(152)

2019

922

2018

1,695

Operating, selling, general and administrative expenses decreased $1.0 billion in 2020. The decrease is primarily due to

lower services and fees, expenses for non-operated upstream properties, materials and supplies expense and lower

transportation expense, partially offset by higher severance costs.

International downstream earned $618 million in 2020, compared with $922 million in 2019. The decrease in earnings was
largely due to lower margins on refined product sales of $160 million, primarily resulting from unfavorable inventory effects.
Unfavorable tax items of $110 million also contributed to the decrease. Partially offsetting the decrease in earnings were
lower operating expenses of $130 million. Foreign currency effects had an unfavorable impact on earnings of $169 million
between periods.

Total refined product sales of 1.22 million barrels per day in 2020 were down 8 percent from 2019, mainly due to lower jet
fuel demand associated with the COVID-19 pandemic.

Exploration expenses in 2020 increased primarily due to higher charges for well write-offs.

Depreciation, depletion and amortization expenses decreased in 2020 primarily due to lower impairments.

All Other

Millions of dollars

Net charges*

*Includes foreign currency effects:

2020

(3,157)

(208)

2019

2018

(2,133) $

(2,290)

(5)

Taxes other than on income increased in 2020 primarily due to higher regulatory expenses and property taxes, partially offset

by lower taxes on production, payroll tax and sales and use tax.

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 2020 increased $1.02 billion from 2019. The change between periods was mainly due to the absence of the
second quarter 2019 Anadarko merger termination fee, higher pension expenses, severance and Noble acquisition costs,
partially offset by the absence of a prior year tax charge and favorable tax items. Foreign currency effects increased net
charges by $210 million between periods.

38
Chevron Corporation 2020 Annual Report
38

Interest and debt expenses decreased in 2020 mainly due to lower interest rates, partially offset by higher debt balances.

Other components of net periodic benefit costs increased in 2020 primarily due to higher pension settlement costs.

Millions of dollars

Exploration expense

Millions of dollars

Depreciation, depletion and amortization

Millions of dollars

Taxes other than on income

Millions of dollars

Interest and debt expense

Millions of dollars

Other components of net periodic benefit costs

2020

2019

2018

24,536

25,528

24,382

2020

2019

1,537

770

2018

1,210

2020

2019

2018

19,508

29,218

19,419

2020

2019

4,499

4,136

2020

2019

697

798

2020

2019

880

417

2018

4,867

2018

748

2018

560

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

higher charges of $1.4 billion for impairments and write-offs (charges of $3.6 billion in 2020 compared to $2.2 billion in

2019), and lower crude oil sales volumes of $1.1 billion. Lower gains on asset sales of $730 million also contributed to the

decrease and were largely offset by lower operating expenses of $710 million. Foreign currency effects had a favorable

impact on earnings of $38 million between periods.

The company’s average realization for international crude oil and natural gas liquids in 2020 was $36.07 per barrel compared

with $58.14 in 2019. The average natural gas realization was $4.59 per thousand cubic feet in 2020 compared with $5.83 in

International net oil-equivalent production was 2.03 million barrels per day in 2020, down 5 percent from 2019. The decrease

was due to production curtailments associated with OPEC+ restrictions and market conditions, and asset sale related

decreases of 94,000 barrels per day, partially offset by higher production entitlement effects and volumes associated with the

The net liquids component of international oil-equivalent production was 1.08 million barrels per day in 2020, down

6 percent from 2019. International net natural gas production of 5.68 billion cubic feet per day in 2020 decreased 4 percent

2019.

Noble acquisition.

from 2019.

U.S. Downstream

Millions of dollars

Earnings (Loss)

2020

2019

(571)

1,559

2018

2,103

U.S. downstream reported a loss of $571 million in 2020, compared with earnings of $1.56 billion in 2019. The decrease was

primarily due to lower margins on refined product sales of $1.08 billion and lower sales volumes of $1.00 billion. Lower

equity earnings from the 50 percent-owned CPChem of $220 million also contributed to the decrease. These were partially

offset by lower operating expenses of $220 million.

Total refined product sales of 1.00 million barrels per day in 2020 were down 20 percent from 2019, mainly due to lower jet

fuel, gasoline, and diesel demand associated with the COVID-19 pandemic.

2020

618

(152)

2019

922

2018

1,695

International downstream earned $618 million in 2020, compared with $922 million in 2019. The decrease in earnings was

largely due to lower margins on refined product sales of $160 million, primarily resulting from unfavorable inventory effects.

Unfavorable tax items of $110 million also contributed to the decrease. Partially offsetting the decrease in earnings were

lower operating expenses of $130 million. Foreign currency effects had an unfavorable impact on earnings of $169 million

between periods.

Total refined product sales of 1.22 million barrels per day in 2020 were down 8 percent from 2019, mainly due to lower jet

fuel demand associated with the COVID-19 pandemic.

International Downstream

Millions of dollars

Earnings*

*Includes foreign currency effects:

All Other

Millions of dollars

Net charges*

*Includes foreign currency effects:

2020

(3,157)

(208)

2019

2018

(2,133) $

(2,290)

(5)

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 2020 increased $1.02 billion from 2019. The change between periods was mainly due to the absence of the

second quarter 2019 Anadarko merger termination fee, higher pension expenses, severance and Noble acquisition costs,

partially offset by the absence of a prior year tax charge and favorable tax items. Foreign currency effects increased net

charges by $210 million between periods.

Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2019 and
2018 can be found in the “Consolidated Statement of Income” section on pages 34 through 36 of the company’s 2019 Annual
Report on Form 10-K.

Millions of dollars

Sales and other operating revenues

2020

2019

2018

94,471

139,865

$ 158,902

Sales and other operating revenues decreased in 2020 mainly due to lower refined product, crude oil and natural gas prices,
and lower refined product volumes.

Millions of dollars

Income (loss) from equity affiliates

2020

2019

2018

(472)

3,968

6,327

Income from equity affiliates decreased in 2020 mainly due to the full impairment of Petropiar and Petroboscan in Venezuela
and lower upstream-related earnings from Tengizchevroil in Kazakhstan.

Refer to Note 13, beginning on page 77, for a discussion of Chevron’s investments in affiliated companies.

Millions of dollars

Other income

2020

2019

2018

693

2,683

1,110

Other income decreased in 2020 mainly due to the absence of the receipt of the 2019 Anadarko merger termination fee, lower
gains on asset sales and unfavorable swings in foreign currency effects.

Millions of dollars

Purchased crude oil and products

2020

2019

2018

50,488

80,113

94,578

Crude oil and product purchases decreased $29.6 billion in 2020, primarily due to lower crude oil and refined product prices
and lower refined product and crude oil volumes.

Millions of dollars

Operating, selling, general and administrative expenses

2020

2019

2018

24,536

25,528

24,382

Operating, selling, general and administrative expenses decreased $1.0 billion in 2020. The decrease is primarily due to
lower services and fees, expenses for non-operated upstream properties, materials and supplies expense and lower
transportation expense, partially offset by higher severance costs.

Millions of dollars

Exploration expense

2020

2019

2018

1,537

770

1,210

Exploration expenses in 2020 increased primarily due to higher charges for well write-offs.

Millions of dollars

Depreciation, depletion and amortization

2020

2019

2018

19,508

29,218

19,419

Depreciation, depletion and amortization expenses decreased in 2020 primarily due to lower impairments.

Millions of dollars

Taxes other than on income

2020

2019

2018

4,499

4,136

4,867

Taxes other than on income increased in 2020 primarily due to higher regulatory expenses and property taxes, partially offset
by lower taxes on production, payroll tax and sales and use tax.

Millions of dollars

Interest and debt expense

2020

2019

697

798

Interest and debt expenses decreased in 2020 mainly due to lower interest rates, partially offset by higher debt balances.

Millions of dollars

Other components of net periodic benefit costs

2020

2019

880

417

Other components of net periodic benefit costs increased in 2020 primarily due to higher pension settlement costs.

2018

748

2018

560

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

Millions of dollars

Income tax expense (benefit)

2020

2019

2018

(1,892)

2,691

5,715

Selected Operating Data1,2

The decrease in income tax expense in 2020 of $4.58 billion is due to the decrease in total income before tax for the company
of $12.99 billion. The decrease in income before taxes for the company is primarily the result of lower crude oil prices
partially offset by lower impairments and project write off charges.

U.S. income before tax decreased from a loss of $5.48 billion in 2019 to a loss of $5.70 billion in 2020. This decrease in
earnings before tax was primarily driven by the effect of lower crude oil prices in the U.S. and the absence of the Anadarko
merger fee, partially offset by lower impairment charges and higher production. The U.S. tax benefit increased from
$1.17 billion in 2019 to $1.58 billion in 2020 primarily due to the increase in before-tax loss.

International income before tax decreased from $11.02 billion in 2019 to a loss of $1.75 billion in 2020. This decrease was
primarily driven by the effect of lower crude oil and natural gas prices, lower production, higher impairments and other
charges. The lower before-tax income primarily drove the $4.17 billion decrease in international income tax expense, from a
charge of $3.86 billion in 2019 to a benefit of $308 million in 2020.

Refer also to the discussion of the effective income tax rate in Note 15 beginning on page 79.

U.S. Upstream

Net Crude Oil and Natural Gas Liquids Production (MBPD)

2019

2018

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):

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.

379

373

48.54

1.09

58.14

5.83

724

1,225

929

4,016

130

1,141

5,932

2,129

5,869

929

2,129

3,058

667

583

1,250

101

947

289

1,038

1,327

617

602

618

1,034

791

3,481

110

58.17

1.86

1,164

5,855

2,139

5,604

64.25

6.29

791

2,139

2,930

627

591

1,218

905

336

1,101

1,437

706

584

2020

790

1,607

1,058

3,894

208

30.53

0.98

1,078

5,683

2,025

5,634

36.07

4.59

1,058

2,025

3,083

581

422

1,003

793

264

957

1,221

584

566

—

348

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

Millions of dollars

Income tax expense (benefit)

2020

2019

(1,892)

2,691

2018

5,715

Selected Operating Data1,2

The decrease in income tax expense in 2020 of $4.58 billion is due to the decrease in total income before tax for the company

of $12.99 billion. The decrease in income before taxes for the company is primarily the result of lower crude oil prices

partially offset by lower impairments and project write off charges.

U.S. income before tax decreased from a loss of $5.48 billion in 2019 to a loss of $5.70 billion in 2020. This decrease in

earnings before tax was primarily driven by the effect of lower crude oil prices in the U.S. and the absence of the Anadarko

merger fee, partially offset by lower impairment charges and higher production. The U.S. tax benefit increased from

$1.17 billion in 2019 to $1.58 billion in 2020 primarily due to the increase in before-tax loss.

International income before tax decreased from $11.02 billion in 2019 to a loss of $1.75 billion in 2020. This decrease was

primarily driven by the effect of lower crude oil and natural gas prices, lower production, higher impairments and other

charges. The lower before-tax income primarily drove the $4.17 billion decrease in international income tax expense, from a

charge of $3.86 billion in 2019 to a benefit of $308 million in 2020.

Refer also to the discussion of the effective income tax rate in Note 15 beginning on page 79.

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

2018

2020

790
1,607
1,058
3,894
208

724
1,225
929
4,016
130

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

$
$

30.53
0.98

$
$

48.54
1.09

$
$

1,078
5,683
2,025
5,634
46

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

$
$

36.07
4.59

$
$

58.14
5.83

$
$

1,058
2,025

3,083

581
422

1,003
25
793

264
957

1,221
74
584

929
2,129

3,058

667
583

1,250
101
947

289
1,038

1,327
72
617

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

37
566

54
—

36
602

53
3

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.

348

379

35
584

53
24

373

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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 $5.6 billion and $5.7 billion at
December 31, 2020 and 2019, respectively. Cash provided by operating activities in 2020 was $10.6 billion, compared to
$27.3 billion in 2019, primarily due to lower crude oil prices. Cash provided by operating activities was net of contributions
to employee pension plans of approximately $1.2 billion in 2020 and $1.4 billion in 2019. Cash provided by investing
activities included proceeds and deposits related to asset sales of $2.9 billion in 2020 and $2.8 billion in 2019.

Restricted cash of $1.1 billion and $1.2 billion at December 31, 2020 and 2019, 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 $9.7 billion in 2020 and $9.0 billion in 2019.

page 83.

Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $44.3 billion at December 31, 2020, up
from $27.0 billion at year-end 2019.

The $17.3 billion increase in total debt and finance lease liabilities during 2020 was primarily due to the company’s issuance
of long-term public bonds of $8.0 billion in May 2020 and $4.0 billion in August 2020, and the assumption of debt with a
fair value of $9.4 billion as part of the transaction to acquire Noble in October 2020. In January 2021, Chevron U.S.A. Inc.
(CUSA) issued bonds, guaranteed by Chevron Corporation, in exchange for the Noble debt. More information on bond
issuances is included in Note 18 on page 84. These amounts were partially offset by repayment of long-term notes that
matured in 2020. 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 $11.4 billion at December 31,
2020, compared with $13.0 billion at year-end 2019. Of these amounts, $9.825 billion and $9.75 billion were reclassified to
long-term debt at the end of 2020 and 2019, respectively.

At year-end 2020, settlement of these obligations was not expected to require the use of working capital in 2021, as the
company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

The company has an automatic shelf registration statement that expires in August 2023 for an unspecified amount of
nonconvertible debt securities issued by Chevron Corporation or CUSA.

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,

CUSA, Noble and Texaco Capital Inc. Most 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, lending commitments to affiliates 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 has the flexibility to 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

Summarized Financial Information for Guarantee of Securities of Subsidiaries In August 2020, long-term public bonds

were issued by CUSA and fully and unconditionally guaranteed on an unsecured basis by Chevron Corporation (together the

“Obligor Group”). In March 2020, the U.S. Securities and Exchange Commission (SEC) issued a final rule that amended the

disclosure requirements with respect to certain guaranteed securities registered or being registered in Rule 3-10 of Regulation

S-X and adopted new Rule 13-01 of Regulation S-X. These amendments were effective January 4, 2021. Accordingly, as

disclosed in the tables below, summary financial information is presented for Chevron Corporation, as Guarantor, excluding

its consolidated subsidiaries, and CUSA, as the issuer, excluding its consolidated subsidiaries. The summary financial

information of the Obligor Group is presented on a combined basis and transactions between the combined entities have been

eliminated. Financial information for non-guarantor entities has been excluded.

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Sales and other operating revenues

Sales and other operating revenues – related party

Total costs and other deductions

Total costs and other deductions – related party

Net income (loss)

Current assets

Current assets – related party

Other assets

Current liabilities

Current liabilities – related party

Other liabilities

Total net equity (deficit)

Year Ended

December 31, 2020

December 31, 2019

(Millions of dollars) (unaudited)

At December 31,

(Millions of dollars) (unaudited)

49,636

17,044

57,575

14,052

(1,610) $

2020

9,196

5,719

48,993

20,965

55,273

34,983

82,206

24,336

87,287

22,632

2,173

2019

10,180

952

50,595

25,187

46,237

25,622

(47,313) $

(35,319)

Common 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, 2020,

the company had purchased a total of 48.6 million shares for $5.5 billion, resulting in $19.5 billion remaining under the

program authorized in February 2019. On March 24, 2020, the company announced the suspension of the stock repurchase

program in response to depressed market conditions following the global outbreak of the COVID-19 pandemic. No shares

were purchased under the program after this announcement.

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

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 $5.6 billion and $5.7 billion at

December 31, 2020 and 2019, respectively. Cash provided by operating activities in 2020 was $10.6 billion, compared to

$27.3 billion in 2019, primarily due to lower crude oil prices. Cash provided by operating activities was net of contributions

to employee pension plans of approximately $1.2 billion in 2020 and $1.4 billion in 2019. Cash provided by investing

activities included proceeds and deposits related to asset sales of $2.9 billion in 2020 and $2.8 billion in 2019.

Restricted cash of $1.1 billion and $1.2 billion at December 31, 2020 and 2019, 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 $9.7 billion in 2020 and $9.0 billion in 2019.

Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $44.3 billion at December 31, 2020, up

from $27.0 billion at year-end 2019.

The $17.3 billion increase in total debt and finance lease liabilities during 2020 was primarily due to the company’s issuance

of long-term public bonds of $8.0 billion in May 2020 and $4.0 billion in August 2020, and the assumption of debt with a

fair value of $9.4 billion as part of the transaction to acquire Noble in October 2020. In January 2021, Chevron U.S.A. Inc.

(CUSA) issued bonds, guaranteed by Chevron Corporation, in exchange for the Noble debt. More information on bond

issuances is included in Note 18 on page 84. These amounts were partially offset by repayment of long-term notes that

matured in 2020. 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 $11.4 billion at December 31,

2020, compared with $13.0 billion at year-end 2019. Of these amounts, $9.825 billion and $9.75 billion were reclassified to

long-term debt at the end of 2020 and 2019, respectively.

At year-end 2020, settlement of these obligations was not expected to require the use of working capital in 2021, as the

company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

The company has an automatic shelf registration statement that expires in August 2023 for an unspecified amount of

nonconvertible debt securities issued by Chevron Corporation or CUSA.

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,
CUSA, Noble and Texaco Capital Inc. Most 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, lending commitments to affiliates 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 has the flexibility to 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 83.

Summarized Financial Information for Guarantee of Securities of Subsidiaries In August 2020, long-term public bonds
were issued by CUSA and fully and unconditionally guaranteed on an unsecured basis by Chevron Corporation (together the
“Obligor Group”). In March 2020, the U.S. Securities and Exchange Commission (SEC) issued a final rule that amended the
disclosure requirements with respect to certain guaranteed securities registered or being registered in Rule 3-10 of Regulation
S-X and adopted new Rule 13-01 of Regulation S-X. These amendments were effective January 4, 2021. Accordingly, as
disclosed in the tables below, summary financial information is presented for Chevron Corporation, as Guarantor, excluding
its consolidated subsidiaries, and CUSA, as the issuer, excluding its consolidated subsidiaries. The summary financial
information of the Obligor Group is presented on a combined basis and transactions between the combined entities have been
eliminated. Financial information for non-guarantor entities has been excluded.

Sales and other operating revenues
Sales and other operating revenues – related party
Total costs and other deductions
Total costs and other deductions – related party
Net income (loss)

Current assets
Current assets – related party
Other assets
Current liabilities
Current liabilities – related party
Other liabilities

Total net equity (deficit)

Year Ended
December 31, 2020

Year Ended
December 31, 2019
(Millions of dollars) (unaudited)

49,636 $
17,044
57,575
14,052
(1,610) $

82,206
24,336
87,287
22,632
2,173

At December 31,
2020

At December 31,
2019
(Millions of dollars) (unaudited)

9,196
5,719
48,993
20,965
55,273
34,983

10,180
952
50,595
25,187
46,237
25,622

(47,313) $

(35,319)

Common 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, 2020,
the company had purchased a total of 48.6 million shares for $5.5 billion, resulting in $19.5 billion remaining under the
program authorized in February 2019. On March 24, 2020, the company announced the suspension of the stock repurchase
program in response to depressed market conditions following the global outbreak of the COVID-19 pandemic. No shares
were purchased under the program after this announcement.

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

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

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 2020, 2019 and 2018 are as follows:

Millions of dollars

U.S.

Int’l.

2020
Total

U.S.

Int’l.

2019
Total

U.S.

Int’l.

2018
Total

Upstream
Downstream
All Other

Total

$ 5,130
1,021
226

$ 5,784
1,325
13

$10,914
2,346
239

$ 8,197
1,868
365

$ 9,627
920
17

$17,824
2,788
382

$ 7,128
1,582
243

$ 10,529
611
13

$ 17,657
2,193
256

$ 6,377

$ 7,122

$13,499

$ 10,430

$ 10,564

$20,994

$ 8,953

$ 11,153

$ 20,106

Total, Excluding Equity in Affiliates

$ 6,053

$ 3,464

$ 9,517

$ 10,062

$ 4,820

$14,882

$ 8,651

$ 5,739

$ 14,390

Total reported expenditures for 2020 were $13.5 billion, including $4.0 billion for the company’s share of equity-affiliate
expenditures, which did not require cash outlays by the company. The acquisition of Noble is not included in the company’s
capital and exploratory expenditures. For more information on the Noble acquisition, see page 96 in Note 29. In 2019,
expenditures were $21.0 billion, including the company’s share of affiliates’ expenditures of $6.1 billion.

Of the $13.5 billion of expenditures in 2020, 81 percent, or $10.9 billion, related to upstream activities. Approximately
85 percent was expended for upstream operations in 2019. International upstream accounted for 53 percent of the worldwide
upstream investment in 2020 and 54 percent in 2019.

The company estimates that 2021 organic capital and exploratory expenditures will be $14 billion, including $4.2 billion of
spending by affiliates. This is in line with 2020 expenditures, and reflects a robust portfolio of upstream and downstream
investments, highlighted by the FGP/WPMP project at the Tengiz field in Kazakhstan and the company’s Permian Basin
position. In the upstream business, approximately $6.5 billion is allocated to currently producing assets, including about
$2.0 billion for Permian unconventional development. Approximately $3.5 billion of the upstream program is planned for
major capital projects underway, of which about 75 percent is associated with FGP/WPMP at the Tengiz field in Kazakhstan.
Additionally, $1.5 billion is allocated to exploration, early stage development projects, and midstream activities. The
company monitors crude oil market conditions and is able to adjust future capital outlays should oil price conditions
deteriorate.

Worldwide downstream spending in 2021 is estimated to be $2.1 billion, with $1.2 billion estimated for projects in the
United States.

Investments in technology businesses and other corporate operations in 2021 are budgeted at $0.4 billion.

Noncontrolling Interests The company had noncontrolling interests of $1.0 billion at December 31, 2020 and $1.0 billion at
December 31, 2019. Distributions to noncontrolling interests totaled $24 million and $18 million in 2020 and 2019,
respectively. Included within noncontrolling interests for 2020 is $120 million of redeemable noncontrolling interest
associated with Noble Midstream.

Pension Obligations Information related to pension plan contributions is included beginning on page 87 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 2020, the book value of inventory was lower than replacement costs,

based on average acquisition costs during the year, by approximately $2.7 billion.

Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized

interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the

company’s ability to pay interest on outstanding debt. The company’s interest coverage ratio in 2020 was lower than 2019

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

2019.

Millions of dollars

Short-term debt

Long-term debt

Total debt

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 25.2 percent at year-end 2020, compared with 15.8 percent at year-end

Total Chevron Corporation Stockholders’ Equity

131,688

144,213

154,554

Total debt plus total Chevron Corporation Stockholders’ Equity

176,003

171,186

189,013

Debt Ratio

25.2 %

15.8 %

18.2 %

At December 31

2018

34,021

27,171

1.3

2019

28,329

26,530

1.1

Year ended December 31

2020

2019

2018

(7,453)

5,536

20,575

Year ended December 31

798

240

(79)

6,653

817

8.1

2019

27,314

14,116

13,198

2019

3,282

23,691

26,973

748

280

21,567

921

23.4

2018

30,618

13,792

16,826

2018

5,726

28,733

34,459

At December 31

2020

26,078

22,183

1.2

697

205

(18)

(6,533)

735

(8.9)

2020

10,577

8,922

1,655

2020

1,548

42,767

44,315

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

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

Financial Ratios and Metrics

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 2020, 2019 and 2018 are as follows:

Millions of dollars

Upstream

Downstream

All Other

Total

2020

Total

2,346

239

U.S.

8,197

1,868

365

Int’l.

920

2019

Total

2,788

382

U.S.

7,128

1,582

243

Int’l.

611

2018

Total

2,193

256

$10,914

9,627

$17,824

$ 10,529

$ 17,657

7,122

$13,499

$ 10,430

$ 10,564

$20,994

8,953

$ 11,153

$ 20,106

Int’l.

5,784

1,325

U.S.

5,130

1,021

226

6,377

6,053

Total, Excluding Equity in Affiliates

3,464

$ 9,517

$ 10,062

4,820

$14,882

8,651

5,739

$ 14,390

Total reported expenditures for 2020 were $13.5 billion, including $4.0 billion for the company’s share of equity-affiliate

expenditures, which did not require cash outlays by the company. The acquisition of Noble is not included in the company’s

capital and exploratory expenditures. For more information on the Noble acquisition, see page 96 in Note 29. In 2019,

expenditures were $21.0 billion, including the company’s share of affiliates’ expenditures of $6.1 billion.

Of the $13.5 billion of expenditures in 2020, 81 percent, or $10.9 billion, related to upstream activities. Approximately

85 percent was expended for upstream operations in 2019. International upstream accounted for 53 percent of the worldwide

upstream investment in 2020 and 54 percent in 2019.

The company estimates that 2021 organic capital and exploratory expenditures will be $14 billion, including $4.2 billion of

spending by affiliates. This is in line with 2020 expenditures, and reflects a robust portfolio of upstream and downstream

investments, highlighted by the FGP/WPMP project at the Tengiz field in Kazakhstan and the company’s Permian Basin

position. In the upstream business, approximately $6.5 billion is allocated to currently producing assets, including about

$2.0 billion for Permian unconventional development. Approximately $3.5 billion of the upstream program is planned for

major capital projects underway, of which about 75 percent is associated with FGP/WPMP at the Tengiz field in Kazakhstan.

Additionally, $1.5 billion is allocated to exploration, early stage development projects, and midstream activities. The

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

deteriorate.

United States.

Worldwide downstream spending in 2021 is estimated to be $2.1 billion, with $1.2 billion estimated for projects in the

Investments in technology businesses and other corporate operations in 2021 are budgeted at $0.4 billion.

Noncontrolling Interests The company had noncontrolling interests of $1.0 billion at December 31, 2020 and $1.0 billion at

December 31, 2019. Distributions to noncontrolling interests totaled $24 million and $18 million in 2020 and 2019,

respectively. Included within noncontrolling interests for 2020 is $120 million of redeemable noncontrolling interest

associated with Noble Midstream.

Pension Obligations Information related to pension plan contributions is included beginning on page 87 in Note 21,

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

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 2020, the book value of inventory was lower than replacement costs,
based on average acquisition costs during the year, by approximately $2.7 billion.

Millions of dollars

Current assets
Current liabilities

Current Ratio

2020

26,078
22,183

1.2

2019

28,329
26,530

1.1

At December 31
2018

34,021
27,171

1.3

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 2020 was lower than 2019
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

2020

(7,453)
697
205
(18)

(6,533)

735

(8.9)

Year ended December 31
2018

2019

5,536
798
240
(79)

6,653

817

8.1

20,575
748
280
36

21,567

921

23.4

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

2020

10,577
8,922

Year ended December 31
2018

2019

27,314
14,116

30,618
13,792

1,655

13,198

16,826

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 25.2 percent at year-end 2020, compared with 15.8 percent at year-end
2019.

Millions of dollars

Short-term debt
Long-term debt

Total debt

2020

1,548
42,767

44,315

2019

3,282
23,691

26,973

At December 31
2018

5,726
28,733

34,459

Total Chevron Corporation Stockholders’ Equity

131,688

144,213

154,554

Total debt plus total Chevron Corporation Stockholders’ Equity

176,003

171,186

189,013

Debt Ratio

25.2 %

15.8 %

18.2 %

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

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.

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

2020

1,548
42,767

44,315

5,596
—
31

38,688

131,688

At December 31
2018

5,726
28,733

34,459

9,342
950
53

2019

3,282
23,691

26,973

5,686
—
63

21,224

24,114

144,213

154,554

Total adjusted debt plus total Chevron Corporation Stockholders’ Equity

170,376

165,437

178,668

Net Debt Ratio

22.7 %

12.8 %

13.5 %

Information on ARO’s is contained in Note 23 beginning on page 94

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

or liquidity in any single period.

Millions of dollars

Chevron Corporation Stockholders’ Equity

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

2020

131,688
1,548
42,767
1,038

At December 31
2018

2019

144,213
3,282
23,691
995

154,554
5,726
28,733
1,088

Capital Employed at December 31

177,041

172,181

190,101

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

2020

(5,543)
658
(18)

(4,903)

Year ended December 31
2018

2019

2,924
761
(79)

3,606

14,824
713
36

15,573

$ 174,611

181,141

189,092

(2.8) %

2.0 %

8.2 %

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

2020

Year ended December 31
2018

2019

(5,543)
131,688
137,951

2,924
144,213
149,384

14,824
154,554
151,339

Return on Average Stockholders’ Equity

(4.0) %

2.0 %

9.8 %

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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 92 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

2021

2022-2023

2024-2025 After 2025

Payments Due by Period

1,362

$ 1,362

— $

—

40,732

5,119

9,357

13,186

1,464

—

1,580

866

817

211

21,848

1,394

1,469

2,045

468

5,650

702

1,105

2,236

489

13,234

1,443

5,917

8,088

296

1. Excludes contributions for pensions and other postretirement benefit plans and ARO. Information on employee benefit plans is contained in Note 21 beginning on page 87.

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

3. $9.825 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 2022–2023 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

Commitments.

Guarantee of nonconsolidated affiliate or joint-venture obligations

391

176

Additional information related to guarantees is included on page 92 in Note 22, Other Contingencies and Commitments.

Indemnifications Information related to indemnifications is included on page 92 in Note 22, Other Contingencies and

Total

2021

2022-2023

2024-2025 After 2025

Commitment Expiration by Period

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, liquefied natural

gas 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 2020.

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 2020 was not material to the company’s results of operations.

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.

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

Total adjusted debt plus total Chevron Corporation Stockholders’ Equity

170,376

165,437

178,668

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.

2020

1,548

42,767

44,315

5,596

—

38,688

131,688

At December 31

2018

5,726

28,733

34,459

9,342

950

24,114

154,554

2019

3,282

23,691

26,973

5,686

—

21,224

144,213

2020

2019

2018

At December 31

131,688

144,213

154,554

1,548

42,767

1,038

3,282

23,691

995

5,726

28,733

1,088

177,041

172,181

190,101

Year ended December 31

2020

2019

2018

(5,543)

2,924

14,824

658

(18)

761

(79)

713

(4,903)

3,606

15,573

174,611

181,141

189,092

(2.8) %

2.0 %

8.2 %

Year ended December 31

2020

2019

2018

(5,543)

2,924

14,824

131,688

137,951

144,213

149,384

154,554

151,339

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

(4.0) %

2.0 %

9.8 %

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 92 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

1,362
40,732
5,119
9,357

13,186
1,464

Payments Due by Period
2021 2022-2023 2024-2025 After 2025

$ 1,362
—
1,580
866

$ —
21,848
1,394
1,469

$ —
5,650
702
1,105

$ —
13,234
1,443
5,917

817
211

2,045
468

2,236
489

8,088
296

Net Debt Ratio

22.7 %

12.8 %

13.5 %

Information on ARO’s is contained in Note 23 beginning on page 94

1. Excludes contributions for pensions and other postretirement benefit plans and ARO. Information on employee benefit plans is contained in Note 21 beginning on page 87.

2. Does not include amounts related to the company’s income tax liabilities associated with uncertain tax positions. The company is unable to make reasonable estimates of the
periods in which such liabilities may become payable. The company does not expect settlement of such liabilities to have a material effect on its consolidated financial position
or liquidity in any single period.

3. $9.825 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 2022–2023 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

2021

Commitment Expiration by Period
2024-2025 After 2025

2022-2023

Guarantee of nonconsolidated affiliate or joint-venture obligations

391

176

Additional information related to guarantees is included on page 92 in Note 22, Other Contingencies and Commitments.

Indemnifications Information related to indemnifications is included on page 92 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, liquefied natural
gas 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 2020.

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 2020 was not material to the company’s results of operations.

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Management’s Discussion and Analysis of Financial Condition and 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 percent confidence level with a one-day holding period, from the effect of adverse changes in
market conditions on derivative commodity instruments held or issued. Based on these inputs, the VaR for the company’s
primary risk exposures in the area of derivative commodity instruments at December 31, 2020 and 2019 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 material open foreign currency
derivative contracts at December 31, 2020.

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 2020, 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 77, 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 78 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 78.

Environmental The following table displays the annual changes to the company’s before-tax environmental remediation
reserves, including those for U.S. federal Superfund sites and analogous sites under state laws.

Millions of dollars

Balance at January 1
Net Additions
Expenditures

Balance at December 31

2020

1,234
179
(274)

2019

1,327
200
(293)

2018

1,429
197
(299)

1,139

1,234

1,327

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 $13.6 billion for asset retirement obligations at year-end 2020
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 2020 environmental expenditures. Refer to Note 22 on page 93 for additional discussion of environmental
remediation provisions and year-end reserves. Refer also to Note 23 on page 94 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 85.

information becomes known.

Income Taxes Information related to income tax contingencies is included on pages 79 through 82 in Note 15 and page 92 in
Note 22 under the heading “Income Taxes.”

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:

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Other Contingencies Information related to other contingencies is included on page 93 in Note 22 to the Consolidated

Financial Statements under the heading “Other Contingencies.”

Environmental Matters

The company is subject to various international, federal, state and local environmental, health and safety laws, regulations

and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both

number and complexity over time and govern not only the manner in which the company conducts its operations, but also the

products it sells. For example, international agreements 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 23 of the company’s Annual Report on Form 10-K for a discussion of some of the inherent

risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of

operations or financial condition.

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 2020 at approximately $2.0 billion for its consolidated companies. Included in these expenditures

were approximately $0.5 billion of environmental capital expenditures and $1.5 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 2021, total worldwide environmental capital expenditures are estimated at $0.5 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

Management’s Discussion and Analysis of Financial Condition and 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 percent confidence level with a one-day holding period, from the effect of adverse changes in

market conditions on derivative commodity instruments held or issued. Based on these inputs, the VaR for the company’s

primary risk exposures in the area of derivative commodity instruments at December 31, 2020 and 2019 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 material open foreign currency

derivative contracts at December 31, 2020.

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 2020, 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 77, 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 78 in Note 14 under the

Ecuador Information related to Ecuador matters is included in Note 14 under the heading “Ecuador,” beginning on page 78.

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

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

Millions of dollars

Balance at January 1

Net Additions

Expenditures

Balance at December 31

1,234

1,327

2019

200

(293)

2018

1,429

197

(299)

2020

179

(274)

1,139

1,234

1,327

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 $13.6 billion for asset retirement obligations at year-end 2020

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 2020 environmental expenditures. Refer to Note 22 on page 93 for additional discussion of environmental

remediation provisions and year-end reserves. Refer also to Note 23 on page 94 for additional discussion of the company’s

asset retirement obligations.

Wells, beginning on page 85.

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 79 through 82 in Note 15 and page 92 in

Note 22 under the heading “Income Taxes.”

Other Contingencies Information related to other contingencies is included on page 93 in Note 22 to the Consolidated
Financial Statements under the heading “Other Contingencies.”

Environmental Matters

The company is subject to various international, federal, state and local environmental, health and safety laws, regulations
and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both
number and complexity over time and govern not only the manner in which the company conducts its operations, but also the
products it sells. For example, international agreements 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 23 of the company’s Annual Report on Form 10-K for a discussion of some of the inherent
risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of
operations or financial condition.

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 2020 at approximately $2.0 billion for its consolidated companies. Included in these expenditures
were approximately $0.5 billion of environmental capital expenditures and $1.5 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 2021, total worldwide environmental capital expenditures are estimated at $0.5 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:

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

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 2020, Chevron’s UOP Depreciation, Depletion and Amortization
(DD&A) for oil and gas properties was $13.0 billion, and proved developed reserves at the beginning of 2020
were 6.4 billion barrels for consolidated companies. If the estimates of proved reserves used in the UOP
calculations for consolidated operations had been lower by 5 percent across all oil and gas properties, UOP
DD&A in 2020 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 103, for the changes in proved reserve estimates for
the three years ended December 31, 2020, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net
Cash Flows From Proved Reserves” on page 111 for estimates of proved reserve values for each of the three years ended
December 31, 2020.

This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of
Note 1, beginning on page 64, 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 82 and to the section on Properties, Plant and Equipment in Note 1, “Summary of Significant Accounting
Policies,” beginning on page 64.

The company performs impairment assessments when triggering events arise to determine whether any write-down in the

carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and

natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the

carrying value of the asset remains recoverable. Similarly, a significant downward revision in the company’s crude oil or

natural gas price outlook would trigger impairment reviews for impacted upstream assets. In addition, impairments could

occur due to changes in national, state or local environmental regulations or laws, including those designed to stop or impede

the development or production of oil and gas. Also, if the expectation of sale of a particular asset or asset group in any period

has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the

carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until

the asset or asset group is disposed. 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 2020, the company recorded impairments and write-offs for certain oil and gas properties primarily due to downward

revisions to its oil and gas price outlook. In addition, the company fully impaired its investments in Petropiar and

Petroboscan after completing an evaluation of the carrying value of its Venezuelan investments in line with its accounting

policies and concluding that given the current operating environment and overall outlook, which create significant

uncertainties regarding the recovery of the company’s investment, an other than temporary loss of value had occurred.

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 reduced 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.

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 2020 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 94 for additional discussions on asset

retirement obligations.

assumptions.

Pension and Other Postretirement Benefit Plans Note 21, beginning on page 87, 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 89 in

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

beyond the company’s control.

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

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 2020, Chevron’s UOP Depreciation, Depletion and Amortization

(DD&A) for oil and gas properties was $13.0 billion, and proved developed reserves at the beginning of 2020

were 6.4 billion barrels for consolidated companies. If the estimates of proved reserves used in the UOP

calculations for consolidated operations had been lower by 5 percent across all oil and gas properties, UOP

DD&A in 2020 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 103, for the changes in proved reserve estimates for

the three years ended December 31, 2020, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net

Cash Flows From Proved Reserves” on page 111 for estimates of proved reserve values for each of the three years ended

December 31, 2020.

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

Note 1, beginning on page 64, 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 82 and to the section on Properties, Plant and Equipment in Note 1, “Summary of Significant Accounting

Policies,” beginning on page 64.

The company performs impairment assessments when triggering events arise to determine whether any write-down in the
carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and
natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the
carrying value of the asset remains recoverable. Similarly, a significant downward revision in the company’s crude oil or
natural gas price outlook would trigger impairment reviews for impacted upstream assets. In addition, impairments could
occur due to changes in national, state or local environmental regulations or laws, including those designed to stop or impede
the development or production of oil and gas. Also, if the expectation of sale of a particular asset or asset group in any period
has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the
carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until
the asset or asset group is disposed. 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 2020, the company recorded impairments and write-offs for certain oil and gas properties primarily due to downward
revisions to its oil and gas price outlook. In addition, the company fully impaired its investments in Petropiar and
Petroboscan after completing an evaluation of the carrying value of its Venezuelan investments in line with its accounting
policies and concluding that given the current operating environment and overall outlook, which create significant
uncertainties regarding the recovery of the company’s investment, an other than temporary loss of value had occurred.

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 reduced 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.

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 2020 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 94 for additional discussions on asset
retirement obligations.

Pension and Other Postretirement Benefit Plans Note 21, beginning on page 87, 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 89 in
Note 21 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes
beyond the company’s control.

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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 23 of the company’s Annual Report on Form 10-K.

New Accounting Standards

Refer to Note 4 beginning on page 69 for information regarding new accounting standards.

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

For 2020, the company used an expected long-term rate of return of 6.5 percent and a discount rate for service costs of
3.3 percent and a discount rate for interest cost of 2.6 percent for the primary U.S. pension plan. The actual return for 2020
was 9.4 percent. For the 10 years ended December 31, 2020, actual asset returns averaged 7.9 percent for this plan.
Additionally, with the exception of three years within this 10-year period, actual asset returns for this plan equaled or
exceeded 6.5 percent during each year.

Total pension expense for 2020 was $1.5 billion. An increase in the expected long-term return on plan assets or the discount
rate would reduce pension plan expense, and vice versa. As an indication of the sensitivity of pension expense to the long-
term rate of return assumption, a 1 percent increase in this assumption for the company’s primary U.S. pension plan, which
accounted for about 67 percent of companywide pension expense, would have reduced total pension plan expense for 2020
by approximately $88 million. A 1 percent increase in the discount rates for this same plan would have reduced pension
expense for 2020 by approximately $269 million.

The aggregate funded status recognized at December 31, 2020, was a net liability of approximately $6.2 billion. An increase
in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2020,
the company used a discount rate of 2.4 percent to measure the obligations for the primary U.S. pension plan. 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 61 percent of the companywide pension
obligation, would have reduced the plan obligation by approximately $475 million, and would have decreased the plan’s
underfunded status from approximately $3.2 billion to $2.8 billion.

For the company’s OPEB plans, expense for 2020 was $57 million, and the total liability, all unfunded at the end of 2020,
was $2.7 billion. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 3.4 percent and a
discount rate for interest cost of 2.7 percent to measure expense in 2020, and a 2.4 percent discount rate to measure the
benefit obligations at December 31, 2020. Discount rate changes, similar to those used in the pension sensitivity analysis,
resulted in an immaterial impact on 2020 OPEB expense and OPEB liabilities at the end of 2020.

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 88 in Note 21 for more information on the $7.4 billion of
before-tax actuarial losses recorded by the company as of December 31, 2020, In addition, information related to company
contributions is included on page 91 in Note 21 under the heading “Cash Contributions and Benefit Payments.”

Business Combinations – Purchase-Price Allocation Accounting for business combinations requires the allocation of the
company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values. The
company uses all available information to make these fair value determinations. Determining the fair values of assets
acquired generally involves assumptions regarding the amounts and timing of future revenues and expenditures, as well as
discount rates. For additional discussion of purchase price allocations, refer to Note 29 beginning on page 96.

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 92. 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, 2020.

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
in management’s estimates and assumptions may have a material
further

to “Changes

information,

refer

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For 2020, the company used an expected long-term rate of return of 6.5 percent and a discount rate for service costs of

3.3 percent and a discount rate for interest cost of 2.6 percent for the primary U.S. pension plan. The actual return for 2020

was 9.4 percent. For the 10 years ended December 31, 2020, actual asset returns averaged 7.9 percent for this plan.

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

exceeded 6.5 percent during each year.

Total pension expense for 2020 was $1.5 billion. An increase in the expected long-term return on plan assets or the discount

rate would reduce pension plan expense, and vice versa. As an indication of the sensitivity of pension expense to the long-

term rate of return assumption, a 1 percent increase in this assumption for the company’s primary U.S. pension plan, which

accounted for about 67 percent of companywide pension expense, would have reduced total pension plan expense for 2020

by approximately $88 million. A 1 percent increase in the discount rates for this same plan would have reduced pension

expense for 2020 by approximately $269 million.

The aggregate funded status recognized at December 31, 2020, was a net liability of approximately $6.2 billion. An increase

in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2020,

the company used a discount rate of 2.4 percent to measure the obligations for the primary U.S. pension plan. 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 61 percent of the companywide pension

obligation, would have reduced the plan obligation by approximately $475 million, and would have decreased the plan’s

underfunded status from approximately $3.2 billion to $2.8 billion.

For the company’s OPEB plans, expense for 2020 was $57 million, and the total liability, all unfunded at the end of 2020,

was $2.7 billion. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 3.4 percent and a

discount rate for interest cost of 2.7 percent to measure expense in 2020, and a 2.4 percent discount rate to measure the

benefit obligations at December 31, 2020. Discount rate changes, similar to those used in the pension sensitivity analysis,

resulted in an immaterial impact on 2020 OPEB expense and OPEB liabilities at the end of 2020.

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 88 in Note 21 for more information on the $7.4 billion of

before-tax actuarial losses recorded by the company as of December 31, 2020, In addition, information related to company

contributions is included on page 91 in Note 21 under the heading “Cash Contributions and Benefit Payments.”

Business Combinations – Purchase-Price Allocation Accounting for business combinations requires the allocation of the

company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values. The

company uses all available information to make these fair value determinations. Determining the fair values of assets

acquired generally involves assumptions regarding the amounts and timing of future revenues and expenditures, as well as

discount rates. For additional discussion of purchase price allocations, refer to Note 29 beginning on page 96.

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 92. 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, 2020.

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

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

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 23 of the company’s Annual Report on Form 10-K.

New Accounting Standards

Refer to Note 4 beginning on page 69 for information regarding new accounting standards.

53
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965
831

510
(56)

568
(165)

1,172
165

1,196
1,331

538
1,238

(2,515)
83

Revenues and Other Income

Sales and other operating revenues
Income from equity affiliates
Other income

$ 24,843 $ 23,997 $ 15,926 $ 29,705 $ 34,574 $ 34,779 $ 36,323 $ 34,189
1,062
(51)

Quarterly Results
Unaudited

Millions of dollars, except per-share amounts

4th Q

3rd Q

2nd Q

2020
1st Q

4th Q

3rd Q

2nd Q

2019
1st Q

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, 2020. 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 company excluded Noble from our assessment of internal control over financial reporting as of December 31, 2020

because it was acquired by the company in a business combination during 2020. Total assets and total revenues of Noble,

a wholly-owned subsidiary, represent eight percent and one percent, respectively, of the related consolidated financial

statement amounts as of and for the year ended December 31, 2020.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2020, 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 Controller

February 25, 2021

Total Revenues and Other Income

25,246

24,451

13,494

31,501

36,350

36,116

38,850

35,200

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

13,387
4,898
1,129
367
4,486
1,276
199
461

13,448
4,604
832
117
4,017
1,091
164
222

8,144
5,530
1,569
895
6,717
965
172
99

15,509
5,291
683
158
4,288
1,167
162
98

19,693
5,987
1,129
272
16,429
969
178
98

19,882
5,325
954
168
4,361
1,059
197
121

20,835
5,187
1,076
141
4,334
1,047
198
97

19,703
4,886
984
189
4,094
1,061
225
101

Total Costs and Other Deductions

26,203

24,495

24,091

27,356

44,755

32,067

32,915

31,243

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

(957)
(301)

(44)
165

(10,597)
(2,320)

4,145
564

(8,405)
(1,738)

4,049
1,469

5,935
1,645

3,957
1,315

Net Income (Loss)

(656) $

(209) $ (8,277) $ 3,581 $ (6,667) $ 2,580 $ 4,290 $ 2,642

Less: Net income attributable to noncontrolling interests

(2)

(7)

(18)

(57)

—

(15)

(7)

Net Income (Loss) Attributable to Chevron Corporation

(665) $

(207) $ (8,270) $ 3,599 $ (6,610) $ 2,580 $ 4,305 $ 2,649

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron

Corporation
– Basic
– Diluted

Dividends per share

$
$

(0.33) $
(0.33) $

(0.12) $
(0.12) $

(4.44) $
(4.44) $

1.93 $
1.93 $

(3.51) $
(3.51) $

1.38 $
1.36 $

2.28 $
2.27 $

1.40
1.39

1.29 $

1.19 $

1.19

2020.

54
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Millions of dollars, except per-share amounts

4th Q

3rd Q

2nd Q

4th Q

3rd Q

2nd Q

2020

1st Q

2019

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

$ 24,843

$ 23,997

$ 15,926

$ 29,705

$ 34,574

$ 34,779

$ 36,323

$ 34,189

568

(165)

510

(56)

(2,515)

965

831

538

1,238

1,172

165

1,196

1,331

1,062

(51)

25,246

24,451

13,494

31,501

36,350

36,116

38,850

35,200

13,387

4,898

1,129

367

4,486

1,276

199

461

13,448

4,604

832

117

4,017

1,091

164

222

8,144

5,530

1,569

895

6,717

965

172

15,509

5,291

683

158

4,288

1,167

162

19,693

5,987

1,129

272

16,429

969

178

19,882

5,325

954

168

4,361

1,059

197

121

20,835

5,187

1,076

141

4,334

1,047

198

19,703

4,886

984

189

4,094

1,061

225

101

Total Costs and Other Deductions

26,203

24,495

24,091

27,356

44,755

32,067

32,915

31,243

Income (Loss) Before Income Tax Expense

Income Tax Expense (Benefit)

(957)

(301)

(44)

165

(10,597)

(2,320)

4,145

564

(8,405)

(1,738)

4,049

1,469

5,935

1,645

3,957

1,315

Net Income (Loss)

(656) $

(209) $ (8,277) $ 3,581

$ (6,667) $ 2,580

$ 4,290

$ 2,642

Less: Net income attributable to noncontrolling interests

(2)

(7)

(18)

(57)

—

(15)

(7)

Net Income (Loss) Attributable to Chevron Corporation

(665) $

(207) $ (8,270) $ 3,599

$ (6,610) $ 2,580

$ 4,305

$ 2,649

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron

Corporation

– Basic

– Diluted

Dividends per share

1.29

1.19

$ (0.33) $ (0.12) $

(4.44) $

$ (0.33) $ (0.12) $

(4.44) $

1.93

$ (3.51) $

1.38

1.36

2.28

2.27

1.19

1.40

1.39

1.19

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, 2020. 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,
2020.

The company excluded Noble from our assessment of internal control over financial reporting as of December 31, 2020
because it was acquired by the company in a business combination during 2020. Total assets and total revenues of Noble,
a wholly-owned subsidiary, represent eight percent and one percent, respectively, of the related consolidated financial
statement amounts as of and for the year ended December 31, 2020.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2020, 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 25, 2021

Pierre R. Breber
Vice President
and Chief Financial Officer

David A. Inchausti
Vice President
and Controller

55
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Report of Independent Registered Public Accounting Firm

detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the

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, 2020 and 2019, 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, 2020, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2020 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, 2020, 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.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Noble
Energy, Inc. from its assessment of internal control over financial reporting as of December 31, 2020 because it was
acquired by the Company in a purchase business combination during 2020. We have also excluded Noble Energy, Inc.
from our audit of internal control over financial reporting. Noble Energy, Inc. is a wholly-owned subsidiary whose total
assets and total revenues excluded from management’s assessment and our audit of internal control over financial
reporting represent eight percent and one percent, respectively, of the related consolidated financial statement amounts as
of and for the year ended December 31, 2020.

Definition and Limitations of Internal Control over Financial Reporting

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.

financial statements.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated

financial statements that were communicated or required to be communicated to the audit committee and that (i) relate 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

matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they

relate.

The Impact of Proved Crude Oil and Natural Gas Reserves 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 $140.2 billion as of December 31, 2020, and depreciation, depletion and amortization expense

was $18.0 billion, including impairments of $2.8 billion for the year ended December 31, 2020. The Company follows the

successful efforts method of accounting 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. As disclosed by management, variables impacting

the Company’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 Company’s earth scientists, engineers and RAC are collectively

referred to as “management’s specialists”).

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

and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant

judgment by management, including the use of management’s specialists, when developing the estimates of proved crude

oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in

performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by

management and its specialists in developing the estimates of crude oil and natural gas reserve volumes.

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 estimates of proved crude oil and natural gas reserves. The work of management’s specialists

was used in performing the procedures to evaluate the reasonableness of the proved crude oil and natural gas reserve

volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship

with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions

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

Acquisition of Noble Energy, Inc.—Valuation of Crude Oil and Natural Gas Properties

As described in Note 29 to the consolidated financial statements, the Company acquired Noble Energy, Inc. (“Noble”) in

an acquisition accounted for as a business combination, which required assets acquired and liabilities assumed to be

measured at their acquisition date fair values, including approximately $15 billion related to the fair values of acquired oil

and gas properties. Management applied significant judgment in estimating the fair value of properties acquired, which

involved use of a discounted cash flow approach that incorporated internally generated price assumptions and production

profiles, and operating cost and development cost assumptions.

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

natural gas properties from the acquisition of Noble is a critical audit matter are (i) the significant judgment by

management, including the use of management’s specialists as defined in the previous Critical Audit Matter, when

developing the fair value measurement of acquired crude oil and natural gas properties; (ii) a high degree of auditor

judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in the discounted

cash flow approach related to price, production profiles and discount rates; and (iii) the audit effort involved the use of

professionals with specialized skill and knowledge.

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
timely
and directors of

regarding prevention or

reasonable assurance

the company; and

(iii) provide

56
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Report of Independent Registered Public Accounting Firm

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, 2020 and 2019, 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, 2020, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of

the three years in the period ended December 31, 2020 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, 2020, 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.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Noble

Energy, Inc. from its assessment of internal control over financial reporting as of December 31, 2020 because it was

acquired by the Company in a purchase business combination during 2020. We have also excluded Noble Energy, Inc.

from our audit of internal control over financial reporting. Noble Energy, Inc. is a wholly-owned subsidiary whose total

assets and total revenues excluded from management’s assessment and our audit of internal control over financial

reporting represent eight percent and one percent, respectively, of the related consolidated financial statement amounts as

of and for the year ended December 31, 2020.

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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated
financial statements that were communicated or required to be communicated to the audit committee and that (i) relate 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
matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they
relate.

The Impact of Proved Crude Oil and Natural Gas Reserves 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 $140.2 billion as of December 31, 2020, and depreciation, depletion and amortization expense
was $18.0 billion, including impairments of $2.8 billion for the year ended December 31, 2020. The Company follows the
successful efforts method of accounting 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. As disclosed by management, variables impacting
the Company’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 Company’s earth scientists, engineers and RAC are collectively
referred to as “management’s specialists”).

The principal considerations for our determination that performing procedures relating to the impact of proved crude oil
and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant
judgment by management, including the use of management’s specialists, when developing the estimates of proved crude
oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in
performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by
management and its specialists in developing the estimates of crude oil and natural gas reserve volumes.

Acquisition of Noble Energy, Inc.—Valuation of Crude Oil and Natural Gas Properties

As described in Note 29 to the consolidated financial statements, the Company acquired Noble Energy, Inc. (“Noble”) in
an acquisition accounted for as a business combination, which required assets acquired and liabilities assumed to be
measured at their acquisition date fair values, including approximately $15 billion related to the fair values of acquired oil
and gas properties. Management applied significant judgment in estimating the fair value of properties acquired, which
involved use of a discounted cash flow approach that incorporated internally generated price assumptions and production
profiles, and operating cost and development cost assumptions.

The principal considerations for our determination that performing procedures relating to the valuation of crude oil and
natural gas properties from the acquisition of Noble is a critical audit matter are (i) the significant judgment by
management, including the use of management’s specialists as defined in the previous Critical Audit Matter, when
developing the fair value measurement of acquired crude oil and natural gas properties; (ii) a high degree of auditor
judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in the discounted
cash flow approach related to price, production profiles and discount rates; and (iii) the audit effort involved the use of
professionals with specialized skill and knowledge.

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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 the valuation of acquired crude oil and natural gas properties. These procedures also included, among others,
(i) testing management’s process for developing the fair value measurement of the acquired crude oil and natural gas
properties; (ii) evaluating the appropriateness of the discounted cash flow approach; (iii) testing the completeness and
accuracy of underlying data used in the discounted cash flow approach; and (iv) evaluating the reasonableness of
significant assumptions used by management related to price, production profiles and discount rates. Evaluating
production profile assumptions involved evaluating the reasonableness of the assumptions as compared to historical
results of Noble, as well as third party data. Evaluating price assumptions involved comparing the prices to third party
data and underlying contracts. Professionals with specialized skill and knowledge were used to assist in the evaluation of
the discounted cash flow approach and discount rates used. The work of management’s specialists was used in performing
the procedures to evaluate the reasonableness of the proved crude oil and natural gas reserve volumes included in
production profile assumptions as stated in the Critical Audit Matter titled “The Impact of Proved Crude Oil and Natural
Gas Reserves on Upstream Property, Plant, and Equipment, Net”. As a basis for using this work, the specialists’
qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures
performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the
specialists, and an evaluation of the specialists’ findings.

San Francisco, California

February 25, 2021

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

Consolidated Statement of Income

Millions of dollars, except per-share amounts

Revenues and Other Income

Sales and other operating revenues

Income (loss) 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

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

See accompanying Notes to the Consolidated Financial Statements.

Year ended December 31

2020

2019

2018

94,471

139,865

158,902

(472)

693

3,968

2,683

6,327

1,110

94,692

146,516

166,339

80,113

21,385

4,143

770

29,218

4,136

798

417

5,536

2,691

2,845

(79)

94,578

20,544

3,838

1,210

19,419

4,867

748

560

20,575

5,715

14,860

102,145

140,980

145,764

50,488

20,323

4,213

1,537

19,508

4,499

697

880

(7,453)

(1,892)

(5,561)

(18)

(5,543)

(2.96)

2,924

14,824

1.55

1.54

7.81

7.74

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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 the valuation of acquired crude oil and natural gas properties. These procedures also included, among others,

(i) testing management’s process for developing the fair value measurement of the acquired crude oil and natural gas

properties; (ii) evaluating the appropriateness of the discounted cash flow approach; (iii) testing the completeness and

accuracy of underlying data used in the discounted cash flow approach; and (iv) evaluating the reasonableness of

significant assumptions used by management related to price, production profiles and discount rates. Evaluating

production profile assumptions involved evaluating the reasonableness of the assumptions as compared to historical

results of Noble, as well as third party data. Evaluating price assumptions involved comparing the prices to third party

data and underlying contracts. Professionals with specialized skill and knowledge were used to assist in the evaluation of

the discounted cash flow approach and discount rates used. The work of management’s specialists was used in performing

the procedures to evaluate the reasonableness of the proved crude oil and natural gas reserve volumes included in

production profile assumptions as stated in the Critical Audit Matter titled “The Impact of Proved Crude Oil and Natural

Gas Reserves on Upstream Property, Plant, and Equipment, Net”. As a basis for using this work, the specialists’

qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures

performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the

specialists, and an evaluation of the specialists’ findings.

San Francisco, California

February 25, 2021

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

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

Revenues and Other Income

Sales and other operating revenues
Income (loss) from equity affiliates
Other income

Total Revenues and Other Income

Costs and Other Deductions

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

Year ended December 31

2020

2019

2018

94,471
(472)
693

94,692

139,865 $
3,968
2,683

146,516

158,902
6,327
1,110

166,339

50,488
20,323
4,213
1,537
19,508
4,499
697
880

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

102,145

140,980

145,764

(7,453)
(1,892)

(5,561)
(18)

5,536
2,691

2,845
(79)

20,575
5,715

14,860
36

Net Income (Loss) Attributable to Chevron Corporation

(5,543)

2,924 $

14,824

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron Corporation

- Basic
- Diluted

See accompanying Notes to the Consolidated Financial Statements.

$
$

(2.96)
(2.96)

$
$

1.55 $
1.54 $

7.81
7.74

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Consolidated Statement of Comprehensive Income
Millions of dollars

Consolidated Balance Sheet

Millions of dollars, except per-share amounts

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
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

1,107
(2,004)

519
(2,404)

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 tax benefit (cost) on defined benefit plans

Total

Other Comprehensive Gain (Loss), Net of Tax

Comprehensive Income

Comprehensive loss (income) attributable to noncontrolling interests

(23)
—
(104)
369

(655)

(622)

(6,183)

4
(28)
(33)
510

(1,432)

(1,446)

1,399

Year ended December 31

2020

2019

2018

(5,561) $

2,845

14,860

(2)

—
—

—

(18)

(1)
3

(19)

(5)

—
—

—

792
85

(13)
(26)
23
(230)

631

607

15,467

(36)

Comprehensive Income (Loss) Attributable to Chevron Corporation

(6,165) $

1,478

15,431

See accompanying Notes to the Consolidated Financial Statements.

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Accounts and notes receivable (less allowance: 2020 - $284; 2019 - $746)

Assets

Cash and cash equivalents

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

Noncurrent deferred income taxes

Noncurrent employee benefit plans

Total Liabilities2

Deferred credits and other noncurrent obligations

issued at December 31, 2020 and 2019)

Capital in excess of par value

Retained earnings

Accumulated other comprehensive losses

Deferred compensation and benefit plan trust

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

Treasury stock, at cost (2020 - 517,490,263 shares; 2019 - 560,508,479 shares)

Total Chevron Corporation Stockholders’ Equity

Noncontrolling interests (2020 includes $120 redeemable noncontrolling interest)

Total Equity

Total Liabilities and Equity

Includes finance lease liabilities of $447 and $282 at December 31, 2020 and 2019, respectively.

2 Refer to Note 22, “Other Contingencies and Commitments” beginning on page 92.

See accompanying Notes to the Consolidated Financial Statements.

At December 31

2020

2019

5,596

11,471

3,576

457

1,643

5,676

3,304

26,078

589

39,052

345,232

188,614

156,618

11,950

4,402

1,101

239,790

1,548

10,950

7,812

921

952

22,183

42,767

20,328

12,569

9,217

—

1,832

16,829

160,377

(5,612)

(240)

(41,498)

131,688

1,038

132,726

107,064

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

92,220

—

1,832

17,265

174,945

(4,990)

(240)

(44,599)

144,213

995

145,208

239,790

237,428

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

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 tax benefit (cost) on defined benefit plans

Total

Other Comprehensive Gain (Loss), Net of Tax

Comprehensive Income

Comprehensive loss (income) attributable to noncontrolling interests

(2)

—

1,107

(2,004)

(23)

—

(104)

369

(655)

(622)

(6,183)

(18)

(1)

519

(2,404)

(28)

(33)

510

(1,432)

(1,446)

1,399

(19)

(5)

—

792

(13)

(26)

(230)

631

607

15,467

(36)

Comprehensive Income (Loss) Attributable to Chevron Corporation

(6,165)

1,478

15,431

See accompanying Notes to the Consolidated Financial Statements.

Consolidated Statement of Comprehensive Income

Millions of dollars

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

Year ended December 31

2020

2019

2018

(5,561)

2,845

14,860

Assets

Cash and cash equivalents
Marketable securities
Accounts and notes receivable (less allowance: 2020 - $284; 2019 - $746)
Inventories:

At December 31

2020

2019

5,596
31
11,471

3,576
457
1,643

5,676
3,304

26,078
589
39,052
345,232
188,614

156,618
11,950
4,402
1,101

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

239,790

237,428

1,548
10,950
7,812
921
952

22,183
42,767
20,328
12,569
9,217

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

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

107,064

92,220

—

1,832
16,829
160,377
(5,612)
(240)
(41,498)

131,688

1,038

132,726

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

144,213

995

145,208

239,790

237,428

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, 2020 and 2019)

Capital in excess of par value
Retained earnings
Accumulated other comprehensive losses
Deferred compensation and benefit plan trust
Treasury stock, at cost (2020 - 517,490,263 shares; 2019 - 560,508,479 shares)

Total Chevron Corporation Stockholders’ Equity

Noncontrolling interests (2020 includes $120 redeemable noncontrolling interest)

Total Equity

Total Liabilities and Equity

Includes finance lease liabilities of $447 and $282 at December 31, 2020 and 2019, respectively.

2 Refer to Note 22, “Other Contingencies and Commitments” beginning on page 92.

See accompanying Notes to the Consolidated Financial Statements.

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Consolidated Statement of Cash Flows
Millions of dollars

Consolidated Statement of Equity

Amounts in millions of dollars

Operating Activities
Net Income (Loss)
Adjustments

Depreciation, depletion and amortization
Dry hole expense
Distributions more (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

Cash acquired from Noble Energy, Inc.
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

Net Cash Provided by (Used for) Financing Activities

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

Year ended December 31

2020

2019

2018

Common

Stock1

Acc. Other

Retained

Earnings

Comprehensive

Income (Loss)

Treasury

Stock

(at cost)

Chevron Corp.

Stockholders’

Equity

Noncontrolling

Interests

Total

Equity

Balance at December 31, 2017 $ 18,440

174,106

(3,589) $

(40,833) $

148,124

1,195

$ 149,319

(5,561) $

2,845

14,860

Treasury stock transactions

264

19,508
1,036
2,015
(760)
619
(3,604)
(1,652)
296
(248)
(1,213)
141

10,577

373
(8,922)
2,968
—
35
(1,419)

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)

(6,965)

(11,458)

651
12,308
(5,489)
(9,651)
(24)
(1,531)

(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)

(3,736)

(19,758)

(13,699)

(50)

(174)
6,911

332

(3,570)
10,481

(91)

4,538
5,943

Cash, Cash Equivalents and Restricted Cash at December 31

6,737 $

6,911

10,481

See accompanying Notes to the Consolidated Financial Statements.

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Balance at December 31, 2019 $ 18,857

174,945

(4,990) $

(44,599) $

144,213

995

$ 145,208

Balance at December 31, 2018 $ 18,704

180,987

(3,544) $

(41,593) $

154,554

1,088

$ 155,642

Treasury stock transactions

153

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

Treasury stock transactions

Noble Acquisition3

Net income (loss)

Cash dividends

Stock dividends

Other comprehensive income

Purchases of treasury shares

Issuances of treasury shares

Other changes, net

—

(520)

Balance at December 31, 2017

2,442,676,580

Balance at December 31, 2018

2,442,676,580

Balance at December 31, 2019

2,442,676,580

Balance at December 31, 2020

2,442,676,580

Purchases

Issuances

Purchases

Issuances

Purchases

Issuances

—

14,824

(8,502)

(3)

—

562

—

2,924

(8,959)

(3)

—

(4)

—

(5,543)

(9,651)

(5)

—

631

Issued2

—

(1,446)

—

607

—

(562)

—

(622)

(1,751)

991

—

(4,039)

1,033

4,629

(1,757)

229

—

Treasury

(537,974,695)

(14,912,039)

13,047,844

(539,838,890)

(33,955,300)

13,285,711

(560,508,479)

(17,577,457)

60,595,673

(517,490,263)

264

14,824

(8,502)

(3)

607

(1,751)

991

—

153

2,924

(8,959)

(3)

(1,446)

(4,039)

1,033

(4)

4,109

(5,543)

(9,651)

(5)

(622)

(1,757)

229

631

(91)

—

(52)

—

(79)

(18)

—

779

(18)

(24)

—

(694)

264

14,860

(8,593)

(1,751)

(3)

607

991

(52)

153

2,845

(8,977)

(3)

(1,446)

(4,039)

1,033

—

4,888

(5,561)

(9,675)

(5)

(622)

(1,757)

229

(63)

Outstanding

1,904,701,885

(14,912,039)

13,047,844

1,902,837,690

(33,955,300)

13,285,711

1,882,168,101

(17,577,457)

60,595,673

1,925,186,317

Balance at December 31, 2020 $ 18,421

160,377

(5,612) $

(41,498) $

131,688

1,038

$ 132,726

Common Stock Share Activity

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

2 Beginning and ending total issued share balances include 14,168,000 shares associated with Chevron’s Benefit Plan Trust.

Plan Trust. Changes reflect capital in excess of par.

Includes $120 redeemable noncontrolling interest.

See accompanying Notes to the Consolidated Financial Statements.

Operating Activities

Net Income (Loss)

Adjustments

Depreciation, depletion and amortization

Dry hole expense

Distributions more (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

Cash acquired from Noble Energy, Inc.

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

2020

2019

2018

(5,561) $

2,845

14,860

19,508

1,036

2,015

(760)

619

(3,604)

(1,652)

296

(248)

(1,213)

141

10,577

373

(8,922)

2,968

—

(1,419)

(6,965)

651

12,308

(5,489)

(9,651)

(24)

(1,531)

(3,736)

(50)

(174)

6,911

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

(12,290)

2,021

218

(6,741)

(8,502)

(91)

(604)

(91)

4,538

5,943

Consolidated Statement of Cash Flows

Millions of dollars

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, 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

Treasury stock transactions
Noble Acquisition3
Net income (loss)
Cash dividends
Stock dividends
Other comprehensive income
Purchases of treasury shares
Issuances of treasury shares
Other changes, net

84
(520)
—
—
—
—
—
—
—

—
—
(5,543)
(9,651)
(5)
—
—
—
631

—
—
—
—
—
(622)
—
—
—

—
4,629
—
—
—
—
(1,757)
229
—

84
4,109
(5,543)
(9,651)
(5)
(622)
(1,757)
229
631

—
779
(18)
(24)
—
—
—
—
(694)

84
4,888
(5,561)
(9,675)
(5)
(622)
(1,757)
229
(63)

Balance at December 31, 2020 $ 18,421 $

160,377 $

(5,612) $

(41,498) $

131,688 $

1,038 $ 132,726

Net Cash Provided by (Used for) Financing Activities

(19,758)

(13,699)

Balance at December 31, 2017

2,442,676,580

Issued2

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

6,737

6,911

10,481

See accompanying Notes to the Consolidated Financial Statements.

Purchases
Issuances

—
—

Balance at December 31, 2018

2,442,676,580

Purchases
Issuances

—
—

Balance at December 31, 2019

2,442,676,580

Purchases
Issuances

—
—

Balance at December 31, 2020

2,442,676,580

Common Stock Share Activity

Treasury

(537,974,695)

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

(539,838,890)

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

(560,508,479)

(17,577,457)
60,595,673

(517,490,263)

Outstanding

1,904,701,885

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

1,902,837,690

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

1,882,168,101

(17,577,457)
60,595,673

1,925,186,317

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 14,168,000 shares associated with Chevron’s Benefit Plan Trust.
3

Includes $120 redeemable noncontrolling interest.

See accompanying Notes to the Consolidated Financial Statements.

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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 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. Included within noncontrolling interest is redeemable noncontrolling interest.

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.

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Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and

production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and

natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are

capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved

reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves

even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a

sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress

assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are

expensed. Refer to Note 19, beginning on page 85, 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 71, 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 94, relating to

AROs.

Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral

interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves

are produced. Depletion expenses

for capitalized costs of proved mineral

interests are recognized using the

unit-of-production method by individual field as the related proved reserves are produced. 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.”

capitalized.

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

Leases Leases are classified as operating or finance leases. Both operating and finance leases recognize lease liabilities and

associated right-of-use assets. The company has elected the short-term lease exception and therefore only recognizes

right-of-use assets and lease liabilities for leases with a term greater than one year. 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.

Where leases are used in joint ventures, the company recognizes 100 percent 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

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. Included within noncontrolling interest is redeemable noncontrolling interest.

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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and
production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and
natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are
capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved
reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves
even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a
sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress
assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are
expensed. Refer to Note 19, beginning on page 85, 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 71, 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 94, relating to
AROs.

Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral
interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves
are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the
unit-of-production method by individual field as the related proved reserves are produced. 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.

Leases Leases are classified as operating or finance leases. Both operating and finance leases recognize lease liabilities and
associated right-of-use assets. The company has elected the short-term lease exception and therefore only recognizes
right-of-use assets and lease liabilities for leases with a term greater than one year. 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.

Where leases are used in joint ventures, the company recognizes 100 percent 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

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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, 2020, are reflected in the table below.

Balance at December 31, 2017

(105) $

(5) $

(2) $

(3,477) $

(3,589)

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

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications

Reclassifications2

Net Other Comprehensive Income (Loss)

Balance at December 31, 2020

1 All amounts are net of tax.

Currency

Translation

Adjustments

Unrealized

Holding Gains

(Losses) on

Securities Derivatives

Benefit Plans

Total

Defined

(19)

—

(19)

—

(18)

—

(18)

—

(5)

—

(5)

—

(2)

—

(2)

—

(1)

—

603

631

(562)

(1,838)

406

(1,432)

(1,487)

832

(655)

603

607

(562)

(1,855)

409

(1,446)

(1,454)

832

(622)

(142) $

(8) $

— $

(4,840) $

(4,990)

(107) $

(10) $

— $

(5,495) $

(5,612)

Balance at December 31, 2018

(124) $

(10) $

(2) $

(3,408) $

(3,544)

2 Refer to Note 21 beginning on page 87, for reclassified components totaling $1,084 that are included in employee benefit costs for the year ended December 31, 2020. Related

income taxes for the same period, totaling $252, 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.

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

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.

Note 2

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 94, 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.

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

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.

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 94, 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.

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.

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, 2020, are reflected in the table below.

Currency
Translation
Adjustments

Unrealized
Holding Gains
(Losses) on

Securities Derivatives

Defined
Benefit Plans

Total

Balance at December 31, 2017

(105) $

(5) $

(2) $

(3,477) $

(3,589)

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications
Reclassifications2

Net Other Comprehensive Income (Loss)
Stranded Tax Reclassification to Retained Earnings3

(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

Components of Other Comprehensive Income (Loss)1:

Before Reclassifications
Reclassifications2

Net Other Comprehensive Income (Loss)

Balance at December 31, 2020

(18)
—
(18)

2
—
2

(1)
3
2

(1,838)
406
(1,432)

(1,855)
409
(1,446)

(142) $

(8) $

—

(4,840) $

(4,990)

35
—
35

(2)
—
(2)

(107) $

(10) $

—
—
—

—

(1,487)
832
(655)

(1,454)
832
(622)

(5,495) $

(5,612)

1 All amounts are net of tax.
2 Refer to Note 21 beginning on page 87, for reclassified components totaling $1,084 that are included in employee benefit costs for the year ended December 31, 2020. Related
income taxes for the same period, totaling $252, 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.

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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 3
Information Relating to the Consolidated Statement of Cash Flows

Distributions more (less) than income from equity affiliates includes the following:

Distributions from equity affiliates
(Income) loss from equity affiliates

Distributions more (less) than income from equity affiliates

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

2020

Year ended December 31
2018

2019

1,543
472

1,895
(3,968)

2,747
(6,327)

2,015

(2,073) $

(3,580)

2,423
284
(87)
(3,576)
(696)

1,852
7
(323)
(109)
67

(1,652)

1,494

437
(424)
(149)
(494)
(88)

(718)

810
4,817

736
4,748

720
2,987

2,891
77

2,809
142

2,968

2,951

—
—

—

—
35

(3,925)
2,506

—
950

950

(1) $
3

(1,350) $
105

(1,419)

(1,245) $

2,000
392

2,392

(950)
—

(950)

(51)
—

(51)

—
111

111

10,846
(9,771)
(424)

2,586
(1,430)
(3,977)

2,486
(4,136)
3,671

651

(2,821) $

2,021

226
(1,757)

1,104
(4,039)

1,147
(1,751)

(1,531)

(2,935) $

(604)

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.
“Distributions more (less) than income from equity affiliates,” “Depreciation, depletion and amortization,” “Deferred income
tax provision,” “Dry hole expense,” and “Net decrease (increase) in operating working capital” collectively include
approximately $4.8 billion in non-cash reductions in 2020 relating to impairments and other non-cash charges.
“Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense” collectively include
approximately $9.3 billion in non-cash reductions recorded in 2019 relating to impairments and other non-cash charges.
Refer also to Note 23, on page 94, 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, 2020.

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Refer also to Note 29 on page 96 for a discussion of the all-stock acquisition of Noble. The cash received as a result of the

acquisition is reflected on the Consolidated Statement of Cash Flows as “Cash acquired from Noble Energy, Inc.” Other

changes to the Consolidated Balance Sheet resulting from the acquisition that did not affect cash are not reflected on the

Consolidated Statement of Cash Flows.

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.

Capital and exploratory expenditures, including equity affiliates

13,499

20,994

* Excludes non-cash movements of $816 in 2020, $(239) in 2019 and $25 in 2018.

The table below quantifies the beginning and ending balances of restricted cash and restricted cash equivalents in the

Consolidated Balance Sheet:

Year ended December 31

13,839

2020

8,492

136

327

(33)

8,922

500

9,517

3,982

2019

140

124

598

181

(13)

14,882

6,112

2018

13,384

344

(1)

523

—

14,390

5,716

20,106

14,116

13,792

Year ended December 31

2020

5,596

365

776

6,737

2019

5,686

452

773

6,911

2018

9,342

341

798

10,481

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

refer to Note 28 on page 96.

Note 5

Lease Commitments

Financial Instruments—Credit Losses (Topic 326) Effective January 1, 2020, Chevron adopted Accounting Standards

Update (ASU) 2016-13 and its related amendments. For additional information on the company’s expected credit losses,

The company enters into leasing arrangements as a lessee; any lessor arrangements are not significant. Operating lease

arrangements mainly involve land, bareboat charters, terminals, drill ships, drilling rigs, time chartered vessels, office

buildings and warehouses, and exploration and production equipment. Finance leases primarily include facilities, vessels,

office buildings, and production equipment.

presentation, are as follows:

Details of the right-of-use assets and lease liabilities for operating and finance leases,

including the balance sheet

Note 3

Information Relating to the Consolidated Statement of Cash Flows

Distributions more (less) than income from equity affiliates includes the following:

Distributions from equity affiliates

(Income) loss from equity affiliates

Distributions more (less) than income from equity affiliates

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)

Proceeds and deposits related to asset sales and returns of investment consisted of the following gross

Income taxes

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

amounts:

Proceeds from issuances of short-term obligations

Repayments of short-term obligations

Net borrowings (repayments) of short-term obligations consisted of the following gross and net

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

2020

1,543

472

2,015

2,423

284

(87)

(3,576)

(696)

(1,652)

720

2,987

2,891

2,968

(3,925)

2,506

(1,419)

10,846

(9,771)

(424)

651

226

(1,757)

(1,531)

Year ended December 31

2019

2018

1,895

(3,968)

(2,073) $

1,852

(323)

(109)

1,494

810

4,817

2,809

142

2,951

(1,350) $

105

(1,245) $

2,747

(6,327)

(3,580)

437

(424)

(149)

(494)

(88)

(718)

736

4,748

2,000

392

2,392

(950)

—

(950)

(51)

—

(51)

—

111

2,586

(1,430)

(3,977)

2,486

(4,136)

3,671

(2,821) $

2,021

1,104

(4,039)

(2,935) $

1,147

(1,751)

(604)

— $

—

— $

950

— $

(1) $

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.

“Distributions more (less) than income from equity affiliates,” “Depreciation, depletion and amortization,” “Deferred income

tax provision,” “Dry hole expense,” and “Net decrease (increase) in operating working capital” collectively include

approximately $4.8 billion in non-cash reductions in 2020 relating to impairments and other non-cash charges.

“Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense” collectively include

approximately $9.3 billion in non-cash reductions recorded in 2019 relating to impairments and other non-cash charges.

Refer also to Note 23, on page 94, 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, 2020.

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

Refer also to Note 29 on page 96 for a discussion of the all-stock acquisition of Noble. The cash received as a result of the
acquisition is reflected on the Consolidated Statement of Cash Flows as “Cash acquired from Noble Energy, Inc.” Other
changes to the Consolidated Balance Sheet resulting from the acquisition that did not affect cash are not reflected on the
Consolidated Statement of Cash Flows.

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.

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

2020

8,492
136
327
(33)

8,922
500
53
42

9,517
3,982

Year ended December 31
2018
2019

13,839
140
124
13

14,116
598
181
(13)

14,882
6,112

13,384
65
344
(1)

13,792
523
75
—

14,390
5,716

20,106

Capital and exploratory expenditures, including equity affiliates

13,499

20,994

* Excludes non-cash movements of $816 in 2020, $(239) in 2019 and $25 in 2018.

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

2020

5,596
365
776

6,737

Year ended December 31
2018
2019

5,686
452
773

9,342
341
798

6,911

10,481

Note 4
New Accounting Standards
Financial Instruments—Credit Losses (Topic 326) Effective January 1, 2020, Chevron adopted Accounting Standards
Update (ASU) 2016-13 and its related amendments. For additional information on the company’s expected credit losses,
refer to Note 28 on page 96.

Note 5
Lease Commitments
The company enters into leasing arrangements as a lessee; any lessor arrangements are not significant. Operating lease
arrangements mainly involve land, bareboat charters, terminals, drill ships, drilling rigs, time chartered vessels, office
buildings and warehouses, and exploration and production equipment. Finance leases primarily include facilities, vessels,
office buildings, and production equipment.

Details of the right-of-use assets and lease liabilities for operating and finance leases, including the balance sheet
presentation, are as follows:

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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

Deferred charges and other assets
Properties, plant and equipment, net

Right-of-use assets1

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, 2020

At December 31, 2019

Operating
Leases

Finance
Leases

Operating
Leases

Finance
Leases

3,949
—

3,949

1,291
—

1,291

2,615
—

2,615

3,906

—
455

455

—
186

186

—
447

447

633

4,074
—

4,074

1,277
—

1,277

2,608
—

2,608

3,885

—
329

329

—
18

—
282

282

300

7.2
2.8%

10.4
3.9%

5.2
3.2%

16.0
4.7%

Includes non-cash additions of $1,353 and $164 in 2020, and $1,201 and $184 in 2019 for right-of-use assets obtained in exchange for new and modified lease liabilities for
operating and finance leases, respectively. 2020 includes $566 in operating lease right-of-use assets and $566 lease liabilities associated with the Puma acquisition. 2020 also
includes $124 in operating lease right-of-use assets and $148 lease liabilities, and $112 in finance lease right-of-use assets and $309 lease liabilities associated with the Noble
acquisition.

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 for 2018.
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
2020

2,551
45

2,596

2,621
66

2,687

Year-ended December 31
2019
2020

1,744
762
14
34

1,574
1,047
13
24

At December 31, 2020, the estimated future undiscounted cash flows for operating and finance leases were as follows:

Year 2021
2022
2023
2024
2025
Thereafter

Total

Less: Amounts representing interest

Total lease liabilities

Operating Leases

At December 31, 2020
Finance Leases

1,376
779
497
338
255
1,112

4,357

451

3,906

204
60
58
56
53
331

762

129

633

Additionally, the company has $907 in future undiscounted cash flows for operating leases not yet commenced. These leases
are primarily for a drill ship and drilling rigs. 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.

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

Current assets

Other assets

Current liabilities

Other liabilities

Total CUSA net equity

Memo: Total debt

Note 7

Fair Value Measurements

2020

67,950

72,575

(2,676)

Year ended December 31

2019

109,314

116,365

(5,061)

2020

10,555

48,054

12,403

14,102

32,104

7,133

At December 31

2018

125,076

121,351

4,334

2019

13,059

50,796

18,291

12,565

32,999

3,222

The tables on the next page show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and

nonrecurring basis at December 31, 2020 and December 31, 2019.

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,

2020.

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 2020 primarily

due to downward revisions to its oil and gas price outlook. The impact of these impairments is included in “Depreciation,

depletion and amortization” on the Consolidated Statement of Income. The company reported impairments for certain

upstream properties in 2019 primarily due to capital allocation decisions and a lower long-term commodity price outlook.

Investments and Advances In 2020, the company fully impaired its investments in Petropiar and Petroboscan in Venezuela.

The impact of these impairments is included in “Income (loss) from equity affiliates” on the Consolidated Statement of

Income. The company reported impairments for certain upstream equity companies in 2019 primarily due to capital

allocation decisions and lower long-term commodity price outlook.

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Deferred charges and other assets

Properties, plant and equipment, net

Right-of-use assets1

Accrued Liabilities

Short-term Debt

Current lease liabilities

Long-term Debt

Noncurrent lease liabilities

Total lease liabilities

Deferred credits and other noncurrent obligations

At December 31, 2020

At December 31, 2019

Operating

Leases

Finance

Leases

Operating

Leases

Finance

Leases

3,949

—

3,949

1,291

—

1,291

2,615

—

2,615

3,906

—

455

—

186

—

447

633

4,074

—

4,074

1,277

—

1,277

2,608

—

2,608

3,885

Weighted-average remaining lease term (in years)

Weighted-average discount rate

7.2

2.8%

10.4

3.9%

5.2

3.2%

16.0

4.7%

Includes non-cash additions of $1,353 and $164 in 2020, and $1,201 and $184 in 2019 for right-of-use assets obtained in exchange for new and modified lease liabilities for

operating and finance leases, respectively. 2020 includes $566 in operating lease right-of-use assets and $566 lease liabilities associated with the Puma acquisition. 2020 also

includes $124 in operating lease right-of-use assets and $148 lease liabilities, and $112 in finance lease right-of-use assets and $309 lease liabilities associated with the Noble

acquisition.

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:

Cash paid for amounts included in the measurement of lease liabilities was as follows:

At December 31, 2020, the estimated future undiscounted cash flows for operating and finance leases were as follows:

Operating lease costs1, 2

Finance lease costs

Total lease costs

1 Net rental expense of $816 for 2018.

Includes variable and short-term lease costs.

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 2021

2022

2023

2024

2025

Thereafter

Total

Less: Amounts representing interest

Total lease liabilities

—

329

—

282

300

2019

2,621

2,687

2019

1,574

1,047

204

331

762

129

633

Year-ended December 31

2020

2,551

2,596

2020

1,744

762

1,376

779

497

338

255

1,112

4,357

451

3,906

At December 31, 2020

Operating Leases

Finance Leases

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 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

Current assets
Other assets
Current liabilities
Other liabilities

Total CUSA net equity

Memo: Total debt

2020

67,950
72,575
(2,676)

Year ended December 31
2018
2019

109,314
116,365
(5,061)

125,076
121,351
4,334

2020

10,555
48,054
12,403
14,102

32,104

At December 31
2019

13,059
50,796
18,291
12,565

32,999

7,133

3,222

Note 7
Fair Value Measurements
The tables on the next page show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and
nonrecurring basis at December 31, 2020 and December 31, 2019.

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,
2020.

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 2020 primarily
due to downward revisions to its oil and gas price outlook. The impact of these impairments is included in “Depreciation,
depletion and amortization” on the Consolidated Statement of Income. The company reported impairments for certain
upstream properties in 2019 primarily due to capital allocation decisions and a lower long-term commodity price outlook.

Investments and Advances In 2020, the company fully impaired its investments in Petropiar and Petroboscan in Venezuela.
The impact of these impairments is included in “Income (loss) from equity affiliates” on the Consolidated Statement of
Income. The company reported impairments for certain upstream equity companies in 2019 primarily due to capital
allocation decisions and lower long-term commodity price outlook.

Additionally, the company has $907 in future undiscounted cash flows for operating leases not yet commenced. These leases

are primarily for a drill ship and drilling rigs. 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.

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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

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, 2020
Level 3

Level 2

Total

Level 1

At December 31, 2019
Level 3

Level 2

31$
74

105 $

173

31$
37

68 $

—$
37

37 $

115

— $
—

— $

—

173 $

58 $

115 $

— $

63$
11

74 $

63$
1

—$
10

64 $

10 $

26 $

48 $

—
—

—

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 2020

Total Level 1 Level 2 Level 3

At December 31
Before-Tax Loss
Year 2019

Properties, plant and equipment, net (held

and used)

$ 2,443 $ — $

20 $ 2,423 $

2,599 $

2,177 $ — $ — $ 2,177 $

Properties, plant and equipment, net (held

for sale)

Investments and advances

1,418
28

—
—

1,418
—

—
28

193
2,555

1,412
52

—
—

1,412
30

—
22

2,095

8,702
594

Total nonrecurring assets at fair value

$ 3,889 $ — $ 1,438 $ 2,451 $

5,347 $

3,641 $ — $ 1,442 $ 2,199 $

11,391

At year-end 2020, the company had assets measured at fair value Level 3 using unobservable inputs of $2,451. The carrying
value of these assets were written down to fair value based on estimates derived from internal discounted cash flow models.
Cash flows were determined using estimates of future production, an outlook of future price based on published prices and a
discount rate believed to be consistent with those used by principal market participants. The significant Level 3 inputs were
attributed to two assets, one in an international location where volumes and price were primarily based on natural gas, and
the second was in a U.S. location where volumes and price were primarily based on crude.

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 $5,596 and $5,686 at
December 31, 2020, and December 31, 2019, 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,
2020.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,141 and $1,225 at December 31,
2020, and December 31, 2019, respectively. At December 31, 2020, these investments are classified as Level 1 and include
restricted funds related to certain upstream decommissioning activities, 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 $30,805 and $13,659 at December 31, 2020, and December 31, 2019, respectively, had estimated fair values of
$34,390 and $14,326, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate
bonds is $32,123 and classified as Level 1. The fair value of other long-term debt is $2,267 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, 2020 and 2019, 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.

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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, 2020, December 31, 2019, and December 31, 2018, 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

2020

172

173

At December 31

2019

—

Gain/(Loss)

Year ended December 31

2020

2019

(291) $

(36)

(17)

(2)

(310) $

2018

135

(33)

105

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated

Balance Sheet at December 31, 2020 and December 31, 2019.

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

At December 31, 2020

Derivative Assets

Derivative Liabilities

At December 31, 2019

Derivative Assets

Derivative Liabilities

Gross Amounts

Recognized

Gross Amounts

Offset

Net Amounts

Presented

Gross Amounts

Not Offset

Net Amounts

818

917

656

719

744

645

173

— $

173

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.

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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, 2020

At December 31, 2019

Total

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

31 $

105 $

173

173 $

31 $

68 $

58 $

— $

37 $

115

— $

—

— $

—

115 $

— $

63 $

74 $

63 $

64 $

26 $

— $

10 $

48 $

—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

At December 31

Before-Tax Loss

Year 2019

8,702

594

11,391

Total Level 1 Level 2 Level 3

At December 31

Before-Tax Loss

Year 2020

Properties, plant and equipment, net (held

and used)

for sale)

Investments and advances

$ 2,443 $ — $

20 $ 2,423 $

2,599

2,177 $ — $ — $ 2,177 $

2,095

1,418

— 1,418

—

193

2,555

1,412

— 1,412

—

Total nonrecurring assets at fair value

$ 3,889 $ — $ 1,438 $ 2,451 $

5,347 $

3,641 $ — $ 1,442 $ 2,199 $

At year-end 2020, the company had assets measured at fair value Level 3 using unobservable inputs of $2,451. The carrying

value of these assets were written down to fair value based on estimates derived from internal discounted cash flow models.

Cash flows were determined using estimates of future production, an outlook of future price based on published prices and a

discount rate believed to be consistent with those used by principal market participants. The significant Level 3 inputs were

attributed to two assets, one in an international location where volumes and price were primarily based on natural gas, and

the second was in a U.S. location where volumes and price were primarily based on crude.

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 $5,596 and $5,686 at

December 31, 2020, and December 31, 2019, 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,

2020.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,141 and $1,225 at December 31,

2020, and December 31, 2019, respectively. At December 31, 2020, these investments are classified as Level 1 and include

restricted funds related to certain upstream decommissioning activities, 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 $30,805 and $13,659 at December 31, 2020, and December 31, 2019, respectively, had estimated fair values of

$34,390 and $14,326, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate

bonds is $32,123 and classified as Level 1. The fair value of other long-term debt is $2,267 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, 2020 and 2019, 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.

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 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, 2020, December 31, 2019, and December 31, 2018, 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

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

2020

73
1

172
1

173

At December 31
2019

11
—

74
—

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
2018

2019

2020

69 $
(36)
7

(291) $
(17)
(2)

40 $

(310) $

135
(33)
3

105

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated
Balance Sheet at December 31, 2020 and December 31, 2019.

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

At December 31, 2020

Derivative Assets
Derivative Liabilities

At December 31, 2019
Derivative Assets
Derivative Liabilities

Gross Amounts
Recognized

Gross Amounts
Offset

Net Amounts
Presented

Gross Amounts
Not Offset

Net Amounts

$
$

818
917

656
719

$
$

744
744

645
645

$
$

74
173

11
74

$
$

—
—

$
$

74
173

11
74

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.

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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 9
Assets Held for Sale
At December 31, 2020, the company classified $1,101 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 2020 were not material.

Note 10
Equity
Retained earnings at December 31, 2020 and 2019, included $26,532 and $25,319, respectively, for the company’s share of
undistributed earnings of equity affiliates.

At December 31, 2020, about 67 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, 644,376 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 86). The table below sets forth the computation of basic and diluted EPS:

2020

Year ended December 31
2018
2019

Basic EPS Calculation

Earnings available to common stockholders - Basic1

(5,543) $

2,924

14,824

1,870
—

1,870

1,882
—

1,882

(2.96) $

1.55

1,897
1

1,898

7.81

(5,543) $

2,924

14,824

Net Income (Loss) Attributable to Chevron Corporation

(5,543) $

2,924

Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2020 and 2019

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

1,870
—
—

1,870

1,882
—
13

1,895

1,897
1
16

1,914

7.74

Earnings per share of common stock - Diluted

(2.96) $

1.54

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; 1 million shares of employee-based awards were not included in the 2020 diluted EPS calculation as the result would be anti-dilutive.

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, producing and transporting 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, refined products and lubricants;
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.

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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. Non billable costs remain at the corporate level in “All

Other.” Earnings by major operating area are presented in the following table:

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

Year ended December 31

2020

2019

(5,094) $

(1,608) $

(825)

(2,433)

(571)

618

(2,386)

(658)

(2,551)

7,670

2,576

1,559

922

2,481

5,057

(761)

181

(1,553)

2018

3,278

10,038

13,316

2,103

1,695

3,798

17,114

(713)

137

(1,714)

14,824

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

At December 31

2020

2019

42,431

144,476

4,402

191,309

23,490

16,096

39,586

230,895

4,017

4,878

8,895

69,938

165,450

4,402

239,790

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal

transfers, for the years 2020, 2019 and 2018, are presented in the table on the next page. Products are transferred between

operating segments at internal product values that approximate market prices.

At December 31, 2020, the company classified $1,101 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 2020 were not material.

Retained earnings at December 31, 2020 and 2019, included $26,532 and $25,319, respectively, for the company’s share of

undistributed earnings of equity affiliates.

At December 31, 2020, about 67 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, 644,376 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 86). The table below sets forth the computation of basic and diluted EPS:

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

Year ended December 31

2020

2019

2018

(5,543) $

2,924

14,824

1,870

—

1,870

(2.96) $

(5,543) $

1,870

—

1,870

1,882

—

1,882

1.55

2,924

1,882

—

1,895

1,897

1,898

7.81

14,824

1,897

1,914

7.74

Earnings per share of common stock - Diluted

(2.96) $

1.54

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; 1 million shares of employee-based awards were not included in the 2020 diluted EPS calculation as the result would be anti-dilutive.

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, producing and transporting 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, refined products and lubricants;

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.

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 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. Non billable costs remain at the corporate level in “All
Other.” Earnings by major operating area are presented in the following table:

Upstream

United States
International

Total Upstream

Downstream
United States
International

Total Downstream

Total Segment Earnings
All Other

Interest expense
Interest income
Other

2020

(1,608) $
(825)

(2,433)

(571)
618

(2,386)

(658)
52
(2,551)

Year ended December 31
2018
2019

(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)

14,824

Net Income (Loss) Attributable to Chevron Corporation

(5,543) $

2,924 $

Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2020 and 2019
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

2020

42,431 $
144,476
4,402

191,309

23,490
16,096

39,586

230,895

4,017
4,878

8,895

69,938
165,450
4,402

239,790 $

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

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal
transfers, for the years 2020, 2019 and 2018, are presented in the table on the next page. Products are transferred between
operating segments at internal product values that approximate market prices.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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.

Year ended December 311
2018

2019

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

2020

14,577
26,804

41,381

(8,068)
(7,002)

26,311

32,589
38,936

71,525

(2,150)
(1,292)

68,083

744
15

759

(667)
(15)

47,910
65,755

113,665

(10,885)
(8,309)

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)

Total Sales and Other Operating Revenues

94,471

139,865

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 2020, 2019 and 2018 is as follows:

Upstream

United States
International

Total Upstream

Downstream

United States
International

Total Downstream

All Other

2020

(570)
(415)

(985)

(192)
253

(968)

(1,550) $
3,492

1,942

392
170

562

187

Total Income Tax Expense (Benefit)

(1,892)

2,691

Year ended December 31
2018

2019

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)

158,902

811
4,687

5,498

534
328

862

(645)

5,715

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 13,
on page 77. Information related to properties, plant and equipment by segment is contained in Note 16, on page 82.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 13

Investments and Advances

Upstream

Tengizchevroil

Petropiar

Petroboscan

Caspian Pipeline Consortium

Angola LNG Limited

Noble Midstream equity affiliates

Other

Total Upstream

Downstream

GS Caltex Corporation

Other

Total Downstream

All Other

Other

Chevron Phillips Chemical Company LLC

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.”

Investments and Advances

At December 31

2020

2019

2020

Equity in Earnings

Year ended December 31

2019

2018

22,685

20,214

3,067

3,614

1,238

(1,396)

(1,112)

159

(166)

(9)

146

(1,140)

630

(185)

223

668

—

(11)

155

(26)

—

(478)

2,787

880

288

1,181

—

317

357

170

172

—

4,649

1,034

373

273

1,680

(2)

6,327

—

835

2,258

895

980

27,653

6,181

3,547

1,389

11,117

(14)

38,756

296

39,052

7,978

31,074

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

Total equity method

Other non-equity method investments

Total investments and advances

Total United States

Total International

(472)

3,968

709

(1,181)

641

3,327

1,033

5,294

Descriptions of major affiliates and non-equity investments, 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, 2020, the company’s carrying value of its investment in TCO was

about $100 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 $4,825.

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. In 2020, the company fully impaired its investments in the Petropiar

affiliate and, effective July 1, 2020, began accounting for this venture as a non-equity method investment. At December 31,

2020, the underlying equity in Petropiar’s net assets was approximately $1,500.

Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in

Venezuela. In 2020, the company fully impaired its investments in the Petroboscan affiliate and, effective July 1, 2020,

began accounting for this venture as a non-equity method investment. At December 31, 2020, the underlying equity in

Petroboscan’s net assets was approximately $1,100. The company also has an outstanding long-term loan to Petroboscan of

$560 at year-end 2020.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, which provides the

critical export route for crude oil from both TCO and Karachaganak.

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.

Noble Midstream Equity Affiliates Noble Midstream, a fully consolidated subsidiary of Chevron, has equity investments in

entities which operate midstream assets in the United States. At December 31, 2020, equity investments included

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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
Noble Midstream equity affiliates
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

2020

22,685
—
—
835
2,258
895
980

27,653

6,181
3,547
1,389

11,117

(14)

38,756
296

39,052

7,978
31,074

$
$

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

$
$

2020

1,238
(1,396)
(1,112)
159
(166)
(9)
146

(1,140)

630
(185)
223

668

—

Equity in Earnings
Year ended December 31
2018
2019

3,067
80
(11)
155
(26)
—
(478)

2,787

880
13
288

1,181

—

3,614
317
357
170
172
—
19

4,649

1,034
373
273

1,680

(2)

6,327

(472)

3,968

709
(1,181)

$
$

641
3,327

$
$

1,033
5,294

Descriptions of major affiliates and non-equity investments, 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, 2020, the company’s carrying value of its investment in TCO was
about $100 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 $4,825.

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. In 2020, the company fully impaired its investments in the Petropiar
affiliate and, effective July 1, 2020, began accounting for this venture as a non-equity method investment. At December 31,
2020, the underlying equity in Petropiar’s net assets was approximately $1,500.

Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in
Venezuela. In 2020, the company fully impaired its investments in the Petroboscan affiliate and, effective July 1, 2020,
began accounting for this venture as a non-equity method investment. At December 31, 2020, the underlying equity in
Petroboscan’s net assets was approximately $1,100. The company also has an outstanding long-term loan to Petroboscan of
$560 at year-end 2020.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, which provides the
critical export route for crude oil from both TCO and Karachaganak.

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.

Noble Midstream Equity Affiliates Noble Midstream, a fully consolidated subsidiary of Chevron, has equity investments in
entities which operate midstream assets in the United States. At December 31, 2020, equity investments included

Chevron Corporation 2020 Annual Report
77

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Advantage Pipeline LLC (50 percent), Delaware Crossing LLC (50 percent), EPIC Crude Holdings (30 percent), EPIC
Y-Grade (15 percent), EPIC Propane (15 percent), and Saddlehorn Pipeline Company, LLC (20 percent).

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 in South Korea.
The joint venture imports, refines and markets petroleum products, petrochemicals and lubricants.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $6,038, $8,006
and $10,378 with affiliated companies for 2020, 2019 and 2018, respectively. “Purchased crude oil and products” includes
$3,003, $5,694 and $6,598 with affiliated companies for 2020, 2019 and 2018, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $807 and $810 due from affiliated companies at
December 31, 2020 and 2019, respectively. “Accounts payable” includes $244 and $506 due to affiliated companies at
December 31, 2020 and 2019, 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 $5,153, $4,331 and $3,402 at December 31, 2020,
2019 and 2018, 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

2020

49,093
5,682
4,704

17,087
97,468
12,164
25,586

2019

66,473
13,197
9,809

30,791
97,177
26,032
21,593

Affiliates
2018

84,469
16,693
13,321

32,657
87,614
26,006
20,000

2020

21,641
2,550
2,034

7,328
43,247
5,052
5,884

Chevron Share
2018

40,679
6,755
6,384

12,813
36,369
9,843
4,446

2019

32,628
5,954
4,366

12,998
41,531
10,610
5,068

Total affiliates’ net equity

76,805

80,343

74,265

39,639

38,851

34,893

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. 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

Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of an oil production consortium
with Ecuadorian state-owned Petroecuador from 1967 until 1992. After termination of the consortium and a third-party
environmental audit, Ecuador and the consortium parties entered into a settlement agreement specifying Texpet’s
remediation obligations. Following Texpet’s completion of a three-year remediation program, Ecuador certified the
remediation as proper and released Texpet and its affiliates from environmental liability. In May 2003, plaintiffs alleging
environmental harm from the consortium’s activities sued Chevron in the Superior Court in Lago Agrio, Ecuador. In
February 2011, that court entered a judgment against Chevron for approximately $9,500 plus additional punitive damages.
An appellate panel affirmed, and Ecuador’s National Court of Justice ratified the judgment but nullified the punitive
damages, resulting in a judgment of approximately $9,500. Ecuador’s highest Constitutional Court rejected Chevron’s final
appeal in July 2018.

In February 2011, Chevron sued the Lago Agrio plaintiffs and several of their lawyers and supporters in the U.S. District
Court for the Southern District of New York (SDNY) for violations of the Racketeer Influenced and Corrupt Organizations
(RICO) Act and state law. The SDNY court ruled that the Ecuadorian judgment had been procured through fraud, bribery,
and corruption, and prohibited the RICO defendants from seeking to enforce the Ecuadorian judgment in the United States or
profiting from their illegal acts. The Court of Appeals for the Second Circuit affirmed, and the U.S. Supreme Court denied
certiorari in June 2017, rendering final the U.S. judgment in favor of Chevron. The Lago Agrio plaintiffs sought to

Chevron Corporation 2020 Annual Report
78

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

have the Ecuadorian judgment recognized and enforced in Canada, Brazil, and Argentina. All of those recognition and
enforcement actions were dismissed and resolved in Chevron’s favor. Chevron and Texpet filed an arbitration claim against
Ecuador in September 2009 before an arbitral tribunal administered by the Permanent Court of Arbitration in The Hague,
under the United States-Ecuador Bilateral Investment Treaty. In August 2018, the Tribunal issued an award holding that the
Ecuadorian judgment was based on environmental claims that Ecuador had settled and released, and that it was procured
through fraud, bribery, and corruption. 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 ordered Ecuador to remove
the status of enforceability from the Ecuadorian judgment and to compensate Chevron for any injuries resulting from the
judgment. The third and final phase of the arbitration, to determine the amount of compensation Ecuador owes to Chevron, is
ongoing. In September 2020, the District Court of The Hague denied Ecuador’s request to set aside the Tribunal’s award,
stating that it now is “common ground” between Ecuador and Chevron that the Ecuadorian judgment is fraudulent. In
December 2020, Ecuador appealed the District Court’s decision to The Hague Court of Appeals. In a separate proceeding,
Ecuador also admitted that the Ecuadorian judgment is fraudulent in a public filing with the Office of the United States Trade
Representative in July 2020.

Management’s Assessment The ultimate outcome of the foregoing matters, including any financial effect on Chevron,
remains uncertain. Chevron continues to believe that the Ecuadorian judgment is illegitimate and unenforceable and that it
does not provide any basis upon which an estimate of a reasonably possible loss or range of loss can be made.

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

2020

(182)
(1,315)

65
(152)

(1,584)

1,833
(2,141)

(308)

Year ended December 31
2018

2019

(73) $

(1,074)

153
(172)

(1,166)

4,577
(720)

3,857

(181)
738

183
(16)

724

4,662
329

4,991

5,715

Total income tax expense (benefit)

(1,892)

2,691

The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed
in the following table:

Income (loss) before income taxes

United States
International

Total income (loss) before income taxes

Theoretical tax (at U.S. statutory rate of 21% )
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

2020

(5,700)
(1,753)

(7,453)

(1,565)
—
211
(39)
(65)
(236)
(33)
(165)

(1,892)

2019

2018

(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

25.4%

48.6%

27.8%

Includes one-time tax costs (benefits) associated with changes in uncertain tax positions and valuation allowances.

The 2020 decrease in income tax expense of $4,583 is a result of the year-over-year decrease in total income before income
tax expense, which is primarily due to lower crude oil prices in 2020, partially offset by lower impairment and write off

Chevron Corporation 2020 Annual Report
79

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

charges. The company’s effective tax rate changed from 49 percent in 2019 to 25 percent in 2020. 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.

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

2020

16,603
5,617

22,220

17,251
5,372

22,623

(10,585)
(4,721)
(3,856)
(1,056)
(6,701)
(228)
(633)
(1,234)
(3,685)

(32,699)

17,762

(9,840)
(4,329)
(3,454)
(1,083)
(5,262)
(441)
(662)
(1,211)
(2,796)

(29,078)

15,965

7,283

9,510

Deferred tax liabilities decreased by $403 from year-end 2019. The decrease to Properties, plant and equipment temporary
differences was partially offset with an increase to Investments and other. The Properties, plant and equipment decrease was
primarily due to upstream impairments. Deferred tax assets increased by $3,621 from year-end 2019. This increase was
primarily related to increases in tax loss carryforwards for various locations, miscellaneous items related to foreign exchange
and foreign tax credits acquired with the purchase of Noble.

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 2020, the company had gross tax loss carryforwards of
approximately $19,763 and tax credit carryforwards of approximately $1,056, 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 2021 through 2034. U.S. foreign tax credit carryforwards of $10,585 will expire between 2021 and 2030.

At December 31, 2020 and 2019, deferred taxes were classified on the Consolidated Balance Sheet as follows:

Deferred charges and other assets
Noncurrent deferred income taxes

Total deferred income taxes, net

At December 31
2019

(4,178)
13,688

9,510

2020

(5,286)
12,569

7,283

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 $52,100 at
December 31, 2020. 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.

Chevron Corporation 2020 Annual Report
80

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

charges. The company’s effective tax rate changed from 49 percent in 2019 to 25 percent in 2020. 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

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

higher or lower tax rate jurisdictions.

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

At December 31

2020

2019

16,603

5,617

22,220

(10,585)

(4,721)

(3,856)

(1,056)

(6,701)

(228)

(633)

(1,234)

(3,685)

(32,699)

17,762

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

9,510

7,283

Deferred tax liabilities decreased by $403 from year-end 2019. The decrease to Properties, plant and equipment temporary

differences was partially offset with an increase to Investments and other. The Properties, plant and equipment decrease was

primarily due to upstream impairments. Deferred tax assets increased by $3,621 from year-end 2019. This increase was

primarily related to increases in tax loss carryforwards for various locations, miscellaneous items related to foreign exchange

and foreign tax credits acquired with the purchase of Noble.

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 2020, the company had gross tax loss carryforwards of

approximately $19,763 and tax credit carryforwards of approximately $1,056, 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 2021 through 2034. U.S. foreign tax credit carryforwards of $10,585 will expire between 2021 and 2030.

At December 31, 2020 and 2019, deferred taxes were classified on the Consolidated Balance Sheet as follows:

At December 31

2020

(5,286)

12,569

7,283

2019

(4,178)

13,688

9,510

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 $52,100 at

December 31, 2020. 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,
2020, 2019 and 2018. 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

2020

4,987
2
253
437
(216)
(429)
(16)

2019

5,070
1
94
313
(194)
(78)
(219)

Balance at December 31

5,018

4,987

2018

4,828
(6)
239
153
(131)
(13)
—

5,070

Approximately 83 percent of the $5,018 of unrecognized tax benefits at December 31, 2020, 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, 2020. For these jurisdictions, the latest years for which income tax examinations had
been finalized were as follows: United States – 2013, Nigeria – 2007, 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, 2020, accrual benefit of $(95) for anticipated interest and penalty
were included on the Consolidated Balance Sheet, compared with accrual charges of $30 as of year-end 2019. Income tax
expense (benefit) associated with interest and penalties was $(124), $(3) and $8 in 2020, 2019 and 2018, respectively.

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Commercial paper1

Notes payable to banks and others with originating terms of one year or less

Current maturities of long-term debt

Current maturities of long-term finance leases

Redeemable long-term obligations

Long-term debt

Subtotal

Reclassified to long-term debt

Total short-term debt

At December 31

2020

5,612

2,600

186

2,960

11,373

(9,825)

2019

4,654

228

5,054

3,078

13,032

(9,750)

1,548

3,282

1 Weighted-average interest rates at December 31, 2020 and 2019, were 0.15% and 1.69%, respectively.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current

liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2020, the

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

At December 31, 2020, the company had $9,825 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, 2020.

The company classified $9,825 and $9,750 of short-term debt as long-term at December 31, 2020 and 2019, 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

Taxes Other Than on Income

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

Note 16
Properties, Plant and Equipment1

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Year ended December 31
2018

2019

Note 17

Short-Term Debt

2020

4,566
(4,566)
7
2,248
235
317

2,807

2,367
(2,367)
39
1,461
117
75

1,692

4,990
(4,990)
2
1,785
254
355

2,396

2,801
(2,801)
35
1,435
125
145

1,740

4,830
(4,830)
15
1,577
246
325

2,163

3,031
(3,031)
37
2,370
132
165

2,704

4,867

4,499

4,136

Gross Investment at Cost
2018
2019

2020

At December 31
Net Investment
2018
2019

Additions at Cost2
2018

2019

2020

Year ended December 31
Depreciation Expense3
2018

2019

2020

Upstream

United States
International

96,555 $ 82,117 $ 88,155 $
209,846 206,292

215,329

38,175 $ 31,082 $ 39,526 $ 13,067 $ 7,751 $ 6,434 $
102,010

102,639

113,603

11,069

4,865

3,664

6,841 $ 15,222 $
11,121

12,618

5,328
12,726

Total Upstream

306,401 288,409

303,484

140,185

133,721

153,129

24,136

11,415

11,299

17,962

27,840

18,054

Downstream

United States
International

26,499
7,993

25,968
7,480

24,685
7,237

11,101
3,395

11,398
3,114

10,838
3,023

638
573

1,452
355

1,259
278

851
283

869
256

751
282

Total Downstream

34,492

33,448

31,922

14,496

14,512

13,861

1,211

1,807

1,537

1,134

1,125

1,033

All Other

United States
International

Total All Other

4,195
144

4,339

4,719
146

4,865

4,667
171

4,838

1,916
21

1,937

2,236
25

2,261

2,186
31

2,217

194
5

199

324
9

333

224
6

230

403
9

412

243
10

253

320
12

332

Total United States
Total International

127,249 112,804
217,983 213,918

117,507
222,737

51,192
105,426

44,716
105,778

52,550
116,657

13,899
11,647

9,527
4,028

7,917
5,149

8,095
11,413

16,334
12,884

6,399
13,020

Total

$ 345,232 $ 326,722 $ 340,244 $ 156,618 $ 150,494 $ 169,207 $ 25,546 $ 13,555 $ 13,066 $ 19,508 $ 29,218 $ 19,419

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 2020. Australia
had PP&E of $48,060, $51,359 and $53,768 in 2020, 2019 and 2018, respectively. Gross Investment at Cost, Net Investment and Additions at Cost for 2020 each include
$16,703 associated with the Noble acquisition.

2 Net of dry hole expense related to prior years’ expenditures of $709, $49 and $343 in 2020, 2019 and 2018, respectively.
3 Depreciation expense includes accretion expense of $560, $628 and $654 in 2020, 2019 and 2018, respectively, and impairments of $2,792, $10,797 and $735 in 2020, 2019

and 2018, respectively.

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Taxes Other Than on Income

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

4,566

(4,566)

4,990

(4,990)

2,248

235

317

2,807

2,367

(2,367)

1,461

117

1,692

4,499

1,785

254

355

2,396

2,801

(2,801)

1,435

125

145

1,740

4,830

(4,830)

1,577

246

325

2,163

3,031

(3,031)

2,370

132

165

2,704

4,867

Total taxes other than on income

4,136

Upstream

United States

International

Downstream

United States

International

All Other

United States

International

Total All Other

Gross Investment at Cost

Additions at Cost2

Depreciation Expense3

2020

2019

2018

2020

2019

2018

2020

2019

2018

2020

2019

2018

At December 31

Net Investment

Year ended December 31

96,555 $ 82,117 $ 88,155 $

38,175 $ 31,082 $ 39,526 $ 13,067 $ 7,751 $ 6,434 $

6,841 $ 15,222 $

209,846

206,292

215,329

102,010

102,639

113,603

11,069

3,664

4,865

Total Upstream

306,401

288,409

303,484

140,185

133,721

153,129

24,136

11,415

11,299

Total Downstream

34,492

33,448

26,499

7,993

25,968

7,480

4,195

144

4,339

4,719

146

4,865

24,685

7,237

31,922

4,667

171

4,838

11,101

3,395

14,496

11,398

3,114

14,512

10,838

3,023

13,861

638

573

1,211

1,452

355

1,807

1,259

278

1,537

1,916

1,937

2,236

2,261

2,186

2,217

194

199

324

333

224

230

Total United States

Total International

127,249

217,983

112,804

213,918

117,507

222,737

51,192

105,426

44,716

105,778

52,550

116,657

13,899

11,647

9,527

4,028

7,917

5,149

8,095

11,413

16,334

12,884

6,399

13,020

Total

$ 345,232 $ 326,722 $ 340,244 $ 156,618 $ 150,494 $ 169,207 $ 25,546 $ 13,555 $ 13,066 $ 19,508 $ 29,218 $ 19,419

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 2020. Australia

had PP&E of $48,060, $51,359 and $53,768 in 2020, 2019 and 2018, respectively. Gross Investment at Cost, Net Investment and Additions at Cost for 2020 each include

2 Net of dry hole expense related to prior years’ expenditures of $709, $49 and $343 in 2020, 2019 and 2018, respectively.

3 Depreciation expense includes accretion expense of $560, $628 and $654 in 2020, 2019 and 2018, respectively, and impairments of $2,792, $10,797 and $735 in 2020, 2019

$16,703 associated with the Noble acquisition.

and 2018, respectively.

11,121

17,962

12,618

27,840

5,328

12,726

18,054

1,134

1,125

1,033

851

283

403

412

869

256

243

253

751

282

320

332

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Year ended December 31

2020

2019

2018

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 debt
Current maturities of long-term finance leases
Redeemable long-term obligations

Long-term debt

Subtotal

Reclassified to long-term debt

Total short-term debt

2020

5,612
15
2,600
186

2,960

11,373
(9,825)

At December 31
2019

4,654
228
5,054
18

3,078

13,032
(9,750)

1,548

3,282

1 Weighted-average interest rates at December 31, 2020 and 2019, were 0.15% and 1.69%, respectively.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current
liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2020, the
company had no interest rate swaps on short-term debt.

At December 31, 2020, the company had $9,825 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, 2020.

The company classified $9,825 and $9,750 of short-term debt as long-term at December 31, 2020 and 2019, 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.

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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, 2020, was $42,767. The company’s long-term debt
outstanding at year-end 2020 and 2019 was as follows:

Weighted Average
Interest Rate (%)1

Range of Interest
Rates (%)2

Principal

See Note 7, beginning on page 71, for information concerning the fair value of the company’s long-term debt.

At December 31
2019

2020

requirements.

Notes due 2021
Floating rate notes due 2021
Debentures due 2021
Notes due 2022
Floating rate notes due 2022
Notes due 2023
Floating rate notes due 2023
Notes due 2024
Notes due 2025
Notes due 2026
Notes due 2027
Notes due 2028
Notes due 2029
Notes due 2030
Debentures due 2031
Debentures due 2032
Notes due 2040
Notes due 2041
Notes due 2043
Notes due 2044
Notes due 2047
Notes due 2049
Notes due 2050
Debentures due 2097
Bank loans due 2021 - 2023
3.400% loan3
Medium-term notes, maturing from 2021 to 2038
Notes due 2020

Total including debt due within one year

Debt due within one year
Fair market valuation adjustment of Noble long-term debt
Reclassified from short-term debt
Unamortized discounts and debt issuance costs
Finance lease liabilities4

Total long-term debt

0.913

2.179
0.594
2.377
0.676
3.291
1.724

2.379

8.414

2.763

1.530

6.131

2.100
0.751 - 1.171
8.875
0.333 - 2.498
0.324 - 0.762
0.426 - 7.250
0.414 - 1.114
2.895 - 3.900
0.687 - 3.326
2.954
1.018 - 8.000
3.850
3.250
2.236
8.625
8.000 - 8.625
2.978
6.000
5.250
5.050
4.950
4.200
2.343 - 3.078
7.250
1.240 - 2.004
3.400
0.000 - 8.875

1,350
650
40
3,800
1,000
4,800
800
1,650
4,000
2,250
2,000
600
500
1,500
108
222
500
850
1,000
850
500
500
1,750
84
1,948
218
37
—

1,350
650
40
3,400
650
3,000
—
1,000
750
2,250
—
—
—
—
108
222
—
—
—
—
—
—
—
—
—
218
38
5,054

33,507
(2,600)
1,690
9,825
(102)
447

18,730
(5,054)
—
9,750
(17)
282

42,767

23,691

Balance at December 31

1 Weighted-average interest rate at December 31, 2020
2 Range of interest rates at December 31, 2020.
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 69

Chevron has an automatic shelf registration statement that expires in August 2023. This registration statement is for an
unspecified amount of nonconvertible debt securities issued or guaranteed by Chevron Corporation or CUSA.

Long-term debt excluding finance lease liabilities with a principal balance of $33,507 matures as follows: 2021 – $2,600;
2022 – $5,548; 2023 – $6,475; 2024 – $1,650; 2025 – $4,000; and after 2025 – $13,234.

The company completed bond issuances of $8,000 and $4,000 in May and August 2020, respectively. Chevron also assumed
total debt, including finance lease obligations, with a fair value of approximately $9,400, associated with the acquisition of
Noble on October 5, 2020.

Included in the debt assumed from Noble were senior notes, with an aggregate principal amount of $5,800, with interest rates
ranging from 3.250 percent to 8.000 percent and maturity dates ranging from 2023 to 2049. On January 6, 2021, Chevron
announced that the aggregate principal amount of $5,697 of prior Noble senior notes were exchanged for new

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Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

senior notes issued by CUSA, guaranteed by Chevron, and having the same interest rates and maturity dates as the Noble

senior notes. The aggregate principal amount of $5,697 prior Noble notes were validly tendered and accepted and

subsequently terminated. Following such termination, $103 aggregate principal amount remains outstanding across ten series

of senior notes issued by Noble, for which Chevron provided no guarantee, and the indentures were modified to eliminate

any financial reporting or credit rating requirements. In February 2021, the indenture governing Noble’s 7.250 percent senior

debentures due 2097 was modified to provide a guarantee by Chevron and eliminate any financial reporting or credit rating

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.

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended

December 31, 2020:

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*

Ending balance at December 31

2020 represents fair value of well costs acquired in the Noble acquisition. 2019 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. The aging of the former Noble wells

is based on the date the drilling was completed, rather than Chevron’s October 2020 acquisition of Noble.

2020

2019

2018

3,041

3,563

3,702

(102)

(667)

212

244

(500)

(125)

(141)

207

(13)

(333)

—

2,512

3,041

3,563

2020

2,486

2,512

At December 31

2019

214

2,827

3,041

2018

202

3,361

3,563

Exploratory well costs capitalized for a period of one year or less

Exploratory well costs capitalized for a period greater than one year

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 $2,486 of exploratory well costs capitalized for more than one year at December 31, 2020, $1,197 is related to 7

projects that had drilling activities underway or firmly planned for the near future. The $1,289 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 $1,289 referenced above had the following activities associated with assessing the reserves and the

projects’ economic viability: (a) $826 (seven projects) – undergoing front-end engineering and design with final investment

decision expected within four years; (b) $463 (three projects) – development alternatives under review. While progress was

being made on all 17 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.

Total long-term debt including finance lease liabilities at December 31, 2020, was $42,767. The company’s long-term debt

outstanding at year-end 2020 and 2019 was as follows:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 18

Long-Term Debt

Notes due 2021

Floating rate notes due 2021

Debentures due 2021

Notes due 2022

Floating rate notes due 2022

Notes due 2023

Floating rate notes due 2023

Notes due 2024

Notes due 2025

Notes due 2026

Notes due 2027

Notes due 2028

Notes due 2029

Notes due 2030

Notes due 2040

Notes due 2041

Notes due 2043

Notes due 2044

Notes due 2047

Notes due 2049

Notes due 2050

Debentures due 2031

Debentures due 2032

Debentures due 2097

Bank loans due 2021 - 2023

3.400% loan3

Medium-term notes, maturing from 2021 to 2038

Notes due 2020

Total including debt due within one year

Debt due within one year

Fair market valuation adjustment of Noble long-term debt

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, 2020

2 Range of interest rates at December 31, 2020.

At December 31

2020

2019

Weighted Average

Interest Rate (%)1

Range of Interest

Rates (%)2

Principal

0.913

0.751 - 1.171

2.100

1,350

2.179

0.594

2.377

0.676

3.291

1.724

8.875

0.333 - 2.498

0.324 - 0.762

0.426 - 7.250

0.414 - 1.114

2.895 - 3.900

0.687 - 3.326

2.379

1.018 - 8.000

8.414

8.000 - 8.625

2.763

2.343 - 3.078

1.530

1.240 - 2.004

6.131

0.000 - 8.875

2.954

3.850

3.250

2.236

8.625

2.978

6.000

5.250

5.050

4.950

4.200

7.250

3.400

650

3,800

1,000

4,800

800

1,650

4,000

2,250

2,000

600

500

1,500

108

222

500

850

500

1,000

1,750

1,948

218

—

33,507

(2,600)

1,690

9,825

(102)

447

1,350

650

3,400

650

3,000

—

1,000

750

2,250

108

222

—

218

5,054

18,730

(5,054)

—

9,750

(17)

282

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

senior notes issued by CUSA, guaranteed by Chevron, and having the same interest rates and maturity dates as the Noble
senior notes. The aggregate principal amount of $5,697 prior Noble notes were validly tendered and accepted and
subsequently terminated. Following such termination, $103 aggregate principal amount remains outstanding across ten series
of senior notes issued by Noble, for which Chevron provided no guarantee, and the indentures were modified to eliminate
any financial reporting or credit rating requirements. In February 2021, the indenture governing Noble’s 7.250 percent senior
debentures due 2097 was modified to provide a guarantee by Chevron and eliminate any financial reporting or credit rating
requirements.

See Note 7, beginning on page 71, 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.

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended
December 31, 2020:

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*

Ending balance at December 31

* 2020 represents fair value of well costs acquired in the Noble acquisition. 2019 represents property sales.

2020

3,041
28
(102)
(667)
212

2019

3,563
244
(500)
(125)
(141)

2018

3,702
207
(13)
(333)
—

2,512

3,041

3,563

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. The aging of the former Noble wells
is based on the date the drilling was completed, rather than Chevron’s October 2020 acquisition of Noble.

42,767

23,691

Balance at December 31

Exploratory well costs capitalized for a period of one year or less
Exploratory well costs capitalized for a period greater than one year

2020

26
2,486

At December 31
2018

2019

214
2,827

202
3,361

2,512

3,041

3,563

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 69

Chevron has an automatic shelf registration statement that expires in August 2023. This registration statement is for an

unspecified amount of nonconvertible debt securities issued or guaranteed by Chevron Corporation or CUSA.

Long-term debt excluding finance lease liabilities with a principal balance of $33,507 matures as follows: 2021 – $2,600;

2022 – $5,548; 2023 – $6,475; 2024 – $1,650; 2025 – $4,000; and after 2025 – $13,234.

The company completed bond issuances of $8,000 and $4,000 in May and August 2020, respectively. Chevron also assumed

total debt, including finance lease obligations, with a fair value of approximately $9,400, associated with the acquisition of

Noble on October 5, 2020.

Included in the debt assumed from Noble were senior notes, with an aggregate principal amount of $5,800, with interest rates

ranging from 3.250 percent to 8.000 percent and maturity dates ranging from 2023 to 2049. On January 6, 2021, Chevron

announced that

the aggregate principal amount of $5,697 of prior Noble senior notes were exchanged for new

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 $2,486 of exploratory well costs capitalized for more than one year at December 31, 2020, $1,197 is related to 7
projects that had drilling activities underway or firmly planned for the near future. The $1,289 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 $1,289 referenced above had the following activities associated with assessing the reserves and the
projects’ economic viability: (a) $826 (seven projects) – undergoing front-end engineering and design with final investment
decision expected within four years; (b) $463 (three projects) – development alternatives under review. While progress was
being made on all 17 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.

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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 $2,486 of suspended well costs capitalized for a period greater than one year as of December 31, 2020, represents 89
exploratory wells in 17 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

2000-2009
2010-2014
2015-2019

Total

Aging based on drilling completion date of last suspended well in project:

2003-2012
2013-2016
2017-2020

Total

342
1,457
687

2,486

17
54
18

Amount Number of projects

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.

371
1,627
488

2,486

4
8
5

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

2020

6.6

20.8 %

1.5 %

4.0 %

Year ended December 31

2019

6.6

20.5 %

2.6 %

3.8 %

2018

6.5

21.2 %

2.6 %

3.8 %

13.00

15.82

18.18

Note 20
Stock Options and Other Share-Based Compensation
Compensation expense for stock options for 2020, 2019 and 2018 was $94 ($74 after tax), $81 ($64 after tax) and $105 ($83
after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares
and restricted stock units was $96 ($76 after tax), $313 ($266 after tax) and $60 ($47 after tax) for 2020, 2019 and 2018,
respectively. No significant stock-based compensation cost was capitalized at December 31, 2020, or December 31, 2019.

Cash received in payment for option exercises under all share-based payment arrangements for 2020, 2019 and 2018 was
$226, $1,090 and $1,159, respectively. Actual tax benefits realized for the tax deductions from option exercises were $8, $43
and $43 for 2020, 2019 and 2018, respectively.

Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $95, $119 and $157 for 2020,
2019 and 2018, respectively. Cash paid in 2020 included $11 million for Noble awards paid under change-in-control plan
provisions.

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.

Noble Share-Based Plans (Noble Plans) On the closing of the acquisition of Noble in October 2020, outstanding stock
options granted under various Noble Plans were exchanged for fully vested Chevron options at a conversion rate of 0.1191
Chevron shares for each Noble share. These awards retained the same provision as the original Noble Plans. Awards issued
may be exercised for up to 5 years after termination of employment, depending upon the termination type, or the original
expiration date, whichever is earlier. Other awards issued under the Noble Plans included restricted stock, phantom stock
units, and performance shares that retained the same provisions as the original Noble Plans. Upon termination of employment
due to change-in-control, all unvested awards issued under the Noble Plans, including stock options, restricted stock,
phantom stock units and performance shares become vested on the termination date.

Fair Value and Assumptions The fair market values of stock options and stock appreciation rights granted in 2020, 2019
and 2018 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-
average assumptions:

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A summary of option activity, including Noble, during 2020 is presented below:

Shares (Thousands)

Exercise Price

Contractual Term (Years) Aggregate Intrinsic Value

Weighted-Average

Averaged Remaining

Outstanding at January 1, 2020

Granted

Exercised

Forfeited

Outstanding at December 31, 2020

Exercisable at December 31, 2020

86,641

8,281

(2,739)

(2,033)

90,150

80,860

103.22

150.98

78.92

110.72

108.17

107.65

4.11

3.59

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during

2020, 2019 and 2018 was $92, $516 and $506, respectively. During this period, the company continued its practice of issuing

treasury shares upon exercise of these awards.

As of December 31, 2020, there was $57 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 1.7 years.

At January 1, 2020, the number of LTIP performance shares outstanding was equivalent to 4,386,784 shares. During 2020,

2,064,598 performance shares were granted, 676,282 shares vested with cash proceeds distributed to recipients and 1,340,303

shares were forfeited. At December 31, 2020, performance shares outstanding were 4,434,797. The fair value of the liability

recorded for these instruments was $385, and was measured using the Monte Carlo simulation method.

At January 1, 2020, the number of restricted stock units outstanding was equivalent to 2,512,345 shares. During 2020,

1,253,337 restricted stock units were granted, 165,007 units vested with cash proceeds distributed to recipients and 296,742

units were forfeited. At December 31, 2020, restricted stock units outstanding were 3,303,933. The fair value of the liability

recorded for the vested portion of these instruments was $197, valued at the stock price as of December 31, 2020. In addition,

outstanding stock appreciation rights that were granted under LTIP totaled approximately 4.1 million equivalent shares as of

December 31, 2020. The fair value of the liability recorded for the vested portion of these instruments was $34.

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.

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 $2,486 of suspended well costs capitalized for a period greater than one year as of December 31, 2020, represents 89

exploratory wells in 17 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

342

1,457

687

2,486

371

1,627

488

2,486

2000-2009

2010-2014

2015-2019

Total

2003-2012

2013-2016

2017-2020

Total

Note 20

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2020, 2019 and 2018 was $94 ($74 after tax), $81 ($64 after tax) and $105 ($83

after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares

and restricted stock units was $96 ($76 after tax), $313 ($266 after tax) and $60 ($47 after tax) for 2020, 2019 and 2018,

respectively. No significant stock-based compensation cost was capitalized at December 31, 2020, or December 31, 2019.

Cash received in payment for option exercises under all share-based payment arrangements for 2020, 2019 and 2018 was

$226, $1,090 and $1,159, respectively. Actual tax benefits realized for the tax deductions from option exercises were $8, $43

and $43 for 2020, 2019 and 2018, respectively.

Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $95, $119 and $157 for 2020,

2019 and 2018, respectively. Cash paid in 2020 included $11 million for Noble awards paid under change-in-control plan

provisions.

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.

Noble Share-Based Plans (Noble Plans) On the closing of the acquisition of Noble in October 2020, outstanding stock

options granted under various Noble Plans were exchanged for fully vested Chevron options at a conversion rate of 0.1191

Chevron shares for each Noble share. These awards retained the same provision as the original Noble Plans. Awards issued

may be exercised for up to 5 years after termination of employment, depending upon the termination type, or the original

expiration date, whichever is earlier. Other awards issued under the Noble Plans included restricted stock, phantom stock

units, and performance shares that retained the same provisions as the original Noble Plans. Upon termination of employment

due to change-in-control, all unvested awards issued under the Noble Plans, including stock options, restricted stock,

phantom stock units and performance shares become vested on the termination date.

Fair Value and Assumptions The fair market values of stock options and stock appreciation rights granted in 2020, 2019

and 2018 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

2020

6.6
20.8 %
1.5 %
4.0 %

Year ended December 31
2019

2018

6.6
20.5 %
2.6 %
3.8 %

6.5
21.2 %
2.6 %
3.8 %

13.00

15.82

18.18

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, including Noble, during 2020 is presented below:

Shares (Thousands)

Weighted-Average
Exercise Price

Averaged Remaining

Contractual Term (Years) Aggregate Intrinsic Value

Outstanding at January 1, 2020

Granted
Exercised
Forfeited

Outstanding at December 31, 2020

Exercisable at December 31, 2020

86,641
8,281
(2,739)
(2,033)
90,150

80,860

$ 103.22
$ 150.98
$
78.92
$ 110.72
$ 108.17

$ 107.65

4.11

3.59

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during
2020, 2019 and 2018 was $92, $516 and $506, respectively. During this period, the company continued its practice of issuing
treasury shares upon exercise of these awards.

As of December 31, 2020, there was $57 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 1.7 years.

At January 1, 2020, the number of LTIP performance shares outstanding was equivalent to 4,386,784 shares. During 2020,
2,064,598 performance shares were granted, 676,282 shares vested with cash proceeds distributed to recipients and 1,340,303
shares were forfeited. At December 31, 2020, performance shares outstanding were 4,434,797. The fair value of the liability
recorded for these instruments was $385, and was measured using the Monte Carlo simulation method.

At January 1, 2020, the number of restricted stock units outstanding was equivalent to 2,512,345 shares. During 2020,
1,253,337 restricted stock units were granted, 165,007 units vested with cash proceeds distributed to recipients and 296,742
units were forfeited. At December 31, 2020, restricted stock units outstanding were 3,303,933. The fair value of the liability
recorded for the vested portion of these instruments was $197, valued at the stock price as of December 31, 2020. In addition,
outstanding stock appreciation rights that were granted under LTIP totaled approximately 4.1 million equivalent shares as of
December 31, 2020. The fair value of the liability recorded for the vested portion of these instruments was $34.

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.

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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 funded status of the company’s pension and OPEB plans for 2020 and 2019 follows:

Change in Benefit Obligation

Benefit obligation at January 1
Service cost
Interest cost
Plan participants’ contributions
Plan amendments
Actuarial (gain) loss
Foreign currency exchange rate changes
Benefits paid
Divestitures/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.

14,465
497
353
—
—
1,782
—
(2,045)
22
92

15,166

10,177
848
—
950
—
(2,045)
—

9,930

2020
Int’l.

5,680
130
175
3
—
550
158
(368)
—
(21)

6,307

4,791
500
174
263
3
(368)
—

5,363

Pension Benefits
2019
Int’l.

U.S.

11,726
406
397
—
—
2,922
—
(1,035)
49
—

14,465

8,532
1,548
—
1,096
—
(1,035)
36

10,177

4,820
139
199
4
29
673
121
(302)
—
(3)

5,680

4,142
566
115
266
4
(302)
—

4,791

2020

2,520
38
71
59
—
191
(1)
(214)
—
(14)

2,650

—
—
—
155
59
(214)
—

—

Other Benefits
2019

Projected benefit obligations

Accumulated benefit obligations

Fair value of plan assets

U.S.

15,103

13,545

9,842

2020

Int’l.

2,084

1,622

600

Pension Benefits

2019

Int’l.

1,554

1,268

278

U.S.

14,401

12,718

10,091

2,430
36
96
72
—
125
2
(240)
(1)
—

2,520

—
—
—
168
72
(240)
—

—

Funded status at December 31

(5,236)

(944)

(4,288) $

(889)

(2,650)

(2,520)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2020
and 2019, include:

Deferred charges and other assets
Accrued liabilities
Noncurrent employee benefit plans

U.S.

24
(258)
(5,002)

2020
Int’l.

547
(76)
(1,415)

Pension Benefits
2019
Int’l.

U.S.

23
(239)
(4,072)

413
(71)
(1,231)

Other Benefits
2019

—
(174)
(2,346)

2020

—
(153)
(2,497)

Net amount recognized at December 31

(5,236)

(944)

(4,288)

(889)

(2,650)

(2,520)

For the years ended December 31, 2020 and December 31, 2019, the increase in benefit obligations was primarily due to
actuarial losses caused by lower discount rates used to value the obligations.

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB
plans were $7,278 and $6,357 at the end of 2020 and 2019, respectively. These amounts consisted of:

Net actuarial loss
Prior service (credit) costs

Total recognized at December 31

U.S.

5,714
3

2020
Int’l.

1,401
86

5,717

1,487

Pension Benefits
2019
Int’l.

U.S.

5,135
5

5,140

1,269
102

1,371

Other Benefits
2019

74
(228)

(154)

2020

260
(186)

The accumulated benefit obligations for all U.S. and international pension plans were $13,608 and $5,758, respectively, at
December 31, 2020, and $12,781 and $5,203, respectively, at December 31, 2019.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at
December 31, 2020 and 2019, was:

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The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive

Income for 2020, 2019 and 2018 are shown in the table below:

Total net periodic benefit cost

1,299

190

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)

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

2020

Int’l.

$ 130

175

U.S.

497

353

385

620

(650)

(209)

1,584

(1,005)

—

(2)

230

(98)

—

(17)

U.S.

406

397

(565)

239

259

—

738

1,939

(498)

—

(2)

Pension Benefits

2018

Int’l.

141

206

(253)

169

(62)

(13)

U.S.

480

370

(636)

304

411

—

931

151

(715)

—

(2)

2019

Int’l.

139

199

(231)

158

338

(24)

(30)

Other Benefits

2020

2019

2018

—

(28)

(27)

190

(4)

—

(28)

(3)

—

101

128

(1)

(28)

—

123

(248)

(15)

577

115

1,439

313

(566)

(40)

228

158

(232)

Other Comprehensive Income

$ 1,876

$ 305

$ 2,177

471

365

129

285

$ 259

$ (109)

Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic

benefit costs for years ended December 31:

2020

Int’l.

Pension Benefits

2019

Int’l.

2018

Int’l.

U.S.

2020

2019

2018

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

2.4% 2.4%

4.5% 4.0%

3.1% 3.2% 4.2% 4.4%

4.5% 4.0% 4.5% 4.0%

3.3% 3.2%

2.6% 3.2%

6.5% 4.5%

4.5% 4.0%

4.4% 4.4% 3.7% 3.9%

3.7% 4.4% 3.0% 3.9%

6.8% 5.6% 6.8% 5.5%

4.5% 4.0% 4.5% 4.0%

2.6%

N/A

3.5%

3.0%

N/A

3.2%

N/A

4.6%

4.2%

N/A

4.4%

N/A

3.9%

3.5%

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 2020, the company used an expected long-term rate of return of 6.50 percent for U.S. pension plan assets, which account

for 65 percent of the company’s pension plan assets. In both 2019 and 2018, 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.

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 funded status of the company’s pension and OPEB plans for 2020 and 2019 follows:

Pension Benefits

Other Benefits

2020

2019

Projected benefit obligations
Accumulated benefit obligations
Fair value of plan assets

U.S.

15,103
13,545
9,842

2020
Int’l.

2,084
1,622
600

Pension Benefits
2019
Int’l.

1,554
1,268
278

U.S.

14,401
12,718
10,091

14,465

5,680

11,726

4,820

2,520

2,430

The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive
Income for 2020, 2019 and 2018 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)

2020
Int’l.

U.S.

$ 497
353
(650)
2
385
620
92

$ 130
175
(209)
10
45
37
2

2019
Int’l.

139
199
(231)
11
21
3

U.S.

406
397
(565)
2
239
259
—16

Total net periodic benefit cost

1,299

190

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

1,584
(1,005)
—
(2)

230
(98)
—
(17)

1,939
(498)
—
(2)

338
(24)
29
(30)

Pension Benefits
2018
Int’l.

U.S.

480
370
(636)
2
304
411
—

931

151
(715)
—
(2)

141
206
(253)
10
29
33
3

169

12
(62)
23
(13)

Other Benefits
2018

2019

2020

38
71
—
(28)
3
—
(27)

36
96
—
(28)
(3)
—
—

42
94
—
(28)
15
—
—

101

123

190
(4)
—
42

128
3
(1)
28

(248)
(15)
3
28

577

115

1,439

313

(566)

(40)

228

158

(232)

Other Comprehensive Income

$ 1,876

$ 305

$ 2,177

471

365

129

285

$ 259

(109)

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

Assumptions used to determine benefit obligations:

Discount rate
Rate of compensation increase

Assumptions used to determine net periodic benefit cost:

Discount rate for service cost
Discount rate for interest cost
Expected return on plan assets
Rate of compensation increase

2020
Int’l.

U.S.

Pension Benefits
2018
Int’l.

U.S.

2019
Int’l.

2.4%
4.5%

2.4%
4.0%

3.1%
4.5%

3.2%
4.0%

4.2%
4.5%

4.4%
4.0%

3.3%
2.6%
6.5%
4.5%

3.2%
3.2%
4.5%
4.0%

4.4%
3.7%
6.8%
4.5%

4.4%
4.4%
5.6%
4.0%

3.7%
3.0%
6.8%
4.5%

3.9%
3.9%
5.5%
4.0%

2020

2.6%
N/A

3.5%
3.0%
N/A
N/A

Other Benefits
2018

2019

3.2%
N/A

4.6%
4.2%
N/A
N/A

4.4%
N/A

3.9%
3.5%
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 2020, the company used an expected long-term rate of return of 6.50 percent for U.S. pension plan assets, which account
for 65 percent of the company’s pension plan assets. In both 2019 and 2018, 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.

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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.

497

353

—

1,782

(2,045)

—

15,166

10,177

848

—

950

—

(2,045)

—

9,930

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

(889)

—

191

(1)

(214)

—

(14)

2,650

—

155

(214)

—

125

(240)

(1)

—

2,520

—

168

(240)

—

Funded status at December 31

(5,236)

(944)

(4,288)

(2,650)

(2,520)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2020

and 2019, include:

Deferred charges and other assets

Accrued liabilities

Noncurrent employee benefit plans

U.S.

(258)

(5,002)

2020

Int’l.

547

(76)

(1,415)

Pension Benefits

U.S.

(239)

(4,072)

2019

Int’l.

413

(71)

(1,231)

Other Benefits

2019

—

(174)

(2,346)

(2,520)

2020

—

(153)

(2,497)

(2,650)

Net amount recognized at December 31

(5,236)

(944)

(4,288)

(889)

For the years ended December 31, 2020 and December 31, 2019, the increase in benefit obligations was primarily due to

actuarial losses caused by lower discount rates used to value the obligations.

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB

plans were $7,278 and $6,357 at the end of 2020 and 2019, respectively. These amounts consisted of:

Net actuarial loss

Prior service (credit) costs

Total recognized at December 31

U.S.

5,714

5,717

2020

Int’l.

1,401

1,487

Pension Benefits

U.S.

5,135

5,140

2019

Int’l.

1,269

102

1,371

Other Benefits

2019

(228)

(154)

2020

260

(186)

The accumulated benefit obligations for all U.S. and international pension plans were $13,608 and $5,758, respectively, at

December 31, 2020, and $12,781 and $5,203, respectively, at December 31, 2019.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at

December 31, 2020 and 2019, was:

2020

Int’l.

130

175

—

550

158

(368)

—

(21)

6,307

4,791

500

174

263

(368)

—

5,363

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

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 2020
were 2.4 for the main U.S. pension plan and 2.4 for the main U.S. OPEB plan. The discount rates for these plans at the end of
2019 were 3.1 and 3.1 percent, respectively, while in 2018 they were 4.2 and 4.3 percent for these plans, respectively.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2020,
for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 6.1 percent in 2021 and gradually decline to
4.5 percent for 2027 and beyond. For this measurement at December 31, 2019, the assumed health care cost-trend rates
started with 6.8 percent in 2020 and gradually declined to 4.5 percent for 2025 and beyond.

Plan Assets and Investment Strategy

The fair value measurements of the company’s pension plans for 2020 and 2019 are as follows:

Total

Level 1

Level 2 Level 3

U.S.
NAV

Total

Level 1 Level 2 Level 3

Int’l.
NAV

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 Investments
Cash and Cash Equivalents
Other5

$ 1,769 $ 1,769 $

1,958
1,079

523
1,444
120
1
963
—
1,089
924
235
72

1,958
52

—
—
—
—
—
—
—
—
228
(5)

— $ — $ —
—
—
—
1,027
—
—

471 $
422
184

471 $ — $ — $ —
—
421
178
6

—
—

1
—

523
1,444
113
1
—
—
—
—
7
29

—
—
7
—
—
—
—
—
—
44

—
—
—
—
963
—
1,089
924
—
4

265
493
—
4
2,230
84
277
—
338
23

144
—
—
—
5
7
—
—
334
—

121
490
—
4
—
77
—
—
2
21

—
3
—
—
—
—
55
—
—
2

—
—
—
—
2,225
—
222
—
2
—

Total at December 31, 2019

$ 10,177 $ 4,002 $

2,117 $

51 $ 4,007

4,791 $

1,388 $ 715 $

61 $ 2,627

At December 31, 2020
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 Investments
Cash and Cash Equivalents
Other5

$ 2,286 $ 2,286 $

2,211
1,107

231
778
129
1
1,901
—
1,018
—
221
47

2,210
48

—
—
—
—
13
—
—
—
209
(19)

— $ — $ —
—
1
—
1,059
—
—

443 $
373
192

443 $ — $ — $ —
373
—
185
7

—
—

231
778
127
1
—
—
—
—
12
22

—
—
2
—
—
—
—
—
—
41

—
—
—
—
1,888
—
1,018
—
—
3

240
578
—
4
2,520
127
448
—
417
21

125
10
—
—
4
38
—
—
408
(2)

115
568
—
4
—
89
—
—
3
19

—
—
—
—
—
—
45
—
—
4

—
—
—
—
2,516
—
403
—
6
—

Total at December 31, 2020

$ 9,930 $ 4,747 $

1,171 $

44 $ 3,968

5,363 $

1,406 $ 798 $

49 $ 3,110

1 U.S. equities include investments in the company’s common stock in the amount of $4 at December 31, 2020, and $6 at December 31, 2019.
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 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).

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

below:

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

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, 2020

Equity

Fixed Income

International

Corporate

Bank Loans

Real Estate

Other

(1)

—

(19)

—

(3)

—

— $

—

(5)

—

(1)

—

(10)

—

(1)

—

(2)

—

Total

129

(1)

—

(19)

112

(10)

—

The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of

risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate

liquidity for benefit payments and portfolio management.

The company’s U.S. and U.K. pension plans comprise 91 percent of the total pension assets. Both the U.S. and U.K. plans

have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess

the plans’ investment performance, long-term asset allocation policy benchmarks have been established.

For the primary U.S. pension plan, the company’s Investment Committee has established the following approved asset

allocation ranges: Equities 40–65 percent, Fixed Income 20–40 percent, Real Estate 0–15 percent, Alternative Investments

0–5 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 2020, the company contributed $950 and $263 to its U.S. and international

pension plans, respectively. In 2021, the company expects contributions to be approximately $1,050 to its U.S. plans and

$200 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 $153 in 2021; $155 was paid in 2020.

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

10 years:

2021

2022

2023

2024

2025

2026-2030

Pension Benefits

Other

U.S.

Int’l.

Benefits

1,779

919

1,069

1,097

1,068

4,856

658

220

225

243

250

1,400

153

162

158

154

151

706

Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron

Employee Savings Investment Plan (ESIP). Compensation expense for the ESIP totaled $281, $284 and $270 in 2020, 2019

and 2018, respectively.

Total

129

(1)
—
(19)
3

112

1
(10)
(10)
—

(1)
—
1
—

1
—
(2)
—

—
—
—
—

—
—
(3)
—

—

(1)
—
—
1

1
—
(19)
—

—
—
—
2

—
—
(5)
—

—
—
(1)
—

—
(10)
—
—

Equity
International

Corporate

Fixed Income
Bank Loans

Real Estate

Other

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

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

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, 2020

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 2020

were 2.4 for the main U.S. pension plan and 2.4 for the main U.S. OPEB plan. The discount rates for these plans at the end of

2019 were 3.1 and 3.1 percent, respectively, while in 2018 they were 4.2 and 4.3 percent for these plans, respectively.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2020,

for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 6.1 percent in 2021 and gradually decline to

4.5 percent for 2027 and beyond. For this measurement at December 31, 2019, the assumed health care cost-trend rates

started with 6.8 percent in 2020 and gradually declined to 4.5 percent for 2025 and beyond.

Plan Assets and Investment Strategy

The fair value measurements of the company’s pension plans for 2020 and 2019 are as follows:

Total

Level 1

Level 2 Level 3

Total

Level 1 Level 2 Level 3

$ 1,769 $

1,769 $

— $ — $

471 $

471 $ — $ — $

At December 31, 2019

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 Investments

Cash and Cash Equivalents

Other5

At December 31, 2020

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 Investments

Cash and Cash Equivalents

Other5

1,958

1,079

523

1,444

120

1,089

963

—

924

235

2,211

1,107

231

778

129

1,901

—

1,018

—

221

1,958

228

(5)

2,210

—

209

(19)

523

1,444

113

—

231

778

127

—

2,230

2,225

Int’l.

NAV

—

178

—

222

—

185

—

403

—

421

144

—

334

—

373

125

—

408

(2)

—

121

490

—

115

568

—

422

184

265

493

—

277

—

338

373

192

240

578

—

127

448

—

417

2,520

2,516

U.S.

NAV

1,027

—

963

—

1,089

924

—

1,059

—

1,888

1,018

—

Total at December 31, 2019

$ 10,177 $

4,002 $

2,117 $

51 $ 4,007

4,791 $

1,388 $

715 $

61 $ 2,627

$ 2,286 $

2,286 $

— $ — $

443 $

443 $ — $ — $

The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of
risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate
liquidity for benefit payments and portfolio management.

The company’s U.S. and U.K. pension plans comprise 91 percent of the total pension assets. Both the U.S. and U.K. plans
have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess
the plans’ investment performance, long-term asset allocation policy benchmarks have been established.

For the primary U.S. pension plan, the company’s Investment Committee has established the following approved asset
allocation ranges: Equities 40–65 percent, Fixed Income 20–40 percent, Real Estate 0–15 percent, Alternative Investments
0–5 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 2020, the company contributed $950 and $263 to its U.S. and international
pension plans, respectively. In 2021, the company expects contributions to be approximately $1,050 to its U.S. plans and
$200 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 $153 in 2021; $155 was paid in 2020.

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

Total at December 31, 2020

$ 9,930 $

4,747 $

1,171 $

44 $ 3,968

5,363 $

1,406 $

798 $

49 $ 3,110

1 U.S. equities include investments in the company’s common stock in the amount of $4 at December 31, 2020, and $6 at December 31, 2019.

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 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).

2021
2022
2023
2024
2025
2026-2030

Pension Benefits
Int’l.

U.S.

Other
Benefits

1,779
919
1,069
1,097
1,068
4,856

658
220
225
243
250
1,400

153
162
158
154
151
706

Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron
Employee Savings Investment Plan (ESIP). Compensation expense for the ESIP totaled $281, $284 and $270 in 2020, 2019
and 2018, 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

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 2020, 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, 2020 and 2019, trust assets
of $36 and $35, 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
$462, $826 and $1,048 in 2020, 2019 and 2018, 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 86.

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 79, 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 $391. Of this amount, $137 is associated with a
financing arrangement with an equity affiliate. Over the approximate 1-year remaining term of this guarantee, the maximum
amount will be reduced as payments are made by the affiliate. The remaining amount of $254 is associated with certain
payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 7-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: 2021 – $1,000; 2022 – $1,200;
2023 – $1,300; 2024 – $1,300; 2025 – $1,400; 2026 and after – $8,400. A portion of these commitments may

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Chevron Corporation 2020 Annual Report
92

ultimately be shared with project partners. Total payments under the agreements were approximately $500 in 2020, $800 in

2019 and $1,400 in 2018.

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal

proceedings related to environmental matters that are subject to legal settlements or that in the future may require the

company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum

substances, including MTBE, by the company or other parties. Such contingencies may exist for various operating, closed

and divested sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries,

chemical plants, marketing facilities, crude oil fields, and mining sites.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is

likely that the company will continue to incur additional liabilities. The amount of additional future costs are not fully

determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the

corrective actions that may be required, the determination of the company’s liability in proportion to other responsible

parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of

operations in the period in which they are recognized, but the company does not expect these costs will have a material effect

on its consolidated financial position or liquidity.

Chevron’s environmental reserve as of December 31, 2020, was $1,139. Included in this balance was $247 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 2020 environmental reserves balance of $892, $611 is related to the company’s U.S. downstream

operations, $47 to its international downstream operations, $233 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 2020 had a recorded liability that was material to the company’s results of operations, consolidated financial

Refer to Note 23 on page 94 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.

Seven coastal parishes and the State of Louisiana have filed 43 separate lawsuits in Louisiana against numerous oil and gas

companies seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s

State and Local Coastal Resources Management Act (SLCRMA). Chevron entities are defendants in 39 of these cases. The

lawsuits allege that the defendants’ historical operations were conducted without necessary permits or failed to comply with

permits obtained and seek damages and other relief, including the costs of restoring coastal wetlands allegedly impacted by

oil field operations. Plaintiffs’ SLCRMA theories are unprecedented; thus, there remains significant uncertainty about the

scope of the claims and alleged damages and any potential effects on the company’s results of operations and financial

condition. Management believes that the claims lack legal and factual merit and will continue to vigorously defend against

such proceedings.

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,

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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

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 2020, 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, 2020 and 2019, trust assets

of $36 and $35, 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

$462, $826 and $1,048 in 2020, 2019 and 2018, 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 86.

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 79, 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 $391. Of this amount, $137 is associated with a

financing arrangement with an equity affiliate. Over the approximate 1-year remaining term of this guarantee, the maximum

amount will be reduced as payments are made by the affiliate. The remaining amount of $254 is associated with certain

payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 7-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: 2021 – $1,000; 2022 – $1,200;

2023 – $1,300; 2024 – $1,300; 2025 – $1,400; 2026 and after – $8,400. A portion of these commitments may

ultimately be shared with project partners. Total payments under the agreements were approximately $500 in 2020, $800 in
2019 and $1,400 in 2018.

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal
proceedings related to environmental matters that are subject to legal settlements or that in the future may require the
company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum
substances, including MTBE, by the company or other parties. Such contingencies may exist for various operating, closed
and divested sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries,
chemical plants, marketing facilities, crude oil fields, and mining sites.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is
likely that the company will continue to incur additional liabilities. The amount of additional future costs are not fully
determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the
corrective actions that may be required, the determination of the company’s liability in proportion to other responsible
parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of
operations in the period in which they are recognized, but the company does not expect these costs will have a material effect
on its consolidated financial position or liquidity.

Chevron’s environmental reserve as of December 31, 2020, was $1,139. Included in this balance was $247 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 2020 environmental reserves balance of $892, $611 is related to the company’s U.S. downstream
operations, $47 to its international downstream operations, $233 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 2020 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 94 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.

Seven coastal parishes and the State of Louisiana have filed 43 separate lawsuits in Louisiana against numerous oil and gas
companies seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s
State and Local Coastal Resources Management Act (SLCRMA). Chevron entities are defendants in 39 of these cases. The
lawsuits allege that the defendants’ historical operations were conducted without necessary permits or failed to comply with
permits obtained and seek damages and other relief, including the costs of restoring coastal wetlands allegedly impacted by
oil field operations. Plaintiffs’ SLCRMA theories are unprecedented; thus, there remains significant uncertainty about the
scope of the claims and alleged damages and any potential effects on the company’s results of operations and financial
condition. Management believes that the claims lack legal and factual merit and will continue to vigorously defend against
such proceedings.

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,

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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

individually and in the aggregate, may be significant and take lengthy periods to resolve, and may result in gains or losses in
future periods.

Note 25

Other Financial Information

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 2020, 2019 and 2018:

Balance at January 1
Liabilities assumed in the Noble acquisition
Liabilities incurred
Liabilities settled
Accretion expense
Revisions in estimated cash flows

Balance at December 31

2020

12,832
630
10
(1,661)
560
1,245

2019

14,050
—
32
(1,694)
628
(184)

2018

14,214
—
96
(830)
654
(84)

13,616

12,832

14,050

In the table above, the amount associated with “Revisions in estimated cash flows” in 2020 reflects increased cost estimates
to decommission wells, equipment and facilities. The long-term portion of the $13,616 balance at the end of 2020 was
$11,877.

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 74 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 $7,631 and
$9,247 at December 31, 2020 and December 31, 2019, 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.

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Chevron Corporation 2020 Annual Report
94

Earnings in 2020 included after-tax gains of approximately $765 relating to the sale of certain properties. Of this amount,

approximately $30 and $735 related to downstream and upstream, respectively. Earnings in 2019 included after-tax gains of

approximately $1,500 relating to the sale of certain properties, of which approximately $50 and $1,450 related to

downstream and upstream assets, 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 2020 included after-tax charges of approximately $4,800 for impairments and other asset write-offs

related to upstream. 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

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 $(152), $(28) and $416 in 2020, 2019 and 2018, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $4,402 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 2020, 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 77, for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem is

other asset write-offs related to upstream.

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

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

Year ended December 31

2020

735

697

435

2,749

(147)

(645)

2019

817

798

500

4,513

(9)

(304)

2018

921

173

748

453

5,134

611

Year ended December 31

2020

8,407

7,221

1,260

2019

9,333

7,863

1,760

At December 31

2018

11,310

9,812

2,069

2019

2,554

14,314

1,247

3,174

12,447

2020

2,816

14,210

1,394

3,380

12,252

Note 27

Restructuring and Reorganization Costs

In 2020, the company recorded severance accruals and adjustments for employee reduction programs related to enterprise-

wide restructuring, which are expected to be substantially completed by the end of 2021.

A before-tax charge of $859 ($670 after-tax) was recorded in 2020, with $690 reported as “Operating expenses” and $169

reported as “Selling, general and administrative expenses” on the Consolidated Statement of Income. Approximately $127

($97 after-tax) is associated with terminations in U.S. Upstream, $288 ($228 after-tax) in International Upstream, $112 ($85

after-tax) in U.S. Downstream, $69 ($54 after-tax) in International Downstream and $263 ($206 after-tax) in All Other.

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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

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.

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 2020, 2019 and 2018:

2020

2019

2018

12,832

14,050

14,214

630

(1,661)

560

1,245

—

(1,694)

628

(184)

—

(830)

654

(84)

13,616

12,832

14,050

Balance at January 1

Liabilities assumed in the Noble acquisition

Liabilities incurred

Liabilities settled

Accretion expense

Revisions in estimated cash flows

Balance at December 31

$11,877.

Note 24

Revenue

In the table above, the amount associated with “Revisions in estimated cash flows” in 2020 reflects increased cost estimates

to decommission wells, equipment and facilities. The long-term portion of the $13,616 balance at the end of 2020 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 74 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 $7,631 and

$9,247 at December 31, 2020 and December 31, 2019, 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 2020 included after-tax gains of approximately $765 relating to the sale of certain properties. Of this amount,
approximately $30 and $735 related to downstream and upstream, respectively. Earnings in 2019 included after-tax gains of
approximately $1,500 relating to the sale of certain properties, of which approximately $50 and $1,450 related to
downstream and upstream assets, 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 2020 included after-tax charges of approximately $4,800 for impairments and other asset write-offs
related to upstream. 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.

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*

2020

735
38

697

435

2,749
(147)

(645)

$
$

Year ended December 31
2018

2019

$
$

817
19

798

500

4,513
(9)

(304)

$
$

921
173

748

453

5,134
26

611

Includes $(152), $(28) and $416 in 2020, 2019 and 2018, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $4,402 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 2020, 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 77, 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

2020

8,407
7,221
1,260

Year ended December 31
2018

2019

9,333
7,863
1,760

11,310
9,812
2,069

At December 31
2019

2,554
14,314
1,247
3,174

2020

2,816
14,210
1,394
3,380

12,252

12,447

Note 27
Restructuring and Reorganization Costs
In 2020, the company recorded severance accruals and adjustments for employee reduction programs related to enterprise-
wide restructuring, which are expected to be substantially completed by the end of 2021.

A before-tax charge of $859 ($670 after-tax) was recorded in 2020, with $690 reported as “Operating expenses” and $169
reported as “Selling, general and administrative expenses” on the Consolidated Statement of Income. Approximately $127
($97 after-tax) is associated with terminations in U.S. Upstream, $288 ($228 after-tax) in International Upstream, $112 ($85
after-tax) in U.S. Downstream, $69 ($54 after-tax) in International Downstream and $263 ($206 after-tax) in All Other.

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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

During 2020, the company made payments of $396 associated with these liabilities. The following table summarizes the
accrued severance liability, which is classified as current on the Consolidated Balance Sheet.

a fair value of $9,231.

immediately after the acquisition. As part of the transaction, the company recognized long-term debt and finance leases with

Balance at January 1, 2020
Accruals/Adjustments
Payments

Balance at December 31, 2020

Amounts Before Tax

7
859
(396)

470

Note 28
Financial Instruments—Credit Losses
Chevron adopted Accounting Standards Update (ASU) 2016-13, Financial Instruments—Credit Losses, and its related
amendments at the effective date of January 1, 2020. The standard replaces the “incurred loss model” and requires an
estimate of expected credit losses, measured over the contractual life of a financial instrument, that considers forecast of
future economic conditions in addition to information about past events and current conditions. The cumulative-effect
adjustment to the opening retained earnings at January 1, 2020 was a reduction of $25, representing a decrease to the net
accounts and notes receivable balances shown on the company’s consolidated balance sheet on page 61. Chevron’s expected
credit loss allowance balance was $671 as of December 31, 2020 and $849 as of December 31, 2019, with a majority of the
allowance relating to non-trade receivable balances. A reduction in the allowance for non-trade receivables of $550 was
recorded in the second quarter as an agreement was reached with a government joint venture partner that resulted in the
write-off of the associated receivable balances. Additionally, new allowances of $265 were recorded in the second and third
quarters associated with other than trade receivables.

The majority of the company’s receivable balance is concentrated in trade receivables, with a balance of $9.5 billion as of
December 31, 2020, which reflects the company’s diversified sources of revenues and is dispersed across the company’s
broad worldwide customer base. As a result, the company believes the concentration of credit risk is 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 forms of collateral. Once credit is extended and a receivable balance exists, the company applies a quantitative
calculation to current trade receivable balances that reflects credit risk predictive analysis, including probability of default
and loss given default, which takes into consideration current and forward-looking market data as well as the company’s
historical loss data. This statistical approach becomes the basis of the company’s expected credit loss allowance for current
trade receivables with payment terms that are typically short-term in nature, with most due in less than 90 days. The
company continues to monitor credit risk in response to the COVID-19 pandemic and the significant reduction in crude
prices resulting from decreased demand associated with government-mandated travel restrictions.

Chevron’s non-trade receivable balance was $3.3 billion as of December 31, 2020, which includes receivables from certain
governments in their capacity as joint venture partners. Joint venture partner balances that are paid as per contract terms or
not yet due are subject to the statistical analysis described above while past due balances are subject to additional qualitative
management quarterly review. This management review includes review of reasonable and supportable repayment forecasts.
Non-trade receivables also include employee and tax receivables that are deemed immaterial and low risk.

Equity affiliate loans are also considered non-trade and during the second quarter 2020 review, a $560 allowance was
recognized within “Investments and advances” on the Consolidated Balance Sheet.

Note 29
Acquisition of Noble Energy, Inc.
On October 5, 2020, the company acquired Noble Energy, Inc., an independent oil and gas exploration and production
company. Noble’s principal upstream operations are in the United States, the Eastern Mediterranean and West Africa.
Noble’s operations also include an integrated midstream business in the United States. The acquisition of Noble provides the
company with low-cost proved reserves, attractive undeveloped resources and cash-generating assets.

The aggregate purchase price of Noble was $4,109, with approximately 58 million shares of Chevron common stock issued
as consideration in the transaction, representing approximately 3 percent of shares of Chevron common stock outstanding

The acquisition was accounted for as a business combination under ASC 805, which requires assets acquired and liabilities

assumed to be measured at their acquisition date fair values. Provisional fair value measurements were made for acquired

assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the

acquisition date, as information necessary to complete the analysis is obtained. Oil and gas properties were valued using a

discounted cash flow approach that incorporated internally generated price assumptions and production profiles together with

appropriate operating cost and development cost assumptions. Debt assumed in the acquisition was valued based on

observable market prices for Noble’s debt. As a result of measuring the assets acquired and the liabilities assumed at fair

value, there was no goodwill or bargain purchase recognized.

The following table summarizes the values assigned to assets acquired and liabilities assumed:

Current assets

Investments and long-term receivables

Properties (includes $14,935 for oil and gas properties)

Other assets

Total assets acquired

Current liabilities

Long-term debt and finance leases

Deferred income taxes

Other liabilities

Total liabilities assumed

Net assets acquired

January 1, 2019:

Sales and other operating revenues

Net income

Noncontrolling interest and redeemable noncontrolling interest

The following unaudited pro forma summary presents the results of operations as if the acquisition of Noble had occurred

The pro forma summary uses estimates and assumptions based on information available at the time. Management believes

the estimates and assumptions to be reasonable; however, actual results may differ significantly from this pro forma financial

information. The pro forma information does not reflect any synergistic savings that might be achieved from combining the

operations and is not intended to reflect the actual results that would have occurred had the companies actually been

combined during the periods presented.

At October 5, 2020

1,105

1,282

16,703

607

19,697

1,829

9,231

2,355

1,394

14,809

779

4,109

Year ended December 31

2020

96,980

(9,890)

2019

144,303

1,412

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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

During 2020, the company made payments of $396 associated with these liabilities. The following table summarizes the

accrued severance liability, which is classified as current on the Consolidated Balance Sheet.

immediately after the acquisition. As part of the transaction, the company recognized long-term debt and finance leases with
a fair value of $9,231.

Amounts Before Tax

859

(396)

470

The acquisition was accounted for as a business combination under ASC 805, which requires assets acquired and liabilities
assumed to be measured at their acquisition date fair values. Provisional fair value measurements were made for acquired
assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the
acquisition date, as information necessary to complete the analysis is obtained. Oil and gas properties were valued using a
discounted cash flow approach that incorporated internally generated price assumptions and production profiles together with
appropriate operating cost and development cost assumptions. Debt assumed in the acquisition was valued based on
observable market prices for Noble’s debt. As a result of measuring the assets acquired and the liabilities assumed at fair
value, there was no goodwill or bargain purchase recognized.

The following table summarizes the values assigned to assets acquired and liabilities assumed:

Current assets
Investments and long-term receivables
Properties (includes $14,935 for oil and gas properties)
Other assets

Total assets acquired

Current liabilities
Long-term debt and finance leases
Deferred income taxes
Other liabilities

Total liabilities assumed

Noncontrolling interest and redeemable noncontrolling interest

Net assets acquired

At October 5, 2020

1,105
1,282
16,703
607

19,697

1,829
9,231
2,355
1,394

14,809
779

4,109

The following unaudited pro forma summary presents the results of operations as if the acquisition of Noble had occurred
January 1, 2019:

Sales and other operating revenues
Net income

Year ended December 31
2019

2020

$
$

96,980
(9,890)

$
$

144,303
1,412

The pro forma summary uses estimates and assumptions based on information available at the time. Management believes
the estimates and assumptions to be reasonable; however, actual results may differ significantly from this pro forma financial
information. The pro forma information does not reflect any synergistic savings that might be achieved from combining the
operations and is not intended to reflect the actual results that would have occurred had the companies actually been
combined during the periods presented.

Balance at January 1, 2020

Accruals/Adjustments

Payments

Balance at December 31, 2020

Note 28

Financial Instruments—Credit Losses

Chevron adopted Accounting Standards Update (ASU) 2016-13, Financial Instruments—Credit Losses, and its related

amendments at the effective date of January 1, 2020. The standard replaces the “incurred loss model” and requires an

estimate of expected credit losses, measured over the contractual life of a financial instrument, that considers forecast of

future economic conditions in addition to information about past events and current conditions. The cumulative-effect

adjustment to the opening retained earnings at January 1, 2020 was a reduction of $25, representing a decrease to the net

accounts and notes receivable balances shown on the company’s consolidated balance sheet on page 61. Chevron’s expected

credit loss allowance balance was $671 as of December 31, 2020 and $849 as of December 31, 2019, with a majority of the

allowance relating to non-trade receivable balances. A reduction in the allowance for non-trade receivables of $550 was

recorded in the second quarter as an agreement was reached with a government joint venture partner that resulted in the

write-off of the associated receivable balances. Additionally, new allowances of $265 were recorded in the second and third

quarters associated with other than trade receivables.

The majority of the company’s receivable balance is concentrated in trade receivables, with a balance of $9.5 billion as of

December 31, 2020, which reflects the company’s diversified sources of revenues and is dispersed across the company’s

broad worldwide customer base. As a result, the company believes the concentration of credit risk is 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 forms of collateral. Once credit is extended and a receivable balance exists, the company applies a quantitative

calculation to current trade receivable balances that reflects credit risk predictive analysis, including probability of default

and loss given default, which takes into consideration current and forward-looking market data as well as the company’s

historical loss data. This statistical approach becomes the basis of the company’s expected credit loss allowance for current

trade receivables with payment terms that are typically short-term in nature, with most due in less than 90 days. The

company continues to monitor credit risk in response to the COVID-19 pandemic and the significant reduction in crude

prices resulting from decreased demand associated with government-mandated travel restrictions.

Chevron’s non-trade receivable balance was $3.3 billion as of December 31, 2020, which includes receivables from certain

governments in their capacity as joint venture partners. Joint venture partner balances that are paid as per contract terms or

not yet due are subject to the statistical analysis described above while past due balances are subject to additional qualitative

management quarterly review. This management review includes review of reasonable and supportable repayment forecasts.

Non-trade receivables also include employee and tax receivables that are deemed immaterial and low risk.

Equity affiliate loans are also considered non-trade and during the second quarter 2020 review, a $560 allowance was

recognized within “Investments and advances” on the Consolidated Balance Sheet.

Note 29

Acquisition of Noble Energy, Inc.

On October 5, 2020, the company acquired Noble Energy, Inc., an independent oil and gas exploration and production

company. Noble’s principal upstream operations are in the United States, the Eastern Mediterranean and West Africa.

Noble’s operations also include an integrated midstream business in the United States. The acquisition of Noble provides the

company with low-cost proved reserves, attractive undeveloped resources and cash-generating assets.

The aggregate purchase price of Noble was $4,109, with approximately 58 million shares of Chevron common stock issued

as consideration in the transaction, representing approximately 3 percent of shares of Chevron common stock outstanding

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Five-Year Financial Summary
Unaudited

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Millions of dollars, except per-share amounts

2020

2019

2018

2017

2016

Statement of Income Data
Revenues and Other Income

Total sales and other operating revenues*
Income from equity affiliates and other income

94,471
221

139,865 $
6,651

158,902 $
7,437

134,674 $
7,048

110,215
4,257

Total Revenues and Other Income
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

94,692
102,145

(7,453)
(1,892)

(5,561)

146,516
140,980

5,536
2,691

2,845

166,339
145,764

20,575
5,715

14,860

141,722
132,501

114,472
116,632

9,221
(48)

9,269

(2,160)
(1,729)

(431)

interests

(18)

(79)

Net Income (Loss) Attributable to Chevron Corporation $

(5,543)

2,924 $

14,824 $

9,195 $

(497)

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:

(2.96)
(2.96)

5.16

26,078
213,712

239,790

1,548
20,635
42,767
42,114

107,064

131,688
1,038

132,726

—

$
$

1.55 $
1.54 $

4.76 $

7.81 $
7.74 $

4.48 $

4.88 $
4.85 $

4.32 $

(0.27)
(0.27)

4.29

28,329 $
209,099

34,021 $
219,842

28,560 $
225,246

29,619
230,459

237,428

253,863

253,806

260,078

3,282
23,248
23,691
41,999

92,220

5,726
21,445
28,733
42,317

98,221

5,192
22,545
33,571
43,179

10,840
20,945
35,286
46,285

104,487

113,356

144,213 $
995

154,554 $
1,088

148,124 $
1,195

145,556
1,166

145,208 $

155,642 $

149,319 $

146,722

— $

7,189

6,905

Development3

7,072

1,216

199

10,304

5,112

Total Costs Incurred4

8,014

1,614

1,166

$ 210

11,926

5,112

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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

Table I - Costs Incurred in Exploration, Property Acquisitions and Development1

Millions of dollars

U.S.

Americas

Africa

Asia

Europe

Total

TCO

Other

Australia/

Oceania

Consolidated Companies

Affiliated Companies

181

$ — $

— $

Total Costs Incurred4

11,386

1,029

1,050

9,197

23,506

2,998

— $

Year Ended December 31, 2020

Exploration

Wells

Other

Geological and geophysical

Total exploration

Property acquisitions2

Proved - Noble

Proved - Other

Unproved - Noble

Unproved - Other

Total property acquisitions

Development3

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

Total property acquisitions

Development3

190

125

398

3,463

2,845

6,366

4,622

571

140

793

149

508

190

782

160

212

6,245

287

—

740

118

214

150

184

161

—

494

856

7,945

129

—

8,130

1,034

110

1,020

117

144

1,095

101

438

113

563

386

—

279

344

711

784

381

185

307

873

11,846

3,089

15,061

7,572

634

238

306

1,178

208

236

444

676

142

376

1,194

284

575

859

—

753

805

—

518

578

—

845

901

2,998

—

158

166

—

200

Total Costs Incurred4

7,239

1,511

1,332

$ 316

12,083

4,963

1 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 94.

2 Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions.

3 Includes $897, $246 and $114 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2020, 2019, and 2018,

respectively.

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

278

10,030

4,963

2020

2019

2018

Total cost incurred

Noble acquisition

Non-oil and gas activities

ARO reduction/(build)

26.6

17.2

(14.9)

—

(0.8)

—

0.3

—

0.6

(0.1)

See Note 29 for additional information

(Primarily; LNG and transportation activities.)

Upstream C&E

10.9

17.8

17.7

Reference page 44 Upstream total

— $

Millions of dollars, except per-share amounts

2020

2019

2018

2017

2016

94,471

139,865

158,902

134,674

110,215

6,651

146,516

140,980

5,536

2,691

2,845

7,437

166,339

145,764

20,575

5,715

14,860

7,048

141,722

132,501

9,221

(48)

9,269

Net Income (Loss) Attributable to Chevron Corporation $

(5,543)

2,924

14,824

9,195

(18)

(79)

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 (Loss) Before Income Tax Expense

Income Tax Expense (Benefit)

Net Income (Loss)

interests

Less: Net income (loss) attributable to noncontrolling

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

4,257

114,472

116,632

(2,160)

(1,729)

(431)

(497)

(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

1.55

1.54

4.76

7.81

7.74

4.48

28,329

209,099

237,428

3,282

23,248

23,691

41,999

92,220

34,021

219,842

253,863

5,726

21,445

28,733

42,317

98,221

144,213

995

145,208

154,554

1,088

155,642

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

221

94,692

102,145

(7,453)

(1,892)

(5,561)

(2.96)

5.16

26,078

213,712

239,790

1,548

20,635

42,767

42,114

107,064

131,688

1,038

132,726

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

Table I - Costs Incurred in Exploration, Property Acquisitions and Development1

U.S.

Other
Americas

Africa

Asia

Australia/

Oceania Europe

Total

TCO

Other

Consolidated Companies

Affiliated Companies

Millions of dollars

Year Ended December 31, 2020
Exploration
Wells
Geological and geophysical
Other

Total exploration

Property acquisitions2
Proved - Noble
Proved - Other
Unproved - Noble
Unproved - Other

Total property acquisitions

Development3

1$ —$
12
39

—
2

190
83
125

398

3,463
23
2,845
35

6,366

4,622

181
29
77

287

—
—
2
—

740

1$
58
42

101

438
2
113
10

563

386

8$
3
22

7,945
56
129
—

8,130

1,034

—
—
—
—

—

753

Total Costs Incurred4

11,386

$ 1,029

1,050

9,197

805

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

9
21
35

—
—

—

2
5
29

93
17

110

4
11
44

—
1

381
185
307

873

11,846
81
3,089
45

15,061

7,572

—$
—
—

—

—
—
—
—

—

2,998

23,506

2,998

634
238
306

1,178

208
236

444

—
—
—

—

—
—

—

—
—
—
—

—

4
1
6

—
—

—

—
—
—

—

—
—
—
—

—

—
—
8

—
—

—

158

166

—
—
—

—

—
—

—

200

* Includes excise, value-added and similar taxes:

—

— $

7,189

6,905

Development3

7,072

1,216

279

1,020

518

199

10,304

5,112

Total Costs Incurred4

8,014

$ 1,614

344

1,166

578

$ 210

11,926

5,112

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

25
4
35

7
2

55
5
33

117
27

144

$ —
7
49

—
—

—

14
1
23

—
—

—

676
142
376

1,194

284
575

859

—
—
—

—

—
—

—

711

1,095

845

278

10,030

4,963

Total Costs Incurred4

7,239

$ 1,511

784

1,332

901

$ 316

12,083

4,963

2
3

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 94.
Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions.
Includes $897, $246 and $114 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2020, 2019, and 2018,
respectively.

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

2020

2019

2018

Total cost incurred

Noble acquisition
Non-oil and gas activities
ARO reduction/(build)

$ 26.6
(14.9)
—
(0.8)

$ 17.2
—
0.3
0.3

$ 17.2
—
0.6
(0.1)

See Note 29 for additional information
(Primarily; LNG and transportation activities.)

Upstream C&E

$ 10.9

$ 17.8

$ 17.7

Reference page 44 Upstream total

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

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 77, for a discussion of the company’s
major equity affiliates.

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

Millions of dollars

At December 31, 2020
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, 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

U.S.

Other
Americas

Africa

Asia

Australia/
Oceania

Europe

Total

TCO

Other

Consolidated Companies

Affiliated Companies

3,519 $

2,438 $

188 $

984 $

1,987 $

— $

9,116

108 $

—

81,573
1,882
411
5,549

92,934

179

55,839
1,002

57,020

24,108
197
142
582

27,467

1,471

13,141
159

14,771

46,637
1,087
202
1,030

49,144

126

35,899
742

36,767

58,086
2,042
505
803

62,420

856

42,354
1,644

44,854

22,321
18,898
1,144
1,157

45,507

110

7,541
2,965

10,616

2,117
—
108
20

2,245

—

498
—

498

234,842
24,106
2,512
9,141

279,717

2,742

155,272
6,512

164,526

11,326
2,023
—
18,806

32,263

6,746
1,169

7,982

1,548
—
—
23

1,571

—

493
—

493

35,914 $

12,696 $

12,377 $

17,566 $

34,891 $

1,747 $

115,191

24,281 $

1,078

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

10,757
1,981
—
16,503

29,349

6,018
1,053

7,136

4,311
—
—
743

5,054

—

1,912
—

1,912

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 $

—

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

9,892
1,858
—
12,311

24,169

5,276
947

6,284

4,336
—
—
605

4,941

—

1,730
—

1,730

Net Capitalized Costs

39,430 $

14,542 $

16,318 $

16,508 $

38,261 $

3,186 $

128,245

17,885 $

3,211

Table III - Results of Operations for Oil and Gas Producing Activities1

The company’s results of operations from oil and gas producing activities for the years 2020, 2019 and 2018 are shown in the

following table. Net income (loss) from exploration and production activities as reported on page 75 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 75.

Other

U.S.

Americas

Africa

Australia/

Oceania

Asia

Europe

Total

TCO

Other

Consolidated Companies

Affiliated Companies

Millions of dollars

Year Ended December 31, 2020

Revenues from net production

Sales

Transfers

Total

Production expenses excluding taxes

Taxes other than on income

Proved producing properties:

Depreciation and depletion

Accretion expense2

Exploration expenses

Unproved properties valuation

Other income (expense)3

Results before income taxes

Income tax (expense) benefit

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 expense2

Exploration expenses

Unproved properties valuation

Other income (expense)3

Results before income taxes

Income tax (expense) benefit

1,665 $

505 $

473 $

5,629 $ 3,010 $

149 $

3,088 $

3,378

1,092

(6,482)

(1,221)

(2,323)

(15,776)

(879)

(146)

7,711

9,376

(3,933)

(597)

(165)

(457)

(58)

(2,265)

558

1,683

2,188

(981)

(62)

(22)

(314)

(215)

(8)

(635)

(5)

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)

1,830

4,840

(589)

(121)

(2,192)

(62)

(231)

(1)

(2)

1,642

(558)

2,596

6,928

(616)

(221)

(53)

(60)

(2)

6,721

(2,408)

(11)

(3,466)

(120)

(67)

(8)

1,053

1,694

(353)

8,721

(2,703)

(16)

(133)

(93)

(388)

413

2,636

(1,212)

3,837

(1,161)

3,851

(1,485)

(77)

(136)

(431)

(6)

(11)

(618)

888

7,202

(1,460)

(101)

(2,548)

(148)

(73)

(2)

(121)

2,749

(1,731)

—

149

(64)

(2)

(92)

(10)

(15)

—

(9)

(43)

592 $

655

1,247

(343)

(2)

(85)

(37)

(10)

—

1,373

2,143

(311)

11,431

15,694

27,125

(9,460)

(870)

(515)

(1,515)

(288)

1,074

(225)

542

317

16,124

24,299

40,423

(9,709)

(999)

(583)

(740)

(4,251)

1,623

4,735

(3,131)

—

3,088

(419)

(190)

(9)

—

(29)

1,562

(471)

—

5,603

(475)

(57)

(5)

—

(4)

4,193

(1,261)

288

—

288

(98)

(30)

(6)

—

(2,103)

(2,094)

161

780

—

780

(247)

(10)

(8)

—

(157)

139

(73)

(11,659)

(1,380)

(3,165)

(2,192)

(21,029)

(870)

(211)

2,259 $

863 $

668 $

7,410 $ 4,332 $

5,603 $

11,043

2,160

6,534

1,311

Results of Producing Operations

(1,707) $

(640) $

270 $

1,341 $ 1,084 $

(31) $

1,091 $

(1,933)

Results of Producing Operations

(5,011) $

(335) $

1,018 $

1,424 $ 2,676 $

1,832 $

1,604

2,932 $

1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from

net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.

2 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 94.

Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

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4,620 $

2,492 $

151 $

1,081 $

1,986 $

— $

10,330

108 $

—

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 77, for a discussion of the company’s

major equity affiliates.

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

Millions of dollars

U.S.

Americas

Africa

Asia

Europe

Total

TCO

Other

Australia/

Oceania

Consolidated Companies

Affiliated Companies

3,519 $

2,438 $

188 $

984 $

1,987 $

— $

9,116

108 $

At December 31, 2020

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

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

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

81,573

1,882

411

5,549

92,934

179

55,839

1,002

57,020

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

Other

24,108

197

142

582

27,467

1,471

13,141

159

14,771

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

2,245

279,717

1,571

22,321

18,898

1,144

1,157

45,507

110

7,541

2,965

10,616

22,032

18,610

1,322

1,023

44,973

109

6,064

2,272

8,445

22,047

17,712

1,323

1,462

44,530

107

4,631

1,531

6,269

2,117

—

108

—

498

—

498

2,082

—

121

—

404

—

404

12,634

124

261

300

13,319

—

10,014

119

10,133

234,842

24,106

2,512

9,141

2,742

155,272

6,512

164,526

232,906

24,381

3,041

8,725

6,306

154,507

6,510

167,323

233,534

23,614

3,563

13,232

284,579

2,408

148,178

5,748

156,334

11,326

2,023

—

18,806

32,263

6,746

1,169

7,982

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

2,218

279,383

1,548

—

493

—

493

4,311

—

743

5,054

—

1,912

—

1,912

3,142

4,336

—

605

4,941

—

1,730

—

1,730

3,211

46,637

1,087

202

1,030

49,144

126

35,899

742

36,767

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

58,086

2,042

505

803

62,420

856

42,354

1,644

44,854

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

100

Net Capitalized Costs

39,430 $

14,542 $

16,318 $

16,508 $

38,261 $

3,186 $

128,245

17,885 $

Net Capitalized Costs

32,209 $

13,503 $

14,081 $

13,925 $

36,528 $

1,814 $

112,060

22,213 $

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table III - Results of Operations for Oil and Gas Producing Activities1

The company’s results of operations from oil and gas producing activities for the years 2020, 2019 and 2018 are shown in the
following table. Net income (loss) from exploration and production activities as reported on page 75 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 75.

Millions of dollars

Year Ended December 31, 2020
Revenues from net production

Sales
Transfers

Total

Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion

Accretion expense2
Exploration expenses
Unproved properties valuation
Other income (expense)3

Results before income taxes

Income tax (expense) benefit

Other
Americas

U.S.

Africa

Australia/
Oceania

Asia

Europe

Total

TCO

Other

Consolidated Companies

Affiliated Companies

1,665 $
7,711

505 $

473 $

1,683

3,378

5,629 $ 3,010 $
1,092

1,830

149 $
—

11,431
15,694

3,088 $
—

9,376
(3,933)
(597)

(6,482)
(165)
(457)
(58)
51

(2,265)
558

2,188
(981)
(62)

(1,221)
(22)
(314)
(215)
(8)

(635)
(5)

3,851
(1,485)
(77)

(2,323)
(136)
(431)
(6)
(11)

(618)
888

6,721
(2,408)
(11)

(3,466)
(120)
(67)
(8)
1,053

1,694
(353)

4,840
(589)
(121)

(2,192)
(62)
(231)
(1)
(2)

1,642
(558)

149
(64)
(2)

(92)
(10)
(15)
—
(9)

(43)
12

27,125
(9,460)
(870)

(15,776)
(515)
(1,515)
(288)
1,074

(225)
542

3,088
(419)
(190)

(879)
(9)
—
—
(29)

1,562
(471)

288
—

288
(98)
(30)

(146)
(6)
1
—
(2,103)

(2,094)
161

Net Capitalized Costs

35,914 $

12,696 $

12,377 $

17,566 $

34,891 $

1,747 $

115,191

24,281 $

1,078

Results of Producing Operations

(1,707) $

(640) $

270 $

1,341 $ 1,084 $

(31) $

317

1,091 $

(1,933)

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 expense2
Exploration expenses
Unproved properties valuation
Other income (expense)3

Results before income taxes

Income tax (expense) benefit

2,259 $
11,043

863 $

668 $

2,160

6,534

7,410 $ 4,332 $
1,311

2,596

592 $
655

16,124
24,299

5,603 $
—

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)

40,423
(9,709)
(999)

(21,029)
(583)
(740)
(4,251)
1,623

4,735
(3,131)

5,603
(475)
(57)

(870)
(5)
—
(4)
1

4,193
(1,261)

4,687 $

2,463 $

201 $

1,299 $

1,986 $

— $

10,636

108 $

—

Results of Producing Operations

(5,011) $

(335) $

1,018 $

1,424 $ 2,676 $

1,832 $

1,604

2,932 $

780
—

780
(247)
(10)

(211)
(8)
(8)
—
(157)

139
(73)

1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from

net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.

2 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 94.
3

Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table III - Results of Operations for Oil and Gas Producing Activities1, continued

Millions of dollars

Year Ended December 31, 2018
Revenues from net production

Sales
Transfers

Total

Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion

Accretion expense2
Exploration expenses
Unproved properties valuation
Other income (expense)3

Results before income taxes

Income tax (expense) benefit

Other
Americas

U.S.

Africa

Asia

Australia/
Oceania

Europe

Total

TCO

Other

Consolidated Companies

Affiliated Companies

2,162 $
11,645

1,008 $
1,808

829 $

7,829

5,880 $
3,206

4,229 $
3,413

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)

8,658
(1,564)
(112)

(3,368)
(149)
(52)
(3)
97

3,507
(2,131)

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)

1,369
—

1,369
(295)
(210)

(306)
(3)
(6)
—
(280)

269
341

610

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.

2 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 94.
3

Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs1

Other
Americas

U.S.

Africa

Asia

Australia/
Oceania

Europe

Total

TCO

Other

Consolidated Companies

Affiliated Companies

Year Ended December 31, 2020
Average sales prices
Liquids, per barrel
Natural gas, per thousand cubic feet

Average production costs, per barrel2

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

30.53 $
0.96
10.01

35.41 $
2.20
14.27

38.06 $
1.61
13.19

39.77 $
4.30
11.24

38.03 $
5.42
4.02

34.20 $
1.07
13.23

34.12
3.68
10.07

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

24.25 $
0.54
3.17

24.07
0.61
3.91

49.14 $
0.79
3.53

45.25
0.99
7.93

56.20 $
0.77
3.59

56.41
3.19
9.29

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

2020

2019

2018

Crude Oil

Synthetic

Natural

Crude Oil

Synthetic

Natural

Crude Oil

Synthetic

Condensate

Oil

NGL

Gas

Condensate

Oil

NGL

Gas

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

346

2,503

1,121

258

2,998

1,061

1,157

168

497

358

115

—

597

—

222

1,629

8,951

— 7,864

—

540

—

397

1,472

— 3,382

4 10,697

—

545

—

179

2,396

393

1,316

— 4,021

5 10,084

205

2,318

597

424 21,177

2,383

540

334 18,954

2,463

545

250 18,415

565

—

1,057

322

—

1,135

308

—

1,179

308

2,885

597

489 22,556

3,081

540

403 20,397

3,166

600

323 19,902

593

851

985

—

247

1,747

107

1,208

— 319

— 2,434

—

961

576

—

244

1,730

339

1,286

— 299

— 3,961

—

869

558

—

349

4,313

470

1,499

— 289

— 3,647

— 100

406 10,318

755

601

285

5,829

1,226

288

7,633

1,311

1,837

4,722

—

597

339

7,366

828 29,922

2,160

5,241

—

540

337

9,060

740 29,457

2,179

5,345

672

450 11,674

773 31,576

174

525

406

136

584

114

807

146

107

889

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

103

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table III - Results of Operations for Oil and Gas Producing Activities1, continued

Millions of dollars

U.S.

Americas

Africa

Asia

Europe

Total

TCO

Other

Australia/

Oceania

Consolidated Companies

Affiliated Companies

2,162 $

1,008 $

829 $

5,880 $

4,229 $

619 $

5,987 $

1,369

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 expense2

Exploration expenses

Unproved properties valuation

Other income (expense)3

Results before income taxes

Income tax (expense) benefit

11,645

13,807

(3,203)

(540)

(4,583)

(186)

(777)

(516)

336

4,338

(886)

1,808

7,829

3,206

2,816

(1,009)

(70)

8,658

(1,564)

(112)

9,086

(2,653)

(22)

(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)

3,413

7,642

(557)

(250)

(50)

(56)

—

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)

(3,368)

(3,714)

(2,103)

(711)

(306)

—

5,987

(447)

160

(4)

(3)

—

5,052

(1,519)

—

1,369

(295)

(210)

(3)

(6)

—

(280)

269

341

610

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.

2 Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page 94.

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

0.96

10.01

2.20

14.27

1.61

13.19

4.30

11.24

5.42

4.02

1.07

13.23

0.54

3.17

0.61

3.91

30.53 $

35.41 $

38.06 $

39.77 $

38.03 $

34.20 $

24.25 $

24.07

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

Year Ended December 31, 2020

Average sales prices

Liquids, per barrel

Year Ended December 31, 2019

Average sales prices

Liquids, per barrel

Year Ended December 31, 2018

Average sales prices

Liquids, per barrel

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

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.

34.12

3.68

10.07

54.47

4.86

10.62

62.45

5.54

10.78

102

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

2020

2019

2018

Crude Oil
Condensate

Synthetic
Oil

Natural
Gas

Crude Oil
Condensate

Synthetic
Oil

NGL

Natural
Gas

Crude Oil
Condensate

Synthetic
Oil

NGL

Natural
Gas

NGL

1,157
168
497
358
115
23

2,318

565
2

—
597
—
—
—
—

597

—
—

346 2,503
6
222
68 1,629
— 7,864
4 8,951
8
—

424 21,177

53 1,057
322
12

1,121
174
525
406
136
21

2,383

584
114

—
540
—
—
—
—

540

—
—

258 2,998
5
397
67 1,472
— 3,382
4 10,697
8
—

334 18,954

59 1,135
10
308

1,061
156
568
470
127
81

2,463

638
65

—
545
—
—
—
—

545

—
55

179 2,396
3
393
60 1,316
— 4,021
5 10,084
205
3

250 18,415

62 1,179
308
11

2,885

597

489 22,556

3,081

540

403 20,397

3,166

600

323 19,902

593
92
57
45
26
38

851

985
1

—
—
—
—
—
—

—

—
—

247 1,747
2
107
36 1,208
—
319
— 2,434
14
—

807
146
88
107
30
48

285 5,829

1,226

49
5

961
576

889
45

—
—
—
—
—
—

—

—
—

244 1,730
11
339
33 1,286
—
299
— 3,961
18
—

813
185
110
109
29
65

288 7,633

1,311

44
5

869
558

866
2

—
—
—
—
—
—

—

—
72

349 4,313
19
470
38 1,499
—
289
— 3,647
100
—

406 10,318

39
5

755
601

1,837

4,722

—

597

339 7,366

828 29,922

2,160

5,241

—

540

337 9,060

740 29,457

2,179

5,345

672

450 11,674

773 31,576

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

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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.

The acquisition of Noble was completed on October 5, 2020. Given the timing of the acquisition, Chevron has continued to
rely on legacy Noble reserves staff and processes for reviewing reserves with input and guidance from the Chevron Reserves
Advisory Committee. The processes include internal reviews and an external audit. Accordingly, Chevron continued to retain
Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, that completed an audit of the legacy
Noble acquisition proved reserves at December 31, 2020 (representing approximately 15% of Chevron’s total reserves).
Based upon their evaluation NSAI issued an unqualified audit opinion, and this report is attached as Exhibit 99.3 to the
company’s Annual Report on Form 10-K.

Technologies Used in Establishing Proved Reserves Additions In 2020, 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

Noteworthy changes in proved undeveloped reserves are shown in the table below and discussed on the following page.

Proved Undeveloped Reserves (Millions of BOE)

Quantity at January 1

Revisions
Improved Recovery
Extension & Discoveries
Purchases
Sales
Transfers to Proved Developed

Quantity at December 31

104
Chevron Corporation 2020 Annual Report
104

2020

4,007
(699)
1
123
329
(95)
(262)

3,404

In 2020, Revisions include a reduction of 392 million BOE in the United States, primarily from the Midland and Delaware

basins where 300 million BOE was attributed to demotions due to capital reductions, commodity price effects and

performance revisions, and 75 million BOE from the Gulf of Mexico, primarily from commodity price effects at Anchor. In

Australia, there was a net reduction of 269 million BOE, primarily from demotion of compression volumes related to capital

and approval delays at Jansz Io, partially offset by positive revisions at Gorgon (Gorgon and Jansz Io make up the Gorgon

Project). A reduction of 85 million BOE was recorded in Canada, primarily from commodity price effects at Kaybob

Duvernay. In Nigeria, there was a reduction of 67 million BOE, primarily from gas volume changes based on reduced

demand and development plan changes at Meren. In Venezuela, there was a demotion of 48 million BOE, due to impairment

and accounting methodology change. These negative revisions were partially offset by an increase of 143 million BOE in

Kazakhstan, primarily from entitlement effects at TCO and Karachaganak.

In 2020, Extensions and Discoveries of 108 million BOE in the United States were primarily due to portfolio optimizations

where future drilling in various fields is being targeted toward liquids-rich reservoirs with higher execution efficiencies in the

Midland and Delaware basins.

The differences in 2020 Extensions and Discoveries of 124 million BOE, between the net quantities of Proved reserves of

247 million BOE as reflected on pages 106 to 109 and net quantities of Proved Undeveloped of 123 million BOE, are

primarily due to proved extensions and discoveries that were not recognized as PUDs in the prior year but rather were

recognized directly as proved developed.

basin in the United States.

Purchases of 329 million BOE in 2020 include 326 million BOE from the Noble acquisition, primarily in Israel and the DJ

Sales of 95 million BOE in 2020 include 77 million BOE from the sale of the company’s interest in Azerbaijan.

Transfers to proved developed reserves in 2020 include 178 million BOE in the United States, primarily from the Midland

and Delaware basin developments and 84 million BOE in Canada, Kazakhstan, and other international locations. These

transfers are the consequence of development expenditures on completing wells and facilities.

During 2020, investments totaling approximately $6.3 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 $3.4 billion, primarily related to development projects of the TCO

affiliate in Kazakhstan. The United States accounted for about $2.1 billion related primarily to various development activities

in the Midland and Delaware basins and the Gulf of Mexico. In Africa, about $0.3 billion was expended on various offshore

development and natural gas projects in Nigeria, Angola and Republic of Congo. Development activities in Canada and other

international locations were primarily responsible for about $0.5 billion of expenditures.

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 2020, the company held approximately 1.6 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 400 million BOE remain undeveloped for five years or

more related to the Gorgon and Wheatstone Projects. Further field development

to convert

the remaining proved

undeveloped reserves is scheduled to occur in line with operating constraints and infrastructure optimization. In Africa,

approximately 200 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 1.3 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 2020, 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

the

appropriate

reserves

105

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In 2020, Revisions include a reduction of 392 million BOE in the United States, primarily from the Midland and Delaware
basins where 300 million BOE was attributed to demotions due to capital reductions, commodity price effects and
performance revisions, and 75 million BOE from the Gulf of Mexico, primarily from commodity price effects at Anchor. In
Australia, there was a net reduction of 269 million BOE, primarily from demotion of compression volumes related to capital
and approval delays at Jansz Io, partially offset by positive revisions at Gorgon (Gorgon and Jansz Io make up the Gorgon
Project). A reduction of 85 million BOE was recorded in Canada, primarily from commodity price effects at Kaybob
Duvernay. In Nigeria, there was a reduction of 67 million BOE, primarily from gas volume changes based on reduced
demand and development plan changes at Meren. In Venezuela, there was a demotion of 48 million BOE, due to impairment
and accounting methodology change. These negative revisions were partially offset by an increase of 143 million BOE in
Kazakhstan, primarily from entitlement effects at TCO and Karachaganak.

In 2020, Extensions and Discoveries of 108 million BOE in the United States were primarily due to portfolio optimizations
where future drilling in various fields is being targeted toward liquids-rich reservoirs with higher execution efficiencies in the
Midland and Delaware basins.

The differences in 2020 Extensions and Discoveries of 124 million BOE, between the net quantities of Proved reserves of
247 million BOE as reflected on pages 106 to 109 and net quantities of Proved Undeveloped of 123 million BOE, are
primarily due to proved extensions and discoveries that were not recognized as PUDs in the prior year but rather were
recognized directly as proved developed.

Purchases of 329 million BOE in 2020 include 326 million BOE from the Noble acquisition, primarily in Israel and the DJ
basin in the United States.

Sales of 95 million BOE in 2020 include 77 million BOE from the sale of the company’s interest in Azerbaijan.

Transfers to proved developed reserves in 2020 include 178 million BOE in the United States, primarily from the Midland
and Delaware basin developments and 84 million BOE in Canada, Kazakhstan, and other international locations. These
transfers are the consequence of development expenditures on completing wells and facilities.

During 2020, investments totaling approximately $6.3 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 $3.4 billion, primarily related to development projects of the TCO
affiliate in Kazakhstan. The United States accounted for about $2.1 billion related primarily to various development activities
in the Midland and Delaware basins and the Gulf of Mexico. In Africa, about $0.3 billion was expended on various offshore
development and natural gas projects in Nigeria, Angola and Republic of Congo. Development activities in Canada and other
international locations were primarily responsible for about $0.5 billion of expenditures.

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 2020, the company held approximately 1.6 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 400 million BOE remain undeveloped for five years or
more related to the Gorgon and Wheatstone Projects. Further field development to convert the remaining proved
undeveloped reserves is scheduled to occur in line with operating constraints and infrastructure optimization. In Africa,
approximately 200 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 1.3 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.

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.

reserves.

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.

The acquisition of Noble was completed on October 5, 2020. Given the timing of the acquisition, Chevron has continued to

rely on legacy Noble reserves staff and processes for reviewing reserves with input and guidance from the Chevron Reserves

Advisory Committee. The processes include internal reviews and an external audit. Accordingly, Chevron continued to retain

Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, that completed an audit of the legacy

Noble acquisition proved reserves at December 31, 2020 (representing approximately 15% of Chevron’s total reserves).

Based upon their evaluation NSAI issued an unqualified audit opinion, and this report is attached as Exhibit 99.3 to the

company’s Annual Report on Form 10-K.

Technologies Used in Establishing Proved Reserves Additions In 2020, 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

Noteworthy changes in proved undeveloped reserves are shown in the table below and discussed on the following page.

consistent reserves estimates.

Proved Undeveloped Reserves

Proved Undeveloped Reserves (Millions of BOE)

Quantity at January 1

Revisions

Improved Recovery

Extension & Discoveries

Purchases

Sales

Transfers to Proved Developed

Quantity at December 31

2020

4,007

(699)

123

329

(95)

(262)

3,404

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 2020, 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
reserves
have
these

circumstances

appropriate

significant

discussed

changes

been

and

the

104

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sections. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between
31 percent and 38 percent.

Proved Reserve Quantities For the three years ending December 31, 2020, 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, 2020, proved reserves for the company were 11.1 billion BOE. The company’s estimated net proved
reserves of liquids including crude oil, condensate and synthetic oil for the years 2018, 2019 and 2020 are shown in the table
on page 107. The company’s estimated net proved reserves of natural gas liquids are shown on page 108 and the company’s
estimated net proved reserves of natural gas are shown on page 109.

Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2018 through 2020 are discussed below
and shown in the table on the following page:

Revisions 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.

In 2020, capital reductions and commodity price effects in the Midland and Delaware basins and Anchor in the Gulf of
Mexico, were primarily responsible for the 279 million barrels decrease in the United States. Reserves in Venezuela affiliates
decreased by 149 million barrels, primarily due to impairments and accounting methodology change. Entitlement effects and
performance revisions in the TCO affiliate were primarily responsible for the 180 million barrels increase. Entitlement
effects primarily contributed to an increase of 77 million barrels synthetic oil at the Athabasca Oil sands in Canada and
74 million barrels at multiple locations in Asia.

Extensions and Discoveries 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.

In 2020, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 105 million
barrels increase in the United States.

Purchases In 2018, purchases of 31 million barrels in the United States were primarily in the Midland and Delaware basins.

In 2020, the acquisition of Noble assets contributed 227 million barrels in the DJ basin, Midland and Delaware basins in the
United States.

Sales In 2019, sales of 69 million barrels in Europe were in the United Kingdom and Denmark.

In 2020, sale of 99 million barrels in Asia were in Azerbaijan.

Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil

Total

5,937

277

391

(31)

(598)

6,017

(18)

438

(73)

(611)

(126)

110

258

(110)

(596)

5,319

Millions of barrels

Other

Australia/

Synthetic

U.S.

Americas1 Africa Asia

Oceania Europe

Oil2 Total

TCO

Oil Other3

and Affiliated

Companies

Consolidated Companies

Affiliated Companies

Consolidated

Reserves at January 1, 2018

1,573

280

743

631

153

142

543

4,065

1,630

159

Reserves at December 31, 20184

1,874

341

678

579

545

4,319

1,504

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

121

359

(26)

(189)

(153)

394

—

(213)

(279)

105

227

(11)

(221)

—

1 —

— —

(5) —

(29)

(122)

(90)

(25)

—

— —

(4) — —

(33)

(108)

(86)

(25)

—

(39)

— —

1 —

— (99)

(92)

(95)

(14)

156

—

(16)

166

(11)

—

(15)

141

—

(19)

146

—

(69)

(16)

(4)

—

(4)

—

335

— 391

— (31)

(19)

(482)

(28)

—

(98)

(72)

— 438

— (73)

(19)

(491)

—

— 110

— 258

— (110)

(20)

(486)

—

(103)

(126)

105

(7)

—

(9)

—

(7)

(23)

—

(9)

127

—

(106)

(1)

(13)

(157)

180

— (149)

Reserves at December 31, 20194

1,928

320

613

513

540

4,149

1,473

— 159

5,781

Reserves at December 31, 20204

1,750

260

554

403

597

3,766

1,550

1 Ending reserve balances in North America were 166, 230 and 269 and in South America were 94, 90 and 72 in 2020, 2019 and 2018, respectively.

2 Reserves associated with Canada.

3 Ending reserve balances in Africa were 3, 3 and 3 and in South America were 0, 156 and 64 in 2020, 2019 and 2018, 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 9 percent, 11 percent and 14 percent for consolidated companies for 2020, 2019 and 2018, respectively.

Noteworthy changes in natural gas liquids proved reserves for 2018 through 2020 are discussed below and shown in the table

on the following page:

Revisions 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.

In 2020, capital reductions and commodity price effects in various fields in Midland and Delaware basins were primarily

responsible for the 71 million barrels decrease in the United States.

Extensions and Discoveries 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.

In 2020, extensions and discoveries in various fields in Midland and Delaware basins were primarily responsible for the

60 million barrels increase in the United States.

Purchases In 2020, the acquisition of Noble assets contributed 198 million barrels primarily in the Denver Julesburg basin,

Midland and Delaware basins and Eagle Ford Shale in the United States.

106
Chevron Corporation 2020 Annual Report
106

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

sections. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between

Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil

31 percent and 38 percent.

Proved Reserve Quantities For the three years ending December 31, 2020, 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, 2020, proved reserves for the company were 11.1 billion BOE. The company’s estimated net proved

reserves of liquids including crude oil, condensate and synthetic oil for the years 2018, 2019 and 2020 are shown in the table

on page 107. The company’s estimated net proved reserves of natural gas liquids are shown on page 108 and the company’s

estimated net proved reserves of natural gas are shown on page 109.

Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2018 through 2020 are discussed below

and shown in the table on the following page:

Revisions 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.

In 2020, capital reductions and commodity price effects in the Midland and Delaware basins and Anchor in the Gulf of

Mexico, were primarily responsible for the 279 million barrels decrease in the United States. Reserves in Venezuela affiliates

decreased by 149 million barrels, primarily due to impairments and accounting methodology change. Entitlement effects and

performance revisions in the TCO affiliate were primarily responsible for the 180 million barrels increase. Entitlement

effects primarily contributed to an increase of 77 million barrels synthetic oil at the Athabasca Oil sands in Canada and

74 million barrels at multiple locations in Asia.

Extensions and Discoveries 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.

In 2020, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 105 million

barrels increase in the United States.

Purchases In 2018, purchases of 31 million barrels in the United States were primarily in the Midland and Delaware basins.

In 2020, the acquisition of Noble assets contributed 227 million barrels in the DJ basin, Midland and Delaware basins in the

United States.

Sales In 2019, sales of 69 million barrels in Europe were in the United Kingdom and Denmark.

In 2020, sale of 99 million barrels in Asia were in Azerbaijan.

106

U.S.

1,573

121
5
359
31
(26)
(189)

Millions of barrels

Reserves at January 1, 2018
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

Reserves at December 31, 20194
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Other

Americas1 Africa Asia

Australia/

Oceania Europe

Oil2 Total

Consolidated Companies
Synthetic

Affiliated Companies

Synthetic

Oil Other3

TCO

Total
Consolidated
and Affiliated
Companies

280

743 631

153

142

543 4,065

1,630

159

5,937

59
—
31
—
—
(29)

37
61
—
1
1 —
— —
(5) —
(122) (90)

17
—
—
—
—
(14)

19
4
—
—
—
(19)

21
—
—
—
—
(19)

335
10
391
31
(31)
(482)

(28)
—
—
—
—
(98)

(23)
—
—
—
—
(9)

1,874

341

678 579

156

146

545 4,319

1,504

127

(153)
7
394
19
—
(213)

42
19
(25)
— —
—
1
1
39
— —
2
(4) — —
(108) (86)
(33)

25
—
1
—
—
(16)

1,928

320

613 513

166

(279)
1
105
227
(11)
(221)

(25)
1
3
—
—
(39)

74
11
— —
1 —
10
21
—
(99)
(92) (95)

(11)
—
1
—
—
(15)

6
—
2
—
(69)
(16)

(4)
—
—
—
—
(4)

14
—
—
—
—
(19)

(72)
7
438
21
(73)
(491)

75
—
—
—
—
(106)

(126)
—
—
—
—
(1)

540 4,149

1,473

—

159

5,781

77
—
—
—
—
(20)

(157)
2
110
258
(110)
(486)

180
—
—
—
—
(103)

597 3,766

1,550

—
—
—
—
—
—

—

(149)
—
—
—
—
(7)

(126)
2
110
258
(110)
(596)

5,319

(7)
—
—
—
—
(9)

105
—
—
—
—
(13)

277
10
391
31
(31)
(598)

6,017

(18)
7
438
21
(73)
(611)

Reserves at December 31, 20204

1,750

260

554 403

141

1 Ending reserve balances in North America were 166, 230 and 269 and in South America were 94, 90 and 72 in 2020, 2019 and 2018, respectively.
2 Reserves associated with Canada.
3 Ending reserve balances in Africa were 3, 3 and 3 and in South America were 0, 156 and 64 in 2020, 2019 and 2018, 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 9 percent, 11 percent and 14 percent for consolidated companies for 2020, 2019 and 2018, respectively.

Noteworthy changes in natural gas liquids proved reserves for 2018 through 2020 are discussed below and shown in the table
on the following page:

Revisions 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.

In 2020, capital reductions and commodity price effects in various fields in Midland and Delaware basins were primarily
responsible for the 71 million barrels decrease in the United States.

Extensions and Discoveries 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.

In 2020, extensions and discoveries in various fields in Midland and Delaware basins were primarily responsible for the
60 million barrels increase in the United States.

Purchases In 2020, the acquisition of Noble assets contributed 198 million barrels primarily in the Denver Julesburg basin,
Midland and Delaware basins and Eagle Ford Shale in the United States.

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Net Proved Reserves of Natural Gas Liquids

Millions of barrels

Reserves at January 1, 2018
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
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Reserves at December 31, 20203

U.S.

343

34
—
173
19
(6)
(35)

528

(120)
—
140
5
—
(51)

502

(71)
—
60
198
(27)
(69)

593

Other

Americas1 Africa Asia

—

1
—
5
—
—
(1)

(4)
—
—
—
—
(2)

(7)
—
1
—
—
(2)

7 —
—
—
— —
—
—
—
—
(5) —

—

6 —
—
—
— —
—
—
—
—
(4) —

100 —

(3) —
—
—
—
—
—
12
—
(5) —

104 —

Consolidated Companies

Australia/

Oceania Europe Total

Affiliated
Companies

TCO Other2

Total
Consolidated
and Affiliated
Companies

—
—
—
—
—
(1)

—
—
—
—
—
—

465

119

1
—
—
—
—
(1)

43
—
178
19
(6)
(43)

656

—
—
—
—
(2)
(1)

(118)
—
140
5
(2)
(59)

(11)
—
—
—
—
(7)

101

10
—
—
—
—
(8)

— 622

103

(81)
—
—
—
61
—
— 210
(27)
—
(76)
—

8
—
—
—
—
(9)

—

709

102

(3)
—
—
—
—
(2)

2
—
—
—
—
(3)

5
—
—
—
—
(3)

605

29
—
178
19
(6)
(52)

773

(106)
—
140
5
(2)
(70)

740

(68)
—
61
210
(27)
(88)

828

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 2020,

2019 and 2018, respectively.

Noteworthy changes in natural gas proved reserves for 2018 through 2020 are discussed below and shown in the table above:

Revisions 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.

In 2020, the demotion of Jansz Io compression project reserves and lower field performance, partially offset by positive
revisions at Gorgon, were mainly responsible for the net 2.5 TCF decrease in Australia. Capital reductions and commodity
price effects in various fields of the Midland and Delaware basins were mainly responsible for the 509 BCF decrease in the
United States. In Africa, a 229 BCF decrease was primarily due to reduced demand and development plan changes at Meren
in Nigeria.

Extensions and Discoveries 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.

In 2020, extensions and discoveries of 385 BCF in the United States were primarily in the Midland and Delaware basins.

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Purchases In 2020, the acquisition of Noble assets contributed 5.4 TCF in Israel in Asia, 1.5 TCF in the Denver Julesburg

basin, Midland and Delaware basins and Eagle Ford Shale in the United States and 441 BCF in Equatorial Guinea in Africa.

Sales In 2019, sales of 240 BCF in Europe were in the United Kingdom and Denmark.

In 2020, sales of 1.3 TCF were primarily in the Appalachian basin, in the United States and 264 BCF primarily in Azerbaijan

in Asia.

Net Proved Reserves of Natural Gas

Billions of cubic feet (BCF)

U.S.

Americas1 Africa

Asia

Europe

Total

TCO Other2

Other

Australia/

Oceania

Reserves at January 1, 2018

5,180

795

2,906

4,773

13,559

301

27,514

2,183

1,039

Consolidated Companies

Affiliated

Companies

Total

Consolidated

and Affiliated

Companies

Reserves at December 31, 20184

6,709

863

2,815

4,310

13,731

305

28,733

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

258

1,627

144

(125)

(377)

(2,565)

—

1,008

(1)

(447)

(509)

—

385

1,548

(1,314)

(588)

347

1,012

(108)

(38)

(3)

138

—

(69)

(107)

—

(2)

(67)

(5)

(112)

—

(815)

(841)

(65)

(2,279)

165

1,732

—

(240)

(43)

1,707

1,771

145

(130)

(726)

1,156

—

(243)

(2,357)

(178)

(229)

(2,455)

(2)

(3,204)

—

441

169

—

5,350

(177)

(60)

— (264)

(135)

(753)

(876)

—

453

7,339

— (1,755)

(2)

(2,414)

—

(141)

1,934

223

—

162

—

(95)

909

—

866

138

—

(148)

(106)

Reserves at December 31, 20194

4,728

736

2,758

3,681

14,658

26,587

2,004

(103)

(799)

(898)

(153)

(102)

30,736

1,561

1,774

145

(130)

(2,515)

31,576

(464)

1,176

—

(243)

(2,612)

29,457

(2,904)

—

453

7,339

(1,755)

(2,668)

29,922

Reserves at December 31, 20204

4,250

329

2,837

8,183

11,385

27,006

2,018

898

1 Ending reserve balances in North America and South America were 234, 462, 582 and 95, 274, 281 in 2020, 2019 and 2018, respectively.

2 Ending reserve balances in Africa and South America were 898, 802, 799 and 0, 64, 110 in 2020, 2019 and 2018, respectively.

3 Total “as sold” volumes are 2,447, 2,379 and 2,289 for 2020, 2019 and 2018, 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 10 percent for consolidated companies for 2020, 2019 and 2018, respectively.

109

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Net Proved Reserves of Natural Gas Liquids

Millions of barrels

U.S.

Americas1 Africa Asia

Europe

Total

TCO Other2

Other

Australia/

Oceania

Consolidated Companies

Affiliated

Companies

Total

Consolidated

and Affiliated

Companies

Purchases In 2020, the acquisition of Noble assets contributed 5.4 TCF in Israel in Asia, 1.5 TCF in the Denver Julesburg
basin, Midland and Delaware basins and Eagle Ford Shale in the United States and 441 BCF in Equatorial Guinea in Africa.

Sales In 2019, sales of 240 BCF in Europe were in the United Kingdom and Denmark.

In 2020, sales of 1.3 TCF were primarily in the Appalachian basin, in the United States and 264 BCF primarily in Azerbaijan
in Asia.

Reserves at January 1, 2018

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

Purchases

Sales

Production

Reserves at December 31, 20193

Changes attributable to:

Revisions

Improved recovery

Extensions and discoveries

Reserves at December 31, 20203

1 Reserves associated with North America.

2 Reserves associated with Africa.

2019 and 2018, respectively.

(120)

343

—

173

(6)

(35)

528

—

140

—

(51)

502

(71)

—

198

(27)

(69)

593

—

(1)

(4)

—

(2)

(7)

—

(2)

—

(5) —

(4) —

100

(3) —

(5) —

104

—

(1)

—

(1)

—

465

— 178

—

(1)

—

(2)

(1)

—

(6)

(43)

656

—

(2)

(59)

(81)

—

(27)

(76)

— (118)

— 140

— 622

— 210

— 709

119

(11)

—

(7)

101

(8)

103

—

(9)

102

(3)

(2)

—

(3)

—

(3)

(106)

605

—

178

(6)

(52)

773

—

140

(2)

(70)

740

(68)

—

210

(27)

(88)

828

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 2020,

Noteworthy changes in natural gas proved reserves for 2018 through 2020 are discussed below and shown in the table above:

Revisions 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.

In 2020, the demotion of Jansz Io compression project reserves and lower field performance, partially offset by positive

revisions at Gorgon, were mainly responsible for the net 2.5 TCF decrease in Australia. Capital reductions and commodity

price effects in various fields of the Midland and Delaware basins were mainly responsible for the 509 BCF decrease in the

United States. In Africa, a 229 BCF decrease was primarily due to reduced demand and development plan changes at Meren

in Nigeria.

Extensions and Discoveries 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.

In 2020, extensions and discoveries of 385 BCF in the United States were primarily in the Midland and Delaware basins.

108

Net Proved Reserves of Natural Gas

Billions of cubic feet (BCF)

Reserves at January 1, 2018
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
Changes attributable to:

Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production3

U.S.

5,180

258
2
1,627
144
(125)
(377)

6,709

(2,565)
—
1,008
24
(1)
(447)

4,728

(509)
—
385
1,548
(1,314)
(588)

Consolidated Companies

Affiliated
Companies

Other

Americas1 Africa

Australia/

Oceania Europe

Asia

Total

TCO Other2

Total
Consolidated
and Affiliated
Companies

795

2,906

4,773

13,559

301

27,514

2,183

1,039

30,736

(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)

39
—
20
—
—
(102)

736

2,758

3,681

14,658

26,587

2,004

866

(178)
—
8
—
(177)
(60)

(229)
—
2
441
—
(135)

169
—
—
5,350
(264)
(753)

(2,455)
—
58
—
—
(876)

(2)
—
—
—
—
(2)

(3,204)
—
453
7,339
(1,755)
(2,414)

162
—
—
—
—
(148)

138
—
—
—
—
(106)

1,561
5
1,774
145
(130)
(2,515)

31,576

(464)
—
1,176
24
(243)
(2,612)

29,457

(2,904)
—
453
7,339
(1,755)
(2,668)

29,922

Reserves at December 31, 20204

4,250

329

2,837

8,183

11,385

27,006

2,018

898

1 Ending reserve balances in North America and South America were 234, 462, 582 and 95, 274, 281 in 2020, 2019 and 2018, respectively.
2 Ending reserve balances in Africa and South America were 898, 802, 799 and 0, 64, 110 in 2020, 2019 and 2018, respectively.
3 Total “as sold” volumes are 2,447, 2,379 and 2,289 for 2020, 2019 and 2018, 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 10 percent for consolidated companies for 2020, 2019 and 2018, respectively.

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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, 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

Present Value at December 31, 2018

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 2018

Development costs incurred

Purchases of reserves

Sales of reserves

Accretion of discount

Net change in income tax

Net Change for 2019

Development costs incurred

Purchases of reserves

Sales of reserves

Present Value at December 31, 2019

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 2020

Present Value at December 31, 2020

$ 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

(16,621)

6,301

10,295

(803)

2,066

(1,293)

(62,788)

11,274

19,616

(31,953)

$ 48,443

$ 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

(2,322)

2,892

—

4,033

(22,925)

2,948

5,317

(10,057)

$ 10,094

$ 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

(18,943)

9,193

10,295

(803)

2,066

2,740

(85,713)

14,222

24,933

(42,010)

$ 58,537

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved 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

Other
Americas

U.S.

Africa

Asia

Australia/

Oceania Europe

Total

TCO

Other

Consolidated Companies

Affiliated
Companies

Total
Consolidated
and Affiliated
Companies

At December 31, 2020
Future cash inflows from production $ 74,671 $ 29,605 $ 27,521 $ 49,265 $ 53,241 $ 2,304 $ 236,607 $ 53,309 $ 1,070 $
Future production costs
Future development costs
Future income taxes

(30,359) (15,410)
(2,366)
(10,492)
(3,131)
(5,874)

(11,036)
(3,205)
(11,700)

(12,784)
(2,274)
(17,543)

(86,289)
(21,876)
(44,623)

(19,525)
(7,138)
(7,994)

(15,364)
(3,017)
(6,197)

(1,336)
(522)
(178)

(426)
(38)
(212)

290,986
(106,240)
(29,052)
(52,829)

Undiscounted future net cash flows
10 percent midyear annual discount
for timing of estimated cash flows

Standardized Measure

Net Cash Flows

27,946

8,698

2,943

16,664

27,300

268

83,819

18,652

394

102,865

(10,456)

(4,652)

(582)

(7,856)

(11,774)

(56)

(35,376)

(8,803)

(149)

(44,328)

$ 17,490 $ 4,046 $

2,361 $

8,808 $ 15,526 $

212 $ 48,443 $

9,849 $

245 $

58,537

At December 31, 2019
Future cash inflows from production $ 122,012 $ 45,701 $ 45,706 $ 43,386 $ 95,845 $ 4,466 $ 357,116 $ 85,179 $ 12,309 $
Future production costs
Future development costs
Future income taxes

(32,349) (18,324)
(4,219)
(15,987)
(6,491)
(15,780)

(98,870)
(34,718)
(74,932)

(22,302)
(14,340)
(14,561)

(14,141)
(5,458)
(22,874)

(14,646)
(5,070)
(11,147)

(17,982)
(3,643)
(17,562)

(2,487)
(705)
(3,855)

(1,428)
(341)
(1,078)

454,604
(123,659)
(49,763)
(93,348)

Undiscounted future net cash flows
10 percent midyear annual discount
for timing of estimated cash flows

Standardized Measure

Net Cash Flows

57,896

16,667

6,519

12,523

53,372

1,619

148,596

33,976

5,262

187,834

(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

At December 31, 2018
Future cash inflows from production $ 132,512 $ 52,470 $ 56,856 $ 54,012 $ 109,116 $ 11,959 $ 416,925 $ 100,518 $ 16,928 $
Future production costs
Future development costs
Future income taxes

(34,679) (20,691)
(5,106)
(17,322)
(7,553)
(17,369)

(6,609) (114,484)
(41,184)
(1,393)
(90,224)
(1,676)

(24,580)
(14,069)
(18,561)

(18,850)
(4,112)
(23,593)

(16,296)
(7,757)
(25,519)

(17,359)
(5,494)
(14,514)

(4,665)
(1,692)
(4,496)

534,371
(143,729)
(56,945)
(113,281)

Undiscounted future net cash flows
10 percent midyear annual discount
for timing of estimated cash flows

Standardized Measure

Net Cash Flows

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

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

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, 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 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

17,490 $

4,046 $

2,361 $

8,808 $ 15,526 $

212 $ 48,443 $

9,849 $

245 $

58,537

Net Change for 2019

Present Value at December 31, 2019
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 2020

Present Value at December 31, 2020

$ 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
(16,621)
6,301
10,295
(803)
2,066
(1,293)
(62,788)
11,274
19,616

(31,953)

$ 48,443

$ 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
(2,322)
2,892
—
—
—
4,033
(22,925)
2,948
5,317

(10,057)

$ 10,094

$ 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
(18,943)
9,193
10,295
(803)
2,066
2,740
(85,713)
14,222
24,933

(42,010)

$ 58,537

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

Future cash inflows from production $

74,671 $ 29,605 $ 27,521 $ 49,265 $ 53,241 $ 2,304 $ 236,607 $

53,309 $ 1,070 $

(30,359)

(10,492)

(5,874)

(15,410)

(15,364)

(12,784)

(11,036)

(1,336)

(2,366)

(3,131)

(3,017)

(6,197)

(2,274)

(3,205)

(17,543)

(11,700)

(522)

(178)

(86,289)

(21,876)

(44,623)

(19,525)

(7,138)

(7,994)

Undiscounted future net cash flows

27,946

8,698

2,943

16,664

27,300

268

83,819

18,652

10 percent midyear annual discount

for timing of estimated cash flows

(10,456)

(4,652)

(582)

(7,856)

(11,774)

(56)

(35,376)

(8,803)

(149)

(44,328)

Affiliated

Companies

Total

Consolidated

and Affiliated

Companies

(426)

(38)

(212)

394

290,986

(106,240)

(29,052)

(52,829)

102,865

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

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)

10 percent midyear annual discount

Standardized Measure

Net Cash Flows

34,039 $

7,984 $

7,655 $ 11,823 $ 31,268 $ 1,862 $ 94,631 $

21,283 $ 3,413 $

119,327

454,604

(123,659)

(49,763)

(93,348)

534,371

(143,729)

(56,945)

(113,281)

Millions of dollars

At December 31, 2020

Future production costs

Future development costs

Future income taxes

Standardized Measure

Net Cash Flows

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

110

111
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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 fnished 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 efects 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 proft oil and/or gas is
reduced once specifed 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, hydrofuorocarbons,
perfuorocarbons and sulfur hexafuoride).

Integrated energy company A company engaged
in all aspects of the energy industry, including
exploring for and producing crude oil and natural
gas; refning, marketing and transporting crude oil,
natural gas and refned products; manufacturing and
distributing petrochemicals; and generating power.

Liquefed natural gas (LNG) Natural gas that is
liquefed 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 refned to yield synthetic oil.

Petrochemicals Compounds derived from
petroleum. These include aromatics, which are used
to make plastics, adhesives, synthetic fbers and

household detergents; and olefns, 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 proft
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 proft 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
specifc 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 flings 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, 2020.

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 classifed 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
classifcations. 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 refect the relative uncertainty
represented by the various classifcations. These
estimates may change signifcantly as development
work provides additional information. At times,

Chevron Corporation 2020 Annual Report
112

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 fne-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 fuid-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.

fnancial 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, 2021,
stockholders of record numbered
approximately 114,000.

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.)

Investor information
Securities analysts, portfolio managers
and representatives of fnancial
institutions may contact:
Investor Relations
Chevron Corporation
6001 Bollinger Canyon Road
San Ramon, CA 94583-2324
925 842 5690
Email: invest@chevron.com

Notice
As used in this report, the term
“Chevron” and such terms as “the
company,” “the corporation,” “our,”
“we,” “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 afairs.

Corporate headquarters

6001 Bollinger Canyon Road
San Ramon, CA 94583-2324
925 842 1000

Annual meeting
The Annual Meeting of Stockholders will
be held online via live audio webcast at
8 a.m. PDT, Wednesday, May 26, 2021.
www.virtualshareholdermeeting.com/CVX2021

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.

assisting local
communities during the
-
COVID 19 crisis

Chevron has a history of
supporting communities during
crises. This pandemic is no
different. To date, we have
contributed more than $30 million
to COVID 19 humanitarian relief
efforts in 17 countries to support
medical needs, essential workers,
food banks, education, small
businesses and more. In the Riau
province of Indonesia, we delivered
over 50 patient beds.

Chevron Corporation 2020 Annual Report
113

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COVID‑19 response
Chevron has a robust infrastructure to deal with
emergencies – from earthquakes and wildfires to
hurricanes, typhoons and other extreme weather.
We also have become adept at managing epidemics,
like SARS-1, Ebola and AIDS. These experiences
remain in our corporate DNA as a foundation for
emergency planning.

After China first reported COVID-19 cases in January
2020, we quickly mustered an enterprisewide response.
Data-focused analysis of the virus’s potential global
reach prompted Chevron’s leadership to activate our
Corporate Pandemic Response Team – weeks before
the World Health Organization declared a pandemic,
to protect our workers, communities and operations.

Learn more at www.chevron.com/covid‑19

Details of the company’s political
contributions for 2020 are
available on the company’s website,
www.chevron.com, or by writing to:

Corporate Affairs
Chevron Corporation
6001 Bollinger Canyon Road
Building G
San Ramon, CA 94583-2324

For additional information about the
company and the energy industry, visit
Chevron’s website, 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 2020 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 our 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
Building 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,” “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 30 for a discussion of some of the factors that could cause actual results to differ materially.

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