2020 Annual Report
C O N T E N T S
II To our shareholders
IV Positioning for a lower-carbon energy future
VI Energy for a growing population
Scalable technology solutions
VIII Providing energy and products for modern life
IX Progressing advantaged investments
X Creating value through our integrated businesses
XII Upstream
XIV Downstream
XV Chemical
XVI Board of Directors
1 Form 10-K
124 Stock performance graphs
125 Frequently used terms
126 Footnotes
127
Investor information
A B O U T T H E C O V E R
Delivery of two modules to the Corpus Christi
Chemical Project site in 2020. Each module
weighed more than 17 million pounds, reached
the height of a 17-story building, and was
transported more than 5 miles over land.
Cautionary Statement • Statements of future events or conditions in this report are forward-looking statements. Actual future results,
including financial and operating performance; demand growth and mix; planned capital and cash operating expense reductions and efficiency
improvements, and ability to meet or exceed announced reduction objectives; future reductions in emissions intensity and resulting reductions
in absolute emissions; carbon capture results; resource recoveries; production rates; project plans, timing, costs, and capacities; drilling programs
and improvements; and product sales and mix differ materially due to a number of factors including global or regional changes in oil, gas, or
petrochemicals prices or other market or economic conditions affecting the oil, gas, and petrochemical industries; the severity, length and ultimate
impact of COVID-19 on people and economies and the timing and pace of regional and global economic recovery; the ability to realize efficiencies
within and across our business lines and to maintain cost reductions while protecting our competitive positioning; the impact of company actions to
protect the health and safety of employees, vendors, customers, and communities; reservoir performance; the outcome and timing of exploration
and development projects; timely completion of construction projects; war and other security disturbances, including shipping blockades or
harassment; political factors including changes in local, national, or international policies affecting our business; changes in law or government
regulation or policies, including trade sanctions, taxes, environmental regulations and policies to address climate change risks, the granting of
necessary licenses and permits, and government actions to address the COVID-19 pandemic; the outcome of commercial negotiations; actions of
competitors and commercial counterparties; actions of consumers including changes in demand preferences; the outcome of research efforts and
the ability to bring new technology to commercial scale on a cost-competitive basis; the development and competitiveness of alternative energy and
emission reduction technologies; unforeseen technical or operating difficulties; and other factors discussed here and in Item 1A. Risk Factors of our
most recent Form 10-K. All forward-looking statements are based on management’s knowledge and reasonable expectations at the time of this
report and we assume no duty to update these statements as of any future date.
As used in this publication, the term “industry” refers to publicly traded international energy companies. The term “project” can refer to a variety of
different activities and does not necessarily have the same meaning as in any government payment transparency reports. Unless otherwise specified,
data shown is for 2020. Prior years’ data have been reclassified in certain cases to conform to the 2020 presentation basis. Unless otherwise stated,
production rates, project capacities, and acreage values are gross. References to “emissions” refer to energy-related emissions.
To the people on the front lines – the
first responders, health care workers,
employees and essential businesses –
who are courageously helping all of
us during the coronavirus pandemic.
As a company with employees worldwide, we have a deep appreciation
for what is needed to mobilize and assist people on a global scale.
We have worked together to endure unprecedented challenges this year,
and we will continue to provide the critical products and reliable energy that
support our heroes on the front lines and our communities around the world.
We are grateful to all who stepped up to help.
THANK YOU
I
| L E T T E R F R O M T H E C H A I R M A N
T O O U R S H A R E H O L D E R S
deliver the strongest returns. These include our
high-performance chemical projects, refinery upgrades
and, in the Upstream, our advantaged assets in Guyana,
the Permian Basin, and Brazil.
Our recent reorganizations along value chains enabled
us to reduce operating costs and improve efficiencies
to better position ourselves for the future. Structural
changes during the year resulted in reduced cash
operating expenses of $3 billion. These savings grow
to $6 billion a year by 2023 compared to 2019.1
We also continued to make strong progress on our
plans to mitigate climate risk and position the
company for success in a lower-carbon energy future.
We met emission-reduction goals for methane and
flaring and established new plans that are projected to
be consistent with the goals of the Paris Agreement.2
Our forward plans are expected to reduce absolute
Upstream greenhouse gas emissions by an estimated
30 percent by 2025 compared to 2016, and by the end
of the decade, deliver industry-leading greenhouse gas
performance and align our Upstream operations with
the World Bank’s initiative to eliminate routine flaring.3
Other notable milestones in 2020 include:
• Our active Board refreshment program continued
with two new directors added by the end of January
2021, which brings to six the number of independent
directors added since 2015. In recent years the
company has pursued additional board expertise
in climate science, asset and risk management, and
relevant industry experience. The average tenure for
our directors is about six years, compared to an average
of about eight years for companies in the S&P 500.
• In Guyana, Liza Phase 2 and Payara developments
progressed, and we continued exploration success
with three new discoveries, increasing the recoverable
resource estimate on the Stabroek Block to nearly
9 billion oil-equivalent barrels.
• The Chemical business set a new record for
polyethylene sales, reflecting demand growth
for performance packaging and strong operating
performance.
The past year was like no other in recent memory.
The global pandemic took a tragic toll on people and
communities, while severely impacting businesses,
big and small. Yet, as is often the case, hardships bring
out the best in people, as exemplified by the thousands
of frontline workers, first responders and medical
professionals who are battling the virus.
An exceptional commitment was also displayed
by thousands of ExxonMobil employees around
the world who responded to the pandemic by
serving their communities. I’m proud of the way they
stepped up and made contributions to those in need
of our products, from hand sanitizer and specialty
products for protective equipment to fuel for
first responders. Through extraordinary efforts,
we kept operations running 24/7 while achieving
strong safety and reliability performance.
The impact of the pandemic on our business was
severe. As economies shut down, energy consumption
collapsed. For the first time in memory, all of our
businesses faced simultaneous lows.
We adjusted our capital investment plans,
reducing spending last year by more than 30 percent,
and developed future plans more flexible to market
conditions and focused on priority areas that will
II
EXXONMOBIL 2020 ANNUAL REPORT “We look forward to playing an important role in the recovery and
beyond – by providing energy and products that are critical to economic
growth while minimizing environmental impacts. We support society’s
aspiration of net-zero emissions by 2050 and its ambition to achieve a
lower-carbon energy future.”
• We maintained our position as a global leader in
carbon capture and storage (CCS), increasing captured
carbon dioxide (CO2) to more than 120 million tonnes.
This is well over twice the closest competitor and larger
than the next five competitors combined.4
More recently, we announced the creation of a new
business – ExxonMobil Low Carbon Solutions – to
commercialize our extensive low-carbon technology
portfolio and help society achieve the climate goals
outlined in the Paris Agreement. This new business
builds on the work of our Carbon Capture and Storage
Venture established in 2018.
The business will initially concentrate on CCS, advancing
plans for over 20 opportunities around the world
to enable large-scale emission reductions. It will
also leverage ExxonMobil’s significant experience in
hydrogen production and add other technology focus
areas, such as advanced biofuels, as they mature to
commercialization.
Our research and development program is continuing
to pursue breakthrough technologies to address
emissions in the economy’s highest-emitting
sectors: power generation, industrial, and commercial
transportation. We plan to invest $3 billion in
lower-emission energy solutions through 2025.5
Over the past two decades, we have invested more
than $10 billion to research, develop, and deploy lower-
emission energy solutions, resulting in highly efficient
operations that have eliminated or avoided approximately
480 million tonnes of greenhouse gas emissions as of
year-end 2019 – equivalent to the average annual energy
demand of more than 55 million U.S. homes.6
New technologies will be critically important in the future
as the global economy and energy use recover. The
market fundamentals underpinning our business remain
strong – growing populations and improved living
standards will require more energy. The respected
International Energy Agency projects that oil and gas
will comprise 46 percent of the global energy mix in
2040 under their Paris Agreement-aligned Sustainable
Development Scenario.7
We look forward to playing an important role in the
recovery and beyond – by providing energy and products
that are critical to economic growth while minimizing
environmental impacts. We support society’s aspiration
of net-zero emissions by 2050 and its ambition to achieve
a lower-carbon energy future.
The events of the past year were among the most
difficult we’ve ever experienced, yet our employees
rose to the challenge. This gives all of us at ExxonMobil
tremendous confidence in our plans, our people, and
our future.
Thank you for investing in ExxonMobil.
Darren Woods
Chairman and CEO
III
P O S I T I O N I N G F O R A
L OW E R - C A R B O N E N E R G Y F U T U R E
Since 2000, we have invested more than $10 billion to research, develop, and deploy
lower-emission technologies. These investments include carbon capture and storage, advanced
biofuels, and hydrogen. They also include substantial investments in cogeneration including the
latest unit, which was completed at Imperial’s Strathcona refinery in Alberta, Canada.
The unit produces 41 megawatts of power, reduces greenhouse gas
(GHG) emissions by approximately 112,000 tonnes per year, and is just
one example of how ExxonMobil is positioning for a lower-carbon
energy future.
PHOTO: Imperial’s Strathcona refinery in Alberta, Canada.
IV
EXXONMOBIL 2020 ANNUAL REPORT We play an important role in meeting society’s
need for energy and at the same time are
committed to supporting efforts to mitigate
the risks of climate change. This is reflected in
the four pillars of our climate strategy.
MITIGATING EMISSIONS IN
COMPANY OPERATIONS
PROVIDING PRODUCTS TO
HELP CUSTOMERS REDUCE
THEIR EMISSIONS
DEVELOPING AND DEPLOYING
SCALABLE TECHNOLOGY
SOLUTIONS
PROACTIVELY ENGAGING ON
CLIMATE-RELATED POLICY
We seek to be an industry leader in
greenhouse gas performance by 2030 with
emission reduction plans projected to be
consistent with goals of the Paris Agreement.
T H E 2 0 2 5 P L A N
15-20% REDUCTION IN GREENHOUSE
GAS INTENSITY OF OUR UPSTREAM OPERATIONS
S U P P O R T E D B Y
REDUCTION IN
METHANE INTENSITY
40-50%
35-45% REDUCTION IN
FLARING INTENSITY
E X P E C T E D T O D E L I V E R
AN ABSOLUTE REDUCTION
OF ~30 PERCENT IN
GREENHOUSE GAS
EMISSIONS IN OUR UPSTREAM BUSINESS
~30%
Upstream operations also plan to align with
the World Bank’s initiative to eliminate routine
flaring by 2030.
Emission reduction plans cover Scope 1 and Scope 2
emissions from assets operated by the company versus
2016 levels.
V
E X X O N M O B I L 2 0 2 0 A N N U A L R E P O R T
| E N E R G Y A N D T E C H N O L O G Y S O L U T I O N S
E N E R G Y F O R A G R OW I N G P O P U L AT I O N
Affordable, reliable energy is essential to facilitate
improvements in quality of life, including longer life
expectancy, higher education, and increased gross
national income per capita, regardless of location.
Today, half of the world’s population has a life expectancy
of 12 years less than those living in the United States, and
receives a third less education.8 Close to 1 billion people
still live without electricity.7 This has enormous implications
for the future of energy and the products that make
modern life possible.
Global demand for energy will increase as the world’s
population grows by an expected 1.6 billion people in
the next two decades to more than 9 billion; the middle
class will expand to more than 5 billion people by 2030,
with almost 90 percent of the next 1 billion entrants
into the middle class living in Asia.9, 10
S C A L A B L E T E C H N O L O G Y S O L U T I O N S
GLOBAL LEADER IN CCS
EXXONMOBIL IS THE FIRST COMPANY IN THE WORLD TO
CAPTURE MORE THAN 120 MILLION TONNES OF CO24
EXXONMOBIL’S EFFORTS ACCOUNT FOR APPROXIMATELY
40 PERCENT OF ALL THE
40%
ANTHROPOGENIC CO2 THAT HAS
BEEN CAPTURED SINCE 1970 4
OUR ANNUAL CARBON CAPTURE
CAPACITY IS ~9 MILLION TONNES OR THE
EMISSIONS FROM APPROXIMATELY
2 MILLION CARS PER YEAR 11
2 MILLION
CARBON CAPTURE AND STORAGE
Carbon capture and storage (CCS) is the process in which
carbon dioxide (CO2), that would have otherwise been
emitted into the atmosphere, is captured and injected into
deep underground geologic formations for safe, secure
storage. It is recognized as one of the most important
low-carbon technologies required to achieve society’s
net-zero goals at the lowest costs and is one of the only
technologies that could enable some industrial sectors to
decarbonize. ExxonMobil is the global leader in carbon
capture and has more than 30 years of experience developing
and deploying CCS technologies. We also have an equity
share of about one-fifth of the world’s CO2 capture capacity
and are evaluating multiple opportunities to expand
capacity. Furthermore, we are working on negative
emissions technologies, like direct air capture, which uses
advanced materials to capture CO2 from the atmosphere.
~480 MILLION TONNES OF GREENHOUSE GAS EMISSIONS ELIMINATED
OR AVOIDED SINCE 2000 THROUGH ENERGY EFFICIENCY AND MITIGATION OF EMISSIONS 11 CO2➠
VI
EXXONMOBIL 2020 ANNUAL REPORT
Impacts from the COVID-19 pandemic have been
significant, affecting not only lives but also the global
economy and energy demand. As the global response to
the pandemic continues and vaccines are administered and
economies begin to recover, the fundamental drivers for
energy demand are expected to return.
Under most third-party scenarios that meet the objectives
of the Paris Agreement, oil and natural gas will continue
to play a significant role for decades in meeting increasing
energy demand of a growing and more prosperous world
population. ExxonMobil expects to play an important part
in meeting society’s need for energy and is committed to
supporting efforts to mitigate the risks of climate change.
Commercially viable technology advances are required to
achieve the goals of the Paris Agreement. ExxonMobil’s
sustained investment in research and development is focused
on society’s highest-emitting sectors of industrial, power
generation, and commercial transportation, which together
770 MILLION PEOPLE
WITHOUT ACCESS TO ELECTRICITY
account for 80 percent of global energy-related CO2 emissions,
and for which the current solution set is insufficient.9
To address these gaps in available technologies, we are
working to develop breakthrough solutions in a number of
areas – including carbon capture, biofuels, hydrogen, and
energy-efficient process technology – and recently created
a new business to commercialize our extensive low-carbon
technology portfolio.
Providing affordable and reliable energy while managing
emissions requires a long-term perspective, competency
in fundamental science and engineering, and significant
investment. ExxonMobil has a history of more than
135 years as an energy innovator and is committed to
doing its part to help society address this critical challenge.
ENERGY-EFFICIENT MANUFACTURING
Demand for industrial products is expected to continue
to grow as the global economy recovers and standards of
living rise in the developing world. To meet this demand,
manufacturing solutions that are more energy- and
greenhouse gas-efficient than those currently available
will be required. Since 2000, ExxonMobil has reduced and
avoided more than 320 million tonnes of emissions through
energy efficiency and cogeneration projects and continues
to target research in equipment design, advanced
separations, catalysis, and process configurations as part
of efforts to develop energy-efficient manufacturing.11
ADVANCED BIOFUELS
Heavy-duty transportation requires fuels with high energy
density that liquid hydrocarbons provide. Biofuels, such
as those derived from algae, have the potential to be a
scalable solution and deliver the required energy density in
a liquid form that could reduce greenhouse gas emissions
by more than 50 percent compared to today’s heavy-duty
transportation fuels.11 We continue to progress and invest
in research to transform algae and cellulosic biomass into
liquid fuels (biofuels) for the transportation sector.
D
C
E
O
-
N
O
N
12
80% OF
EMMISSIONS
PRODUCED BY
3 SEGMENTS
D
C
E
O
6
3
0
GLOBAL ENERGY-RELATED
CO2 EMISSIONS BY SECTOR9
(2017, billion tonnes)
POWER GENERATION
INDUSTRIAL
COMMERCIAL
TRANSPORTATION
LIGHT-DUTY
TRANSPORTATION
RESIDENTIAL/
COMMERCIAL
VII
E X X O N M O B I L 2 0 2 0 A N N U A L R E P O R T
| C O R P O R A T E O V E R V I E W
P R OV I D I N G E N E R G Y A N D P R O D U C T S F O R M O D E R N L I F E
ExxonMobil safely provides the energy and products that advance modern life, exploring for and producing oil and gas;
refining the fuels and lubricants that enable transportation by land, sea, and air; and manufacturing the chemical
building blocks for many products essential to life today.
EXPLORATION: ExxonMobil searches the globe for
low-cost hydrocarbon supplies that can help the world
responsibly meet increasing energy needs. ExxonMobil
maintains one of the most active exploration programs
in the industry, with particular focus on the deepwater
portfolio.
PRODUCTION: ExxonMobil develops and produces
oil and natural gas around the world, and has
deepwater, unconventional, liquefied natural gas
(LNG), heavy oil, and conventional operations.
We use innovation and industry-leading technology
to safely and responsibly produce hydrocarbons
to meet global energy demand.
REFINING: ExxonMobil is one of the world’s largest
manufacturers and marketers of fuels and lubricants,
selling about 5 million barrels per day of petroleum
products, through a global network of more than
20,000 retail stations and commercial channels.
CHEMICAL: ExxonMobil leverages proprietary,
industry-leading technology to produce high-value
performance products. They are differentiated due to
their enhanced properties and the significant value
they bring to our customers and end-users.
C O M P E T I T I V E A DVA N TAG E S
Combined with a best-in-class portfolio
and financial capacity, ExxonMobil’s
competitive advantages position the
company to resiliently respond to market
conditions and deliver superior growth
and value.
VIII
TECHNOLOGY
SCALE
We are a proven technology leader
and our partnerships and investments
in fundamental science and research
lead to lower operating and project
costs and development of higher-value
products to meet society’s evolving
needs.
The scale of our global business
facilitates broad deployment of
expertise, cost efficiencies, and
operational learnings, while also
enabling preferred partnership
opportunities.
EXXONMOBIL 2020 ANNUAL REPORT P R O G R E S S I N G A DVA N TAG E D I N V E S T M E N T S
PERMIAN Started up Delaware
central processing and export facility
and the long haul pipeline connecting
Permian to the Houston area
CORPUS CHRISTI CHEMICAL PROJECT
Progressed construction, including
module installation, to provide additional
chemical performance product capacity
ROTTERDAM Advancing
projects that could position our
Rotterdam refinery for future
CCS investments
GUYANA
Progressing
phased development
projects, including
funding of a third project,
Payara, in parallel to the
exploration program
Countries with
ExxonMobil operation
BUSINESS LINES
Upstream
Downstream
Chemical
Countries with
ExxonMobil operations
BUSINESS LINES
Upstream
Downstream
Chemical
BRAZIL
Advanced Bacalhau development
and continued active exploration
CHINA FUCHUANG JV
Implemented a digital automotive environment
expanding and highgrading the existing
network of Mobil 1 Car Care outlets
42 MILLION
BUSINESS LINES
Upstream
Downstream
Chemical
Countries with
ExxonMobil operations
PROJECT WORK HOURS MANAGED BY OUR
GLOBAL PROJECTS ORGANIZATION IN 2020
INTEGRATION
FUNCTIONAL
EXCELLENCE
PEOPLE
Integration across global value chains
enables us to capture incremental value
for our products through extensive
operational and product flexibility,
security of feed supply, and cost
benefits, including sharing of support
organizations and facility infrastructure.
R
E
N
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:
A successful history of operating
complex global businesses has
resulted in the development of
deep knowledge in critical disciplines
Data list is used t o drive th e black and
and industry-leading execution
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N
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A
A world-class workforce is our most
important competitive advantage.
Our employees bring expertise
across a wide range of disciplines,
and we deploy those capabilities
to create value across our global
portfolio.
IX
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R Michael D. Foley • Investor Relations
Exx on Mobil Corporati on, Ir ving, TX
Offic e: 9 72-940 -6729
Mobile: 214- 608-9345
mich ael.d.fole y@exxo nmobil.com
K Eric Whetstone • Whetst one D esign
studio/cell: 214-412-8000
fax: 817-583-6119
ericwhetsto ne@g mail.com
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Carol Zuber- Mal lison • ZM Graphics, Inc.
Data list is used t o drive th e black and
studio/c ell: 2 14-906-416 2 • fax: 8 17-924- 7783
white chart, which is then u sed as a
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carol@zmgr aph ics.com
template fo r the c olor chart. Bars and lin es
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are cut an d past ed from the black and
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data; it is a piec e of artwor k buiilt by a
human. Therefore, the edit or needs to
thorou ghly proo f the fin al artw ork, not
JUST the data list.
R Michael D. Foley • Investor Relations
Exx on Mobil Corporati on, Ir ving, TX
Offic e: 9 72-940 -6729
Mobile: 214- 608-9345
mich ael.d.fole y@exxo nmobil.com
K Eric Whetstone • Whetst one D esign
studio/cell: 214-412-8000
fax: 817-583-6119
ericwhetsto ne@g mail.com
Carol Zuber- Mal lison • ZM Graphics, Inc.
studio/c ell: 2 14-906-416 2 • fax: 8 17-924- 7783
carol@zmgr aph ics.com
Usag e: Ex clu sive right s with in Exxo nMobil
LAST FILE CH ANG E MADE BY
Carol
Eric
Bill
Feb. 07, 2021
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Mich ael F oley
C R E AT I N G VA L U E T H R O U G H
O U R I N T E G R AT E D B U S I N E S S E S
The Corpus Christi Chemical Project is an example of an advantaged investment executed by ExxonMobil’s
unique Global Projects organization, which has combined innovative modular design from the upstream with
industry-leading chemical design technology to deliver the project at below 75 percent of average industry cost.12
When operational, it will integrate feed from the Permian Basin development with a global distribution of
chemical products to help meet growing demand. Deployment of new, innovative technologies
maximizes returns and reduces emissions.
PHOTO: Corpus Christi Chemical Project module delivery.
X
EXXONMOBIL 2020 ANNUAL REPORT 2 02 0 H I G H L I G H T S
SAFETY PERFORMANCE
(lost-time incidents per 200,000 work hours) 13
0.15
0.10
0.05
0
U.S. petroleum industry benchmark
ExxonMobil workforce
2011 12
13
14
15
16
17
18
19 2020
BEST-EVER SAFETY PERFORMANCE
CAPITAL INVESTMENTS
(Capex, billion dollars)
2019
2020
$31 billion
$21 billion
MORE THAN 30-PERCENT DECREASE WITH
DEFERRAL COSTS OFFSET BY SAVINGS
CASH OPERATING COSTS14
(billion dollars)
2019
2020
$49 billion
$42 billion
MORE THAN 15-PERCENT REDUCTION IN COSTS
~370 KOEBD
NET PERMIAN PRODUCTION EXCEEDING
PLANS DESPITE CURTAILMENTS
3 DISCOVERIES
CONTRIBUTING TO ALMOST 9 BOEB OF GROSS
RECOVERABLE RESOURCES IN GUYANA
>9 MILLION
TONNES OF RECORD POLYETHYLENE SALES
KOEBD: Thousands of oil-equivalent barrels per day
BOEB: Billions of oil-equivalent barrels
XI
| B U S I N E S S S E G M E N T S
U P S T R E A M
ExxonMobil produces about 4 million oil-equivalent
barrels of net oil and natural gas per day. We are active in
40 countries, and participate in all aspects of the upstream
global value chain, including exploration, development,
production, and marketing. Our Upstream is organized
into five value-chains: deepwater, unconventional,
LNG, heavy oil, and conventional. Our industry-leading,
low cost-of-supply developments in deepwater,
unconventional Permian, and LNG underpin the growing
value of our portfolio.
UP CLOSE: GUYANA
ExxonMobil is supporting local communities and
helping to develop the local oil and natural gas
industry in Guyana. More than 2,000 Guyanese are
now supporting project activities and, along with
our primary contractors, we have spent more than
$300 million with 700 local companies since 2015.
XII
DEEPWATER
In Guyana, our exploration success continued in 2020
with three additional discoveries, bringing the total to
18 at year end and increased the estimated gross
recoverable resource to almost 9 billion oil-equivalent
barrels. In partnership with the government of Guyana, we
are efficiently developing these resources while maintaining
active exploration to test multiple prospects.
The Liza Phase 1 development started production in
December 2019, less than five years after initial discovery,
in approximately half the time of the industry average for
projects of this size. The Liza Phase 2 development is on
schedule for start-up in 2022. The third development,
Payara, has progressed through final investment decision
following government issuance of the production license.
These three developments, combined with two additional
floating production, storage, and offloading (FPSO) vessels,
are expected to produce more than 750,000 barrels of oil
per day by 2026.
In Brazil, our acreage position is among the largest of any
company, with 2.6 million net acres. We operate more than
60 percent of our 28-block portfolio and expect to begin
operated exploration drilling in 2021. Development work is
ongoing in the Bacalhau field in the prolific pre-salt Santos
Basin. Our interests are 40 percent in each of the blocks
where the field is located.
PERMIAN
Leveraging our large contiguous acreage position and
unique development plan, we continue to increase resource
recovery and production in the Permian Basin while also
significantly reducing development and operating costs.
We produced an average of approximately 370,000 net
oil-equivalent barrels per day in 2020, a 35-percent
year-on-year production increase despite challenging
market conditions. Our estimated net recoverable
resource exceeds 10 billion oil-equivalent barrels and,
by applying our leading technology, we are positioned
to significantly increase production, unit profitability,
and overall cash flow.15
We have invested in infrastructure from New Mexico to
the U.S. Gulf Coast to provide logistics flexibility and
maximize the integrated value of our Permian development.
In 2020, we started operations at a central processing and
export facility in the Delaware Basin. Integration, including
EXXONMOBIL 2020 ANNUAL REPORT UP CLOSE: PERMIAN TECHNOLOGY
Technology advances are increasing the overall value of the Permian development through higher resource recovery,
lower development costs, and improvements in sustainability. We are using our proprietary modeling and subsurface field
measurement capabilities to optimize well spacing and stacking, helping to reduce drilling and completion cost.
>30% REDUCTION IN DRILLING AND COMPLETION COST SINCE 2018
transportation and downstream investments, enables
us to maximize our value-chain contributions from
resource development through to fuels, lubricants,
and chemicals production.
LNG
ExxonMobil is an industry leader in liquefied natural gas
and participates in the production of 86 million tonnes
per year, almost 25 percent of global LNG demand. This
leading position comes from decades of innovative technical
application and superior project management capabilities.
World-class resources and strong project performance
will enable continued addition of low cost-of-supply LNG
UP CLOSE: EMISSIONS REDUCTIONS
To further reduce methane emissions, we commenced
field trials of eight emerging methane detection
technologies, including satellite and aerial surveillance
monitoring, at nearly 1,000 sites in Texas and
New Mexico.
2020 UPSTREAM PRODUCTION BY VALUE CHAIN
2020 UPSTREAM PRODUCTION BY VALUE CHAIN
DEEPWATER 11%
DEEPWATER 11%
LNG 22%
LNG 22%
HEAVY OIL 11%
HEAVY OIL 11%
UNCONVENTIONAL 25%
UNCONVENTIONAL 25%
CONVENTIONAL 31%
CONVENTIONAL 31%
~4 million
~4 million
oil-equivalent
oil-equivalent
barrels per day
barrels per day
production in the coming decade. Key projects include
the Golden Pass export facility on the U.S. Gulf Coast
and future developments in Papua New Guinea and
Mozambique.
We conduct conventional oil and natural gas operations in
17 countries. In our mature conventional operations, we are
focused on maximizing cash flow generation by lowering
costs and optimizing recovery efficiency. In Canada, through
our majority-owned affiliate Imperial Oil Limited (IOL),
we have a significant low-decline heavy-oil portfolio and
continue to reduce cost and improve reliability to maximize
long-term value.
XIII
| B U S I N E S S S E G M E N T S
D OW N S T R E A M
ExxonMobil is one of the world’s largest manufacturers and
marketers of fuels and lubricants, and sells about 5 million
barrels per day of petroleum products. The commercial
success of well-known brands and high-quality products
is underpinned by our strong customer focus and supply
reliability. Mobil 1 synthetic lubricant is the worldwide
leader in synthetic motor oils and is the best-selling
U.S. retail motor oil.16, 17
FUELS
The integrated fuels value chain includes crude acquisition,
manufacturing, distribution, and sales of fuels products
through retail, commercial, and supply channels.
As one of the world’s largest refiners, we have nearly
5 million barrels per day of distillation capacity at
21 refineries. An integrated, global manufacturing and
logistics footprint enables reliable supply of high-quality,
high-value products.
UP CLOSE: DIGITAL CUSTOMER EXPERIENCE
Customers can now pay from the comfort of their car
through the ExxonMobil Rewards+ app, Alexa-enabled
device or pay at the pump with Google Pay or Apple Pay.
These new customer experiences are just the latest in a
rich history of innovation at the pump.
XIV
LUBRICANTS
The lubricants value chain includes the development,
production, and sale of basestocks and finished lubricant
products. We are integrated across the entire lubricants
value chain, with six basestock refineries and 21 finished
lubricant blending facilities. Leading brands and proprietary
technology support the wide-ranging offer of products and
services we provide to customers.
Expanding basestocks • As the world’s largest Group I and
Group II basestocks producer, we bring some of the most
efficient production capacity to the base oils marketplace,
helping to enable reliable supply and consistent quality.
We develop basestock products leveraging leading-edge
technology and ongoing investment in research and
development.
Growing synthetic lubricants • ExxonMobil is the market
leader in high-value synthetic lubricants. Growth in
synthetics to meet global consumer demand for higher-
performance products remains a strategic priority, with
a strong focus on growing markets. The start-up of a
digital automotive maintenance environment in the China
FuChuang Joint Venture will integrate suppliers and
customers of Mobil branded lubricants. It will expand and
highgrade the existing network of Mobil 1 Car Care outlets
and other vehicle maintenance products and services.
INTEGRATED PANDEMIC RESPONSE
At the onset of the pandemic, the need for hand sanitizer,
medical gowns, and masks was an essential societal challenge.
We responded by re-optimizing units that typically produce
gasoline, to increase production of the key feedstock for
our chemical plants, critical to the manufacturing of these
finished products.
EXXONMOBIL 2020 ANNUAL REPORT C H E M I C A L
UP CLOSE: SUPERIOR PERFORMANCE PRODUCTS
POLYPROPYLENE: More than
10-percent increase in production
of specialized products that improve
hygiene barriers in medical gowns
and masks
POLYETHYLENE: Increased
demand for barrier films and food
and goods packaging supported
record sales
VISTAMAXX POLYMERS:
Record sales driven by enhanced
softness in medical fabrics and
enabling recyclability without
degrading performance 18
ExxonMobil is among the largest chemical producers in the
world with annual sales of over 25 million tonnes. We are
the number one or two producer for more than 80 percent
of our chemical product portfolio,19 achieved through
operational excellence, cost discipline, a balanced product
portfolio, proprietary technology, and industry-leading
integration with our Downstream and Upstream operations.
flexible processes enable us to respond to dynamic market
conditions, rapidly transitioning our chemical operations
across an unparalleled range of feedstocks, from light
gases to crude oil. This capability, in addition to reliable
operations, helped us achieve an olefins production record
in 2020, providing advantaged, secure feedstock for our
performance and commodity products.
Worldwide demand for chemicals is expected to rise by
approximately 40 percent by 2030,20 underpinned by
global population growth, an expanding middle class, and
improved living standards. These factors, together with a
recognition of the lower greenhouse gas emissions from
plastics versus alternatives, correspond to an increase in
demand for everyday products.21 We are investing in
new capacity to meet that demand.
BASIC CHEMICALS
Basic chemicals are the building blocks for many of the
products essential to modern life. Olefins are the feed to
produce polyethylene, polypropylene, and other polymers.
Aromatics and glycols are
vital for a wide range of
consumer and industrial
products, including
polyester resins, fibers for
clothing, and insulation.
Integration, advanced
optimization tools, and
PERFORMANCE PRODUCTS
Our performance products are used in a wide range of
consumer applications, including food packaging, vehicles,
and diapers. They enable tougher and lighter products that
use less material, save energy, and reduce cost and waste.
The enhanced properties of our performance products,
and the significant value they bring to customers and
end-users, differentiate them from commodity products.
Leveraging our technology leadership and extensive
customer collaboration, performance product sales grew
by nearly 5 percent in 2020, despite lower global GDP.
UP CLOSE: SUSTAINABILITY
Plastics provide sustainability benefits and
play an important role in helping society mitigate
greenhouse gas emissions. We are investing in
advantaged technology to recycle plastic waste at our
integrated sites. We are also a founding member of the
Alliance to End Plastic Waste, an organization focused
on developing safe, scalable, and economically viable
solutions to help end plastic waste in the environment.
XV
B OA R D O F D I R E C T O R S
Kenneth C. Frazier (Lead Director)
Chairman of the Board and
Chief Executive Officer,
Merck & Company (pharmaceuticals)
Director since 2009
Angela F. Braly
Former Chairman of the Board,
President, and Chief Executive Officer,
WellPoint, Inc. (health care)
Director since 2016
Joseph L. Hooley
Former Chairman of the Board,
President, and Chief Executive Officer,
State Street Corporation
(financial services)
Director since 2020
Douglas R. Oberhelman
Former Chairman of the Board and
Chief Executive Officer, Caterpillar Inc.
(heavy equipment)
Director since 2015
William C. Weldon
Former Chairman of the Board
and Chief Executive Officer,
Johnson & Johnson (pharmaceuticals)
Director since 2013
Susan K. Avery
President Emerita, Woods Hole
Oceanographic Institution (nonprofit
ocean research, exploration, and
education)
Director since 2017
Ursula M. Burns
Former Chairman of the Board and
Chief Executive Officer, VEON Ltd.
(telecommunication services)
Director since 2012
Steven A. Kandarian
Former Chairman of the Board,
President, and Chief Executive Officer,
MetLife Inc. (insurance)
Director since 2018
Samuel J. Palmisano
Former Chairman of the Board, President,
and Chief Executive Officer, International
Business Machines Corporation
(computer hardware, software,
business consulting, and IT services)
Director since 2006
Darren W. Woods
Chairman of the Board and
Chief Executive Officer
Director since 2016
6 YEARS AVERAGE TENURE
OF NON-EMPLOYEE DIRECTORS, ABOUT 2 YEARS LOWER THAN THE S&P 500 AVERAGE22
6 NON-EMPLOYEE DIRECTORS ADDED WITHIN THE LAST 6 YEARS23
As of January 1, 2021
STANDING COMMITTEES OF THE BOARD
Audit Committee
U.M. Burns (Chair), J.L. Hooley, D.R. Oberhelman, W.C. Weldon
Board Affairs Committee
K.C. Frazier (Chair), S.K. Avery, S.J. Palmisano
Compensation Committee
S.J. Palmisano (Chair), A.F. Braly, K.C. Frazier, S.A. Kandarian
XVI
Finance Committee
D.W. Woods (Chair), U.M. Burns, J.L. Hooley, D.R. Oberhelman,
W.C. Weldon
Public Issues and Contributions Committee
A.F. Braly (Chair), S.K. Avery, S.A. Kandarian
Executive Committee
D.W. Woods (Chair), U.M. Burns, K.C. Frazier, S.J. Palmisano,
W.C. Weldon
EXXONMOBIL 2020 ANNUAL REPORT
2020
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-2256
Exxon Mobil Corporation
(Exact name of registrant as specified in its charter)
New Jersey
(State or other jurisdiction of
incorporation or organization)
13-5409005
(I.R.S. Employer
Identification Number)
5959 Las Colinas Boulevard, Irving, Texas 75039-2298
(Address of principal executive offices) (Zip Code)
(972) 940-6000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, without par value
0.142% Notes due 2024
0.524% Notes due 2028
0.835% Notes due 2032
1.408% Notes due 2039
Trading Symbol
XOM
XOM24B
XOM28
XOM32
XOM39A
Name of Each Exchange on Which Registered
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90
days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of
Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes R No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth
company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the
Exchange Act.
Large accelerated filer
Non-accelerated filer
☑
☐
Accelerated filer
Smaller reporting company
Emerging growth company
☐
☐
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial
reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes ☐ No ☑
The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2020, the last business day of the registrant’s most recently completed
second fiscal quarter, based on the closing price on that date of $44.72 on the New York Stock Exchange composite tape, was in excess of $189 billion.
Class
Common stock, without par value
Outstanding as of January 31, 2021
4,233,483,160
Documents Incorporated by Reference: Proxy Statement for the 2021 Annual Meeting of Shareholders (Part III)
EXXON MOBIL CORPORATION
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2020
TABLE OF CONTENTS
PART I
Item 1.
Business
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Item 3.
Item 4.
Properties
Legal Proceedings
Mine Safety Disclosures
Information about our Executive Officers
PART II
Item 5.
Item 7.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
PART IV
Item 15.
Item 16.
Exhibits, Financial Statement Schedules
Form 10-K Summary
Financial Section
Index to Exhibits
Signatures
Exhibits 31 and 32 — Certifications
1
2
5
6
27
27
28
30
30
30
31
31
31
31
32
32
32
33
33
33
33
34
124
125
PART I
ITEM 1. BUSINESS
Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil
operate or market products in the United States and most other countries of the world. Their principal business involves exploration
for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum
products, petrochemicals and a wide variety of specialty products. Affiliates of ExxonMobil conduct extensive research programs in
support of these businesses.
Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso,
Mobil or XTO. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso, Mobil and XTO, as well as terms
like Corporation, Company, our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates.
The precise meaning depends on the context in question.
The energy and petrochemical industries are highly competitive, both within the industries and also with other industries in supplying
the energy, fuel and chemical needs of industrial and individual consumers. The Corporation competes with other firms in the sale or
purchase of needed goods and services in many national and international markets and employs all methods of competition which are
lawful and appropriate for such purposes.
Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the
following: “Note 18: Disclosures about Segments and Related Information” and “Operating Information”. Information on oil and gas
reserves is contained in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production
Activities” portion of the Financial Section of this report.
ExxonMobil has a long-standing commitment to the development of proprietary technology. We have a wide array of research
programs designed to meet the needs identified in each of our business segments. ExxonMobil held nearly 9 thousand active patents
worldwide at the end of 2020. For technology licensed to third parties, revenues totaled approximately $130 million in 2020. Although
technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment
is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.
ExxonMobil operates in a highly complex, competitive and changing global energy business environment where decisions and risks
play out over time horizons that are often decades in length. This long-term orientation underpins the Corporation's philosophy on
talent development.
Talent development begins with recruiting exceptional candidates and continues with individually planned experiences and training
designed to facilitate broad development and a deep understanding of our business across the business cycle. Our career-oriented
approach to talent development results in strong retention and an average length of service of 30 years for our career employees.
Compensation, benefits and workplace programs support the Corporation's talent management approach, and are designed to attract
and retain employees for a career through compensation that is market competitive, long-term oriented, and highly differentiated by
individual performance.
Sixty percent of our global employee workforce is from outside the U.S., and over the past decade 39 percent of our global hires for
management, professional and technical positions were female and 31 percent of our U.S. hires for management, professional and
technical positions were minorities. With over 160 nationalities represented in the Company, we encourage and respect diversity of
thought, ideas and perspective from our workforce. We consider and monitor diversity through all stages of employment, including
recruitment, training and development of our employees. We also work closely with the communities where we operate to identify and
invest in initiatives that help support local needs, including local talent and skill development.
The number of regular employees was 72 thousand, 75 thousand, and 71 thousand at years ended 2020, 2019, and 2018, respectively.
Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or
part time for the Corporation and are covered by the Corporation’s benefit plans and programs.
As discussed in item 1A. Risk Factors in this report, compliance with existing and potential future government regulations, including
taxes, environmental regulations, and other government regulations and policies that directly or indirectly affect the production and
sale of our products, may have material effects on the capital expenditures, earnings, and competitive position of ExxonMobil. With
respect to the environment, throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the
impact of our operations on air, water and ground, including, but not limited to, compliance with environmental regulations. These
include a significant investment in refining infrastructure and technology to manufacture clean fuels, as well as projects to monitor and
reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions, and expenditures for asset retirement obligations. Using definitions
and guidelines established by the American Petroleum Institute, ExxonMobil’s 2020 worldwide environmental expenditures for all
such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.5 billion, of which
$3.4 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to
increase to approximately $4.9 billion in 2021 and 2022. Capital expenditures are expected to account for approximately 25 percent of
the total.
1
Information concerning the source and availability of raw materials used in the Corporation’s business, the extent of seasonality in the
business, the possibility of renegotiation of profits or termination of contracts at the election of governments and risks attendant to
foreign operations may be found in “Item 1A. Risk Factors” and “Item 2. Properties” in this report.
ExxonMobil maintains a website at exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act
of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the
Securities and Exchange Commission (SEC). Also available on the Corporation’s website are the Company’s Corporate Governance
Guidelines, Code of Ethics and Business Conduct, and additional policies as well as the charters of the audit, compensation, and other
committees of the Board of Directors. Information on our website is not incorporated into this report.
The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other
information regarding issuers that file electronically with the SEC.
ITEM 1A. RISK FACTORS
ExxonMobil’s financial and operating results are subject to a variety of risks inherent in the global oil, gas, and petrochemical
businesses. Many of these risk factors are not within the Company’s control and could adversely affect our business, our financial and
operating results, or our financial condition. These risk factors include:
Supply and Demand
The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil’s operations and
earnings may be significantly affected by changes in oil, gas, and petrochemical prices and by changes in margins on refined products.
Oil, gas, petrochemical, and product prices and margins in turn depend on local, regional, and global events or conditions that affect
supply and demand for the relevant commodity. Any material decline in oil or natural gas prices could have a material adverse effect
on certain of the Company’s operations, especially in the Upstream segment, financial condition, and proved reserves. On the other
hand, a material increase in oil or natural gas prices could have a material adverse effect on certain of the Company’s operations,
especially in the Downstream and Chemical segments.
Economic conditions. The demand for energy and petrochemicals is generally linked closely with broad-based economic activities
and levels of prosperity. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct
adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes
in population growth rates, periods of civil unrest, government austerity programs, trade tariffs, security or public health issues and
responses, or currency exchange rate fluctuations, can also impact the demand for energy and petrochemicals. Sovereign debt
downgrades, defaults, inability to access debt markets due to credit or legal constraints, liquidity crises, the breakup or restructuring of
fiscal, monetary, or political systems such as the European Union, and other events or conditions that impair the functioning of
financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our financial assets and to the ability
of our partners and customers to fulfill their commitments to ExxonMobil. Demand reduction due to the COVID-19 pandemic as well
as accompanying conditions of oversupply have led to a significant decrease in commodity prices and margins. Future business
results, including cash flows and financing needs, will be affected by the extent and duration of these conditions and the effectiveness
of responsive actions that the Corporation and others take, including actions to reduce capital and operating expenses, and actions
taken by governments and others to address the COVID-19 pandemic including the ongoing development and distribution of
COVID-19 vaccines, and the impact of the pandemic on national and global economies and markets.
Other demand-related factors. Other factors that may affect the demand for oil, gas, and petrochemicals, and therefore impact our
results, include technological improvements in energy efficiency; seasonal weather patterns; increased competitiveness of, or
government policy support for, alternative energy sources; changes in technology that alter fuel choices, such as technological
advances in energy storage that make wind and solar more competitive for power generation; changes in consumer preferences for our
products, including consumer demand for alternative fueled or electric transportation or alternatives to plastic products; and broad-
based changes in personal income levels.
Other supply-related factors. Commodity prices and margins also vary depending on a number of factors affecting supply. For
example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from
existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in
demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins
on the affected products. World oil, gas, and petrochemical supply levels can also be affected by factors that reduce available supplies,
such as adherence by countries to OPEC production quotas and other agreements among sovereigns, government policies that restrict
oil and gas production or increase associated costs, and the occurrence of wars, hostile actions, natural disasters, disruptions in
competitors’ operations, logistics constraints or unexpected unavailability of distribution channels that may disrupt supplies.
Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture
petrochemicals.
Other market factors. ExxonMobil’s business results are also exposed to potential negative impacts due to changes in interest rates,
inflation, currency exchange rates, and other local or regional market conditions.
2
Government and Political Factors
ExxonMobil’s results can be adversely affected by political or regulatory developments affecting our operations.
Access limitations. A number of countries limit access to their oil and gas resources, including by restricting leasing or permitting
activities, or may place resources off-limits from development altogether. Restrictions on production of oil and gas could increase to
the extent governments view such measures as a viable approach for pursuing national and global energy and climate policies.
Restrictions on foreign investment in the oil and gas sector tend to increase in times of high commodity prices, when national
governments may have less need of outside sources of private capital. Many countries also restrict the import or export of certain
products based on point of origin.
Restrictions on doing business. ExxonMobil is subject to laws and sanctions imposed by the United States or by other jurisdictions
where we do business that may prohibit ExxonMobil or certain of its affiliates from doing business in certain countries, or restricting
the kind of business that may be conducted. Such restrictions may provide a competitive advantage to competitors who may not be
subject to comparable restrictions.
Lack of legal certainty. Some countries in which we do business lack well-developed legal systems, or have not yet adopted, or may
be unable to maintain, clear regulatory frameworks for oil and gas development. Lack of legal certainty exposes our operations to
increased risk of adverse or unpredictable actions by government officials, and also makes it more difficult for us to enforce our
contracts. In some cases these risks can be partially offset by agreements to arbitrate disputes in an international forum, but the
adequacy of this remedy may still depend on the local legal system to enforce an award.
Regulatory and litigation risks. Even in countries with well-developed legal systems where ExxonMobil does business, we remain
exposed to changes in law or interpretation of settled law (including changes that result from international treaties and accords) that
could adversely affect our results, such as:
•
•
•
•
•
•
•
increases in taxes, duties, or government royalty rates (including retroactive claims);
price controls;
changes in environmental regulations or other laws that increase our cost of compliance or reduce or delay available business
opportunities (including changes in laws affecting offshore drilling operations, water use, methane emissions, hydraulic
fracturing or use of plastics);
actions by regulators or other political actors to delay or deny necessary licenses and permits or restrict the transportation of
our products;
adoption of regulations mandating efficiency standards, the use of alternative fuels or uncompetitive fuel components;
adoption of government payment transparency regulations that could require us to disclose competitively sensitive
commercial information, or that could cause us to violate the non-disclosure laws of other countries; and
government actions to cancel contracts, re-denominate the official currency, renounce or default on obligations, renegotiate
terms unilaterally, or expropriate assets.
Legal remedies available to compensate us for expropriation or other takings may be inadequate.
We also may be adversely affected by the outcome of litigation, especially in countries such as the United States in which very large
and unpredictable punitive damage awards may occur; by government enforcement proceedings alleging non-compliance with
applicable laws or regulations; or by state and local government actors as well as private plaintiffs acting in parallel that attempt to use
the legal system to promote public policy agendas, gain political notoriety, or obtain monetary awards from the Company.
Security concerns. Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or
terrorism, cybersecurity attacks, and other local security concerns. Such concerns may require us to incur greater costs for security or
to shut down operations for a period of time.
Climate change and greenhouse gas restrictions. Driven by concern over the risks of climate change, a number of countries have
adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions or production and use of oil
and gas. These include adoption of cap and trade regimes, carbon taxes, trade tariffs, minimum renewable usage requirements,
restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. Political and other actors and
their agents also increasingly seek to advance climate change objectives indirectly, such as by seeking to reduce the availability of or
increase the cost for, financing and investment in the oil and gas sector and taking actions intended to promote changes in business
strategy for oil and gas companies. Depending on how policies are formulated and applied, they could have the potential to negatively
affect investment returns, make our products more expensive or less competitive, lengthen project implementation times, and reduce
demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon sources such as natural gas. Current
and pending greenhouse gas regulations or policies may also increase our compliance costs, such as for monitoring or sequestering
emissions.
3
Alternative energy. Many governments are providing tax advantages and other subsidies to support transitioning to alternative energy
sources or are mandating the use of specific fuels or technologies. Governments and others are also promoting research into new
technologies to reduce the cost and increase the scalability of alternative energy sources. We are conducting our own research both in-
house and by working with more than 80 leading universities around the world, including the Massachusetts Institute of Technology,
Princeton University, The University of Texas, and Stanford University in the U.S., and in Singapore with Nanyang Technological
Institute and the National University. Our research projects focus on developing advanced biofuels and hydrogen, carbon capture and
storage, breakthrough energy efficiency processes, advanced energy-saving materials, and other technologies in collaboration with our
partners including Synthetic Genomics, FuelCell Energy and Global Thermostat. Our future results may depend in part on the success
of our research efforts and on our ability to adapt and apply the strengths of our current business model to providing the energy
products of the future in a cost-competitive manner. See “Operational and Other Factors” below.
Operational and Other Factors
In addition to external economic and political factors, our future business results also depend on our ability to manage successfully
those factors that are at least in part within our control. The extent to which we manage these factors will impact our performance
relative to competition. For projects in which we are not the operator, we depend on the management effectiveness of one or more co-
venturers whom we do not control.
Exploration and development program. Our ability to maintain and grow our oil and gas production depends on the success of our
exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most promising
resource prospects and apply our project management expertise to bring discovered resources on line as scheduled and within budget.
Project and portfolio management. The long-term success of ExxonMobil’s Upstream, Downstream, and Chemical businesses
depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management
expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate
successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance;
develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage
changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping;
prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project startup or cause
unscheduled project downtime; and influence the performance of project operators where ExxonMobil does not perform that role. In
addition to the effective management of individual projects, ExxonMobil’s success, including our ability to mitigate risk and provide
attractive returns to shareholders, depends on our ability to successfully manage our overall portfolio, including diversification among
types and locations of our projects and strategies to divest assets. We may not be able to divest assets at a price or on the timeline we
contemplate in our strategies. Additionally, we may retain certain liabilities following a divestment and could be held liable for past
use or for different liabilities than anticipated.
The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as
in any government payment transparency reports.
Operational efficiency. An important component of ExxonMobil’s competitive performance, especially given the commodity-based
nature of many of our businesses, is our ability to operate efficiently, including our ability to manage expenses and improve
production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control,
productivity enhancements, regular reappraisal of our asset portfolio, and the recruitment, development, and retention of high caliber
employees.
Research and development and technological change. To maintain our competitive position, especially in light of the technological
nature of our businesses and the need for continuous efficiency improvement, ExxonMobil’s research and development organizations
must be successful and able to adapt to a changing market and policy environment, including developing technologies to help reduce
greenhouse gas emissions. To remain competitive we must also continuously adapt and capture the benefits of new and emerging
technologies, including successfully applying advances in the ability to process very large amounts of data to our businesses.
Safety, business controls, and environmental risk management. Our results depend on management’s ability to minimize the
inherent risks of oil, gas, and petrochemical operations, to control effectively our business activities, and to minimize the potential for
human error. We apply rigorous management systems and continuous focus on workplace safety and avoiding spills or other adverse
environmental events. For example, we work to minimize spills through a combined program of effective operations integrity
management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. Similarly, we are
implementing cost-effective new technologies and adopting new operating practices to reduce air emissions, not only in response to
government requirements but also to address community priorities. We also maintain a disciplined framework of internal controls and
apply a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts
could result if our management systems and controls do not function as intended.
4
Cybersecurity. ExxonMobil is regularly subject to attempted cybersecurity disruptions from a variety of threat actors including state-
sponsored actors. ExxonMobil’s defensive preparedness includes multi-layered technological capabilities for prevention and detection
of cybersecurity disruptions; non-technological measures such as threat information sharing with governmental and industry groups;
internal training and awareness campaigns including routine testing of employee awareness and an emphasis on resiliency including
business response and recovery. If the measures we are taking to protect against cybersecurity disruptions prove to be insufficient or if
our proprietary data is otherwise not protected, ExxonMobil as well as our customers, employees, or third parties could be adversely
affected. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise
business systems; result in proprietary information being altered, lost, or stolen; result in employee, customer, or third-party
information being compromised; or otherwise disrupt our business operations. We could incur significant costs to remedy the effects
of a major cybersecurity disruption in addition to costs in connection with resulting regulatory actions, litigation or reputational harm.
Preparedness. Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For
example, hurricanes may damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas.
Our facilities are designed, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety
factors built in to cover a number of engineering uncertainties, including those associated with wave, wind, and current intensity,
marine ice flow patterns, permafrost stability, storm surge magnitude, temperature extremes, extreme rainfall events, and earthquakes.
Our consideration of changing weather conditions and inclusion of safety factors in design covers the engineering uncertainties that
climate change and other events may potentially introduce. Our ability to mitigate the adverse impacts of these events depends in part
upon the effectiveness of our robust facility engineering as well as our rigorous disaster preparedness and response, and business
continuity planning.
Insurance limitations. The ability of the Corporation to insure against many of the risks it faces as described in this Item 1A is
limited by the capacity of the applicable insurance markets, which may not be sufficient.
Competition. As noted in Item 1 above, the energy and petrochemical industries are highly competitive. We face competition not only
from other private firms, but also from state-owned companies that are increasingly competing for opportunities outside of their home
countries and as partners with other private firms. In some cases, these state-owned companies may pursue opportunities in
furtherance of strategic objectives of their government owners, with less focus on financial returns than companies owned by private
shareholders, such as ExxonMobil. Technology and expertise provided by industry service companies may also enhance the
competitiveness of firms that may not have the internal resources and capabilities of ExxonMobil or reduce the need for resource-
owning countries to partner with private-sector oil and gas companies in order to monetize national resources.
Reputation. Our reputation is an important corporate asset. An operating incident, significant cybersecurity disruption, change in
consumer views concerning our products, or other adverse event such as those described in this Item 1A may have a negative impact
on our reputation, which in turn could make it more difficult for us to compete successfully for new opportunities, obtain necessary
regulatory approvals, obtain financing, or could reduce consumer demand for our branded products. ExxonMobil’s reputation may
also be harmed by events which negatively affect the image of our industry as a whole.
Projections, estimates, and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 1A, 2, 7 and 7A of
this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital
expenditures, costs, and business plans could differ materially due to, among other things, the factors discussed above and elsewhere
in this report.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
5
ITEM 2. PROPERTIES
Information with regard to oil and gas producing activities follows:
1. Disclosure of Reserves
A. Summary of Oil and Gas Reserves at Year-End 2020
The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated
subsidiaries and equity companies. Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.
The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the
last 12-month period. Primarily as a result of very low prices during 2020 and the effects of reductions in capital expenditures, under
the SEC definition of proved reserves, certain quantities of crude oil, bitumen, and natural gas that qualified as proved reserves in prior
years did not qualify as proved reserves at year-end 2020. Otherwise, no major discovery or other favorable or adverse event has
occurred since December 31, 2020, that would cause a significant change in the estimated proved reserves as of that date.
Crude
Oil
(million bbls)
Natural Gas
Liquids
(million bbls)
Bitumen
(million bbls)
Synthetic
Oil
(million bbls)
Natural
Gas
(billion cubic ft)
Oil-
Equivalent
Total
All Products
(million bbls)
Proved Reserves
Developed
Consolidated Subsidiaries
United States
Canada/Other Americas (1)
Europe
Africa
Asia
Australia/Oceania
Total Consolidated
Equity Companies
United States
Europe
Africa
Asia
Total Equity Company
Total Developed
Undeveloped
Consolidated Subsidiaries
United States
Canada/Other Americas (1)
Europe
Africa
Asia
Australia/Oceania
Total Consolidated
Equity Companies
United States
Europe
Africa
Asia
Total Equity Company
Total Undeveloped
Total Proved Reserves
1,029
288
11
314
2,215
44
3,901
107
8
—
432
547
4,448
930
209
11
42
935
30
2,157
24
1
6
393
424
2,581
7,029
444
5
2
31
84
23
589
4
—
—
214
218
807
412
—
5
—
40
8
465
—
—
—
59
59
524
1,331
—
76
—
—
—
—
76
—
—
—
—
—
76
—
5
—
—
—
—
5
—
—
—
—
—
5
81
—
311
—
—
—
—
311
—
—
—
—
—
311
—
133
—
—
—
—
133
—
—
—
—
—
133
444
10,375
472
399
318
3,323
3,344
18,231
83
293
—
8,992
9,368
27,599
3,064
89
42
2
986
2,790
6,973
19
67
917
2,385
3,388
10,361
37,960
3,202
759
79
398
2,853
624
7,915
125
57
—
2,144
2,326
10,241
1,853
362
23
42
1,139
503
3,922
27
12
159
850
1,048
4,970
15,211
(1) Other Americas includes proved developed reserves of 119 million barrels of crude oil and 138 billion cubic feet of natural gas,
as well as proved undeveloped reserves of 179 million barrels of crude oil and 77 billion cubic feet of natural gas.
6
In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the
Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.
The Corporation anticipates several projects will come online over the next few years providing additional production capacity.
However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir
performance; performance of enhanced oil recovery projects; regulatory changes; the impact of fiscal and commercial terms; asset
sales; weather events; price effects on production sharing contracts; changes in the amount and timing of capital investments that may
vary depending on the oil and gas price environment; and other factors described in Item 1A. Risk Factors.
The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous
technical evaluations, commercial and market assessments and detailed analysis of well and reservoir information such as flow rates
and reservoir pressures. Furthermore, the Corporation only records proved reserves for projects which have received significant
funding commitments by management toward the development of the reserves. Although the Corporation is reasonably certain that
proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of
development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, and significant
changes in crude oil and natural gas price levels. In addition, proved reserves could be affected by an extended period of low prices
which could reduce the level of the Corporation’s capital spending and also impact our partners’ capacity to fund their share of joint
projects.
During the first and second quarters of 2020, the balance of supply and demand for petroleum and petrochemical products experienced
two significant disruptive effects. On the demand side, the COVID-19 pandemic spread rapidly through most areas of the world
resulting in substantial reductions in consumer and business activity and significantly reduced demand for crude oil, natural gas, and
petroleum products. This reduction in demand coincided with announcements of increased production in certain key oil-producing
countries which led to increases in inventory levels and sharp declines in prices for crude oil, natural gas, and petroleum products.
Market conditions continued to reflect considerable uncertainty throughout 2020.
As noted above, certain quantities of crude oil, bitumen, and natural gas that qualified as proved reserves in prior years did not qualify
as proved reserves at year-end 2020. Amounts no longer qualifying as proved reserves include 3.1 billion barrels of bitumen at Kearl,
0.6 billion barrels of bitumen at Cold Lake, and 0.5 billion oil-equivalent barrels in the United States. The Corporation's near-term
reduction in capital expenditures resulted in a net reduction to estimates of proved reserves of approximately 1.5 billion oil-equivalent
barrels, mainly related to unconventional drilling in the United States. Among the factors that could result in portions of these amounts
being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, cost reductions, operating
efficiencies, and increases in planned capital spending.
B. Technologies Used in Establishing Proved Reserves Additions in 2020
Additions to ExxonMobil’s proved reserves in 2020 were based on estimates generated through the integration of available and
appropriate geological, engineering and production data, utilizing well-established technologies that have been demonstrated in the
field to yield repeatable and consistent results.
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs,
reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance
information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 3-
D and 4-D seismic data, calibrated with available well control information. The tools used to interpret the data included proprietary
seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis
packages.
In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to
increase the quality of and confidence in the reserves estimates.
7
C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves
ExxonMobil has a dedicated Global Reserves and Resources group that provides technical oversight and is separate from the operating
organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with Securities
and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of
ExxonMobil’s proved reserves. This group also maintains the official company reserves estimates for ExxonMobil’s proved reserves
of crude oil, natural gas liquids, bitumen, synthetic oil, and natural gas. In addition, the group provides training to personnel involved
in the reserves estimation and reporting process within ExxonMobil and its affiliates. The Manager of the Global Reserves and
Resources group has more than 30 years of experience in reservoir engineering and reserves assessment, has a degree in Engineering
and currently serves on the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE). The group is staffed with
individuals that have an average of more than 15 years of technical experience in the petroleum industry, including expertise in the
classification and categorization of reserves under SEC guidelines. This group includes individuals who hold degrees in either
Engineering or Geology.
The Global Reserves and Resources group maintains a central database containing the official company reserves estimates.
Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this
central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation
process include technical evaluations, commercial and market assessments, analysis of well and field performance, and long-standing
approval guidelines. No changes may be made to the reserves estimates in the central database, including additions of any new initial
reserves estimates or subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized
geoscience and engineering professionals within the operating organization. In addition, changes to reserves estimates that exceed
certain thresholds require further review and approval by the appropriate level of management within the operating organization
before the changes may be made in the central database. Endorsement by the Global Reserves and Resources group for all proved
reserves changes is a mandatory component of this review process. After all changes are made, reviews are held with senior
management for final endorsement.
2. Proved Undeveloped Reserves
At year-end 2020, approximately 5.0 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as
proved undeveloped. This represents 33 percent of the 15.2 GOEB reported in proved reserves. This compares to the 7.7 GOEB of
proved undeveloped reserves reported at the end of 2019. During the year, ExxonMobil conducted development activities that resulted
in the transfer of approximately 0.9 GOEB from proved undeveloped to proved developed reserves by year end. The largest transfers
were related to development activities in the United States, Qatar, the United Arab Emirates, and Guyana. During 2020, extensions,
primarily in the United States and Canada, resulted in an addition of approximately 0.5 GOEB of proved undeveloped reserves. Also,
as a result of very low prices during 2020 and the effects of reductions in capital expenditures, the Corporation reclassified
approximately 2.3 GOEB of proved undeveloped reserves which no longer met the SEC definition of proved reserves, primarily in the
United States and Canada.
Overall, investments of $10.7 billion were made by the Corporation during 2020 to progress the development of reported proved
undeveloped reserves, including $10.4 billion for oil and gas producing activities, along with additional investments for other non-oil
and gas producing activities such as the construction of support infrastructure and other related facilities. These investments
represented 74 percent of the $14.4 billion in total reported Upstream capital and exploration expenditures.
One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments
toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead-
time in order to be developed. Development projects typically take several years from the time of recording proved undeveloped
reserves to the start of production and can exceed five years for large and complex projects. Proved undeveloped reserves in Australia,
Kazakhstan, the United States, and the United Arab Emirates have remained undeveloped for five years or more primarily due to
constraints on the capacity of infrastructure, as well as the time required to complete development for very large projects. The
Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be
affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals,
government policies, consumer preferences, the pace of co-venturer/government funding, changes in the amount and timing of capital
investments, and significant changes in crude oil and natural gas price levels. Of the proved undeveloped reserves that have been
reported for five or more years, over 80 percent are contained in the aforementioned countries. In Australia, proved undeveloped
reserves are associated with future compression for the Gorgon Jansz LNG project. In Kazakhstan, the proved undeveloped reserves
are related to the remainder of the Tengizchevroil joint venture development that includes a production license in the Tengiz - Korolev
field complex. The Tengizchevroil joint venture is producing, and proved undeveloped reserves will continue to move to proved
developed as approved development phases progress. In the United Arab Emirates, proved undeveloped reserves are associated with
an approved development plan and continued drilling investment for the producing Upper Zakum field.
8
3. Oil and Gas Production, Production Prices and Production Costs
A. Oil and Gas Production
The table below summarizes production by final product sold and by geographic area for the last three years.
Crude oil and natural gas liquids production
Consolidated Subsidiaries
United States
Canada/Other Americas (1)
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Asia
Total Equity Companies
2020
2019
(thousands of barrels daily)
2018
Crude
Oil
NGL
Crude
Oil
NGL
Crude
Oil
NGL
481
121
22
301
449
29
1,403
49
3
208
260
154
5
5
11
23
15
213
1
—
62
63
461
87
84
360
432
30
1,454
52
3
232
287
131
4
21
12
22
15
205
2
—
62
64
395
62
101
377
398
31
1,364
54
4
226
284
101
6
27
10
25
16
185
1
—
62
63
Total crude oil and natural gas liquids production
1,663
276
1,741
269
1,648
248
Bitumen production
Consolidated Subsidiaries
Canada/Other Americas
Synthetic oil production
Consolidated Subsidiaries
Canada/Other Americas
Total liquids production
Natural gas production available for sale
Consolidated Subsidiaries
United States
Canada/Other Americas (1)
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Asia
Total Equity Companies
Total natural gas production available for sale
Oil-equivalent production
342
311
310
68
2,349
2,668
277
447
9
872
1,219
5,492
23
342
2,614
2,979
8,471
65
2,386
(millions of cubic feet daily)
2,756
258
808
7
851
1,319
5,999
22
649
2,724
3,395
9,394
(thousands of oil-equivalent barrels daily)
3,761
3,952
60
2,266
2,550
227
925
13
838
1,325
5,878
24
728
2,775
3,527
9,405
3,833
(1) Other Americas includes crude oil production for 2020, 2019 and 2018 of 29 thousand, 2 thousand, and 2 thousand barrels daily,
respectively; and natural gas production available for sale for 2020, 2019 and 2018 of 45 million, 36 million, and 28 million
cubic feet daily, respectively.
9
B. Production Prices and Production Costs
The table below summarizes average production prices and average production costs by geographic area and by product type for the
last three years.
During 2020
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Bitumen, per barrel
Synthetic oil, per barrel
Average production costs, per oil-equivalent barrel - total
Average production costs, per barrel - bitumen
Average production costs, per barrel - synthetic oil
Equity Companies
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Average production costs, per oil-equivalent barrel - total
Total
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Bitumen, per barrel
Synthetic oil, per barrel
Average production costs, per oil-equivalent barrel - total
Average production costs, per barrel - bitumen
Average production costs, per barrel - synthetic oil
During 2019
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Bitumen, per barrel
Synthetic oil, per barrel
Average production costs, per oil-equivalent barrel - total
Average production costs, per barrel - bitumen
Average production costs, per barrel - synthetic oil
Equity Companies
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Average production costs, per oil-equivalent barrel - total
Total
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Bitumen, per barrel
Synthetic oil, per barrel
Average production costs, per oil-equivalent barrel - total
Average production costs, per barrel - bitumen
Average production costs, per barrel - synthetic oil
United
States
Canada/
Other
Americas Europe
Africa
(dollars per unit)
Asia
Australia/
Oceania
Total
37.26
10.34
1.56
17.71
37.32
18.40
19.22
33.61
—
—
—
—
37.26
10.34
1.56
17.71
37.32
18.40
19.22
33.61
59.39
16.59
1.44
36.25
56.18
23.41
24.18
40.38
—
—
—
—
59.39
16.59
1.44
36.25
56.18
23.41
24.18
40.38
41.39
20.11
3.13
—
—
21.22
—
—
38.95
—
3.85
30.74
41.11
20.11
3.44
—
—
24.76
—
—
63.59
30.56
4.50
—
—
13.69
—
—
58.72
—
5.01
14.04
63.41
30.56
4.73
—
—
13.80
—
—
42.27
21.32
1.24
—
—
16.67
—
—
—
—
—
—
42.27
21.32
1.24
—
—
16.73
—
—
65.64
41.41
1.49
—
—
17.51
—
—
—
—
—
—
65.64
41.41
1.49
—
—
17.56
—
—
39.39
21.37
1.49
—
—
6.50
—
—
35.18
30.02
3.14
1.63
38.07
27.65
2.72
—
—
3.91
—
—
64.14
24.64
2.07
—
—
7.34
—
—
58.74
36.28
5.24
2.03
62.27
33.23
4.49
—
—
4.39
—
—
36.67
27.92
4.34
—
—
5.35
—
—
—
—
—
—
36.67
27.92
4.34
—
—
5.35
—
—
61.08
30.55
6.26
—
—
6.60
—
—
—
—
—
—
61.08
30.55
6.26
—
—
6.60
—
—
38.31
16.05
2.01
17.71
37.32
11.57
19.22
33.61
35.97
29.58
3.20
5.49
37.95
19.16
2.43
17.71
37.32
10.24
19.22
33.61
61.04
22.85
3.05
36.25
56.18
13.43
24.18
40.38
59.15
35.76
5.17
5.16
60.73
25.89
3.82
36.25
56.18
11.51
24.18
40.38
34.97
13.83
0.98
—
—
9.82
—
—
39.10
11.05
1.19
27.39
35.35
13.80
0.98
—
—
10.66
—
—
54.41
18.94
1.54
—
—
12.25
—
—
60.95
15.63
1.75
28.17
55.08
18.90
1.54
—
—
13.08
—
—
10
During 2018
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Bitumen, per barrel
Synthetic oil, per barrel
Average production costs, per oil-equivalent barrel - total
Average production costs, per barrel - bitumen
Average production costs, per barrel - synthetic oil
Equity Companies
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Average production costs, per oil-equivalent barrel - total
Total
Average production prices
Crude oil, per barrel
NGL, per barrel
Natural gas, per thousand cubic feet
Bitumen, per barrel
Synthetic oil, per barrel
Average production costs, per oil-equivalent barrel - total
Average production costs, per barrel - bitumen
Average production costs, per barrel - synthetic oil
United
States
Canada/
Other
Americas Europe
Africa
(dollars per unit)
Asia
Australia/
Oceania
Total
59.84
30.78
2.14
—
—
11.64
—
—
66.30
27.16
2.19
24.71
60.61
30.72
2.14
—
—
12.43
—
—
64.53
37.27
1.68
28.66
54.85
24.32
22.93
45.33
69.80
38.53
6.97
—
—
13.07
—
—
70.84
47.10
1.96
—
—
17.28
—
—
69.86
26.30
2.33
—
—
7.31
—
—
66.89
36.34
6.39
—
—
6.94
—
—
66.91
32.88
3.87
28.66
54.85
13.34
22.93
45.33
—
—
—
—
63.92
—
5.03
16.30
—
—
—
—
67.31
45.10
6.31
1.49
—
—
—
—
67.07
44.64
6.01
4.96
64.53
37.27
1.68
28.66
54.85
24.32
22.93
45.33
69.57
38.53
6.11
—
—
14.06
—
—
70.84
47.10
1.96
—
—
17.31
—
—
68.92
39.69
5.38
—
—
3.98
—
—
66.89
36.34
6.39
—
—
6.94
—
—
66.93
35.85
4.67
28.66
54.85
11.29
22.93
45.33
Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor.
Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural
gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The volumes of
natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The
natural gas available for sale volumes are different from those shown in the reserves table in the “Oil and Gas Reserves” part of the
“Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report due
to volumes consumed or flared. Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
11
4. Drilling and Other Exploratory and Development Activities
A. Number of Net Productive and Dry Wells Drilled
2020
2019
2018
4
2
—
1
—
—
7
—
—
—
—
—
7
—
1
—
—
1
—
2
—
—
—
—
—
2
3
6
1
—
—
1
11
—
—
—
—
—
11
—
1
1
—
—
1
3
—
—
—
—
—
3
1
4
—
1
—
1
7
—
—
—
—
—
7
3
—
1
—
—
2
6
—
—
—
—
—
6
Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Africa
Asia
Total Equity Companies
Total productive exploratory wells drilled
Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Africa
Asia
Total Equity Companies
Total dry exploratory wells drilled
12
Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Africa
Asia
Total Equity Companies
Total productive development wells drilled
Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Africa
Asia
Total Equity Companies
Total dry development wells drilled
2020
2019
2018
412
36
2
2
15
4
471
60
1
—
5
66
537
6
—
—
—
—
1
7
—
—
—
—
—
7
618
49
3
4
12
—
686
199
—
—
9
208
894
8
—
—
1
—
—
9
—
—
—
—
—
9
389
32
3
1
14
—
439
168
3
—
6
177
616
4
1
—
1
—
—
6
—
—
—
—
—
6
Total number of net wells drilled
553
917
635
13
B. Exploratory and Development Activities Regarding Oil and Gas Resources Extracted by Mining Technologies
Syncrude Operations. Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods
to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial
Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial
Oil Limited. In 2020, the company’s share of net production of synthetic crude oil was about 68 thousand barrels per day and share of
net acreage was about 55 thousand acres in the Athabasca oil sands deposit.
Kearl Operations. Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to
extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties
holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest
in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 49 thousand acres in the Athabasca oil
sands deposit.
Kearl is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sands and processed
through bitumen extraction and froth treatment trains. The product, a blend of bitumen and diluent, is shipped to our refineries and to
other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation
by pipeline and rail. During 2020, average net production at Kearl was about 219 thousand barrels per day.
Primarily as a result of very low prices during 2020, under the SEC definition of proved reserves, the entire 3.1 billion barrels of
bitumen at Kearl did not qualify as proved reserves at year-end 2020. Among the factors that could result in portions of these amounts
being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, cost reductions, and/or
operating efficiencies.
5. Present Activities
A. Wells Drilling
Wells Drilling
Consolidated Subsidiaries
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Africa
Asia
Total Equity Companies
Total gross and net wells drilling
Year-End 2020
Year-End 2019
Gross
Net
Gross
Net
1,206
38
13
14
14
—
1,285
3
1
6
2
12
1,297
741
29
6
3
4
—
783
1
1
1
1
4
1,133
27
16
4
46
14
1,240
3
—
6
11
20
704
20
7
1
14
4
750
1
—
1
3
5
787
1,260
755
14
B. Review of Principal Ongoing Activities
UNITED STATES
ExxonMobil’s year-end 2020 acreage holdings totaled 11.2 million net acres, of which 0.4 million net acres were offshore.
ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. Development activities continued on the
Golden Pass liquefied natural gas export project.
During the year, 478.9 net exploration and development wells were completed in the inland lower 48 states. Development activities
focused on liquids-rich opportunities in the onshore U.S., primarily in the Permian Basin of West Texas and New Mexico.
ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2020 was 0.3 million acres. A total of 0.9 net development wells were
completed during the year.
Participation in Alaska production and development continued with a total of 2.7 net development wells completed.
CANADA / OTHER AMERICAS
Canada
Oil and Gas Operations: ExxonMobil’s year-end 2020 acreage holdings totaled 7.4 million net acres, of which 4.6 million net acres
were offshore. A total of 6.1 net exploration and development wells were completed during the year.
In Situ Bitumen Operations: ExxonMobil’s year-end 2020 in situ bitumen acreage holdings totaled 0.6 million net onshore acres. A
total of 28 net development wells at Cold Lake were completed during the year.
Argentina
ExxonMobil’s net acreage totaled 2.9 million acres, of which 2.6 million net acres were offshore at year-end 2020. During the year, a
total of 1.8 net development wells were completed.
Guyana
ExxonMobil’s net acreage totaled 4.6 million offshore acres at year-end 2020. During the year, 2.4 net exploration and development
wells were completed. Development activities continued on the Liza Phase 2 project, and the Payara project was funded in 2020.
EUROPE
Germany
ExxonMobil’s net acreage totaled 1.7 million onshore acres at year-end 2020. During the year, 0.8 net exploration and development
wells were completed.
Netherlands
ExxonMobil’s net interest in licenses totaled approximately 1.4 million acres, of which 1.0 million acres were onshore at year-end
2020. During the year, a total of 1.3 net exploration and development wells were completed. In 2020, the Dutch Government further
reduced Groningen gas extraction and maintained its plan to terminate Groningen production in 2022.
United Kingdom
ExxonMobil’s net interest in licenses totaled approximately 0.3 million offshore acres at year-end 2020. During the year, a total of 1.9
net development wells were completed. Development activities continued on the Penguins Redevelopment project.
15
AFRICA
Angola
ExxonMobil’s net acreage totaled approximately 3.0 million acres, of which 2.9 million net acres were offshore at year-end 2020.
During the year, a total of 0.3 net development wells were completed. In 2020, ExxonMobil acquired approximately 2.7 million net
acres in three offshore blocks located in the Namibe basin.
Chad
ExxonMobil’s net acreage holdings totaled 46 thousand onshore acres at year-end 2020.
Equatorial Guinea
ExxonMobil’s net acreage totaled 0.5 million offshore acres at year-end 2020. During the year, a total of 0.8 net development well was
completed.
Mozambique
ExxonMobil’s net acreage totaled approximately 1.8 million offshore acres at year-end 2020. Development activities continued on the
Coral South Floating LNG project during the year.
Nigeria
ExxonMobil’s net acreage totaled 0.9 million offshore acres at year-end 2020. During the year, a total of 1.8 net exploration and
development wells were completed.
ASIA
Azerbaijan
ExxonMobil's net acreage totaled 7 thousand offshore acres at year-end 2020. During the year, a total of 0.7 net development wells
were completed.
Indonesia
ExxonMobil’s net acreage totaled 0.1 million onshore acres at year-end 2020.
Iraq
ExxonMobil’s net acreage totaled 0.1 million onshore acres at year-end 2020. During the year, a total of 8.2 net development wells
were completed at the West Qurna Phase I oil field. Oil field rehabilitation activities continued during 2020 and across the life of this
project will include drilling of new wells, working over of existing wells, and optimization, debottlenecking and expansion of
facilities. In the Kurdistan Region of Iraq, ExxonMobil has continued exploration activities.
Kazakhstan
ExxonMobil’s net acreage totaled 0.3 million acres, of which 0.2 million net acres were offshore at year-end 2020. During the year, a
total of 4.5 net development wells were completed. Development activities continued on the Tengiz Expansion project.
Malaysia
ExxonMobil’s interests in production sharing contracts covered 0.2 million net acres offshore at year-end 2020. During the year, a
total of 2.0 net development wells were completed. In 2020, ExxonMobil relinquished approximately 2.3 million net acres in three
Sabah offshore blocks.
Qatar
Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2020.
ExxonMobil participated in 62.2 million tonnes per year gross liquefied natural gas capacity and 3.4 billion cubic feet per day of
flowing gas capacity at year-end. During the year, a total of 0.3 net development well was completed. The Barzan project started up in
2020.
16
Russia
ExxonMobil’s net acreage holdings in Sakhalin totaled 85 thousand offshore acres at year-end 2020. During the year, a total of 2.7 net
exploration and development wells were completed.
Thailand
ExxonMobil’s net onshore acreage in Thailand concessions totaled 16 thousand acres at year-end 2020. During the year, a total of 0.5
net exploration and development wells were completed.
United Arab Emirates
ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2020. During
the year, a total of 1.7 net development wells were completed. The Upper Zakum 750 project started up in 2020 while commissioning
continued on the final systems. Development activities continued on the Upper Zakum 1 MBD project.
AUSTRALIA / OCEANIA
Australia
ExxonMobil’s net acreage totaled 1.8 million acres offshore and 10 thousand acres onshore at year-end 2020. During the year, a total
of 3.8 net development wells were completed. Development activities continued on the West Barracouta project during the year.
The co-venturer-operated Gorgon Jansz liquefied natural gas (LNG) development consists of a subsea infrastructure for offshore
production and transportation of the gas, a 15.6 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas
plant located on Barrow Island, Western Australia. Development activities continued on the Gorgon Stage 2 project during the year.
Papua New Guinea
ExxonMobil’s net acreage totaled 5.5 million acres, of which 3.3 million net acres were offshore at year-end 2020. During the year, a
total of 0.8 net exploration and development wells were completed. In 2020, ExxonMobil relinquished approximately 1.4 million net
onshore acres. The Papua New Guinea (PNG) liquefied natural gas integrated development includes gas production and processing
facilities in the southern PNG Highlands, onshore and offshore pipelines, and a 6.9 million tonnes per year liquefied natural gas
facility near Port Moresby.
WORLDWIDE EXPLORATION
At year-end 2020, exploration activities were under way in several areas in which ExxonMobil has no established production
operations and thus are not included above. A total of 29.8 million net acres were held at year-end 2020 and 0.7 net exploration wells
were completed during the year in these countries.
6. Delivery Commitments
ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which
may specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural
gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own production and the
spot market. Worldwide, we are contractually committed to deliver approximately 31 million barrels of oil and 2,600 billion cubic feet
of natural gas for the period from 2021 through 2023. We expect to fulfill the majority of these delivery commitments with production
from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped
reserves and purchases on the open market as necessary.
17
7. Oil and Gas Properties, Wells, Operations and Acreage
A. Gross and Net Productive Wells
Gross and Net Productive Wells
Consolidated Subsidiaries
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Asia
Total Equity Companies
Total gross and net productive wells
Year-End 2020
Year-End 2019
Oil
Gas
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
Gross
Net
19,631
4,754
559
1,141
974
540
27,599
7,878
4,644
126
432
310
102
13,492
20,480
3,276
487
26
132
90
24,491
12,195
1,275
221
10
78
38
13,817
20,559
4,905
741
1,191
943
582
28,921
8,502
4,724
207
456
301
120
14,310
21,893
3,441
517
13
133
87
26,084
13,182
1,347
236
5
79
36
14,885
12,368
57
217
12,642
40,241
4,851
20
54
4,925
18,417
4,223
552
157
4,932
29,423
417
172
32
621
14,438
12,947
57
194
13,198
42,119
5,328
20
49
5,397
19,707
4,500
561
126
5,187
31,271
577
175
30
782
15,667
There were 25,595 gross and 22,239 net operated wells at year-end 2020 and 27,532 gross and 23,857 net operated wells at year-end
2019. The number of wells with multiple completions was 1,067 gross in 2020 and 1,023 gross in 2019.
18
B. Gross and Net Developed Acreage
Gross and Net Developed Acreage
Consolidated Subsidiaries
United States
Canada/Other Americas (1)
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Asia
Total Equity Companies
Total gross and net developed acreage
Year-End 2020
Year-End 2019
Gross
Net
Gross
Net
(thousands of acres)
12,834
2,944
2,231
2,409
1,938
3,262
25,618
928
3,667
701
5,296
30,914
7,971
2,071
1,189
818
561
1,068
13,678
208
1,118
160
1,486
15,164
13,283
3,020
2,229
2,409
1,938
3,262
26,141
926
4,069
628
5,623
31,764
8,097
2,100
1,182
832
561
1,068
13,840
207
1,280
155
1,642
15,482
(1) Includes developed acreage in Other Americas of 490 gross and 311 net thousands of acres for 2020 and 472 gross and 295 net
thousands of acres for 2019.
Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.
C. Gross and Net Undeveloped Acreage
Gross and Net Undeveloped Acreage
Consolidated Subsidiaries
United States
Canada/Other Americas (1)
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
Europe
Africa
Asia
Total Equity Companies
Total gross and net undeveloped acreage
Year-End 2020
Year-End 2019
Gross
Net
Gross
Net
(thousands of acres)
6,969
37,833
14,802
35,956
888
12,971
109,419
160
765
596
—
1,521
110,940
2,967
18,985
6,018
24,558
280
6,265
59,073
64
214
149
—
427
59,500
7,123
36,509
18,212
56,049
6,880
14,773
139,546
189
366
596
73
1,224
140,770
3,146
17,950
7,619
32,449
2,911
7,689
71,764
73
105
149
5
332
72,096
(1) Includes undeveloped acreage in Other Americas of 26,084 gross and 12,471 net thousands of acres for 2020 and 25,327 gross
and 12,065 net thousands of acres for 2019.
19
ExxonMobil’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks, and leases. The terms
and conditions under which the Corporation maintains exploration and/or production rights to the acreage are property-specific,
contractually defined, and vary significantly from property to property. Work programs are designed to ensure that the exploration
potential of any property is fully evaluated before expiration. In some instances, the Corporation may elect to relinquish acreage in
advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases
where additional time may be required to fully evaluate acreage, the Corporation has generally been successful in obtaining
extensions. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to
have a material adverse impact on the Corporation.
D. Summary of Acreage Terms
UNITED STATES
Oil and gas exploration and production rights are acquired from mineral interest owners through a lease. Mineral interest owners
include the Federal and State governments, as well as private mineral interest owners. Leases typically have an exploration period
ranging from one to ten years, and a production period that normally remains in effect until production ceases. Under certain
circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances regarding
private property, a “fee interest” is acquired where the underlying mineral interests are owned outright.
CANADA / OTHER AMERICAS
Canada
Exploration licenses or leases in onshore areas are acquired for varying periods of time with renewals or extensions possible. These
licenses or leases entitle the holder to continue existing licenses or leases upon completing specified work. In general, these license
and lease agreements are held as long as there is proven production capability on the licenses and leases. Exploration licenses in
offshore eastern Canada and the Beaufort Sea are held by work commitments of various amounts and rentals. They are valid for a term
of nine years. Offshore production licenses are valid for 25 years, with rights of extension for continued production. Significant
discovery licenses in the offshore, relating to currently undeveloped discoveries, do not have a definite term.
Argentina
The Federal Hydrocarbon Law was amended in 2014. Pursuant to the amended law, the production term for an onshore
unconventional concession is 35 years, and 25 years for a conventional concession, with unlimited 10-year extensions possible, once a
field has been developed. In 2019, the government granted three offshore exploration licenses, with terms of eight years, divided into
two exploration periods of four years, with an optional extension of five years for each license. Two onshore exploration concessions
were initially granted prior to the amendment and are governed under Provincial Law with expiration terms through 2024.
Guyana
The Petroleum (Exploration and Production) Act authorizes the government of Guyana to grant petroleum prospecting and production
licenses and to enter into petroleum agreements for the exploration and production of hydrocarbons. Petroleum agreements provide for
an exploration period of up to 10 years and a production period of 20 years, with a 10-year extension.
EUROPE
Germany
Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions up to three
years each. Extensions are subject to specific minimum work commitments. Production licenses are normally granted for 20 to 25
years with multiple possible extensions subject to production on the license.
Netherlands
Under the Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued
for a period as explicitly defined in the license. The term is based on the period of time necessary to perform the activities for which
the license is issued. License conditions are stipulated in the license and are based on the Mining Law.
Production rights granted prior to January 1, 2003, remain subject to their existing terms, and differ slightly for onshore and offshore
areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined
in the license, ranging from 35 to 45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years;
from 1976 they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years.
20
United Kingdom
Acreage terms are fixed by the government and are periodically changed. For example, many of the early licenses issued under the
first four licensing rounds provided an initial term of six years with relinquishment of at least one-half of the original area at the end of
the initial term, subject to extension for a further 40 years. At the end of any such 40-year term, licenses may continue in producing
areas until cessation of production; or licenses may continue in development areas for periods agreed on a case-by-case basis until they
become producing areas; or licenses terminate in all other areas. The majority of traditional licenses currently issued have an initial
exploration term of four years with a second term extension of four years, and a final production term of 18 years, with a mandatory
relinquishment of 50 percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end
of the second term.
Terms for exploration acreage in technically challenged areas are governed by frontier production licenses, generally covering a larger
initial area than traditional licenses, with an initial exploration term of six or nine years with a second term extension of six years, and
a final production term of 18 years, with relinquishment of 75 percent of the original area after three years and 50 percent of the
remaining acreage after the next three years. Innovate licenses issued replace traditional and frontier licenses and offer greater
flexibility with respect to periods and work program commitments.
AFRICA
Angola
Exploration and production activities are governed by either production sharing agreements or other contracts with initial exploration
terms ranging from three to four years with options to extend from one to five years. The production periods range from 20 to 30
years, and the agreements generally provide for negotiated extensions.
Chad
Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and
conditions of the permits, including relinquishment obligations, are specified in a negotiated convention. The production term is 30
years and in 2017 was extended by 20 years to 2050.
Equatorial Guinea
Exploration, development and production activities are governed by production sharing contracts (PSCs) negotiated with the State
Ministry of Mines and Hydrocarbons. A new PSC was ratified in 2018; the initial exploration period is five years for oil and gas, with
multi-year extensions available at the discretion of the Ministry and limited relinquishments in the absence of commercial discoveries.
The production period for crude oil ranges from 25 to 30 years, while the production period for natural gas ranges from 25 to 50 years.
Mozambique
Exploration and production activities are generally governed by concession contracts with the Government of the Republic of
Mozambique, represented by the Ministry of Mineral Resources and Energy. An interest in Area 4 offshore Mozambique was acquired
in 2017. Terms for Area 4 are governed by the Exploration and Production Concession Contract (EPCC) for Area 4 Offshore of the
Rovuma Block. The EPCC expires 30 years after an approved plan of development becomes effective for a given discovery area.
In 2018, an interest was acquired in offshore blocks, A5-B, Z5-C and Z5-D. Terms for the three blocks are governed by their
respective EPCCs, which have an initial exploration phase that expires in 2022 with the possibility of two additional exploration
phases expiring in 2024 and 2026. The EPCCs provide a development and production period that expires 30 years after the approval
of a plan of development.
Nigeria
Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs)
with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC typically holds the underlying Oil
Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a 10-
year exploration period (an initial exploration phase that can be divided into multiple optional periods) covered by an OPL. Upon
commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the 10-
year exploration period, and OMLs have a 20-year production period that may be extended.
Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in
deepwater offshore areas are valid for 10 years, while in all other areas the licenses are for five years. Demonstrating a commercial
discovery is the basis for conversion of an OPL to an OML.
21
OMLs granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) were for
30 years onshore and 40 years in offshore areas and have been renewed, effective December 1, 2008, for a further period of 20 years,
with a further renewal option of 20 years. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with
NNPC rather than a PSC. Commercial terms applicable to the existing joint venture oil production are defined by the Petroleum
Profits Tax Act.
OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without
distinction for onshore or offshore location and are renewable, upon 12-months written notice, for another period of 20 years. OMLs
not held by NNPC are also subject to a mandatory 50-percent relinquishment after the first 10 years of their duration.
ASIA
Azerbaijan
The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field was established for an initial period
of 30 years starting from the PSA execution date in 1994. The PSA was amended in September 2017 to extend the term by 25 years to
2049.
Other exploration and production activities are governed by PSAs negotiated with the national oil company of Azerbaijan. The
exploration period typically consists of three or four years with the possibility of a one to three-year extension. The production period,
which includes development, is for 25 years or 35 years with the possibility of one or two five-year extensions.
Indonesia
Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production
sharing contract (PSC), negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas
activities. In 2012, Indonesia’s Constitutional Court ruled certain articles of law relating to BPMIGAS to be unconstitutional, but
stated that all existing PSCs signed with BPMIGAS should remain in force until their expiry, and the functions and duties previously
performed by BPMIGAS are to be carried out by the relevant Ministry of the Government of Indonesia until the promulgation of a
new oil and gas law. By presidential decree, SKKMIGAS became the interim successor to BPMIGAS. The current PSCs have an
exploration period of six years, which can be extended up to 10 years, and an exploitation period of 20 years. PSCs generally require
the contractor to relinquish 10 to 20 percent of the contract area after three years and generally allow the contractor to retain no more
than 50 to 80 percent of the original contract area after six years, depending on the acreage and terms.
Iraq
Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of
the Iraqi Ministry of Oil. An ExxonMobil affiliate entered into a contract with Basra Oil Company of the Iraqi Ministry of Oil for the
rights to participate in the development and production activities of the West Qurna Phase I oil and gas field effective March 1, 2010.
The term of the contract is 20 years with the right to extend for five years. The contract provides for cost recovery plus per-barrel fees
for incremental production above specified levels.
Exploration and production activities in the Kurdistan Region of Iraq are governed by production sharing contracts (PSCs) negotiated
with the regional government of Kurdistan in 2011. The exploration term is for five years, with extensions available as provided by the
PSCs and at the discretion of the regional government of Kurdistan. Current PSCs remain in effect by agreement of the regional
government to allow additional time for exploration or evaluation of commerciality. The production period is 20 years with the right to
extend for five years.
Kazakhstan
Onshore exploration and production activities are governed by the production license, exploration license, and joint venture
agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that
commenced in 1993.
Offshore exploration and production activities are governed by a production sharing agreement negotiated with the Republic of
Kazakhstan. The exploration period is six years followed by separate appraisal periods for each discovery. The production period for
each discovery, which includes development, is 20 years from the date of declaration of commerciality with the possibility of two 10-
year extensions.
Malaysia
Production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The PSCs have
production terms of 25 years. Extensions are generally subject to the national oil company’s prior written approval.
22
Qatar
The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit
the economic development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects.
Russia
Terms for ExxonMobil’s Sakhalin acreage are fixed by the current production sharing agreement between the Russian government and
the Sakhalin-1 consortium, of which ExxonMobil is the operator.
Thailand
The Petroleum Act of 1971 allows production under ExxonMobil’s concessions for 30 years with a 10-year extension at terms
generally prevalent at the time. The term of one of the two concessions expires in 2021.
United Arab Emirates
An interest in the development and production activities of the offshore Upper Zakum field was acquired in 2006. In 2017, the
governing agreements were extended to 2051.
AUSTRALIA / OCEANIA
Australia
Exploration and production activities conducted offshore in Commonwealth waters are governed by Federal legislation. Exploration
permits are granted for an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for
resources that are not commercially viable at the time of application, but are expected to become commercially viable within 15 years.
These are granted for periods of five years and renewals may be requested. Prior to July 1998, production licenses were granted
initially for 21 years, with a further renewal of 21 years and thereafter indefinitely, i.e., for the life of the field. Effective from July
1998, new production licenses are granted indefinitely. In each case, a production license may be terminated if no production
operations have been carried on for five years.
Papua New Guinea
Exploration and production activities are governed by the Oil and Gas Act. Petroleum prospecting licenses are granted for an initial
term of six years with a five-year extension possible (an additional extension of three years is possible in certain circumstances).
Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum
development licenses are granted for an initial 25-year period. An extension of up to 20 years may be granted at the Minister’s
discretion. Petroleum retention licenses may be granted for gas resources that are not commercially viable at the time of application,
but may become commercially viable within the maximum possible retention time of 15 years. Petroleum retention licenses are
granted for five-year terms, and may be extended, at the Minister’s discretion, twice for the maximum retention time of 15 years.
Extensions of petroleum retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at
the time of extension that the resources could become commercially viable in less than five years.
23
Information with regard to the Downstream segment follows:
ExxonMobil’s Downstream segment manufactures, trades and sells petroleum products. The refining and supply operations
encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels,
lubricants and other products and feedstocks to our customers around the world.
Refining Capacity At Year-End 2020 (1)
ExxonMobil
Share KBD (2)
ExxonMobil
Interest %
United States
Joliet
Baton Rouge
Billings
Baytown
Beaumont
Total United States
Canada
Strathcona
Nanticoke
Sarnia
Total Canada
Europe
Antwerp
Fos-sur-Mer
Gravenchon
Karlsruhe
Trecate
Rotterdam
Slagen
Fawley
Total Europe
Asia Pacific
Altona (3)
Fujian
Jurong/PAC
Sriracha
Total Asia Pacific
Middle East
Yanbu
Total Worldwide
Illinois
Louisiana
Montana
Texas
Texas
Alberta
Ontario
Ontario
Belgium
France
France
Germany
Italy
Netherlands
Norway
United Kingdom
Australia
China
Singapore
Thailand
Saudi Arabia
254
520
60
561
369
1,764
196
113
119
428
307
133
244
78
132
192
116
262
1,464
88
67
592
167
914
100
100
100
100
100
69.6
69.6
69.6
100
82.9
82.9
25
75.2
100
100
100
100
25
100
66
200
50
4,770
(1) Capacity data is based on 100 percent of rated refinery process unit stream-day capacities under normal operating conditions,
less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time. The listing
excludes refining capacity for a minor interest held through equity securities in New Zealand, and the Laffan Refinery in Qatar
for which results are reported in the Upstream segment.
(2) Thousands of barrels per day (KBD). ExxonMobil share reflects 100 percent of atmospheric distillation capacity in operations of
ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, ExxonMobil share is the greater of
ExxonMobil’s interest or that portion of distillation capacity normally available to ExxonMobil.
(3) The Corporation expects to convert the Altona refinery into a terminal in 2021.
24
The marketing operations sell products and services throughout the world through our Exxon, Esso and Mobil brands.
Retail Sites At Year-End 2020
—
10,982
10,982
—
2,370
2,370
197
5,764
5,961
569
1,243
1,812
—
411
411
225
192
417
991
20,962
21,953
United States
Owned/leased
Distributors/resellers
Total United States
Canada
Owned/leased
Distributors/resellers
Total Canada
Europe
Owned/leased
Distributors/resellers
Total Europe
Asia Pacific
Owned/leased
Distributors/resellers
Total Asia Pacific
Latin America
Owned/leased
Distributors/resellers
Total Latin America
Middle East/Africa
Owned/leased
Distributors/resellers
Total Middle East/Africa
Worldwide
Owned/leased
Distributors/resellers
Total Worldwide
25
Information with regard to the Chemical segment follows:
ExxonMobil’s Chemical segment manufactures and sells petrochemicals. The Chemical business supplies olefins, polyolefins,
aromatics, and a wide variety of other petrochemicals.
Chemical Complex Capacity At Year-End 2020 (1)
Ethylene
Polyethylene
Polypropylene Paraxylene
ExxonMobil
Interest %
(millions of metric tons per year)
North America
Baton Rouge
Baytown
Beaumont
Mont Belvieu
Sarnia
Total North America
Europe
Antwerp
Fife
Gravenchon
Meerhout
Rotterdam
Total Europe
Middle East
Al Jubail
Yanbu
Total Middle East
Asia Pacific
Fujian
Singapore
Sriracha
Total Asia Pacific
Louisiana
Texas
Texas
Texas
Ontario
Belgium
United Kingdom
France
Belgium
Netherlands
Saudi Arabia
Saudi Arabia
China
Singapore
Thailand
1.1
3.9
0.9
—
0.3
6.2
—
0.4
0.4
—
—
0.8
0.6
1.0
1.6
0.3
1.9
—
2.2
1.3
—
1.7
2.3
0.5
5.8
0.4
—
0.4
0.5
—
1.3
0.7
0.7
1.4
0.2
1.9
—
2.1
Total Worldwide
10.8
10.6
100
100
100
100
69.6
100
50
100
100
100
50
50
25
100
66
0.4
0.7
—
—
—
1.1
—
—
0.3
—
—
0.3
—
0.2
0.2
0.2
0.9
—
1.1
2.7
—
0.6
0.3
—
—
0.9
—
—
—
—
0.7
0.7
—
—
—
0.2
1.8
0.5
2.5
4.1
(1) Capacity reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent
or less, capacity is ExxonMobil’s interest.
26
ITEM 3. LEGAL PROCEEDINGS
ExxonMobil has elected to use a $1 million threshold for disclosing environmental proceedings.
Refer to the relevant portions of “Note 16: Litigation and Other Contingencies” of the Financial Section of this report for additional
information on legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
27
Information about our Executive Officers
(positions and ages as of February 24, 2021)
Darren W. Woods
Chairman of the Board
Held current title since:
January 1, 2017
Age: 56
Mr. Darren W. Woods became a Director and President of Exxon Mobil Corporation on January 1, 2016, and Chairman of the Board
and Chief Executive Officer of Exxon Mobil Corporation on January 1, 2017, positions he continues to hold as of this filing date.
Neil A. Chapman
Senior Vice President
Held current title since:
January 1, 2018
Age: 58
Mr. Neil A. Chapman was President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation
January 1, 2015 – December 31, 2017. He became Senior Vice President of Exxon Mobil Corporation on January 1, 2018, a position
he continues to hold as of this filing date.
Andrew P. Swiger
Senior Vice President
Held current title since:
April 1, 2009
Age: 64
Mr. Andrew P. Swiger became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he continues to hold
as of this filing date.
Jack P. Williams, Jr.
Senior Vice President
Held current title since:
June 1, 2014
Age: 57
Mr. Jack P. Williams, Jr. became Senior Vice President of Exxon Mobil Corporation on June 1, 2014, a position he continues to hold
as of this filing date.
Ian S. Carr
Vice President
September 1, 2020
Held current title since:
Mr. Ian S. Carr was Vice President, Strategy and Planning, ExxonMobil Refining & Supply Company May 1, 2014 – July 31, 2017.
He was Vice President, Upstream Strategy and Planning, ExxonMobil Gas & Power Marketing Company August 1, 2017 –
March 31, 2019. He was Vice President, Strategy and Portfolio Management, ExxonMobil Upstream Business Development
Company April 1, 2019 - September 30, 2019. He was Senior Vice President, Fuels, ExxonMobil Fuels & Lubricants Company
October 1, 2019 – August 31, 2020. He became President of ExxonMobil Fuels & Lubricants Company and Vice President of Exxon
Mobil Corporation on September 1, 2020, positions he continues to hold as of this filing date.
Age: 57
Linda D. DuCharme
Vice President
President, ExxonMobil Integrated Solutions Company
July 1, 2020, and April 1, 2019, respectively
Held current title since:
Ms. Linda D. DuCharme was Vice President, Americas, Africa and Asia, ExxonMobil Gas & Power Marketing Company
July 1, 2015 – July 31, 2016. She was President of ExxonMobil Global Services Company August 1, 2016 – March 31, 2019. She
became President of ExxonMobil Upstream Integrated Solutions Company April 1, 2019, and President of ExxonMobil Upstream
Business Development Company and Vice President of Exxon Mobil Corporation on July 1, 2020, positions she continues to hold as
of this filing date.
Age: 56
Neil W. Duffin
President, ExxonMobil Global Projects Company
Held current title since:
April 1, 2019
Age: 64
Mr. Neil W. Duffin was President of ExxonMobil Development Company April 13, 2007 – December 31, 2016. He was President of
ExxonMobil Production Company and Vice President of Exxon Mobil Corporation January 1, 2017 – March 31, 2019. He became
President of ExxonMobil Global Projects Company on April 1, 2019, a position he continues to hold as of this filing date.
28
Stephen A. Littleton
Vice President – Investor Relations and Secretary
Held current title since:
Mr. Stephen A. Littleton was Assistant Controller of Exxon Mobil Corporation June 1, 2015 - April 30, 2018. He was Vice
President, Downstream Business Services and Downstream Controller May 1, 2018 - March 14, 2020. He became Vice President –
Investor Relations and Secretary of Exxon Mobil Corporation on March 15, 2020, positions he continues to hold as of this filing date.
March 15, 2020
Age: 55
Liam M. Mallon
Vice President
Held current title since:
Mr. Liam M. Mallon was Executive Vice President, ExxonMobil Development Company February 1, 2014 – December 31, 2016. He
was President of ExxonMobil Development Company January 1, 2017 – March 31, 2019. He became President of ExxonMobil
Upstream Oil & Gas Company and Vice President of Exxon Mobil Corporation on April 1, 2019, positions he continues to hold as of
this filing date.
April 1, 2019
Age: 58
Karen T. McKee
Vice President
Held current title since:
Ms. Karen T. McKee was Vice President, Basic Chemicals, ExxonMobil Chemical Company May 1, 2014 – July 31, 2017. She was
Senior Vice President, Basic Chemicals, Integration & Growth, ExxonMobil Chemical Company August 1, 2017 – March 31, 2019.
She became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on April 1, 2019,
positions she continues to hold as of this filing date.
April 1, 2019
Age: 54
Craig S. Morford
Vice President and General Counsel
Held current title since:
Mr. Craig S. Morford was Chief Legal and Compliance Officer of Cardinal Heath, Inc. prior to joining Exxon Mobil Corporation in
May 2019. He was Deputy General Counsel of Exxon Mobil Corporation May 1, 2019 - October 31, 2020. He became Vice
President and General Counsel of Exxon Mobil Corporation on November 1, 2020, positions he continues to hold as of this filing
date.
November 1, 2020
Age: 62
David S. Rosenthal
Vice President and Controller
Held current title since:
October 1, 2008 (Vice President)
September 1, 2014 (Controller)
Age: 64
Mr. David S. Rosenthal was Vice President – Investor Relations and Secretary of Exxon Mobil Corporation October 1, 2008 –
August 31, 2014. He became Vice President and Controller of Exxon Mobil Corporation on September 1, 2014, positions he
continues to hold as of this filing date.
James M. Spellings, Jr.
Vice President – Treasurer and General Tax Counsel
Held current title since:
March 1, 2010 (Vice President and General Tax Counsel)
April 1, 2020 (Treasurer)
Age: 59
Mr. James M. Spellings, Jr. became Vice President and General Tax Counsel of Exxon Mobil Corporation March 1, 2010 and
Treasurer of Exxon Mobil Corporation on April 1, 2020, positions he continues to hold as of this filing date.
Theodore J. Wojnar, Jr.
Vice President – Corporate Strategic Planning
Held current title since:
August 1, 2017
Age: 61
Mr. Theodore J. Wojnar, Jr. was President of ExxonMobil Research and Engineering Company April 1, 2011 – July 31, 2017. He
became Vice President – Corporate Strategic Planning of Exxon Mobil Corporation on August 1, 2017, a position he continues to
hold as of this filing date.
Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such
officer serving until a successor has been elected and qualified. The above-named officers are required to file reports under Section 16
of the Securities Exchange Act of 1934.
29
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is
traded on other exchanges in and outside the United States.
There were 343,633 registered shareholders of ExxonMobil common stock at December 31, 2020. At January 31, 2021, the registered
shareholders of ExxonMobil common stock numbered 341,925.
On January 27, 2021, the Corporation declared an $0.87 dividend per common share, payable March 10, 2021.
Reference is made to Item 12 in Part III of this report.
Issuer Purchases of Equity Securities for Quarter Ended December 31, 2020
Period
October 2020
November 2020
December 2020
Total
Average Price Paid
per Share
Total Number of
Shares Purchased
-
-
-
—
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs
-
-
-
—
Maximum Number
of Shares that May
Yet be Purchased
Under the Plans or
Programs
(See Note 1)
During the fourth quarter, the Corporation did not purchase any shares of its common stock for the treasury, and did not issue or sell
any unregistered equity securities.
Note 1 - In its earnings release dated February 2, 2021, the Corporation stated that it had suspended its first quarter 2021 anti-dilutive
share repurchase program due to market uncertainty and intends to resume this program in the future as market conditions improve.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations”
in the Financial Section of this report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to the section entitled “Market Risks, Inflation and Other Uncertainties”, excluding the part entitled “Inflation and
Other Uncertainties”, in the Financial Section of this report. All statements, other than historical information incorporated in this Item
7A, are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things,
factors discussed in this report.
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to the following in the Financial Section of this report:
•
•
•
Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 24,
2021, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing
through “Note 20: Restructuring Activities”;
“Supplemental Information on Oil and Gas Exploration and Production Activities” (unaudited); and
“Frequently Used Terms” (unaudited).
Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the
consolidated financial statements or notes thereto.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Management’s Evaluation of Disclosure Controls and Procedures
As indicated in the certifications in Exhibit 31 of this report, the Corporation’s Chief Executive Officer, Principal Financial Officer
and Principal Accounting Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2020.
Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in
ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities
Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding
required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the
time periods specified in the Securities and Exchange Commission’s rules and forms.
Management’s Report on Internal Control Over Financial Reporting
Management, including the Corporation’s Chief Executive Officer, Principal Financial Officer and Principal Accounting Officer, is
responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management
conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based
on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of
December 31, 2020.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s
internal control over financial reporting as of December 31, 2020, as stated in their report included in the Financial Section of this
report.
Changes in Internal Control Over Financial Reporting
There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially
affect, the Corporation’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
31
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Reference is made to the section of this report titled “Information about our Executive Officers”.
Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2021 annual meeting of shareholders
(the “2021 Proxy Statement”):
•
•
•
•
The section entitled “Election of Directors”;
The portion entitled “Delinquent Section 16(a) Reports” of the section entitled “Director and Executive Officer Stock
Ownership”;
The portions entitled “Director Qualifications”, “Director Nomination Process and Board Succession”, and “Code of Ethics
and Business Conduct” of the section entitled “Corporate Governance”; and
The “Audit Committee” portion, “Director Independence” portion, and the membership table of the portions entitled
“Board Meetings and Annual Meeting Attendance” and “Board Committees” of the section entitled “Corporate
Governance”.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference to the sections entitled “Director Compensation”, “Compensation Committee Report”, “Compensation
Discussion and Analysis”, “Executive Compensation Tables”, and “Pay Ratio” of the registrant’s 2021 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required under Item 403 of Regulation S-K is incorporated by reference to the sections “Director and Executive
Officer Stock Ownership” and “Certain Beneficial Owners” of the registrant’s 2021 Proxy Statement.
Equity Compensation Plan Information
Plan Category
Equity compensation plans approved by security holders
(a)
(b)
(c)
Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
42,714,580
(1)
Weighted-
Average
Exercise Price of
Outstanding
Options,
Warrants and
Rights
—
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
[Excluding Securities
Reflected in Column (a)]
70,944,592
(2)(3)
Equity compensation plans not approved by security holders
—
Total
42,714,580
(1) The number of restricted stock units to be settled in shares.
—
—
—
70,944,592
(2) Available shares can be granted in the form of restricted stock or other stock-based awards. Includes 70,523,392 shares
available for award under the 2003 Incentive Program and 421,200 shares available for award under the 2004 Non-
Employee Director Restricted Stock Plan.
(3) Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related
standing resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock
when first elected to the Board and, if the director remains in office, an additional 2,500 restricted shares each following
year. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of
regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director
leaves the Board early.
32
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Incorporated by reference to the portion entitled “Related Person Transactions and Procedures” of the section entitled “Director and
Executive Officer Stock Ownership”; and the portion entitled “Director Independence” of the section entitled “Corporate Governance”
of the registrant’s 2021 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section
entitled “Ratification of Independent Auditors” of the registrant’s 2021 Proxy Statement.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
(1) and (2) Financial Statements:
See Table of Contents of the Financial Section of this report.
(b) (3) Exhibits:
See Index to Exhibits of this report.
ITEM 16. FORM 10-K SUMMARY
None.
33
FINANCIAL SECTION
TABLE OF CONTENTS
Business Profile
Financial Information
Frequently Used Terms
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Functional Earnings
Forward-Looking Statements
Overview
Business Environment and Risk Assessment
Review of 2020 and 2019 Results
Liquidity and Capital Resources
Capital and Exploration Expenditures
Taxes
Environmental Matters
Market Risks, Inflation and Other Uncertainties
Restructuring Activities
Critical Accounting Estimates
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Statement of Income
Statement of Comprehensive Income
Balance Sheet
Statement of Cash Flows
Statement of Changes in Equity
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies
2. Accounting Changes
3. Miscellaneous Financial Information
4. Other Comprehensive Income Information
5. Cash Flow Information
6. Additional Working Capital Information
7. Equity Company Information
8. Investments, Advances and Long-Term Receivables
9. Property, Plant and Equipment and Asset Retirement Obligations
10. Accounting for Suspended Exploratory Well Costs
11. Leases
12. Earnings Per Share
13. Financial Instruments and Derivatives
14. Long-Term Debt
15. Incentive Program
16. Litigation and Other Contingencies
17. Pension and Other Postretirement Benefits
18. Disclosures about Segments and Related Information
19. Income and Other Taxes
20. Restructuring Activities
Supplemental Information on Oil and Gas Exploration and Production Activities
Operating Information
34
35
36
37
39
39
39
40
44
48
52
53
54
54
55
56
61
62
65
66
67
68
69
70
74
75
76
77
77
78
80
80
82
84
87
88
89
91
92
94
100
103
107
108
123
BUSINESS PROFILE
Financial
Upstream
United States
Non-U.S.
Total
Downstream
United States
Non-U.S.
Total
Chemical
United States
Non-U.S.
Total
Corporate and financing
Earnings (Loss) After
Income Taxes
Average Capital
Employed
Return on
Average Capital
Employed
Capital and
Exploration
Expenditures
2020
2019
2020
2019
2020
2019
2020
2019
(millions of dollars)
(percent)
(millions of dollars)
(19,385)
536
(645) 13,906
(20,030) 14,442
65,780
107,506
173,286
72,152
107,271
179,423
(29.5)
(0.6)
(11.6)
6,817
0.7
13.0
7,614
8.0 14,431
11,653
11,832
23,485
(852)
(225)
(1,077)
1,717
606
2,323
11,472
18,682
30,154
9,515
18,518
28,033
1,277
686
1,963
(3,296)
14,436
17,600
32,036
206
386
592
(3,017)
(1,445)
13,196
18,113
31,309
(2,162)
236,603
(7.4)
(1.2)
(3.6)
8.8
3.9
6.1
—
(9.3)
18.0
3.3
8.3
2,344
1,877
4,221
2,353
2,018
4,371
2,002
1.6
714
2.1
2,716
1.9
—
6
6.5 21,374
2,547
718
3,265
27
31,148
Total
(22,440) 14,340
234,031
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed.
Operating
Net liquids production
United States
Non-U.S.
Total
2020
2019
(thousands of barrels daily)
685
1,664
2,349
646
1,740
2,386
Refinery throughput
United States
Non-U.S.
Total
2020
2019
(thousands of barrels daily)
1,549
2,224
3,773
1,532
2,449
3,981
(millions of cubic feet daily)
(thousands of barrels daily)
Natural gas production available for sale
United States
Non-U.S.
Total
2,691
5,780
8,471
2,778
6,616
9,394
Petroleum product sales (2)
United States
Non-U.S.
Total
Oil-equivalent production (1)
(thousands of oil-equivalent barrels daily)
3,952
3,761
Chemical prime product sales (2) (3)
United States
Non-U.S.
Total
2,154
2,741
4,895
2,292
3,160
5,452
(thousands of metric tons)
9,010
16,439
25,449
9,127
17,389
26,516
(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
(2) Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty.
(3) Prime product sales are total product sales including ExxonMobil’s share of equity company volumes and finished-product
transfers to the Downstream.
35
FINANCIAL INFORMATION
Sales and other operating revenue
Earnings (Loss)
Upstream
Downstream
Chemical
Corporate and financing
Net income (loss) attributable to ExxonMobil
Earnings (Loss) per common share (dollars)
Earnings (Loss) per common share – assuming dilution (dollars)
2020
2019
2018
(millions of dollars, except where stated otherwise)
178,574
255,583
279,332
(20,030)
14,442
14,079
(1,077)
2,323
1,963
592
6,010
3,351
(3,296)
(3,017)
(2,600)
(22,440)
14,340
20,840
(5.25)
(5.25)
3.36
3.36
4.88
4.88
Earnings (Loss) to average ExxonMobil share of equity (percent)
(12.9)
7.5
11.0
Working capital
Ratio of current assets to current liabilities (times)
Additions to property, plant and equipment
Property, plant and equipment, less allowances
Total assets
Exploration expenses, including dry holes
Research and development costs
Long-term debt
Total debt
Debt to capital (percent)
Net debt to capital (percent) (1)
ExxonMobil share of equity at year-end
ExxonMobil share of equity per common share (dollars)
Weighted average number of common shares
outstanding (millions)
(11,470)
0.80
(13,937)
0.78
(9,165)
0.84
17,342
227,553
24,904
253,018
20,051
247,101
332,750
362,597
346,196
1,285
1,016
1,269
1,214
1,466
1,116
47,182
67,640
29.2
27.8
26,342
46,920
19.1
18.1
20,538
37,796
16.0
14.9
157,150
37.12
4,271
191,650
45.26
4,270
191,794
45.27
4,270
Number of regular employees at year-end (thousands) (2)
72.0
74.9
71.0
(1) Debt net of cash.
(2) Regular employees are defined as active executive, management, professional, technical and wage employees who work full time
or part time for the Corporation and are covered by the Corporation’s benefit plans and programs.
36
FREQUENTLY USED TERMS
Listed below are definitions of several of ExxonMobil’s key business and financial performance measures. These definitions are
provided to facilitate understanding of the terms and their calculation.
Cash Flow From Operations and Asset Sales
Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds associated with
sales of subsidiaries, property, plant and equipment, and sales and returns of investments from the Consolidated Statement of Cash
Flows. This cash flow reflects the total sources of cash from both operating the Corporation’s assets and from the divesting of assets.
The Corporation employs a long-standing and regular disciplined review process to ensure that assets are contributing to the
Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably
more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider proceeds associated with
asset sales together with cash provided by operating activities when evaluating cash available for investment in the business and
financing activities, including shareholder distributions.
Cash flow from operations and asset sales
Net cash provided by operating activities
Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and
returns of investments
Cash flow from operations and asset sales
2020
2019
2018
(millions of dollars)
14,668
29,716
36,014
999
15,667
3,692
33,408
4,123
40,137
Capital Employed
Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it
includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-
term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s
share of total debt and equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the
Corporation believes should be included to provide a more comprehensive measure of capital employed.
Capital employed
Business uses: asset and liability perspective
Total assets
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable
Total long-term liabilities excluding long-term debt
Noncontrolling interests share of assets and liabilities
Add ExxonMobil share of debt-financed equity company net assets
Total capital employed
Total corporate sources: debt and equity perspective
Notes and loans payable
Long-term debt
ExxonMobil share of equity
Less noncontrolling interests share of total debt
Add ExxonMobil share of equity company debt
Total capital employed
2020
2019
2018
(millions of dollars)
332,750
362,597
346,196
(35,905)
(43,411)
(39,880)
(65,075)
(73,328)
(69,992)
(8,773)
(8,839)
(7,958)
4,140
3,906
3,914
227,137
240,925
232,280
20,458
47,182
20,578
26,342
17,258
20,538
157,150
191,650
191,794
(1,793)
(1,551)
(1,224)
4,140
3,906
3,914
227,137
240,925
232,280
37
FREQUENTLY USED TERMS
Return on Average Capital Employed
Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is
annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year
amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital
employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil
excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently
applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive,
long-term industry. Additional measures, which are more cash flow based, are used to make investment decisions.
Return on average capital employed
Net income (loss) attributable to ExxonMobil
Financing costs (after tax)
Gross third-party debt
ExxonMobil share of equity companies
All other financing costs – net
Total financing costs
2020
2019
2018
(millions of dollars)
(22,440)
14,340
20,840
(1,272)
(1,075)
(182)
666
(788)
(207)
141
(1,141)
(912)
(192)
498
(606)
Earnings (Loss) excluding financing costs
(21,652)
15,481
21,446
Average capital employed
234,031
236,603
232,374
Return on average capital employed – corporate total
(9.3) %
6.5 %
9.2 %
38
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUNCTIONAL EARNINGS
Earnings (Loss) (U.S. GAAP)
Upstream
United States
Non-U.S.
Downstream
United States
Non-U.S.
Chemical
United States
Non-U.S.
Corporate and financing
Net income (loss) attributable to ExxonMobil (U.S. GAAP)
Earnings (Loss) per common share
Earnings (Loss) per common share – assuming dilution
2020
2019
2018
(millions of dollars, except per share amounts)
(19,385)
(645)
536
13,906
(852)
(225)
1,717
606
1,277
686
(3,296)
(22,440)
206
386
(3,017)
14,340
(5.25)
(5.25)
3.36
3.36
1,739
12,340
2,962
3,048
1,642
1,709
(2,600)
20,840
4.88
4.88
References in this discussion to total corporate earnings (loss) mean net income (loss) attributable to ExxonMobil (U.S. GAAP) from
the consolidated income statement. Unless otherwise indicated, references to earnings (loss), Upstream, Downstream, Chemical and
Corporate and financing segment earnings (loss), and earnings (loss) per share are ExxonMobil’s share after excluding amounts
attributable to noncontrolling interests.
FORWARD-LOOKING STATEMENTS
Outlooks, projections, goals, targets, descriptions of strategic plans and objectives, and other statements of future events or conditions
in this release are forward-looking statements. Actual future results, including energy demand growth and mix; financial and operating
performance; volume growth; project plans, timing, costs, and capacities; capital expenditures including environmental expenditures;
cost reductions; emission intensity reductions; the impact of new technologies; capital expenditures and mix; investment returns;
accounting and financial reporting effects resulting from market developments and ExxonMobil’s responsive actions, including
potential impairment charges; the benefits of business integration; future debt levels and ability to reduce debt; the outcome of
litigation and tax contingencies; and the impact of the COVID-19 pandemic on results, could differ materially due to a number of
factors. These include global or regional changes in the supply and demand for oil, natural gas, petrochemicals, and feedstocks and
other market conditions that impact prices and differentials; the impact of company actions to protect the health and safety of
employees, vendors, customers, and communities; actions of competitors and commercial counterparties; the ability to access short-
and long-term debt markets on a timely and affordable basis; the severity, length and ultimate impact of COVID-19 and government
responses on people and economies; reservoir performance; the outcome of exploration projects and timely completion of
development and construction projects; changes in law, taxes, or regulation including environmental regulations, and timely granting
of governmental permits; war, trade agreements and patterns, shipping blockades or harassment, and other political or security
disturbances; opportunities for and regulatory approval of potential investments or divestments; the actions of competitors; the capture
of efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies while
maintaining future competitive positioning; unforeseen technical or operating difficulties; the development and competitiveness of
alternative energy and emission reduction technologies; the results of research programs; the ability to bring new technologies to
commercial scale on a cost-competitive basis; general economic conditions including the occurrence and duration of economic
recessions; and other factors discussed under Item 1A. Risk Factors.
OVERVIEW
The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related
notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation.
The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and
production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products,
petrochemicals and a wide variety of specialty products.
ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to
participate in substantial investments to develop new energy supplies. The company’s integrated business model, with significant
investments in Upstream, Downstream and Chemical segments, generally reduces the Corporation’s risk from changes in commodity
prices. While commodity prices depend on supply and demand and may be volatile on a short-term basis, ExxonMobil’s investment
decisions are grounded on fundamentals reflected in our long-term business outlook, and use a disciplined approach in selecting and
pursuing the most attractive investment opportunities.
39
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The corporate plan is a fundamental annual management process that is the basis for setting operating and capital objectives in
addition to providing the economic assumptions used for investment evaluation purposes. Volume projections are based on individual
field production profiles, which are also updated at least annually. Price ranges for crude oil, natural gas, refined products, and
chemical products are based on corporate plan assumptions developed annually by major region and are utilized for investment
evaluation purposes. Major investment opportunities are evaluated over a range of potential market conditions. Once major
investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated
into future projects.
BUSINESS ENVIRONMENT AND RISK ASSESSMENT
Long-Term Business Outlook
Given the uncertainty around the near-term impacts of COVID-19 on economic growth, energy demand and energy supply, and lack
of precedent, the Company is considering a range of recovery pathways to guide near-term plans. These pathways expect that energy
demand will grow beyond 2019 levels as early as 2022 reflecting the phase out of COVID-19 impacts and re-establishment of long-
term supply/demand fundamentals. The Corporation’s Outlook for Energy combined with the near-term pathways are used to help
inform our long-term business strategies and investment plans.
By 2040, the world’s population is projected at around 9.1 billion people, or about 1.6 billion more than in 2018. Coincident with this
population increase, the Corporation expects worldwide economic growth to average close to 2.5 percent per year, with economic
output growing by around 75 percent by 2040. As economies and populations grow, and as living standards improve for billions of
people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to
rise by more than 10 percent from 2018 to 2040. This increase in energy demand is expected to be driven by developing countries (i.e.,
those that are not member nations of the Organisation for Economic Co-operation and Development (OECD)).
As expanding prosperity helps drive global energy demand higher, increasing use of energy efficient technologies and practices as
well as lower-emission products will continue to help significantly reduce energy consumption and emissions per unit of economic
output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2040, affecting energy
requirements for power generation, transportation, industrial applications, and residential and commercial needs.
Global electricity demand is expected to increase approximately 50 percent from 2018 to 2040, with developing countries likely to
account for about 85 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and
fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources. The share of coal
fired generation is likely to decline substantially and approach 20 percent of the world’s electricity in 2040, versus nearly 40 percent in
2018, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address the risks related to
climate change. From 2018 to 2040, the amount of electricity supplied using natural gas, nuclear power, and renewables is likely to
nearly double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and
solar is likely to increase about 400 percent, helping total renewables (including other sources, e.g. hydropower) to account for about
80 percent of the increase in electricity supplies worldwide through 2040. Total renewables will likely reach about 50 percent of
global electricity supplies by 2040. Natural gas and nuclear are also expected to increase shares over the period to 2040, reaching more
than 25 percent and about 10 percent of global electricity supplies respectively by 2040. Supplies of electricity by energy type will
reflect significant differences across regions reflecting a wide range of factors including the cost and availability of various energy
supplies and policy developments.
Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 20 percent from 2018
to 2040. Transportation energy demand is likely to account for over 60 percent of the growth in liquid fuels demand worldwide over
this period. Light-duty vehicle demand for liquid fuels is projected to peak prior to 2025 and then decline to levels seen in the
early-2010s by 2040 as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United
States, work to offset growth in the worldwide car fleet of about 60 percent. By 2040, light-duty vehicles are expected to account for
about 20 percent of global liquid fuels demand. During the same time period, nearly all the world’s commercial transportation fleets
are likely to continue to run on liquid fuels, which are widely available and offer practical advantages in providing a large quantity of
energy in small volumes.
Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of
transportation, and fitness as a practical solution to meet a wide variety of needs. By 2040, global demand for liquid fuels is projected
to grow to approximately 110 million barrels of oil equivalent per day, an increase of about 9 percent from 2018. The non-OECD
share of global liquid fuels demand is expected to increase to about 65 percent by 2040, as liquid fuels demand in the OECD is likely
to decline by close to 15 percent. Much of the global liquid fuels demand today is met by crude production from traditional
conventional sources; these supplies will remain important, and significant development activity is expected to offset much of the
natural declines from these fields. At the same time, a variety of emerging supply sources – including tight oil, deepwater, oil sands,
natural gas liquids and biofuels – are expected to grow to help meet rising demand. The world’s resource base is sufficient to meet
projected demand through 2040 as technology advances continue to expand the availability of economic and lower carbon supply
options. However, timely investments will remain critical to meeting global needs with reliable and affordable supplies.
40
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Natural gas is a lower-emission, versatile and practical fuel for a wide variety of applications, and it is expected to grow the most of
any primary energy type from 2018 to 2040, meeting about 50 percent of global energy demand growth. Global natural gas demand is
expected to rise about 25 percent from 2018 to 2040, with about half of that increase coming from the Asia Pacific region. Significant
growth in supplies of unconventional gas – the natural gas found in shale and other tight rock formations – will help meet these needs.
In total, about 55 percent of the growth in natural gas supplies is expected to be from unconventional sources. At the same time,
conventionally-produced natural gas is likely to remain the cornerstone of global supply, meeting more than two thirds of worldwide
demand in 2040. Liquefied natural gas (LNG) trade will expand significantly, meeting about 40 percent of the increase in global
demand growth, with much of this supply expected to help meet rising demand in Asia Pacific.
The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with
its share remaining close to 30 percent in 2040. Coal is currently the second largest source of energy, but it is likely to lose that
position to natural gas in the next few years. The share of natural gas is expected to reach more than 25 percent by 2040, while the
share of coal falls to about two thirds of the natural gas share. Nuclear power is projected to grow significantly, as many nations are
likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total
renewable energy is likely to exceed 15 percent of global energy by 2040, with biomass, hydro and geothermal contributing a
combined share of more than 10 percent. Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing
over 350 percent from 2018 to 2040, when they will likely be just over 6 percent of the world energy mix.
The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also
from increases in previously discovered fields. Technology will underpin these increases. The investments to develop and supply
resources to meet global demand through 2040 will be significant – even if demand remains flat. This reflects a fundamental aspect of
the oil and natural gas business as the International Energy Agency (IEA) describes in its World Energy Outlook 2020. According to
the IEA’s Stated Energy Policies Scenario, the investment required to meet oil and natural gas supply requirements worldwide over
the period 2019-2040 will be about $17 trillion (measured in 2019 dollars). In the IEA’s Sustainable Development Scenario, which is
in line with the objectives of the Paris Agreement on climate change, the investment need would still accumulate to $12 trillion.
International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with
uncertain timing and outcome, making it difficult to predict their business impact. For many years, the Corporation has taken into
account policies established to reduce energy-related greenhouse gas emissions in its long-term Outlook for Energy. The climate
accord reached at the Conference of the Parties (COP 21) in Paris set many new goals, and many related policies are still emerging.
Our Outlook reflects an environment with increasingly stringent climate policies and is consistent with the aggregation of Nationally
Determined Contributions (NDCs), which were submitted by signatories to the United Nations Framework Convention on Climate
Change (UNFCCC) 2015 Paris Agreement. Our Outlook seeks to identify potential impacts of climate related policies, which often
target specific sectors. It estimates potential impacts of these policies on consumer energy demand by using various assumptions and
tools – including, depending on the sector, application of a proxy cost of carbon or assessment of targeted policies (e.g. automotive
fuel economy standards). For purposes of the Outlook, a proxy cost on energy-related CO2 emissions is assumed to reach about $80
per tonne in 2040 in OECD nations. China and other leading non-OECD nations are expected to trail OECD policy initiatives.
Nevertheless, as people and nations look for ways to reduce risks of global climate change, they will continue to need practical
solutions that do not jeopardize the affordability or reliability of the energy they need. The Corporation continues to monitor the
updates to the NDCs that nations are expected to provide in preparation for COP 26 in Glasgow in November 2021 as well as other
policy developments in light of net zero ambitions recently formulated by some nations.
The information provided in the Long-Term Business Outlook includes ExxonMobil’s internal estimates and projections based upon
internal data and analyses as well as publicly available information from external sources including the International Energy Agency.
Positioning for a Lower-Carbon Energy Future
Practical solutions to the world’s energy and climate challenges will benefit from market competition in addition to well-informed,
well-designed, and transparent policy approaches that carefully weigh costs and benefits. Such policies are likely to help manage the
risks of climate change while also enabling societies to pursue other high priority goals around the world – including clean air and
water, access to reliable and affordable energy, and economic progress for all people. ExxonMobil encourages sound policy solutions
that reduce climate-related risks across the economy at the lowest societal cost. All practical and economically-viable energy sources
will need to be pursued to continue meeting global energy demand, recognizing the scale and variety of worldwide energy needs as
well as the importance of expanding access to modern energy to promote better standards of living for billions of people.
ExxonMobil is committed to advancing sustainable, effective solutions that address both the world’s growing demand for energy and
the risks of climate change. The Company’s plans aim for industry-leading greenhouse gas performance across its businesses by 2030.
These plans include a reduction of the intensity of operated upstream greenhouse gas emissions by 15 to 20 percent in 2025, compared
to 2016 levels, which will be supported by a 40 to 50 percent decrease in methane intensity and a 35 to 45 percent decrease in flaring
intensity across the Corporation’s global operations. The 2025 emission reduction plans are expected to result in a reduction of
absolute emissions by approximately 30 percent for the Company’s current Upstream business by 2025 when compared to 2016
levels. The emission plans cover Scope 1 and Scope 2 emissions from assets operated by the Corporation.
41
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Commercially viable technology advances will be needed to achieve the Paris Agreement objectives at the lowest societal cost. While
many potential pathways exist, ExxonMobil cannot predict how these objectives will become achievable given the range of
uncertainties. ExxonMobil is working to develop breakthrough solutions in areas such as carbon capture, biofuels, hydrogen, and
energy-efficiency process technology that can help achieve the Paris Agreement objectives. In early 2021 ExxonMobil announced the
creation of a new business, ExxonMobil Low Carbon Solutions, to commercialize low-carbon technologies. The business will initially
focus on carbon capture and storage (CCS), one of the critical technologies required to achieve the climate objectives outlined in the
Paris Agreement. In addition to CCS, the business will also leverage ExxonMobil’s significant experience in the production of
hydrogen which, when coupled with CCS, is likely to play a critical role in a lower-carbon energy system. Other technology focus
areas will be added in the future as they mature to commercialization.
Upstream
ExxonMobil continues to sustain a diverse growth portfolio of exploration and development opportunities, which enables the
Corporation to be selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental
strategies guide our global Upstream business, including capturing material and accretive opportunities to continually high-grade the
resource portfolio, selectively developing attractive oil and natural gas resources, developing and applying high-impact technologies,
and pursuing productivity and efficiency gains. These strategies are underpinned by a relentless focus on operational excellence,
development of our employees, and investment in the communities within which we operate.
As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic
mix and in the type of opportunities from which volumes are produced. Based on current investment plans, the proportion of oil-
equivalent production from the Americas is generally expected to increase over the next several years. Further, the proportion of our
global production from unconventional and deepwater resources, as well as LNG currently contributes nearly half of global
production, and is generally expected to grow in the next few years.
The Corporation anticipates several projects will come online over the next few years providing additional production capacity.
However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir
performance; performance of enhanced oil recovery projects; regulatory changes; the impact of fiscal and commercial terms; asset
sales; weather events; price effects on production sharing contracts; changes in the amount and timing of capital investments that may
vary depending on the oil and gas price environment; and other factors described in Item 1A. Risk Factors.
The markets for crude oil and natural gas have a history of significant price volatility. Market demand and prices experienced sharp
decline in the first half of 2020 largely driven by the COVID-19 pandemic. Following this decline, prices increased in the second half
of the year as supply and demand began to rebalance. ExxonMobil believes prices over the long term will continue to be driven by
market supply and demand, with the demand side largely being a function of general economic activities, levels of prosperity,
technology advances, consumer preference and government policies. On the supply side, prices may be significantly impacted by
political events, the actions of OPEC and other large government resource owners, and other factors. To manage the risks associated
with price, ExxonMobil evaluates annual plans and major investments across a range of price scenarios.
In 2020, the Upstream business produced 3.8 million oil-equivalent barrels per day and matched best-ever reliability performance with
continued focus on delivering best in class operations in all aspects of the business while prioritizing cash flow generation and return
on investment. Government-mandated and economic curtailments negatively impacted 2020 production by approximately 0.2 million
oil-equivalent barrels per day. Significant progress was made on key new developments in Guyana and in the Permian basin during
2020. In Guyana, exploration success continued with three additional discoveries increasing the estimated recoverable resource to
nearly 9 billion oil-equivalent barrels on the Stabroek block. In the Permian, despite economic curtailments and reduced capital
investment, production volumes averaged 367 thousand oil-equivalent barrels per day in 2020, a 35 percent year-on-year production
increase which exceeded expectations, while development and operating costs were significantly reduced. Also in the Permian, we
started up the Delaware basin central processing and stabilization facility which enhances the company’s integration advantages by
collecting and processing oil and natural gas for delivery to Gulf Coast markets.
Downstream
ExxonMobil’s Downstream is a large, diversified business with global logistics, trading, refining, and marketing. The Corporation has
a well-established presence in the Americas, Europe, and growing Asia Pacific region.
Downstream strategies competitively position the business across a range of market conditions. These strategies focus on providing
quality, differentiated, and valued products and services to customers, targeting best in class operations performance, capitalizing on
integration across all ExxonMobil businesses, maximizing value from advantaged technology, and selectively investing for resilient,
advantaged returns.
ExxonMobil’s operating results, as noted in Item 2. Properties, reflect 21 refineries, located in 14 countries, with distillation capacity
of 4.8 million barrels per day (MBD) and lubricant base stock manufacturing capacity of 129 thousand barrels per day. ExxonMobil’s
fuels and lubes value chains have significant global reach, with multiple channels to market serving a diverse customer base. Our
portfolio of world-renowned brands includes Exxon, Mobil, Esso, Synergy, and Mobil 1.
42
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuels demand in 2020 was significantly impacted by the COVID-19 pandemic. During the second quarter downturn, global demand
for gasoline, diesel, and jet fuel declined about 23 percent versus 2019. While demand partially recovered in the second half of the
year, fourth quarter total products demand remained 10 percent below 2019 levels. This unprecedented demand impact adversely
affected refining margins resulting in historically low market conditions, with announced refinery closures four times higher than 10-
year historical levels. In the near-term, refining margins will continue to be impacted by COVID-19 demand recovery. Finished
lubricant demand was also impacted by COVID-19, with ExxonMobil’s estimate of industry demand down 5 to 10 percent versus
2019.
Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery
pays for its raw materials and the market prices for the range of products produced. Crude oil and many products are widely traded
with published prices, including those quoted on multiple exchanges around the world (e.g., New York Mercantile Exchange and
Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many
factors, including global and regional supply/demand balances, inventory levels, industry refinery operations, import/export balances,
currency fluctuations, seasonal demand, weather, and political climate.
ExxonMobil’s long-term outlook is that industry refining margins will remain volatile subject to shifting consumer demand as well as
capacity changes from refinery additions and closures. ExxonMobil’s significant integration both within the Downstream value chains
including lubricants, logistics, trading, refining, and marketing, as well as with Upstream and Chemical, improves our ability to
generate shareholder value in different market conditions.
As described in Item 1A. Risk Factors, proposed carbon policy and other climate related regulations in many countries, as well as the
continued growth in biofuels mandates, could have negative impacts on the Downstream business.
ExxonMobil continually evaluates the Downstream portfolio during all phases of the business cycle, which has resulted in numerous
asset divestments over the past decade to strengthen overall profitability and resiliency. When investing in the Downstream,
ExxonMobil remains focused on select and resilient projects across a broad range of market conditions. In 2020, the Strathcona
Cogeneration project started up to improve refinery energy efficiency and reduce greenhouse gas emissions. In addition, the main
segment of the Wink to Webster pipeline system, operated by ExxonMobil Pipeline Company, started transporting Permian crude
from Midland to Houston. Finally, deferral costs associated with pacing previously announced Downstream projects will be offset
with efficiencies captured during the market downturn.
ExxonMobil continues to grow fuels product sales in new markets near major production assets with continued progress in the Mexico
and Indonesia market entries. The lubricants business continues to grow, leveraging world class brands and integration with industry
leading basestock refining capability. Through the Mobil branded properties, such as Mobil 1, ExxonMobil is the worldwide leader in
synthetic motor oils.
Chemical
ExxonMobil is a major manufacturer and marketer of petrochemicals, including a wide variety of performance products that
sustainably support improved living standards around the globe. ExxonMobil sustains its competitive advantage through continued
operational excellence, investment and cost discipline, a balanced portfolio of products, and unparalleled integration with Downstream
and Upstream operations, all underpinned by proprietary technology.
In 2020, many markets were heavily impacted by COVID-19, however demand for chemical products remained resilient in several
key segments including food packaging, hygiene and medical. Overall Chemical margins improved compared to 2019 due to lower
feedstock costs, continued strong packaging demand, and industry supply disruptions through the second half of 2020. We were
uniquely positioned to capture value from the market volatility in 2020 due to our integration, enabling nimble feed and product
optimization. This, in addition to our outstanding safety and reliability performance and structural cost improvement, delivered
industry leading earnings.
Over the long term, demand for chemical products is forecast to outpace growth in global GDP and energy demand. ExxonMobil
estimates that worldwide demand for chemicals will rise by over 40 percent by 2030, driven by continued global population growth
and an expanding middle class. ExxonMobil’s integration with refining, together with our high-value performance products and
unique project execution capability, enhances our ability to generate industry-leading returns on investments across a range of market
environments. In 2020, construction progressed on our joint venture ethane cracker and associated units near Corpus Christi, Texas.
The project is below budget and expected to start up ahead of schedule in the fourth quarter of 2021. We made the decision to slow the
pace of other U.S. Gulf Coast growth projects, capturing current market efficiencies to offset deferral costs. In addition, we continued
to progress plans for a world-scale steam cracker and performance derivative units in Guangdong Province, China.
43
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REVIEW OF 2020 AND 2019 RESULTS
During the first and second quarters of 2020, the balance of supply and demand for petroleum and petrochemical products experienced
two significant disruptive effects. On the demand side, the COVID-19 pandemic spread rapidly through most areas of the world
resulting in substantial reductions in consumer and business activity and significantly reduced demand for crude oil, natural gas, and
petroleum products. This reduction in demand coincided with announcements of increased production in certain key oil-producing
countries which led to increases in inventory levels and sharp declines in prices for crude oil, natural gas, and petroleum products.
Market conditions continued to reflect considerable uncertainty throughout 2020 as consumer and business activity exhibited some
degree of recovery, but remained lower when compared to prior periods as a result of the pandemic. Despite actions taken by key oil-
producing countries to reduce oversupply, the unfavorable economic impacts are likely to persist to some extent well into 2021.
Earnings (Loss) (U.S. GAAP)
Net income (loss) attributable to ExxonMobil (U.S. GAAP)
(22,440) 14,340
20,840
2020
2019
2018
(millions of dollars)
Upstream
Upstream
United States
Non-U.S.
Total
2020
2020
2019
2018
(millions of dollars)
(19,385)
536
1,739
(645) 13,906
(20,030) 14,442
12,340
14,079
Upstream results were a loss of $20,030 million, down $34,472 million from 2019.
•
•
•
•
•
•
•
•
Lower realizations reduced earnings by $11.2 billion.
Unfavorable volume and mix effects decreased earnings by $300 million.
All other items decreased earnings by $23 billion, as impairments of $19.4 billion and the absence of the $3.7 billion gain
from the 2019 Norway non-operated divestment were partly offset by lower expenses of $1 billion.
U.S. Upstream results were a loss of $19,385 million and included asset impairments of $17.1 billion.
Non-U.S. Upstream results were a loss of $645 million, including asset impairments of $2.3 billion and the absence of the
$3.7 billion gain from the Norway non-operated divestment.
On an oil-equivalent basis, production of 3.8 million barrels per day was down 5 percent compared to 2019.
Liquids production of 2.3 million barrels per day decreased 37,000 barrels per day reflecting the impacts of government
mandates, divestments, and lower demand, partly offset by growth and lower downtime.
Natural gas production of 8.5 billion cubic feet per day decreased 923 million cubic feet per day from 2019, reflecting
divestments, lower demand, and higher downtime, partly offset by growth.
2019
•
•
•
Upstream earnings were $14,442 million, up $363 million from 2018.
Lower realizations reduced earnings by $2.7 billion.
Favorable volume and mix effects increased earnings by $860 million.
All other items increased earnings by $2.2 billion, as a $3.7 billion gain from the Norway non-operated divestment was partly
offset by higher expenses of $1.1 billion.
U.S. Upstream earnings were $536 million and included asset impairments of $146 million.
Non-U.S. Upstream earnings were $13,906 million, including the $3.7 billion gain from the Norway non-operated
divestment.
On an oil-equivalent basis, production of 4.0 million barrels per day was up 3 percent compared to 2018.
Liquids production of 2.4 million barrels per day increased 120,000 barrels per day reflecting growth and higher entitlements.
Natural gas production of 9.4 billion cubic feet per day decreased 11 million cubic feet per day from 2018, with the impact
from divestments and higher downtime offset by growth and higher entitlements.
•
•
•
•
•
44
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Upstream Additional Information
Volumes Reconciliation (Oil-equivalent production) (1)
Prior Year
Entitlements - Net Interest
Entitlements - Price / Spend / Other
Government Mandates
Divestments
Growth / Other
Current Year
2020
2019
(thousands of barrels daily)
3,952
(9)
67
(110)
(151)
12
3,761
3,833
(1)
34
(3)
(27)
116
3,952
(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
Listed below are descriptions of ExxonMobil’s volumes reconciliation factors which are provided to facilitate understanding of the
terms.
Entitlements - Net Interest are changes to ExxonMobil’s share of production volumes caused by non-operational changes to volume-
determining factors. These factors consist of net interest changes specified in Production Sharing Contracts (PSCs) which typically
occur when cumulative investment returns or production volumes achieve defined thresholds, changes in equity upon achieving pay-
out in partner investment carry situations, equity redeterminations as specified in venture agreements, or as a result of the termination
or expiry of a concession. Once a net interest change has occurred, it typically will not be reversed by subsequent events, such as
lower crude oil prices.
Entitlements - Price, Spend and Other are changes to ExxonMobil’s share of production volumes resulting from temporary changes to
non-operational volume-determining factors. These factors include changes in oil and gas prices or spending levels from one period to
another. According to the terms of contractual arrangements or government royalty regimes, price or spending variability can increase
or decrease royalty burdens and/or volumes attributable to ExxonMobil. For example, at higher prices, fewer barrels are required for
ExxonMobil to recover its costs. These effects generally vary from period to period with field spending patterns or market prices for
oil and natural gas. Such factors can also include other temporary changes in net interest as dictated by specific provisions in
production agreements.
Government Mandates are changes to ExxonMobil's sustainable production levels due to temporary non-operational production limits
imposed by governments, generally upon a sector, type or method of production.
Divestments are reductions in ExxonMobil’s production arising from commercial arrangements to fully or partially reduce equity in a
field or asset in exchange for financial or other economic consideration.
Growth and Other factors comprise all other operational and non-operational factors not covered by the above definitions that may
affect volumes attributable to ExxonMobil. Such factors include, but are not limited to, production enhancements from project and
work program activities, acquisitions including additions from asset exchanges, downtime, market demand, natural field decline, and
any fiscal or commercial terms that do not affect entitlements.
45
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Downstream
Downstream
United States
Non-U.S.
Total
2020
Downstream results of a $1,077 million loss decreased $3,400 million from 2019.
2020
2019
2018
(millions of dollars)
(852)
(225)
(1,077)
1,717
606
2,323
2,962
3,048
6,010
• Margins decreased earnings by $3.8 billion including the impact of weaker industry refining conditions.
•
Volume and mix effects increased earnings by $370 million as manufacturing/yield improvement impacts were partly offset
by weaker demand.
All other items increased earnings by $50 million, as lower expenses of $1.3 billion were offset by impairments of $620
million, unfavorable LIFO inventory impacts of $410 million, and unfavorable tax items of $240 million.
U.S. Downstream results were a loss of $852 million, compared to earnings of $1,717 million in the prior year.
Non-U.S. Downstream results were a loss of $225 million, compared to earnings of $606 million in the prior year.
Petroleum product sales of 4.9 million barrels per day were 557,000 barrels per day lower than 2019.
•
•
•
•
2019
Downstream earnings of $2,323 million decreased $3,687 million from 2018.
• Margins decreased earnings by $3 billion including the impact of lower North American crude differentials.
•
Volume and mix effects lowered earnings by $50 million as project contributions and portfolio improvement were more than
offset by increased downtime/maintenance and unfavorable yield/sales mix.
All other items decreased earnings by $660 million, mainly driven by the absence of prior year divestment gains and higher
expenses reflecting increased maintenance and project startups, partly offset by favorable foreign exchange impacts and LIFO
inventory gains.
U.S. Downstream earnings were $1,717 million, compared to $2,962 million in the prior year.
Non-U.S. Downstream earnings were $606 million, compared to $3,048 million in the prior year.
Petroleum product sales of 5.5 million barrels per day were 60,000 barrels per day lower than 2018.
•
•
•
•
46
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Chemical
Chemical
United States
Non-U.S.
Total
2020
2020
2019
2018
(millions of dollars)
1,277
686
1,963
206
386
592
1,642
1,709
3,351
•
•
•
Chemical earnings of $1,963 million increased $1,371 million from 2019.
Stronger margins increased earnings by $930 million.
Volume and mix effects decreased earnings by $150 million.
All other items increased earnings by $590 million as lower expenses of $710 million were partly offset by unfavorable one-
time items, mainly impairments.
U.S. Chemical earnings were $1,277 million in 2020, compared with $206 million in the prior year.
Non-U.S. Chemical earnings were $686 million, compared with $386 million in the prior year.
Prime product sales of 25.4 million metric tons were down 1.1 million metric tons from 2019.
•
•
•
2019
Chemical earnings of $592 million decreased $2,759 million from 2018.
• Weaker margins decreased earnings by $1.8 billion.
•
•
Volume and mix effects were essentially flat, as lower sales volumes were offset by new asset contributions.
All other items decreased earnings by $940 million, primarily due to higher expenses associated with new assets, business
growth, and maintenance activity, the absence of a favorable tax item in the prior year, and unfavorable foreign exchange
impacts.
U.S. Chemical earnings were $206 million in 2019, compared with $1,642 million in the prior year.
Non-U.S. Chemical earnings were $386 million, compared with $1,709 million in the prior year.
Prime product sales of 26.5 million metric tons were down 0.4 million metric tons from 2018.
•
•
•
Corporate and Financing
Corporate and financing
2020
2020
2019
2018
(millions of dollars)
(3,296)
(3,017)
(2,600)
Corporate and financing expenses were $3,296 million in 2020 compared to $3,017 million in 2019, with the increase mainly due to
higher financing costs and employee severance costs, partly offset by lower corporate costs.
2019
Corporate and financing expenses were $3,017 million in 2019 compared to $2,600 million in 2018, with the increase mainly due to
unfavorable tax impacts and higher financing costs.
47
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
Net cash provided by/(used in)
Operating activities
Investing activities
Financing activities
Effect of exchange rate changes
Increase/(decrease) in cash and cash equivalents
Total cash and cash equivalents
2020
2019
2018
(millions of dollars)
14,668
29,716
36,014
(18,459) (23,084) (16,446)
5,285
(6,618) (19,446)
(219)
1,275
33
47
(257)
(135)
(December 31)
4,364
3,089
3,042
Total cash and cash equivalents were $4.4 billion at the end of 2020, up $1.3 billion from the prior year. The major sources of funds in
2020 were the adjustment for the noncash provision of $46.0 billion for depreciation and depletion, a net debt increase of
$20.1 billion, proceeds from asset sales of $1.0 billion, and other investing activities of $2.7 billion. The major uses of funds included
a net loss including noncontrolling interests of $23.3 billion, spending for additions to property, plant and equipment of $17.3 billion,
dividends to shareholders of $14.9 billion, and additional investments and advances of $4.9 billion.
Total cash and cash equivalents were $3.1 billion at the end of 2019, up $47 million from the prior year. The major sources of funds in
2019 were net income including noncontrolling interests of $14.8 billion, the adjustment for the noncash provision of $19.0 billion for
depreciation and depletion, a net debt increase of $8.7 billion, and proceeds from asset sales of $3.7 billion. The major uses of funds
included spending for additions to property, plant and equipment of $24.4 billion, dividends to shareholders of $14.7 billion, and
additional investments and advances of $3.9 billion.
The Corporation has access to significant capacity of long-term and short-term liquidity. Commercial paper continues to provide short-
term liquidity, and is reflected in “Notes and loans payable” on the Consolidated Balance Sheet with changes in outstanding
commercial paper between periods included in the Consolidated Statement of Cash Flows. The Corporation took steps to strengthen its
liquidity in 2020, including issuing $23.2 billion of long-term debt and implementing significant capital and operating cost reductions.
The Corporation ended the year with $68 billion in gross debt and intends to reduce debt over time. On December 31, 2020, the
Corporation had unused short-term committed lines of credit of $11.3 billion and no unused long-term lines of credit.
To support cash flows in future periods the Corporation will need to continually find or acquire and develop new fields, and continue
to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a
period of production at plateau rates, it is the nature of oil and gas fields eventually to produce at declining rates for the remainder of
their economic life. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type
of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. In particular, the Corporation’s key tight-oil
plays have higher initial decline rates which tend to moderate over time. Furthermore, the Corporation’s net interest in production for
individual fields can vary with price and the impact of fiscal and commercial terms.
The Corporation has long been successful at mitigating the effects of natural field decline through disciplined investments in quality
opportunities and project execution. The Corporation anticipates several projects will come online over the next few years providing
additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups;
operational outages; reservoir performance; performance of enhanced oil recovery projects; regulatory changes; the impact of fiscal
and commercial terms; asset sales; weather events; price effects on production sharing contracts; and changes in the amount and
timing of investments that may vary depending on the oil and gas price environment. The Corporation’s cash flows are also highly
dependent on crude oil and natural gas prices. Please refer to Item 1A. Risk Factors for a more complete discussion of risks.
The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in
2020 were $21.4 billion, reflecting the Corporation’s continued active investment program. The Corporation is prioritizing
opportunities to hold 2021 capital spending in a range of $16 billion to $19 billion.
48
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large
and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical
risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength and diverse portfolio of
opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s
liquidity or ability to generate sufficient cash flows for operations and its fixed commitments.
The Corporation, as part of its ongoing asset management program, continues to evaluate its mix of assets for potential upgrade.
Because of the ongoing nature of this program, dispositions will continue to be made from time to time which will result in either
gains or losses. In light of the current low commodity price environment, and depending on the extent and pace of recovery, the
Corporation's planned divestment program could be adversely affected by fewer financially suitable buyers. This could result in a
slowing of the pace of divestments, certain assets being sold at a price below current book value, or impairment charges if the
likelihood of divesting certain assets increases. Additionally, the Corporation continues to evaluate opportunities to enhance its
business portfolio through acquisitions of assets or companies, and enters into such transactions from time to time. Key criteria for
evaluating acquisitions include potential for future growth and attractive current valuations. Acquisitions may be made with cash,
shares of the Corporation’s common stock, or both.
ExxonMobil closely monitors the potential impacts of Brexit and Interbank Offered Rate (IBOR) reforms, including LIBOR, under a
number of scenarios and has taken steps to mitigate their potential impact. Accordingly, ExxonMobil does not believe these events
represent a material risk to the Corporation’s consolidated results of operations or financial condition.
Cash Flow from Operating Activities
2020
Cash provided by operating activities totaled $14.7 billion in 2020, $15.0 billion lower than 2019. Net income (loss) including
noncontrolling interests was a loss of $23.3 billion, a decrease of $38.0 billion. The noncash provision for depreciation and depletion
was $46.0 billion, up $27.0 billion from the prior year, mainly due to asset impairments. The noncash provision for deferred income
tax benefits was $8.9 billion and also included impacts from asset impairments. The adjustment for the net loss on asset sales was $4
million, a decrease of $1.7 billion. The adjustment for dividends received less than equity in current earnings of equity companies was
an increase of $1.0 billion, compared to a reduction of $0.9 billion in 2019. Changes in operational working capital, excluding cash
and debt, decreased cash in 2020 by $1.7 billion.
2019
Cash provided by operating activities totaled $29.7 billion in 2019, $6.3 billion lower than 2018. The major source of funds was net
income including noncontrolling interests of $14.8 billion, a decrease of $6.6 billion. The noncash provision for depreciation and
depletion was $19.0 billion, up $0.3 billion from the prior year. The adjustment for the net gain on asset sales was $1.7 billion, a
decrease of $0.3 billion. The adjustment for dividends received less than equity in current earnings of equity companies was a
reduction of $0.9 billion, compared to a reduction of $1.7 billion in 2018. Changes in operational working capital, excluding cash and
debt, increased cash in 2019 by $0.9 billion.
Cash Flow from Investing Activities
2020
Cash used in investing activities netted to $18.5 billion in 2020, $4.6 billion lower than 2019. Spending for property, plant and
equipment of $17.3 billion decreased $7.1 billion from 2019. Proceeds associated with sales of subsidiaries, property, plant and
equipment, and sales and returns of investments of $1.0 billion compared to $3.7 billion in 2019. Additional investments and advances
were $1.0 billion higher in 2020, while proceeds from other investing activities including collection of advances increased by
$1.2 billion.
2019
Cash used in investing activities netted to $23.1 billion in 2019, $6.6 billion higher than 2018. Spending for property, plant and
equipment of $24.4 billion increased $4.8 billion from 2018. Proceeds associated with sales of subsidiaries, property, plant and
equipment, and sales and returns of investments of $3.7 billion compared to $4.1 billion in 2018. Additional investments and advances
were $1.9 billion higher in 2019, while proceeds from other investing activities including collection of advances increased by
$0.5 billion.
49
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cash Flow from Financing Activities
2020
Cash flow from financing activities was $5.3 billion in 2020, $11.9 billion higher than 2019. Dividend payments on common shares
increased to $3.48 per share from $3.43 per share and totaled $14.9 billion. During 2020, the Corporation issued $23.2 billion of long-
term debt. Total debt increased $20.7 billion to $67.6 billion at year-end.
ExxonMobil share of equity decreased $34.5 billion to $157.2 billion. The reduction to equity for losses was $22.4 billion and the
reduction for distributions to ExxonMobil shareholders was $14.9 billion, all in the form of dividends. Foreign exchange translation
effects of $1.8 billion for the weaker U.S. dollar and a $1.0 billion change in the funded status of the postretirement benefits reserves
increased equity.
During 2020, Exxon Mobil Corporation acquired 8 million shares of its common stock for the treasury. Purchases were made to offset
shares or units settled in shares issued in conjunction with the company’s benefit plans and programs. Shares outstanding decreased
from 4,234 million to 4,233 million at the end of 2020.
2019
Cash used in financing activities was $6.6 billion in 2019, $12.8 billion lower than 2018. Dividend payments on common shares
increased to $3.43 per share from $3.23 per share and totaled $14.7 billion. During the third quarter of 2019, the Corporation issued
$7.0 billion of long-term debt. Total debt increased $9.1 billion to $46.9 billion at year-end.
ExxonMobil share of equity decreased $0.1 billion to $191.7 billion. The addition to equity for earnings was $14.3 billion. This was
offset by reductions for distributions to ExxonMobil shareholders of $14.7 billion, all in the form of dividends. Foreign exchange
translation effects of $1.4 billion for the weaker U.S. currency increased equity, while a $1.4 billion change in the funded status of the
postretirement benefits reserves reduced equity.
During 2019, Exxon Mobil Corporation acquired 8 million shares of its common stock for the treasury. Purchases were made to offset
shares or units settled in shares issued in conjunction with the company’s benefit plans and programs. Shares outstanding decreased
from 4,237 million to 4,234 million at the end of 2019.
50
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Commitments
Set forth below
the Corporation’s consolidated subsidiaries at
December 31, 2020. The table combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated
Financial Statements.
the outstanding commitments of
information about
is
Commitments
Long-term debt excluding finance lease obligations (1)
Asset retirement obligations (2)
Pension and other postretirement obligations (3)
Lease commitments (4)
Operating and finance leases - commenced
Operating and finance leases - not yet commenced
Take-or-pay and unconditional purchase obligations (5)
Firm capital commitments (6)
Note
Reference
Number
6, 14
9
17
11
Payments Due by Period
2021
2022-
2023
2024-
2025
2026 and
Beyond
Total
(millions of dollars)
2,828
689
1,860
1,558
192
4,155
6,027
7,364
1,203
1,576
2,163
1,081
7,246
4,469
8,640
1,005
1,530
29,263
8,350
16,495
48,095
11,247
21,461
1,358
495
5,626
1,689
2,004
2,786
16,932
599
7,083
4,554
33,959
12,784
This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold
shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing
terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery
products at market prices. Inclusion of such commitments would not be meaningful in assessing liquidity and cash flow, because these
purchases will be offset in the same periods by cash received from the related sales transactions. The table also excludes unrecognized
tax benefits totaling $8.8 billion as of December 31, 2020, because the Corporation is unable to make reasonably reliable estimates of
the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in
“Note 19: Income and Other Taxes”.
Notes:
(1) The amount due in 2021 is included in Notes and loans payable of $20,458 million. The amounts due 2022 and beyond are
included in Long-term debt of $47,182 million.
(2) Asset retirement obligations are primarily upstream asset removal costs at the end of field life.
(3) The amount by which the benefit obligations exceeded the fair value of fund assets for U.S. and non-U.S. pension and other
postretirement plans at year-end. The payments by period include expected contributions to funded pension plans in 2021 and
estimated benefit payments for unfunded plans in all years.
(4) Commitments for operating and finance leases cover drilling equipment, tankers and other assets.
(5) Take-or-pay obligations are noncancelable, long-term commitments for goods and services. Unconditional purchase obligations
are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have
used to secure financing for the facilities that will provide the contracted goods or services. The obligations mainly pertain to
pipeline, manufacturing supply and terminal agreements.
(6) Firm capital commitments represent legally binding payment obligations to third parties where agreements specifying all
significant terms have been executed for the construction and purchase of fixed assets and other permanent investments. In
certain cases where the Corporation executes contracts requiring commitments to a work scope, those commitments have been
included to the extent that the amounts and timing of payments can be reliably estimated. Firm capital commitments, shown on an
undiscounted basis, totaled $12.8 billion, including $5.3 billion in the U.S.
Firm capital commitments for the non-U.S. Upstream of $5.9 billion were primarily associated with projects in Guyana, Angola,
Malaysia, United Kingdom, Canada, Australia, Brazil and United Arab Emirates. The Corporation expects to fund the majority of
these commitments with internally generated funds, supplemented by short-term and long-term debt as required.
51
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Guarantees
The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2020, for guarantees relating to
notes, loans and performance under contracts (Note 16). Where guarantees for environmental remediation and other similar matters do
not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. These guarantees are not
reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or
expenses, results of operations, liquidity, capital expenditures or capital resources.
Financial Strength
On December 31, 2020, the Corporation had total unused short-term committed lines of credit of $11.3 billion (Note 6) and no unused
long-term lines of credit (Note 14). The table below shows the Corporation’s consolidated debt to capital ratios.
Debt to capital (percent)
Net debt to capital (percent)
2020
29.2
27.8
2019
19.1
18.1
2018
16.0
14.9
Management views the Corporation’s financial strength to be a competitive advantage of strategic importance. The Corporation’s
financial position gives it the opportunity to access the world’s capital markets in the full range of market conditions, and enables the
Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.
Industry conditions in 2020 led to lower realized prices for the Corporation’s products which resulted in substantially lower earnings
and operating cash flow in comparison to 2019. The Corporation took steps to strengthen its liquidity in 2020, including issuing $23
billion of long-term debt and implementing significant capital and operating cost reductions. The Corporation ended the year with $68
billion in gross debt and intends to reduce debt over time.
Litigation and Other Contingencies
As discussed in Note 16, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a
number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the
ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s
operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already
included in reported financial information that would indicate a material change in future operating results or financial condition.
Refer to Note 16 for additional information on legal proceedings and other contingencies.
CAPITAL AND EXPLORATION EXPENDITURES
Capital and exploration expenditures (Capex) represents the combined total of additions at cost to property, plant and equipment, and
exploration expenses on a before-tax basis from the Consolidated Statement of Income. ExxonMobil’s Capex includes its share of
similar costs for equity companies. Capex excludes assets acquired in nonmonetary exchanges, the value of ExxonMobil shares used
to acquire assets, and depreciation on the cost of exploration support equipment and facilities recorded to property, plant and
equipment when acquired. While ExxonMobil’s management is responsible for all investments and elements of net income, particular
focus is placed on managing the controllable aspects of this group of expenditures.
Upstream (1)
Downstream
Chemical
Other
Total
(1) Exploration expenses included.
2020
2019
U.S.
Non-U.S.
Total
U.S.
Non-U.S.
Total
6,817
2,344
2,002
6
11,169
7,614
1,877
714
—
10,205
(millions of dollars)
14,431
11,653
4,221
2,716
6
21,374
2,353
2,547
27
16,580
11,832
2,018
718
—
14,568
23,485
4,371
3,265
27
31,148
52
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Capex in 2020 was $21.4 billion, as the Corporation continued to pursue opportunities to find and produce new supplies of oil and
natural gas to meet global demand for energy. The Corporation is prioritizing opportunities to hold 2021 capital spending in a range of
$16 billion to $19 billion. Actual spending could vary depending on the progress of individual projects and property acquisitions.
Upstream spending of $14.4 billion in 2020 was down 39 percent from 2019 in response to market conditions. Investments in 2020
included the U.S. Permian Basin and key development projects in Guyana. Development projects typically take several years from the
time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. The
percentage of proved developed reserves was 67 percent of total proved reserves at year-end 2020, and has been over 60 percent for
the last ten years.
Capital investments in the Downstream totaled $4.2 billion in 2020, a decrease of $0.2 billion from 2019, reflecting lower global
project spending. Chemical capital expenditures of $2.7 billion, decreased $0.5 billion, representing reduced spend on growth projects.
TAXES
Income taxes
Effective income tax rate
Total other taxes and duties
Total
2020
2020
2019
2018
(millions of dollars)
(5,632)
5,282
9,532
17 %
34 %
37 %
28,425
33,186
35,230
22,793
38,468
44,762
Total taxes on the Corporation’s income statement were $22.8 billion in 2020, a decrease of $15.7 billion from 2019. Income tax
expense, both current and deferred, was a benefit of $5.6 billion compared to $5.3 billion expense in 2019. The relative benefit is
driven by asset impairments recorded in 2020. The effective tax rate, which is calculated based on consolidated company income taxes
and ExxonMobil’s share of equity company income taxes, was 17 percent compared to 34 percent in the prior year due primarily to a
change in mix of results in jurisdictions with varying tax rates. Total other taxes and duties of $28.4 billion in 2020 decreased $4.8
billion.
2019
Total taxes on the Corporation’s income statement were $38.5 billion in 2019, a decrease of $6.3 billion from 2018. Income tax
expense, both current and deferred, was $5.3 billion compared to $9.5 billion in 2018. The effective tax rate, which is calculated based
on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 34 percent compared to 37
percent in the prior year due primarily to the impact of the divestment of non-operated upstream assets in Norway. Total other taxes
and duties of $33.2 billion in 2019 decreased $2.0 billion.
53
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ENVIRONMENTAL MATTERS
Environmental Expenditures
Capital expenditures
Other expenditures
Total
2020
2019
(millions of dollars)
1,087
3,389
4,476
1,276
3,969
5,245
Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on
air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels, as
well as projects to monitor and reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions, and expenditures for asset
retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2020
worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity
company expenditures, were $4.5 billion, of which $3.4 billion were included in expenses with the remainder in capital expenditures.
The total cost for such activities is expected to increase to approximately $4.9 billion in 2021 and 2022. Capital expenditures are
expected to account for approximately 25 percent of the total.
Environmental Liabilities
The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be
reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued
liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental
Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially
responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no
individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company
provisions made in 2020 for environmental liabilities were $263 million ($290 million in 2019) and the balance sheet reflects
liabilities of $902 million as of December 31, 2020, and $835 million as of December 31, 2019.
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
Worldwide Average Realizations (1)
Crude oil and NGL ($ per barrel)
Natural gas ($ per thousand cubic feet)
(1) Consolidated subsidiaries.
2020
35.41
2.01
2019
56.32
3.05
2018
62.79
3.87
Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of
these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a
$1 per barrel change in the weighted-average realized price of oil would have approximately a $475 million annual after-tax effect on
Upstream consolidated plus equity company earnings, excluding the impact of derivatives. Similarly, a $0.10 per thousand cubic feet
change in the worldwide average gas realization would have approximately a $165 million annual after-tax effect on Upstream
consolidated plus equity company earnings, excluding the impact of derivatives. For any given period, the extent of actual benefit or
detriment will be dependent on the price movements of individual types of crude oil, results of trading activities, taxes and other
government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly,
changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any
particular period.
In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than
absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw
materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and
regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.
54
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the
Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated
with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s
financial strength as a competitive advantage.
In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where
such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes.
Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in
worldwide markets that have substantial liquidity, capacity, and transportation capabilities. Refer to Note 18 for additional information
on intersegment revenue.
Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to global economic
conditions, political events, decisions by OPEC and other major government resource owners and other factors, industry economics
over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation evaluates the viability of its
major investments over a range of prices.
The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or
considered for divestment. The asset management program includes a disciplined, regular review to ensure that assets are contributing
to the Corporation’s strategic objectives.
Risk Management
The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and
Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates and interest
rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and for
trading purposes. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation
also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of
December 31, 2020 and 2019, or results of operations for the years ended 2020, 2019 and 2018. Credit risk associated with the
Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of
and financial limits placed on derivative counterparties. No material market or credit risks to the Corporation’s financial position,
results of operations or liquidity exist as a result of the derivatives described in Note 13. The Corporation maintains a system of
controls that includes the authorization, reporting and monitoring of derivative activity.
The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries
floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material
to earnings or cash flow. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated
funds are generally expected to cover financial requirements, supplemented by long-term and short-term debt as required. Commercial
paper is used to balance short-term liquidity requirements. Some joint-venture partners are dependent on the credit markets, and their
funding ability may impact the development pace of joint-venture projects.
The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales,
expenses, financing and investment transactions. Fluctuations in exchange rates are often offsetting and the impacts on ExxonMobil’s
geographically and functionally diverse operations are varied. The Corporation makes limited use of currency exchange contracts to
mitigate the impact of changes in currency values, and exposures related to the Corporation’s use of these contracts are not material.
Inflation and Other Uncertainties
The general rate of inflation in many major countries of operation has remained moderate over the past few years, and the associated
impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Prices for
services and materials continue to evolve in response to constant changes in commodity markets and industry activities, impacting
operating and capital costs. However, the global COVID-19 pandemic since early 2020 has brought unprecedented uncertainties to
near-term economic outlooks. The Corporation continues to monitor market trends and works to minimize costs in all commodity
price environments through its economies of scale in global procurement and its efficient project management practices.
RESTRUCTURING ACTIVITIES
During 2020, ExxonMobil conducted an extensive global review of staffing levels and subsequently commenced targeted workforce
reductions within a number of countries to improve efficiency and reduce costs. The programs, which are expected to be substantially
complete by the end of 2021, include both voluntary and involuntary employee separations and reductions in contractors.
In 2020 the Corporation recorded before-tax charges of $450 million ($349 million after tax), consisting primarily of employee
separation costs, associated with announced workforce reduction programs in Europe, North America, and Australia. These costs are
captured in “Selling, general and administrative expenses” on the Statement of Income and reported in the Corporate and financing
segment. Before-tax cash outflows in 2020 associated with these activities were $47 million. The Corporation estimates additional
charges of up to $200 million in 2021 related to planned workforce reduction programs with cash outflows ranging between $400
million and $600 million. Before-tax workforce reduction savings, including employees and contractors, are estimated to range
between $1 billion and $2 billion per year after program completion when compared to 2019 levels.
55
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING ESTIMATES
The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and
production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products,
petrochemicals and a wide variety of specialty products. The preparation of financial statements in conformity with U.S. Generally
Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies
are summarized in Note 1.
Oil and Natural Gas Reserves
The estimation of proved oil and natural gas reserve volumes is an ongoing process based on rigorous technical evaluations,
commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines,
development and production costs, among other factors. The estimation of proved reserves is controlled by the Corporation through
long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level
geoscience and engineering professionals, assisted by the Global Reserves and Resources Group which has significant technical
experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific
quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in Disclosure of
Reserves in Item 2.
Oil and natural gas reserves include both proved and unproved reserves.
•
Proved oil and natural gas reserves are determined in accordance with Securities and Exchange Commission (SEC)
requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data,
can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and
government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during
the reporting year.
Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include
amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved
undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing
wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a
development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific
circumstances support a longer period of time.
The percentage of proved developed reserves was 67 percent of total proved reserves at year-end 2020 (including both
consolidated and equity company reserves), an increase from 66 percent in 2019, and has been over 60 percent for the last ten
years. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered
can be affected by a number of factors including completion of development projects, reservoir performance, regulatory
approvals, government policy, consumer preferences and significant changes in oil and natural gas price levels.
•
Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include
probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered.
Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of (1)
already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in the average of
first-of-month oil and natural gas prices and / or costs that are used in the estimation of reserves. Revisions can also result from
significant changes in development strategy or production equipment and facility capacity.
Unit-of-Production Depreciation
Oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets.
Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to actual
production. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some
variability.
56
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream
asset, an alternative method is used. The straight-line method may be used in limited situations where the expected life of the asset
does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural
gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully
depreciated by the end of its useful life.
To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the
resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a
unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of
proved reserves, appropriately adjusted for production and technical changes.
Impairment
The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances
indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that
the carrying value of an asset or asset group may not be recoverable are the following:
•
•
•
•
•
•
a significant decrease in the market price of a long-lived asset;
a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a
significant decrease in current and projected reserve volumes;
a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or
assessment by a regulator;
an accumulation of project costs significantly in excess of the amount originally expected;
a current-period operating loss combined with a history and forecast of operating or cash flow losses; and
a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the
end of its previously estimated useful life.
Asset valuation analyses, profitability reviews and other periodic control processes assist the Corporation in assessing whether events
or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.
In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that
prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will
occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand
fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate
production from new discoveries, field developments and technology and efficiency advancements. OPEC investment activities and
production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and
levels of prosperity. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the value of
these assets is predominantly based on long-term views of future commodity prices and development and production costs. During the
lifespan of these major assets, the Corporation expects that oil and gas prices will experience significant volatility, and consequently
these assets will experience periods of higher earnings and periods of lower earnings, or even losses.
In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the
Corporation considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are
subject to wide fluctuations, longer-term price views are more stable and meaningful for purposes of assessing future cash flows.
When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may
result in changes to the Corporation’s price or margin assumptions it uses for its capital investment decisions. To the extent those
changes result in a significant reduction to its oil price, natural gas price or margin ranges, the Corporation may consider that situation,
in conjunction with other events or changes in circumstances such as a history of operating losses, an indicator of potential impairment
for certain assets.
57
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas
Exploration and Production Activities is required to use prices based on the average of first-of-month prices. These prices represent
discrete points in time and could be higher or lower than the Corporation’s price assumptions which are used for impairment
assessments. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows
to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and
therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment
assessment.
The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year.
This process is aligned with the requirements of ASC 360 and ASC 932, and relies in part on the Corporation’s planning and
budgeting cycle. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the
Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In
performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely
independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the Corporation’s
assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses
to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude
oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and
operating costs, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles,
throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved
reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimates for impairment testing exclude the
effects of derivative instruments.
An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying value. Impairments are measured
by the amount by which the carrying value exceeds fair value. The assessment of fair value requires the use of Level 3 inputs and
assumptions that are based upon the views of a likely market participant. The principal parameters used to establish fair value include
estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical
cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of
future production volumes, commodity prices which are consistent with the average of third-party industry experts and government
agencies, drilling and development costs, and discount rates ranging from 6 percent to 8 percent which are reflective of the
characteristics of the asset group.
Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are
assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's
future development plans, the estimated economic chance of success and the length of time that the Corporation expects to hold the
properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and
average holding period.
In 2020, the Corporation identified a number of situations where events or changes in circumstances indicated that the carrying value
of certain long-lived assets may not be recoverable. Those situations primarily related to the annual review and approval of the
Corporation's business and strategic plan. As part of the planning process, the Corporation assessed its full portfolio to prioritize assets
with the highest future value potential within its broad range of available opportunities in order to optimize resources within current
levels of debt and operating cash flow, as well as identify potential asset divestment candidates. This effort included a re-assessment of
dry gas assets, primarily in North America, which previously had been included in the Corporation’s future development plans. Under
the plan as approved, the Corporation no longer plans to develop a significant portion of its dry gas portfolio, including a portion of its
resources in the Appalachian, Rocky Mountains, Oklahoma, Texas, Louisiana, and Arkansas regions of the U.S. as well as resources
in Western Canada and Argentina. The decision not to develop these assets resulted in non-cash, after-tax charges of $18.4 billion in
Upstream to reduce the carrying value of those assets to fair value. Other after-tax impairment charges in 2020 include $0.5 billion in
Upstream and $0.3 billion in Downstream. As a result of these impairments, the Corporation expects lower 2021 depreciation and
depletion charges in Upstream for most of these asset groups. However, largely due to the impact of lower 2020 proved reserves
resulting from low prices, higher unit-of-production rates on certain assets in 2021 are expected to offset the effect of lower
depreciation and depletion charges related to 2020 impairments. For further discussion on proved reserves, see Summary of Oil and
Gas Reserves in the Disclosure of Reserves section in Item 2.
Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price outlooks,
changes in the allocation of capital, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural
gas price increases. However, due to the inherent difficulty in predicting future commodity prices, and the relationship between
industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges
related to the Corporation’s long-lived assets. For discussion of goodwill and equity company impairments, see Note 3 and Note 7 to
the financial statements, respectively.
58
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Asset Retirement Obligations
The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a
discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses
assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical
assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement obligations
are disclosed in Note 9 to the financial statements.
Suspended Exploratory Well Costs
The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify
its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and
operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. The facts and circumstances
that support continued capitalization of suspended wells at year-end are disclosed in Note 10 to the financial statements.
Consolidations
The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the
Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses. Amounts representing the
Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are accounted for using the
equity method of accounting.
Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they
serve to balance worldwide risks, and in others they provide the only available means of entry into a particular market or area of
interest. The other parties, who also have an equity interest in these companies, are either independent third parties or host
governments that share in the business results according to their ownership. The Corporation does not invest in these companies in
order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting
method that would require each investor to consolidate its share of all assets and liabilities in these partially-owned companies rather
than only its interest in net equity. This method of accounting for investments in partially-owned companies is not permitted by U.S.
GAAP except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of
calculating return on average capital employed, which is not covered by U.S. GAAP standards, the Corporation includes its share of
debt of these partially-owned companies in the determination of average capital employed.
Pension Benefits
The Corporation and its affiliates sponsor about 80 defined benefit (pension) plans in over 40 countries. The Pension and Other
Postretirement Benefits footnote (Note 17) provides details on pension obligations, fund assets and pension expense.
Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate
cash flow rather than a separate pension fund because applicable tax rules and regulatory practices do not encourage advance funding.
Book reserves are established for these plans. The portion of the pension cost attributable to employee service is expensed as services
are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the
obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that
pension expense for funded plans also includes a credit for the expected long-term return on fund assets.
For funded plans, including those in the U.S., pension obligations are financed in advance through segregated assets or insurance
arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required
funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining
liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for
accounting purposes.
The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations,
regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the
respective sponsoring affiliate.
Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the
discount rate for the benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually
by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and
outlook. The long-term expected earnings rate on U.S. pension plan assets in 2020 was 5.3 percent. The 10-year and 20-year actual
returns on U.S. pension plan assets were 9 percent and 7 percent, respectively. The Corporation establishes the long-term expected rate
of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors
such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the
weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide
reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $210
million before tax.
59
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year
that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension
expense over the expected remaining service life of employees.
Litigation Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending
lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for
accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16.
The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable, and the amount
can be reasonably estimated. These accrued liabilities are not reduced by amounts that may be recovered under insurance or claims
against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation
revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which
are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For
purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items which management
believes should be disclosed.
Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict.
However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on
operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are
often reversed or substantially reduced as a result of appeal or settlement.
Tax Contingencies
The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in
the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the
financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities.
For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is
greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken or expected to be
taken in an income tax return and the amount recognized in the financial statements. The Corporation’s unrecognized tax benefits and
a description of open tax years are summarized in Note 19.
Foreign Currency Translation
The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is
prescribed by U.S. GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional
currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional
currency after evaluating this economic environment.
Factors considered by management when determining the functional currency for a subsidiary include the currency used for cash flows
related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; the history of inflation in the
country; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies;
sources of financing; and significance of intercompany transactions.
60
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the Corporation’s Chief Executive Officer, Principal Financial Officer, and Principal Accounting Officer, is
responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management
conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal
Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based
on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of
December 31, 2020.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s
internal control over financial reporting as of December 31, 2020, as stated in their report included in the Financial Section of this
report.
Darren W. Woods
Chief Executive Officer
Andrew P. Swiger
Senior Vice President
(Principal Financial Officer)
David S. Rosenthal
Vice President and Controller
(Principal Accounting Officer)
61
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Exxon Mobil Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Exxon Mobil Corporation and its subsidiaries (the “Corporation”) as
of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income, of changes in 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 Corporation'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 Corporation 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 Corporation 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 Corporation'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
Corporation’s consolidated financial statements and on the Corporation'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 Corporation 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.
62
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 a separate opinion on the
critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Proved Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net
As described in Notes 1, 9 and 18 to the consolidated financial statements, the Corporation’s consolidated upstream property, plant
and equipment (PP&E), net balance was $167.5 billion as of December 31, 2020, and the related depreciation and depletion expense
for the year ended December 31, 2020 was $41.4 billion. Management uses the successful efforts method to account for its exploration
and production activities. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are
capitalized when incurred. As disclosed by management, proved oil and natural gas reserve volumes are used as the basis to calculate
unit-of-production depreciation rates for most upstream assets. The estimation of proved oil and natural gas reserve volumes is an
ongoing process based on technical evaluations, commercial and market assessments, and detailed analysis of well information such as
flow rates and reservoir pressure declines, development and production costs, among other factors. As further disclosed by
management, reserve changes are made within a well-established, disciplined process driven by senior level geoscience and
engineering professionals, assisted by the Global Reserves and Resources Group (together “management’s specialists”).
The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas
reserves on upstream PP&E, 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 oil and natural gas reserve volumes, as the reserve volumes are
based on engineering assumptions and methods, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in
performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its
specialists in developing the estimates of oil and natural gas reserve volumes and the assumptions applied to the data related to future
development costs and production costs, as applicable.
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 oil and natural gas reserve volumes. The work of management's specialists was used in performing the procedures
to evaluate the reasonableness of the proved 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. These procedures also included, among others, testing the completeness and accuracy of the data related to
future development costs and production costs. Additionally, these procedures included evaluating whether the assumptions applied to
the data related to future development costs and production costs were reasonable considering the past performance of the Company.
63
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Impairment Assessment of Certain Upstream Property, Plant and Equipment, Net
As described in Notes 1, 9, and 18 to the consolidated financial statements, the Corporation’s consolidated upstream property, plant
and equipment (PP&E), net balance was $167.5 billion as of December 31, 2020, and related impairment expense for the year ended
December 31, 2020 was $25.3 billion. If events or changes in circumstances indicate that the carrying value of an asset may not be
recoverable, management estimates the future undiscounted cash flows of the affected properties to judge the recoverability of
carrying amounts. In performing this assessment, assets are grouped at the lowest level for which identifiable cash flows are largely
independent of cash flows of other groups of assets. These evaluations make use of management’s assumptions of future capital
allocations, crude oil and natural gas commodity prices including price differentials, volumes, development and operating costs, and
foreign currency exchange rates. An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying
value. Impairments are measured by the amount by which the carrying value exceeds fair value. Management’s estimate of upstream
production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved
reserve quantities.
The principal considerations for our determination that performing procedures relating to the impairment assessment of certain
upstream PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when
developing the estimates of future undiscounted cash flows and (ii) a high degree of auditor judgment, subjectivity, and effort in
performing procedures and evaluating management’s significant assumptions related to future crude oil and natural gas commodity
prices, production volumes, and development costs, as applicable.
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
upstream PP&E, net impairment assessment. These procedures also included, among others (i) testing management’s process for
assessing the recoverability of carrying amounts of upstream PP&E, net; (ii) evaluating the appropriateness of the undiscounted cash
flow models; (iii) testing the completeness and accuracy of underlying data used in the models; and (iv) evaluating the reasonableness
of significant assumptions used by management related to future crude oil and natural gas commodity prices, production volumes, and
development costs. Evaluating the reasonableness of management’s assumptions related to future crude oil and natural gas commodity
prices involved comparing the assumption against observable market data. Evaluating future development costs involved evaluating
the reasonableness of the assumptions as compared to the past performance of the Company. The work of management’s specialists
was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes as stated in the
Critical Audit Matter titled “Impact of Proved Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net” and the
reasonableness of the future production 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.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
February 24, 2021
We have served as the Corporation’s auditor since 1934.
64
CONSOLIDATED STATEMENT OF INCOME
Revenues and other income
Sales and other operating revenue
Income from equity affiliates
Other income
Total revenues and other income
Costs and other deductions
Crude oil and product purchases
Production and manufacturing expenses
Selling, general and administrative expenses
Depreciation and depletion (includes impairments)
Exploration expenses, including dry holes
Non-service pension and postretirement benefit expense
Interest expense
Other taxes and duties
Total costs and other deductions
Income (Loss) before income taxes
Income tax expense (benefit)
Net income (loss) including noncontrolling interests
Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to ExxonMobil
Earnings (Loss) per common share (dollars)
Earnings (Loss) per common share - assuming dilution (dollars)
Note
Reference
Number
7
3, 9
17
19
19
12
12
2020
2019
2018
(millions of dollars)
178,574
255,583
279,332
1,732
1,196
5,441
3,914
7,355
3,525
181,502
264,938
290,212
143,801
156,172
94,007
30,431
10,168
46,009
1,285
1,205
1,158
26,122
210,385
36,826
11,398
18,998
1,269
1,235
830
30,525
244,882
(28,883)
20,056
(5,632)
5,282
(23,251)
14,774
(811)
434
(22,440)
14,340
36,682
11,480
18,745
1,466
1,285
766
32,663
259,259
30,953
9,532
21,421
581
20,840
(5.25)
3.36
4.88
(5.25)
3.36
4.88
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
65
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Net income (loss) including noncontrolling interests
Other comprehensive income (loss) (net of income taxes)
Foreign exchange translation adjustment
Adjustment for foreign exchange translation (gain)/loss included in net income
Postretirement benefits reserves adjustment (excluding amortization)
Amortization and settlement of postretirement benefits reserves adjustment included
in net periodic benefit costs
Total other comprehensive income (loss)
Comprehensive income (loss) including noncontrolling interests
Comprehensive income (loss) attributable to noncontrolling interests
Comprehensive income (loss) attributable to ExxonMobil
2020
2019
2018
(millions of dollars)
(23,251)
14,774
21,421
1,916
14
30
896
2,856
1,735
—
(2,092)
582
225
(20,395)
14,999
(743)
588
(19,652)
14,411
(5,077)
196
280
931
(3,670)
17,751
174
17,577
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
66
CONSOLIDATED BALANCE SHEET
Assets
Current assets
Cash and cash equivalents
Notes and accounts receivable - net
Inventories
Crude oil, products and merchandise
Materials and supplies
Other current assets
Total current assets
Investments, advances and long-term receivables
Property, plant and equipment, at cost, less accumulated depreciation and depletion
Other assets, including intangibles - net
Total assets
Liabilities
Current liabilities
Notes and loans payable
Accounts payable and accrued liabilities
Income taxes payable
Total current liabilities
Long-term debt
Postretirement benefits reserves
Deferred income tax liabilities
Long-term obligations to equity companies
Other long-term obligations
Total liabilities
Commitments and contingencies
Equity
Common stock without par value
(9,000 million shares authorized, 8,019 million shares issued)
Earnings reinvested
Accumulated other comprehensive income
Common stock held in treasury
(3,786 million shares in 2020 and 3,785 million shares in 2019)
ExxonMobil share of equity
Noncontrolling interests
Total equity
Total liabilities and equity
Note
Reference
Number
December 31,
2020
December 31,
2019
(millions of dollars)
6
3
8
9
6
6
14
17
19
16
4,364
20,581
3,089
26,966
14,169
4,681
1,098
44,893
43,515
227,553
16,789
332,750
20,458
35,221
684
56,363
47,182
22,415
18,165
3,253
21,242
14,010
4,518
1,469
50,052
43,164
253,018
16,363
362,597
20,578
41,831
1,580
63,989
26,342
22,304
25,620
3,988
21,416
168,620
163,659
15,688
383,943
15,637
421,341
(16,705)
(19,493)
(225,776)
(225,835)
157,150
191,650
6,980
164,130
332,750
7,288
198,938
362,597
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
67
CONSOLIDATED STATEMENT OF CASH FLOWS
Cash flows from operating activities
Net income (loss) including noncontrolling interests
Adjustments for noncash transactions
Depreciation and depletion (includes impairments)
Deferred income tax charges/(credits)
Postretirement benefits expense
in excess of/(less than) net payments
Other long-term obligation provisions
in excess of/(less than) payments
Dividends received greater than/(less than) equity in current
earnings of equity companies
Changes in operational working capital, excluding cash and debt
Reduction/(increase)
- Notes and accounts receivable
Increase/(reduction)
- Accounts and other payables
- Inventories
- Other current assets
Net (gain)/loss on asset sales
All other items - net
Net cash provided by operating activities
Cash flows from investing activities
Additions to property, plant and equipment
Proceeds associated with sales of subsidiaries, property, plant
and equipment, and sales and returns of investments
Additional investments and advances
Other investing activities including collection of advances
Net cash used in investing activities
Cash flows from financing activities
Additions to long-term debt
Reductions in long-term debt
Reductions in short-term debt
Additions/(reductions) in commercial paper, and debt with
three months or less maturity
Contingent consideration payments
Cash dividends to ExxonMobil shareholders
Cash dividends to noncontrolling interests
Changes in noncontrolling interests
Common stock acquired
Net cash provided by (used in) financing activities
Effects of exchange rate changes on cash
Increase/(decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Note
Reference
Number
2020
2019
2018
(millions of dollars)
(23,251)
14,774
21,421
3, 9
19
46,009
(8,856)
18,998
(944)
18,745
(60)
5
5
498
109
1,070
(1,269)
(3,038)
(68)
979
(936)
(1,684)
5,384
(315)
420
(7,142)
4
2,207
14,668
(2,640)
72
(234)
3,725
(1,710)
1,540
29,716
(545)
(3,107)
(25)
2,321
(1,993)
(61)
36,014
(17,282)
(24,361)
(19,574)
999
(4,857)
2,681
3,692
(3,905)
1,490
4,123
(1,981)
986
(18,459)
(23,084)
(16,446)
23,186
(8)
7,052
(1)
46
—
(1,703)
(4,043)
(4,752)
(1,334)
(21)
5,654
—
(219)
—
(14,865)
(14,652)
(13,798)
(188)
623
(405)
5,285
(219)
1,275
3,089
4,364
(192)
158
(594)
(243)
146
(626)
(6,618)
(19,446)
33
47
3,042
3,089
(257)
(135)
3,177
3,042
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
68
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
ExxonMobil Share of Equity
Common
Stock
Earnings
Reinvested
Accumulated
Other
Comprehensive
Income
Common
Stock Held
in
Treasury
(millions of dollars)
ExxonMobil
Share of
Equity
Non-
controlling
Interests
Total
Equity
Balance as of December 31, 2017
14,656
414,540
(16,262)
(225,246)
187,688
6,812
194,500
Amortization of stock-based awards
Other
Net income (loss) for the year
Dividends - common shares
Cumulative effect of accounting change
Other comprehensive income
Acquisitions, at cost
Dispositions
758
(156)
—
—
—
—
—
—
—
—
20,840
(13,798)
71
—
—
—
—
—
—
—
(39)
(3,263)
—
—
—
—
—
—
—
—
(626)
319
758
(156)
20,840
(13,798)
32
(3,263)
(626)
319
—
436
581
(243)
15
(407)
(460)
—
758
280
21,421
(14,041)
47
(3,670)
(1,086)
319
Balance as of December 31, 2018
15,258
421,653
(19,564)
(225,553)
191,794
6,734
198,528
Amortization of stock-based awards
Other
Net income (loss) for the year
Dividends - common shares
Other comprehensive income
Acquisitions, at cost
Dispositions
697
(318)
—
—
—
—
—
—
—
14,340
(14,652)
—
—
—
—
—
—
—
71
—
—
—
—
—
—
—
(594)
312
697
(318)
14,340
(14,652)
71
(594)
312
—
489
434
(192)
154
(331)
—
697
171
14,774
(14,844)
225
(925)
312
Balance as of December 31, 2019
15,637
421,341
(19,493)
(225,835)
191,650
7,288
198,938
Amortization of stock-based awards
Other
Net income (loss) for the year
Dividends - common shares
Cumulative effect of accounting change
Other comprehensive income
Acquisitions, at cost
Dispositions
696
(645)
—
—
—
—
—
—
—
—
(22,440)
(14,865)
(93)
—
—
—
—
—
—
—
—
2,788
—
—
—
—
—
—
—
—
(405)
464
696
(645)
(22,440)
(14,865)
(93)
2,788
(405)
464
—
692
(811)
(188)
(1)
68
(68)
—
696
47
(23,251)
(15,053)
(94)
2,856
(473)
464
Balance as of December 31, 2020
15,688
383,943
(16,705)
(225,776)
157,150
6,980
164,130
Common Stock Share Activity
Balance as of December 31, 2017
Acquisitions
Dispositions
Balance as of December 31, 2018
Acquisitions
Dispositions
Balance as of December 31, 2019
Acquisitions
Dispositions
Balance as of December 31, 2020
Issued
Held in
Treasury
(millions of shares)
Outstanding
8,019
—
—
8,019
—
—
8,019
—
—
8,019
(3,780)
(8)
6
(3,782)
(8)
5
(3,785)
(8)
7
(3,786)
4,239
(8)
6
4,237
(8)
5
4,234
(8)
7
4,233
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
69
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the
management of Exxon Mobil Corporation.
The Corporation’s principal business involves exploration for, and production of, crude oil and natural gas and manufacture, trade,
transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products.
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires
management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of
contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases
to conform to the 2020 presentation basis.
1. Summary of Accounting Policies
Principles of Consolidation and Accounting for Investments
The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the
Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses. Amounts representing the
Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are included in “Investments,
advances and long-term receivables”. The Corporation’s share of the net income of these companies is included in the Consolidated
Statement of Income caption “Income from equity affiliates”.
Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain
factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method
of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights.
These include the right to approve operating policies, expense budgets, financing and investment plans, and management
compensation and succession plans.
Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed
to determine if such evidence represents a loss in value that is other than temporary. Examples of key indicators include a history of
operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial
condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair
value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment,
discounted cash flows are used to assess fair value.
Investments in equity securities other than consolidated subsidiaries and equity method investments are measured at fair value with
changes in fair value recognized in net income. The Corporation uses the modified approach for equity securities that do not have a
readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes
resulting from observable price changes in orderly transactions in a similar investment of the same issuer.
The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in
“Accumulated other comprehensive income”.
Revenue Recognition
The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing
market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments to
reflect market conditions. Revenue is recognized at the amount the Corporation expects to receive when the customer has taken
control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain
sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued
when the sale is recognized, and are finalized when the price is available. Such adjustments to revenue from performance obligations
satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Future volume
delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases.
These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price
volatility.
Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and
recorded as exchanges measured at the book value of the item sold.
“Sales and other operating revenue” and “Notes and accounts receivable” primarily arise from contracts with customers. Long-term
receivables are primarily from non-customers. Contract assets are mainly from marketing assistance programs and are not significant.
Contract liabilities are mainly customer prepayments and accruals of expected volume discounts and are not significant.
70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income and Other Taxes
The Corporation excludes from the Consolidated Statement of Income certain sales and value-added taxes imposed on and concurrent
with revenue-producing transactions with customers and collected on behalf of governmental authorities. Similar taxes, for which the
Corporation is not considered to be an agent for the government, are reported on a gross basis (included in both “Sales and other
operating revenue” and “Other taxes and duties”).
The Corporation accounts for U.S. tax on global intangible low-taxed income as an income tax expense in the period in which it is
incurred.
Derivative Instruments
The Corporation may use derivative instruments for trading purposes and to offset exposures associated with commodity prices,
foreign currency exchange rates and interest rates that arise from existing assets, liabilities, firm commitments and forecasted
transactions. All derivative instruments, except those designated as normal purchase and normal sale, are recorded at fair value.
Derivative assets and liabilities with the same counterparty are netted if the right of offset exists and certain other criteria are met.
Collateral payables or receivables are netted against derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from adjusting a derivative to fair value depends on the purpose for the
derivative. All gains and losses from derivative instruments for which the Corporation does not apply hedge accounting are
immediately recognized in earnings. The Corporation may designate derivatives as fair value or cash flow hedges. For fair value
hedges, the gain or loss from derivative instruments and the offsetting gain or loss from the hedged item are recognized in earnings.
For cash flow hedges, the gain or loss from the derivative instrument is initially reported as a component of other comprehensive
income and subsequently reclassified into earnings in the period that the forecasted transaction affects earnings.
Fair Value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market
participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value.
Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other
than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs
are inputs that are not observable in the market.
Inventories
Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under
the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and
indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative
expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.
Property, Plant and Equipment
Cost Basis. The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this
method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether
unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient
quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the
reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to
expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development
costs, including costs of productive wells and development dry holes, are capitalized.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization are primarily determined under either the unit-
of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into
consideration.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and
natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with productive depletable extractive
properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are
estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and
natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction
points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an
equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used
in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For
example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation
uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.
71
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the
resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a
unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of
proved reserves, appropriately adjusted for production and technical changes.
Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight-line
basis over a 25-year life. Service station buildings and fixed improvements generally are depreciated over a 20-year life. Maintenance
and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the
assets replaced are retired.
Impairment Assessment. The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or
changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances
which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:
•
•
•
•
•
•
a significant decrease in the market price of a long-lived asset;
a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a
significant decrease in current and projected reserve volumes;
a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action
or assessment by a regulator;
an accumulation of project costs significantly in excess of the amount originally expected;
a current-period operating loss combined with a history and forecast of operating or cash flow losses; and
a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before
the end of its previously estimated useful life.
Asset valuation analysis, profitability reviews and other periodic control processes assist the Corporation in assessing whether events
or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.
In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that
prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will
occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand
fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate
production from new discoveries, field developments and technology and efficiency advancements. OPEC investment activities and
production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and
levels of prosperity. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the value of
these assets is predominantly based on long-term views of future commodity prices and development and production costs. During the
lifespan of these major assets, the Corporation expects that oil and gas prices will experience significant volatility, and consequently
these assets will experience periods of higher earnings and periods of lower earnings, or even losses.
In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the
Corporation considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are
subject to wide fluctuations, longer-term price views are more stable and meaningful for purposes of assessing future cash flows.
When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may
result in changes to the Corporation’s price or margin assumptions it uses for its capital investment decisions. To the extent those
changes result in a significant reduction to its oil price, natural gas price or margin ranges, the Corporation may consider that situation,
in conjunction with other events or changes in circumstances such as a history of operating losses, an indicator of potential impairment
for certain assets.
In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas
Exploration and Production Activities is required to use prices based on the average of first-of-month prices. These prices represent
discrete points in time and could be higher or lower than the Corporation’s price assumptions which are used for impairment
assessments. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows
to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and
therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment
assessment.
72
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year.
This process is aligned with the requirements of ASC 360 and ASC 932, and relies in part on the Corporation’s planning and
budgeting cycle. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the
Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In
performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely
independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the Corporation’s
assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses
to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude
oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and
operating costs, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles,
throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved
reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimates for impairment testing exclude the
effects of derivative instruments.
An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying value. Impairments are measured
by the amount by which the carrying value exceeds fair value. Fair value is based on market prices if an active market exists for the
asset group, or discounted cash flows using a discount rate commensurate with the risk.
Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are
assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's
future development plans, the estimated economic chance of success and the length of time that the Corporation expects to hold the
properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and
average holding period.
Other. Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of
costs applicable to any interest retained nor any substantial obligation for future performance by the Corporation. Losses on properties
sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying
value.
Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the
historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed
engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in
property, plant and equipment and are depreciated over the service life of the related assets.
Environmental Liabilities
Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be
reasonably estimated. These liabilities are not reduced by possible recoveries from third parties, and projected cash expenditures are
not discounted.
Foreign Currency Translation
The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary
economic environment in which each subsidiary operates.
Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of
high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream
operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom and
continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they
predominantly sell crude and natural gas production into U.S. dollar-denominated markets.
For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.
73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. Accounting Changes
Effective January 1, 2020, the Corporation adopted the Financial Accounting Standards Board’s update, Financial Instruments –
Credit Losses (Topic 326), as amended. The standard requires a valuation allowance for credit losses be recognized for certain
financial assets that reflects the current expected credit loss over the asset’s contractual life. The valuation allowance considers the risk
of loss, even if remote, and considers past events, current conditions and reasonable and supportable forecasts. The standard requires
this expected loss methodology for trade receivables, certain other financial assets and off-balance sheet credit exposures. The
cumulative effect adjustment related to the adoption of this standard reduced ExxonMobil's share of equity by $93 million.
The Corporation is exposed to credit losses primarily through sales of petroleum products, crude oil, natural gas liquids and natural
gas, as well as loans to equity companies and joint venture receivables. A counterparty’s ability to pay is assessed through a credit
review process that considers payment terms, the counterparty’s established credit rating or the Corporation’s assessment of the
counterparty’s credit worthiness, contract terms, country of operation, and other risks. The Corporation can require prepayment or
collateral to mitigate certain credit risks.
The Corporation groups financial assets into portfolios that share similar risk characteristics for purposes of determining the allowance
for credit losses and assesses if a significant change in the risk of credit loss has occurred. Among the quantitative and qualitative
factors considered are historical financial data, current conditions, industry and country risk, current credit ratings and the quality of
third-party guarantees secured from the counterparty. Financial assets are written off in whole, or in part, when practical recovery
efforts have been exhausted and no reasonable expectation of recovery exists. Subsequent recoveries of amounts previously written off
are recognized in earnings. The Corporation manages receivable portfolios using past due balances as a key credit quality indicator.
The Corporation recognizes a credit allowance for off-balance sheet credit exposures as a liability on the balance sheet, separate from
the allowance for credit losses related to recognized financial assets. Among these exposures are unfunded loans to equity companies
and financial guarantees that cannot be cancelled unilaterally by the Corporation.
Allowance for Current Expected Credit Losses
Total
503
109
14
(5)
2
623
Notes and Accounts Receivable Advances and
Long-Term
Receivables
Trade
Other
Liabilities for
Off- Balance
Sheet Assets
Balance at December 31, 2019
Cumulative effect of accounting change
Current period provision
Write-offs charged against the allowance
Other
Balance at December 31, 2020
Balance at December 31, 2020
34
52
9
(2)
2
95
(millions of dollars)
56
6
15
(3)
(3)
71
413
39
(9)
—
3
446
—
12
(1)
—
—
11
Financial Assets subject to credit losses standard - net
16,250
1,962
9,447
74
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. Miscellaneous Financial Information
Research and development expenses totaled $1,016 million in 2020, $1,214 million in 2019, and $1,116 million in 2018.
Net income included before-tax aggregate foreign exchange transaction losses of $24 million, $104 million and $138 million in 2020,
2019 and 2018, respectively.
In 2020, 2019, and 2018, net income included gains of $41 million, $523 million, and $107 million, respectively, attributable to the
combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to
exceed their LIFO carrying values by $5.4 billion and $9.7 billion at December 31, 2020, and 2019, respectively.
Crude oil, products and merchandise as of year-end 2020 and 2019 consist of the following:
Crude oil
Petroleum products
Chemical products
Gas/other
Total
Dec 31,
2020
Dec 31,
2019
(millions of dollars)
5,354
5,138
3,023
654
14,169
5,111
5,281
3,240
378
14,010
Mainly as a result of declines in prices for crude oil, natural gas and petroleum products in 2020 and a significant decline in its market
capitalization at the end of the first quarter, the Corporation recognized before-tax goodwill impairment charges of $611 million in
Upstream, Downstream, and Chemical reporting units. Fair value of the goodwill reporting units primarily reflected market-based
estimates of historical EBITDA multiples at the end of the first quarter. Charges related to goodwill impairments are included in
“Depreciation and depletion” on the Statement of Income.
75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Other Comprehensive Income Information
ExxonMobil Share of Accumulated Other
Comprehensive Income
Balance as of December 31, 2017
Current period change excluding amounts reclassified from accumulated other
comprehensive income
Amounts reclassified from accumulated other comprehensive income
Total change in accumulated other comprehensive income
Balance as of December 31, 2018
Current period change excluding amounts reclassified from accumulated other
comprehensive income
Amounts reclassified from accumulated other comprehensive income
Total change in accumulated other comprehensive income
Balance as of December 31, 2019
Current period change excluding amounts reclassified from accumulated other
comprehensive income (1)
Amounts reclassified from accumulated other comprehensive income
Total change in accumulated other comprehensive income
Balance as of December 31, 2020
Cumulative
Foreign
Exchange
Translation
Adjustment
Postretirement
Benefits
Reserves
Adjustment
(millions of dollars)
Total
(9,482)
(6,780)
(16,262)
(4,595)
196
201
896
(4,399)
1,097
(4,394)
1,092
(3,302)
(13,881)
(5,683)
(19,564)
1,435
—
1,435
(12,446)
(1,927)
563
(1,364)
(7,047)
(492)
563
71
(19,493)
1,818
14
1,832
95
861
956
1,913
875
2,788
(10,614)
(6,091)
(16,705)
(1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) of $(355) million, net of taxes.
Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense)
Foreign exchange translation gain/(loss) included in net income
(Statement of Income line: Other income)
Amortization and settlement of postretirement benefits reserves adjustment included
in net periodic benefit costs
(Statement of Income line: Non-service pension and postretirement benefit
expense)
2020
2019
2018
(millions of dollars)
(14)
—
(196)
(1,158)
(751)
(1,208)
Income Tax (Expense)/Credit For
Components of Other Comprehensive Income
Foreign exchange translation adjustment
Postretirement benefits reserves adjustment (excluding amortization)
Amortization and settlement of postretirement benefits reserves adjustment included
in net periodic benefit costs
Total
76
2020
118
109
(262)
(35)
2019
2018
(millions of dollars)
88
719
(169)
638
32
(193)
(277)
(438)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Cash Flow Information
The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid
investments with maturities of three months or less when acquired are classified as cash equivalents.
For 2020, the “Depreciation and depletion” and “Deferred income tax charges/(credits)” on the Consolidated Statement of Cash Flows
includes impacts from asset impairments, primarily in Upstream.
For 2019, the “Net (gain)/loss on asset sales” on the Consolidated Statement of Cash Flows includes before-tax amounts from the sale
of non-operated upstream assets in Norway and upstream asset transactions in the U.S. The Norway assets were sold for $4.5 billion,
resulting in a gain of $3.7 billion and cash proceeds of $3.1 billion in 2019. For 2018, the number includes before-tax amounts from
the sale of service stations in Germany, the divestment of the Augusta refinery in Italy, and the sale of an undeveloped upstream
property in Australia. These net gains are reported in “Other income” on the Consolidated Statement of Income.
In 2020, the “Additions/(reductions) in commercial paper, and debt with three months or less maturity” on the Consolidated Statement
of Cash Flows includes a net $8.4 billion addition of commercial paper with maturity over three months. The gross amount issued was
$35.4 billion, while the gross amount repaid was $27.0 billion. In 2019, the number includes a net $4.6 billion addition of commercial
paper with maturity over three months. The gross amount issued was $18.9 billion, while the gross amount repaid was $14.3 billion. In
2018, the number includes a net $275 million addition of commercial paper with maturity over three months. The gross amount issued
was $4.0 billion, while the gross amount repaid was $3.8 billion.
Income taxes paid
Cash interest paid
Included in cash flows from operating activities
Capitalized, included in cash flows from investing activities
Total cash interest paid
6. Additional Working Capital Information
Notes and accounts receivable
Trade, less reserves of $96 million and $34 million
Other, less reserves of $378 million and $371 million
Total
Notes and loans payable
Bank loans
Commercial paper
Long-term debt due within one year
Total
Accounts payable and accrued liabilities
Trade payables
Payables to equity companies
Accrued taxes other than income taxes
Other
Total
2020
2019
2018
(millions of dollars)
2,428
7,018
9,294
786
665
1,451
560
731
1,291
303
652
955
Dec 31,
2020
Dec 31,
2019
(millions of dollars)
16,339
4,242
20,581
222
17,306
2,930
20,458
17,499
6,476
3,408
7,838
35,221
21,100
5,866
26,966
316
18,561
1,701
20,578
24,694
6,825
3,301
7,011
41,831
The Corporation has short-term committed lines of credit of $11.3 billion which were unused as of December 31, 2020. These lines
are available for general corporate purposes.
The weighted-average interest rate on short-term borrowings outstanding was 0.2 percent and 1.7 percent at December 31, 2020, and
2019, respectively.
77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. Equity Company Information
The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-
owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1).
These companies are primarily engaged in oil and gas exploration and production, and natural gas marketing in North America;
natural gas exploration, production and distribution in Europe; liquefied natural gas (LNG) operations and transportation of crude oil
in Africa; and exploration, production, LNG operations, and the manufacture and sale of petroleum and petrochemical products in
Asia and the Middle East. Also included are several refining, petrochemical manufacturing and marketing ventures.
The share of total equity company revenues from sales to ExxonMobil consolidated companies was 11 percent, 13 percent and 14
percent in the years 2020, 2019 and 2018, respectively.
The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships.
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 factors giving rise to the
difference. The amortization of this difference, as appropriate, is included in “Income from equity affiliates” on the Consolidated
Statement of Income.
Impairments related to U.S. upstream equity investments of $600 million are included in “Income from equity affiliates” on the
Consolidated Statement of Income.
Equity Company
Financial Summary
Total revenues
Income before income taxes
Income taxes
Income from equity affiliates
Current assets
Long-term assets
Total assets
Current liabilities
Long-term liabilities
Net assets
2020
2019
2018
Total
ExxonMobil
Share
Total
ExxonMobil
Share
Total
ExxonMobil
Share
69,954
12,743
4,333
8,410
33,419
150,358
183,777
18,827
66,053
98,897
(millions of dollars)
21,282
102,365
31,240
112,938
2,830
870
1,960
11,969
41,457
53,426
5,245
19,927
28,254
29,424
9,725
19,699
36,035
143,321
179,356
24,583
61,022
93,751
7,927
2,500
5,427
12,661
40,001
52,662
6,939
18,158
27,565
37,203
11,568
25,635
38,670
128,830
167,500
27,324
56,913
83,263
34,539
10,482
3,151
7,331
13,394
35,970
49,364
7,606
17,109
24,649
78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A list of significant equity companies as of December 31, 2020, together with the Corporation’s percentage ownership interest, is
detailed below:
Upstream
Aera Energy LLC
Barzan Gas Company Limited
BEB Erdgas und Erdoel GmbH & Co. KG
Cameroon Oil Transportation Company S.A.
Caspian Pipeline Consortium - Kazakhstan
CORAL FLNG, S.A.
Cross Timbers Energy, LLC
Golden Pass LNG Terminal LLC
Golden Pass Pipeline LLC
Marine Well Containment Company LLC
Mozambique Rovuma Venture, S.p.A.
Nederlandse Aardolie Maatschappij B.V.
Papua New Guinea Liquefied Natural Gas Global Company LDC
Permian Highway Pipeline LLC
Qatar Liquefied Gas Company Limited
Qatar Liquefied Gas Company Limited (2)
Ras Laffan Liquefied Natural Gas Company Limited
Ras Laffan Liquefied Natural Gas Company Limited (II)
Ras Laffan Liquefied Natural Gas Company Limited (3)
South Hook LNG Terminal Company Limited
Tengizchevroil, LLP
Terminale GNL Adriatico S.r.l.
Downstream
Alberta Products Pipe Line Ltd.
Fujian Refining & Petrochemical Co. Ltd.
Permian Express Partners LLC
Saudi Aramco Mobil Refinery Company Ltd.
Chemical
Al-Jubail Petrochemical Company
Gulf Coast Growth Ventures LLC
Saudi Yanbu Petrochemical Co.
Percentage
Ownership
Interest
48
7
50
41
8
25
50
30
30
10
36
50
33
20
10
24
25
31
30
24
25
71
45
25
12
50
50
50
50
79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. Investments, Advances and Long-Term Receivables
Equity method company investments and advances
Investments
Advances, net of allowances of $31 million in 2020
Total equity method company investments and advances
Equity securities carried at fair value and other investments at adjusted cost basis
Long-term receivables and miscellaneous, net of reserves of $6,115 million and $5,643 million
Total
9. Property, Plant and Equipment and Asset Retirement Obligations
Dec 31, 2020
Dec 31, 2019
(millions of dollars)
29,772
8,812
38,584
143
4,788
43,515
29,291
8,542
37,833
190
5,141
43,164
Property, Plant and Equipment
Upstream
Downstream
Chemical
Other
Total
December 31, 2020
December 31, 2019
Cost
Net
Cost
Net
386,614
57,922
42,868
17,918
505,322
(millions of dollars)
167,472
27,716
21,924
10,441
227,553
376,041
52,527
40,788
17,346
486,702
196,767
24,506
21,260
10,485
253,018
The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year.
This process is aligned with the requirements of ASC 360 and ASC 932, and relies in part on the Corporation’s planning and
budgeting cycle. In 2020, the Corporation identified a number of situations where events or changes in circumstances indicated that
the carrying value of certain long-lived assets may not be recoverable. Those situations primarily related to the annual review and
approval of the Corporation's business and strategic plan. As part of the planning process, the Corporation assessed its full portfolio to
prioritize assets with the highest future value potential within its broad range of available opportunities in order to optimize resources
within current levels of debt and operating cash flow, as well as identify potential asset divestment candidates. This effort included a
re-assessment of dry gas assets, primarily in North America, which previously had been included in the Corporation’s future
development plans. Under the plan as approved, the Corporation no longer plans to develop a significant portion of its dry gas
portfolio, including a portion of its resources in the Appalachian, Rocky Mountains, Oklahoma, Texas, Louisiana, and Arkansas
regions of the U.S., as well as resources in Western Canada and Argentina. The decision not to develop these assets resulted in non-
cash, before-tax charges of $24.4 billion in Upstream to reduce the carrying value of those assets to fair value. Other before-tax
impairment charges in 2020 included $0.9 billion in Upstream, $0.5 billion in Downstream, and $0.1 billion in Chemical. Impairment
charges are primarily recognized in the lines “Depreciation and depletion” and “Exploration expenses, including dry holes” on the
Consolidated Statement of Income.
The assessment of fair value requires the use of Level 3 inputs and assumptions that are based upon the views of a likely market
participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics
from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and
assumptions used in discounted cash flow models include estimates of future production volumes, commodity prices which were
consistent with the average of third-party industry experts and government agencies, drilling and development costs, and discount
rates ranging from 6 percent to 8 percent which are reflective of the characteristics of the asset group.
Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price outlooks,
changes in the allocation of capital, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural
gas price increases. However, due to the inherent difficulty in predicting future commodity prices, and the relationship between
industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges
related to the Corporation’s long-lived assets. In 2019 and 2018, the before-tax impairment charges were $0.1 billion and $0.7 billion,
respectively.
Accumulated depreciation and depletion totaled $277,769 million at the end of 2020 and $233,684 million at the end of 2019. Interest
capitalized in 2020, 2019 and 2018 was $665 million, $731 million and $652 million, respectively.
80
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Asset Retirement Obligations
The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a
discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses
assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical
assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement obligations
incurred in the current period were Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part
of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present
value.
Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently
shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these
sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations
cannot be measured, since it is impossible to estimate the future settlement dates of such obligations.
The following table summarizes the activity in the liability for asset retirement obligations:
Balance at January 1
Accretion expense and other provisions
Reduction due to property sales
Payments made
Liabilities incurred
Foreign currency translation
Revisions
Balance at December 31
2020
2019
2018
(millions of dollars)
11,280
584
(77)
(669)
26
239
(136)
12,103
649
(1,085)
(827)
89
84
267
12,705
681
(333)
(600)
46
(481)
85
11,247
11,280
12,103
The long-term Asset Retirement Obligations were $10,558 million and $10,279 million at December 31, 2020, and 2019, respectively,
and are included in “Other long-term obligations.”
81
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Accounting for Suspended Exploratory Well Costs
The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify
its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and
operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not
necessarily have the same meaning as in any government payment transparency reports.
The following two tables provide details of the changes in the balance of suspended exploratory well costs as well as an aging
summary of those costs.
Change in capitalized suspended exploratory well costs:
Balance beginning at January 1
Additions pending the determination of proved reserves
Charged to expense
Reclassifications to wells, facilities and equipment based on the
determination of proved reserves
Divestments/Other
Ending balance at December 31
Ending balance attributed to equity companies included above
Period end capitalized suspended exploratory well costs:
Capitalized for a period of one year or less
Capitalized for a period of between one and five years
Capitalized for a period of between five and ten years
Capitalized for a period of greater than ten years
Capitalized for a period greater than one year - subtotal
Total
2020
2019
2018
(millions of dollars)
4,613
208
(318)
(174)
53
4,382
306
4,160
532
(46)
(37)
4
4,613
306
3,700
564
(7)
(48)
(49)
4,160
306
2020
2019
2018
(millions of dollars)
208
1,828
1,932
414
4,174
4,382
532
2,206
1,411
464
4,081
4,613
564
2,028
1,150
418
3,596
4,160
Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below
provides a breakdown of the number of projects with only exploratory well costs capitalized for a period of one year or less and those
that have had exploratory well costs capitalized for a period greater than one year.
Number of projects that only have exploratory well costs capitalized for a
period of one year or less
Number of projects that have exploratory well costs capitalized for a period
greater than one year
Total
2020
2019
2018
3
34
37
4
46
50
6
52
58
Of the 34 projects that have exploratory well costs capitalized for a period greater than one year as of December 31, 2020, 13 projects
have drilling in the preceding year or exploratory activity planned in the next two years, while the remaining 21 projects are those with
completed exploratory activity progressing toward development.
82
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below provides additional detail for those 21 projects, which total $3,181 million.
Country/Project
Dec. 31,
2020
Years Wells
Drilled /
Acquired
(millions of dollars)
Comment
Angola
– Kaombo Split Hub
Phase 2
Argentina
– La Invernada
Australia
– Gorgon Area Ullage
Brazil
– Bacalhau Phase 1
Canada
– Hibernia North
Iraq
– Kurdistan Pirmam
Kazakhstan
– Kairan
Mozambique
– Rovuma LNG Future
Non-Straddling Train
– Rovuma LNG Phase 1
– Rovuma LNG Unitized
Trains
Nigeria
– Bonga North
– Bonga SW
– Bosi
– Owowo
– Pegi
– Ukot SW
Papua New Guinea
– Papua LNG
– P'nyang
Romania
– Neptun Deep
Tanzania
– Tanzania Block 2
Vietnam
– Blue Whale
10
72
2006
Evaluating development plan to tie into planned production facilities.
2014
Evaluating development plan to tie into planned infrastructure.
347
1994 - 2015 Evaluating development plans to tie into existing LNG facilities.
284
26
109
53
120
150
35
34
3
79
67
32
41
2018
Continuing discussions with the government regarding development plan.
2019
Awaiting capacity in existing/planned infrastructure.
2015
Evaluating commercialization alternatives, while waiting for government
approval to enter Gas Holding Period.
2004 - 2007 Evaluating commercialization and field development alternatives, while
continuing discussions with the government regarding the development
plan.
2017
2017
2017
Evaluating/progressing development plan to tie into planned LNG
facilities.
Progressing development plan to tie into planned LNG facilities.
Evaluating/progressing development plan to tie into planned LNG
facilities.
2004 - 2009 Evaluating/progressing development plan for tieback to existing/planned
2001
infrastructure.
Evaluating/progressing development plan for tieback to existing/planned
infrastructure.
2002 - 2006 Development activity under way, while continuing discussions with the
government regarding development plan.
2009 - 2016 Evaluating development plan for tieback to existing production facilities.
2009
2014
Awaiting capacity in existing/planned infrastructure.
Evaluating development plan for tieback to existing production facilities.
246
116
2017
Evaluating/progressing development plans.
2012 - 2018 Evaluating/progressing development plans.
536
2012 - 2016 Continuing discussions with the government regarding development plan.
525
2012 - 2015 Evaluating development alternatives, while continuing discussions with
the government regarding development plan.
296
2011 - 2015 Evaluating/progressing development plans.
Total 2020 (21 projects)
3,181
83
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Leases
The Corporation and its consolidated affiliates generally purchase the property, plant and equipment used in operations, but there are
situations where assets are leased, primarily for drilling equipment, tankers, office buildings, railcars, and other moveable equipment.
Right of use assets and lease liabilities are established on the balance sheet for leases with an expected term greater than one year by
discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the
probability of exercising any early termination and extension options. The portion of the fixed payment related to service costs for
drilling equipment, tankers and finance leases is excluded from the calculation of right of use assets and lease liabilities. Generally,
assets are leased only for a portion of their useful lives, and are accounted for as operating leases. In limited situations assets are leased
for nearly all of their useful lives, and are accounted for as finance leases.
Variable payments under these lease agreements are not significant. Residual value guarantees, restrictions, or covenants related to
leases, and transactions with related parties are also not significant. In general, leases are capitalized using the incremental borrowing
rate of the leasing affiliate. The Corporation’s activities as a lessor are not significant.
Lease Cost
Operating lease cost
Short-term and other (net of sublease rental income)
Amortization of right of use assets
Interest on lease liabilities
Total
Lease Cost
Operating lease cost
Short-term and other (net of sublease rental income)
Amortization of right of use assets
Interest on lease liabilities
Total
Operating Leases
Drilling Rigs
and Related
Equipment
297
530
Other
Total
(millions of dollars)
2020
1,256
1,083
1,553
1,613
827
2,339
3,166
Operating Leases
Drilling Rigs
and Related
Equipment
238
926
Other
Total
(millions of dollars)
2019
1,196
1,116
1,434
2,042
1,164
2,312
3,476
Finance
Leases
143
169
312
Finance
Leases
121
133
254
84
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Balance Sheet
Right of use assets
Drilling Rigs
and Related
Equipment
Operating Leases
Other
Total
(millions of dollars)
December 31, 2020
Included in Other assets, including intangibles - net
Included in Property, plant and equipment - net
Total right of use assets
834
834
5,244
6,078
5,244
6,078
Lease liability due within one year
Included in Accounts payable and accrued liabilities
243
925
1,168
Included in Notes and loans payable
Long-term lease liability
Included in Other long-term obligations
Included in Long-term debt
Included in Long-term obligations to equity companies
589
3,405
3,994
Total lease liability
832
4,330
5,162
Finance
Leases
2,188
2,188
4
102
1,680
135
1,921
Weighted average remaining lease term - years
Weighted average discount rate - percent
5
2.2 %
12
3.0 %
11
2.9 %
20
8.9 %
Balance Sheet
Right of use assets
Drilling Rigs
and Related
Equipment
Operating Leases
Other
Total
(millions of dollars)
December 31, 2019
Included in Other assets, including intangibles - net
Included in Property, plant and equipment - net
Total right of use assets
572
572
6,061
6,633
6,061
6,633
Lease liability due within one year
Included in Accounts payable and accrued liabilities
221
990
1,211
Included in Notes and loans payable
Long-term lease liability
Included in Other long-term obligations
Included in Long-term debt
Included in Long-term obligations to equity companies
330
4,152
4,482
Total lease liability
551
5,142
5,693
Finance
Leases
1,997
1,997
15
84
1,670
139
1,908
Weighted average remaining lease term - years
Weighted average discount rate - percent
4
3.1 %
11
3.2 %
10
3.2 %
20
9.7 %
85
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Maturity Analysis of Lease Liabilities
2021
2022
2023
2024
2025
2026 and beyond
Total lease payments
Discount to present value
Total lease liability
Operating Leases
Drilling Rigs
and Related
Equipment
Other
Total
Finance
Leases
(millions of dollars)
December 31, 2020
1,031
817
482
387
342
2,157
5,216
(886)
4,330
1,290
1,073
579
458
413
2,281
6,094
(932)
5,162
259
256
97
71
71
124
878
(46)
832
268
259
252
247
240
2,544
3,810
(1,889)
1,921
In addition to the lease liabilities in the table immediately above, at December 31, 2020, undiscounted commitments for leases not yet
commenced totaled $445 million for operating leases and $4,109 million for finance leases. The finance leases relate to floating
production storage and offloading vessels, LNG transportation vessels, and a long-term hydrogen purchase agreement. The underlying
assets for these finance leases were primarily designed by, and are being constructed by, the lessors.
Other Information
Cash paid for amounts included in the measurement of lease liabilities
Cash flows from operating activities
Cash flows from investing activities
Cash flows from financing activities
Operating Leases
Drilling Rigs
and Related
Equipment
Other
Total
(millions of dollars)
Finance
Leases
2020
1,159
283
1,159
283
31
94
Noncash right of use assets recorded in exchange for lease liabilities
552
183
735
108
Other Information
Cash paid for amounts included in the measurement of lease liabilities
Cash flows from operating activities
Cash flows from investing activities
Cash flows from financing activities
Noncash right of use assets recorded for lease liabilities
For January 1 adoption of ASC 842
In exchange for lease liabilities during the period
Operating Leases
Drilling Rigs
and Related
Equipment
Other
Total
(millions of dollars)
Finance
Leases
2019
1,116
1,116
258
2,818
3,313
3,263
3,663
258
445
350
54
177
422
Disclosures under the previous lease standard (ASC 840)
Net rental cost incurred under both cancelable and noncancelable operating leases was $2,715 million in 2018.
86
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. Earnings Per Share
Earnings per common share
Net income (loss) attributable to ExxonMobil (millions of dollars)
2020
2019
(22,440)
14,340
2018
20,840
Weighted average number of common shares outstanding (millions of shares)
4,271
4,270
4,270
Earnings (Loss) per common share (dollars) (1)
Dividends paid per common share (dollars)
(5.25)
3.48
3.36
3.43
4.88
3.23
(1) The earnings (loss) per common share and earnings (loss) per common share - assuming dilution are the same in each period
shown.
87
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. Financial Instruments and Derivatives
Financial Instruments. The estimated fair value of financial instruments at December 31, 2020 and December 31, 2019, and the
related hierarchy level for the fair value measurement is as follows:
At December 31, 2020
(millions of dollars)
Fair Value
Level 1
Level 2
Level 3
Total Gross
Assets &
Liabilities
Effect of
Counterparty
Netting
Effect of
Collateral
Netting
Difference
in Carrying
Value and
Fair Value
Net
Carrying
Value
1,247
194
—
1,441
(1,282)
—
3,275
1,235
—
5,904
944
9,179
2,179
—
—
(6)
—
—
—
153
(367)
125
8,812
2,304
Assets
Derivative assets (1)
Advances to/receivables from equity
companies (2)(6)
Other long-term financial assets (3)
Liabilities
Derivative liabilities (4)
Long-term debt (5)
Long-term obligations to equity companies (6)
Other long-term financial liabilities (7)
1,443
50,263
—
—
254
125
—
—
—
4
3,530
964
1,697
50,392
3,530
964
(1,282)
(202)
—
—
—
—
—
—
—
(4,890)
(277)
44
213
45,502
3,253
1,008
At December 31, 2019
(millions of dollars)
Fair Value
Level 1
Level 2
Level 3
Total Gross
Assets &
Liabilities
Effect of
Counterparty
Netting
Effect of
Collateral
Netting
Difference
in Carrying
Value and
Fair Value
Net
Carrying
Value
533
102
—
635
(463)
(70)
—
102
—
1,941
1,145
—
6,729
974
8,670
2,119
—
—
—
—
(128)
44
8,542
2,163
Assets
Derivative assets (1)
Advances to/receivables from equity
companies (2)(6)
Other long-term financial assets (3)
Liabilities
Derivative liabilities (4)
Long-term debt (5)
Long-term obligations to equity companies (6)
Other long-term financial liabilities (7)
568
25,652
—
—
70
134
—
—
—
3
4,245
1,042
638
25,789
4,245
1,042
(463)
(105)
—
70
—
—
—
—
—
—
(1,117)
24,672
(257)
16
3,988
1,058
Included in the Balance Sheet lines: Notes and accounts receivable - net and Other assets, including intangibles - net
Included in the Balance Sheet line: Investments, advances and long-term receivables
Included in the Balance Sheet lines: Investments, advances and long term receivables and Other assets, including intangibles - net
Included in the Balance Sheet lines: Accounts payable and accrued liabilities and Other long-term obligations
(1)
(2)
(3)
(4)
(5) Excluding finance lease obligations
(6) Advances to/receivables from equity companies and long-term obligations to equity companies are mainly designated as hierarchy level 3 inputs. The fair value is
(7)
calculated by discounting the remaining obligations by a rate consistent with the credit quality and industry of the company.
Included in the Balance Sheet line: Other long-term obligations. Includes contingent consideration related to a prior year acquisition where fair value is based on
expected drilling activities and discount rates.
The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $23 billion of long-
term debt during 2020.
At December 31, 2020 and December 31, 2019, the Corporation had $504 million and $379 million of collateral under master netting
arrangements not offset against the derivatives on the Consolidated Balance Sheet, primarily related to initial margin requirements.
88
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the
Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in commodity prices,
currency rates and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage
commodity price risk and for trading purposes. Commodity contracts held for trading purposes are presented in the Consolidated
Statement of Income on a net basis in the line “Sales and other operating revenue”. The Corporation’s commodity derivatives are not
accounted for under hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which
are material to the Corporation’s financial position as of December 31, 2020 and 2019, or results of operations for the years ended
2020, 2019 and 2018.
Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing
exchanges and the quality of and financial limits placed on derivative counterparties. The Corporation maintains a system of controls
that includes the authorization, reporting and monitoring of derivative activity.
The net notional long/(short) position of derivative instruments at December 31, 2020, and December 31, 2019, was as follows:
Crude oil (barrels)
Petroleum products (barrels)
Natural gas (MMBTUs)
December 31,
December 31,
2020
2019
(millions)
40
(46)
(500)
57
(38)
(165)
Realized and unrealized gains/(losses) on derivative instruments that were recognized in the Consolidated Statement of Income are
included in the following lines on a before-tax basis:
Sales and other operating revenue
Crude oil and product purchases
Total
14. Long-Term Debt
2020
2019
2018
(millions of dollars)
404
(407)
(3)
(412)
179
(233)
130
(120)
10
At December 31, 2020, long-term debt consisted of $41,026 million due in U.S. dollars and $6,156 million representing the U.S.
dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-
term debt, totaling $2,930 million, which matures within one year and is included in current liabilities. The increase in the estimated
fair value and book value of long-term debt reflects the Corporation’s issuance of $23 billion of long-term debt during 2020. The
amounts of long-term debt, excluding finance lease obligations, maturing in each of the four years after December 31, 2021, in
millions of dollars, are: 2022 – $3,340; 2023 – $4,024; 2024 – $3,968; and 2025 – $4,672. At December 31, 2020, the Corporation had
no unused long-term lines of credit.
The Corporation may use non-derivative financial instruments, such as its foreign currency-denominated debt, as hedges of its net
investments in certain foreign subsidiaries. Under this method, the change in the carrying value of the financial instruments due to
foreign exchange fluctuations is reported in accumulated other comprehensive income. As of December 31, 2020, the Corporation has
designated its $5.5 billion of Euro-denominated long-term debt and related accrued interest as a net investment hedge of its European
business. The net investment hedge is deemed to be perfectly effective.
89
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized long-term debt at year-end 2020 and 2019 are shown in the table below:
Average
Rate (1)
Dec 31,
2020
Dec 31,
2019
(millions of dollars)
Exxon Mobil Corporation (2)
2.222% notes due 2021
2.397% notes due 2022
1.902% notes due 2022
Floating-rate notes due 2022 (Issued 2015)
Floating-rate notes due 2022 (Issued 2019)
1.571% notes due 2023
2.726% notes due 2023
3.176% notes due 2024
2.019% notes due 2024
2.709% notes due 2025
2.992% notes due 2025
3.043% notes due 2026
2.275% notes due 2026
3.294% notes due 2027
2.440% notes due 2029
3.482% notes due 2030
2.610% notes due 2030
2.995% notes due 2039
4.227% notes due 2040
3.567% notes due 2045
4.114% notes due 2046
3.095% notes due 2049
4.327% notes due 2050
3.452% notes due 2051
Exxon Mobil Corporation - Euro-denominated
0.142% notes due 2024
0.524% notes due 2028
0.835% notes due 2032
1.408% notes due 2039
XTO Energy Inc. (3)
6.100% senior notes due 2036
6.750% senior notes due 2037
6.375% senior notes due 2038
Mobil Corporation
8.625% debentures due 2021
Industrial revenue bonds due 2022-2051
Other U.S. dollar obligations
Other foreign currency obligations
Finance lease obligations
Debt issuance costs
Total long-term debt
1.118%
1.189%
—
1,150
750
500
750
2,750
1,250
1,000
1,000
1,750
2,807
2,500
1,000
1,000
1,250
2,000
2,000
750
2,091
1,000
2,500
1,500
2,750
2,750
1,841
1,227
1,227
1,227
192
294
227
—
2,500
1,150
750
500
750
—
1,250
1,000
1,000
1,750
—
2,500
1,000
—
1,250
—
—
750
—
1,000
2,500
1,500
—
—
—
—
—
—
193
296
229
250
0.437%
8.730%
2,461
78
61
1,680
(131)
47,182
2,461
89
64
1,670
(60)
26,342
(1) Average effective interest rate for debt and average imputed interest rate for finance leases at December 31, 2020.
(2) Includes premiums of $148 million in 2020.
(3) Includes premiums of $87 million in 2020 and $92 million in 2019.
90
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. Incentive Program
The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock, and other forms of
awards. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding
awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs may be granted at
prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. The maximum number of
shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited, expire, or are settled in
cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made
until the available shares are depleted, unless the Board terminates the plan early. At the end of 2020, remaining shares available for
award under the 2003 Incentive Program were 71 million.
Restricted Stock and Restricted Stock Units. Awards totaling 8,681 thousand, 8,936 thousand, and 8,771 thousand of restricted
(nonvested) common stock units were granted in 2020, 2019, and 2018, respectively. Compensation expense for these awards is based
on the price of the stock at the date of grant and is recognized in income over the requisite service period. Shares for these awards are
issued to employees from treasury stock. The units that are settled in cash are recorded as liabilities and their changes in fair value are
recognized over the vesting period. During the applicable restricted periods, the shares and units may not be sold or transferred and are
subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares and units in each award
vesting after three years and the remaining 50 percent vesting after seven years. Awards granted to a small number of senior
executives have vesting periods of five years for 50 percent of the award and of 10 years for the remaining 50 percent of the award,
except that for awards granted prior to 2020 the vesting of the 10-year portion of the award is delayed until retirement if later than 10
years.
The Corporation has purchased shares in the open market and through negotiated transactions to offset shares or units settled in shares
issued in conjunction with benefit plans and programs. The Corporation suspended its first quarter 2021 anti-dilutive share repurchase
program due to current market uncertainty and intends to resume this program in the future as market conditions improve.
The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2020.
Restricted stock and units outstanding
Issued and outstanding at January 1
Awards issued in 2020
Vested
Forfeited
Issued and outstanding at December 31
Value of restricted stock units
Grant price (dollars)
Value at date of grant:
Units settled in stock
Units settled in cash
Total value
2020
Shares
Weighted Average
Grant-Date
Fair Value per Share
(thousands)
(dollars)
39,628
9,030
(8,990)
(83)
39,585
2020
41.15
2019
68.77
(millions of dollars)
325
32
357
559
55
614
84.50
68.95
86.84
82.04
80.43
2018
77.66
620
61
681
As of December 31, 2020, there was $1,356 million of unrecognized compensation cost related to the nonvested restricted awards.
This cost is expected to be recognized over a weighted-average period of 4.2 years. The compensation cost charged against income for
the restricted stock and restricted stock units was $672 million, $741 million, and $774 million for 2020, 2019, and 2018, respectively.
The income tax benefit recognized in income related to this compensation expense was $51 million, $51 million, and $42 million for
the same periods, respectively. The fair value of shares and units vested in 2020, 2019, and 2018 was $367 million, $647 million, and
$722 million, respectively. Cash payments of $34 million, $56 million, and $61 million for vested restricted stock units settled in cash
were made in 2020, 2019, and 2018, respectively.
91
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. Litigation and Other Contingencies
Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of
pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need
for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those
contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be
reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is
accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount
cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an
unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and,
where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters,
as well as other matters, which management believes should be disclosed. ExxonMobil will continue to defend itself vigorously in
these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome
of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial
condition, or financial statements taken as a whole.
Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2020, for
guarantees relating to notes, loans and performance under contracts. Where guarantees for environmental remediation and other
similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure.
Guarantees
Debt-related
Other
Total
(1) ExxonMobil share.
Equity Company
Obligations (1)
December 31, 2020
Other Third-Party
Obligations
(millions of dollars)
Total
986
745
1,731
124
4,944
5,068
1,110
5,689
6,799
Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business
activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial
condition.
In accordance with a Venezuelan nationalization decree issued in February 2007, a subsidiary of the Venezuelan National Oil
Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. The decree also required conversion of the Cerro
Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s ownership interest in the Project.
ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated
ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.
ExxonMobil collected awards of $908 million in an arbitration against PdVSA under the rules of the International Chamber of
Commerce in respect of an indemnity related to the Cerro Negro Project and $260 million in an arbitration for compensation due for
the La Ceiba Project and for export curtailments at the Cerro Negro Project under rules of International Centre for Settlement of
Investment Disputes (ICSID). An ICSID arbitration award relating to the Cerro Negro Project’s expropriation ($1.4 billion) was
annulled based on a determination that a prior Tribunal failed to adequately explain why the cap on damages in the indemnity owed by
PdVSA did not affect or limit the amount owed for the expropriation of the Cerro Negro Project. ExxonMobil filed a new claim
seeking to restore the original award of damages for the Cerro Negro Project with ICSID on September 26, 2018.
The net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the
Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition.
92
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
An affiliate of ExxonMobil is one of the Contractors under a Production Sharing Contract (PSC) with the Nigerian National Petroleum
Corporation (NNPC) covering the Erha block located in the offshore waters of Nigeria. ExxonMobil's affiliate is the operator of the
block and owns a 56.25 percent interest under the PSC. The Contractors are in dispute with NNPC regarding NNPC's lifting of crude
oil in excess of its entitlement under the terms of the PSC. In accordance with the terms of the PSC, the Contractors initiated
arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conciliation Act. On October 24, 2011, a three-member arbitral
Tribunal issued an award upholding the Contractors' position in all material respects and awarding damages to the Contractors jointly
in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors petitioned a Nigerian federal court
for enforcement of the award, and NNPC petitioned the same court to have the award set aside. On May 22, 2012, the court set aside
the award. The Contractors appealed that judgment to the Court of Appeal, Abuja Judicial Division. On July 22, 2016, the Court of
Appeal upheld the decision of the lower court setting aside the award. On October 21, 2016, the Contractors appealed the decision to
the Supreme Court of Nigeria. In June 2013, the Contractors filed a lawsuit against NNPC in the Nigerian federal high court in order
to preserve their ability to seek enforcement of the PSC in the courts if necessary. Following dismissal by this court, the Contractors
appealed to the Nigerian Court of Appeal in June 2016. In October 2014, the Contractors filed suit in the United States District Court
for the Southern District of New York (SDNY) to enforce, if necessary, the arbitration award against NNPC assets residing within that
jurisdiction. NNPC moved to dismiss the lawsuit. On September 4, 2019, the SDNY dismissed the Contractors’ petition to recognize
and enforce the Erha arbitration award. The Contractors filed a notice of appeal in the Second Circuit on October 2, 2019. At this time,
the net impact of this matter on the Corporation's consolidated financial results cannot be reasonably estimated. However, regardless
of the outcome of enforcement proceedings, the Corporation does not expect the proceedings to have a material effect upon the
Corporation's operations or financial condition.
93
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. Pension and Other Postretirement Benefits
The benefit obligations and plan assets associated with the Corporation’s principal benefit plans are measured on December 31.
Weighted-average assumptions used to determine benefit
obligations at December 31
Discount rate
Long-term rate of compensation increase
Change in benefit obligation
Benefit obligation at January 1
Service cost
Interest cost
Actuarial loss/(gain) (1)
Benefits paid (2) (3)
Foreign exchange rate changes
Amendments, divestments and other
Benefit obligation at December 31
Pension Benefits
Other Postretirement
U.S.
Non-U.S.
Benefits
2020
2019
2020
2019
2020
2019
(percent)
2.80
5.50
3.50
5.75
1.60
4.20
2.30
4.80
2.80
5.50
3.50
5.75
(millions of dollars)
20,959
18,174
29,918
25,378
8,113
7,471
965
708
757
766
707
657
551
763
181
277
1,287
2,562
2,344
3,703
(66)
139
315
556
(1,987)
(1,300)
(1,317)
(1,196)
(510)
(517)
—
(270)
—
—
1,375
(58)
391
328
23
117
25
124
21,662
20,959
33,626
29,918
8,135
8,113
Accumulated benefit obligation at December 31
17,502
16,387
30,952
27,236
—
—
(1) Actuarial loss/(gain) primarily reflects changes in discount rates, partially offset by lower long-term rates of compensation.
(2) Benefit payments for funded and unfunded plans.
(3) For 2020 and 2019, other postretirement benefits paid are net of $16 million and $20 million of Medicare subsidy receipts,
respectively.
For selection of the discount rate for U.S. plans, several sources of information are considered, including interest rate market
indicators and the effective discount rate determined by use of a yield curve based on high-quality, noncallable bonds applied to the
estimated cash outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using a spot yield curve of
high-quality, local-currency-denominated bonds at an average maturity approximating that of the liabilities.
The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.5 percent in 2022 and
subsequent years.
Pension Benefits
Other Postretirement
U.S.
Non-U.S.
Benefits
2020
2019
2020
2019
2020
2019
(millions of dollars)
Change in plan assets
Fair value at January 1
Actual return on plan assets
Foreign exchange rate changes
Company contribution
Benefits paid (1)
Other
Fair value at December 31
(1) Benefit payments for funded plans.
13,636
11,134
22,916
19,486
2,269
2,521
2,795
3,210
—
1,004
(1,609)
—
15,300
—
1,022
(1,041)
—
13,636
1,011
597
(992)
(111)
513
602
(883)
(12)
26,216
22,916
425
42
—
37
(58)
—
446
386
54
—
41
(56)
—
425
94
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the
table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local applicable tax
rules and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the
funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring
affiliate.
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans
Unfunded plans
Total
Pension Benefits
U.S.
Non-U.S.
2020
2019
2020
2019
(millions of dollars)
(4,156)
(2,206)
(6,362)
(4,656)
(2,667)
(7,323)
(1,223)
(6,187)
(7,410)
(1,728)
(5,274)
(7,002)
The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the
overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position
and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.
Assets in excess of/(less than) benefit obligation
Balance at December 31 (1)
(6,362)
(7,323)
(7,410)
(7,002)
(7,689)
(7,688)
Pension Benefits
U.S.
Non-U.S.
Other Postretirement
Benefits
2020
2019
2020
2019
2020
2019
(millions of dollars)
Amounts recorded in the consolidated
balance sheet consist of:
Other assets
Current liabilities
Postretirement benefits reserves
Total recorded
Amounts recorded in accumulated other
comprehensive income consist of:
Net actuarial loss/(gain)
Prior service cost
Total recorded in accumulated other
comprehensive income
—
(377)
(5,985)
(6,362)
—
(242)
(7,081)
(7,323)
1,931
(273)
(9,068)
(7,410)
1,151
(267)
(7,886)
(7,002)
—
(327)
(7,362)
(7,689)
—
(351)
(7,337)
(7,688)
3,102
(275)
3,971
1
5,904
208
5,662
360
1,164
(274)
1,339
(315)
2,827
3,972
6,112
6,022
890
1,024
(1) Fair value of assets less benefit obligation shown on the preceding page.
95
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-
looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific
asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation
percentages and the long-term return assumption for each asset class.
Pension Benefits
U.S.
Non-U.S.
Other Postretirement
Benefits
2020
2019
2018
2020
2019
2018
2020
2019
2018
Weighted-average assumptions used to determine net
periodic benefit cost for years ended December 31
Discount rate
Long-term rate of return on funded assets
Long-term rate of compensation increase
3.50
5.30
5.75
4.40
5.30
5.75
3.80
6.00
5.75
(percent)
3.00
4.10
4.30
2.30
4.10
4.80
2.80
4.70
4.30
3.50
4.60
5.75
4.40
4.60
5.75
3.80
6.00
5.75
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on plan assets
Amortization of actuarial loss/(gain)
Amortization of prior service cost
Net pension enhancement and curtailment/
settlement cost
Net periodic benefit cost
Changes in amounts recorded in accumulated other
comprehensive income:
Net actuarial loss/(gain)
Amortization of actuarial (loss)/gain
Prior service cost/(credit)
Amortization of prior service (cost)/credit
Foreign exchange rate changes
Total recorded in other comprehensive income
Total recorded in net periodic benefit cost and other
comprehensive income, before tax
757
766
965
708
(703) (568)
310
5
305
5
(millions of dollars)
551
763
707
657
819
721
(727) (897) (777)
362
5
306
56
416
68
608
754
(951)
409
46
181
277
139
315
(18)
95
(42)
(15)
55
(42)
152
301
(23)
116
(40)
280
1,565
164
1,429
268
1,448
49
1,000
(98)
801
44
910
—
493
—
452
—
506
(279) 609
(590) (469)
(271) —
(5)
(5)
446
479
(630) (442) (208)
1,268
—
(5)
(82) 379
(68)
—
—
(1,145) 135
—
(156)
236
90
(56)
19
1,402
(92) 517
(95)
(66)
(453)
—
—
98
42
42
(46)
(356)
—
11
(823) (134) 504
(594)
(55) (116)
—
40
(8)
(678)
420
1,564
1,292
1,090
2,203
87
359
956
(172)
Costs for defined contribution plans were $358 million, $422 million and $391 million in 2020, 2019 and 2018, respectively.
96
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of the change in accumulated other comprehensive income is shown in the table below:
(Charge)/credit to other comprehensive income, before tax
U.S. pension
Non-U.S. pension
Other postretirement benefits
Total (charge)/credit to other comprehensive income, before tax
(Charge)/credit to income tax (see Note 4)
(Charge)/credit to investment in equity companies
(Charge)/credit to other comprehensive income including noncontrolling interests,
after tax
Charge/(credit) to equity of noncontrolling interests
(Charge)/credit to other comprehensive income attributable to ExxonMobil
Total Pension and Other Postretirement Benefits
2020
2019
2018
(millions of dollars)
1,145
(90)
134
1,189
(153)
(110)
926
30
956
(135)
(1,402)
(504)
(2,041)
550
(19)
(1,510)
146
(1,364)
156
823
678
1,657
(470)
24
1,211
(114)
1,097
The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in
plan assets and liabilities and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in
passive global equity and local currency fixed income index funds to diversify risk while minimizing costs. The equity funds hold
ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed income funds are largely invested in
investment grade corporate and government debt securities.
Studies are periodically conducted to establish the preferred target asset allocation percentages. The target asset allocation for the U.S.
benefit plans and the major non-U.S. plans is 30 percent equity securities and 70 percent debt securities. The equity for the U.S. and
certain non-U.S. plans include a small allocation to private equity partnerships that primarily focus on early-stage venture capital of 4
percent and 2 percent, respectively.
The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent
the relative risk or credit quality of an investment.
97
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The 2020 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:
U.S. Pension
Fair Value Measurement at
December 31, 2020, Using:
Level 1
Level 2
Level 3
Net
Asset
Value
Non- U.S. Pension
Fair Value Measurement at
December 31, 2020, Using:
Total
Level 1
Level 2
Level 3
(millions of dollars)
Net
Asset
Value
Total
Asset category:
Equity securities
U.S.
Non-U.S.
Private equity
Debt securities
Corporate
Government
Asset-backed
Cash
Total at fair value
Insurance contracts at
contract value
Total plan assets
—
—
—
—
—
—
—
—
—
2,323
1,703
548
2,323
1,703
548
—
89 (1)
—
—
—
—
—
—
—
4,177
3,285
530
4,177
3,374
530
—
—
—
—
—
5,146 (2)
5,261 (2)
—
—
10,407
—
—
—
—
—
1
2
1
308
4,886
5,147
5,263
1
308
15,293
7
15,300
—
250 (3)
—
69
408
138 (2)
116 (2)
24 (2)
21 (4)
299
—
—
—
—
—
5,212
11,993
239
50
25,486
5,350
12,359
263
140
26,193
23
26,216
(1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market
transactions.
(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.
Asset category:
Equity securities
U.S.
Non-U.S.
Debt securities
Corporate
Government
Asset-backed
Cash
Total at fair value
Fair Value Measurement at December 31, 2020, Using:
Other Postretirement
Level 1
Level 2
Level 3
Net Asset
Value
Total
(millions of dollars)
88 (1)
48 (1)
—
—
—
—
136
—
—
103 (2)
204 (2)
—
—
307
—
—
—
—
—
—
—
—
—
—
—
—
3
3
88
48
103
204
—
3
446
(1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market
transactions.
98
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The 2019 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:
U.S. Pension
Fair Value Measurement at
December 31, 2019, Using:
Level 1
Level 2
Level 3
Net
Asset
Value
Non-U.S. Pension
Fair Value Measurement at
December 31, 2019, Using:
Total
Level 1
Level 2
Level 3
Net
Asset
Value
Total
(millions of dollars)
Asset category:
Equity securities
U.S.
Non-U.S.
Private equity
Debt securities
Corporate
Government
Asset-backed
Cash
Total at fair value
Insurance contracts at
contract value
Total plan assets
—
—
—
—
—
—
—
—
—
1,960
1,656
499
1,960
1,656
499
—
70 (1)
—
—
—
—
—
—
—
3,436
3,015
489
3,436
3,085
489
—
—
—
—
—
4,932 (2)
4,470 (2)
—
—
9,402
—
—
—
—
—
1
2
1
107
4,226
4,933
4,472
1
107
13,628
8
13,636
—
280 (3)
—
33
383
129 (2)
139 (2)
21 (2)
12 (4)
301
—
—
—
—
—
4,486
10,511
212
61
22,210
4,615
10,930
233
106
22,894
22
22,916
(1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market
transactions.
(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.
Asset category:
Equity securities
U.S.
Non-U.S.
Debt securities
Corporate
Government
Asset-backed
Cash
Total at fair value
Other Postretirement
Fair Value Measurement at December 31, 2019, Using:
Level 1
Level 2
Level 3
Net Asset
Value
Total
(millions of dollars)
—
—
—
—
—
—
—
—
—
92 (1)
200 (1)
—
—
292
—
—
—
—
—
—
—
81
49
—
—
—
3
133
81
49
92
200
—
3
425
(1) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market
transactions.
99
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of pension plans with an accumulated benefit obligation and projected benefit obligation in excess of plan assets is shown
in the table below:
For funded pension plans with an accumulated benefit obligation
in excess of plan assets:
Accumulated benefit obligation
Fair value of plan assets
For funded pension plans with a projected benefit obligation
in excess of plan assets:
Projected benefit obligation
Fair value of plan assets
For unfunded pension plans:
Projected benefit obligation
Accumulated benefit obligation
All other postretirement benefit plans are unfunded or underfunded.
Contributions expected in 2021
Benefit payments expected in:
2021
2022
2023
2024
2025
2026 - 2030
Pension Benefits
U.S.
Non-U.S.
2020
2019
2020
2019
(millions of dollars)
16,129
15,300
14,940
13,636
4,602
2,652
3,026
1,381
19,456
15,300
18,292
13,636
13,836
10,681
12,496
9,616
2,206
1,373
2,667
1,447
6,187
5,469
5,274
4,629
Pension Benefits
Other Postretirement Benefits
U.S.
Non-U.S.
Gross
Medicare
Subsidy Receipt
(millions of dollars)
865
395
—
2,434
1,079
1,105
1,124
1,142
5,971
1,310
1,193
1,214
1,240
1,186
6,274
424
426
420
418
415
2,058
—
22
23
25
26
27
143
18. Disclosures about Segments and Related Information
The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately.
The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment.
The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is
organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to manufacture
and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.
These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in
business activities from which revenues are recognized and expenses are incurred; (2) whose operating results are regularly reviewed
by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and to assess its
performance; and (3) for which discrete financial information is available.
Earnings after income tax include transfers at estimated market prices.
In the Corporate and financing segment, interest revenue relates to interest earned on cash deposits and marketable securities. Interest
expense includes non-debt-related interest expense of $148 million in 2020, $105 million in 2019 and $84 million in 2018.
100
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2020
Earnings (Loss) after income tax
Effect of asset impairments - noncash
Earnings of equity companies included above
Sales and other operating revenue
Intersegment revenue
Depreciation and depletion expense
Interest revenue
Interest expense
Income tax expense (benefit)
Additions to property, plant and equipment
Investments in equity companies
Total assets
As of December 31, 2019
Earnings after income tax
Earnings of equity companies included above
Sales and other operating revenue
Intersegment revenue
Depreciation and depletion expense
Interest revenue
Interest expense
Income tax expense (benefit)
Additions to property, plant and equipment
Investments in equity companies
Total assets
As of December 31, 2018
Earnings after income tax
Earnings of equity companies included above
Sales and other operating revenue
Intersegment revenue
Depreciation and depletion expense
Interest revenue
Interest expense
Income tax expense (benefit)
Additions to property, plant and equipment
Investments in equity companies
Total assets
Upstream
Downstream
Chemical
U.S.
Non-U.S.
U.S.
Non-U.S.
U.S.
Non-U.S.
Corporate
and
Financing
Corporate
Total
(millions of dollars)
(19,385)
(17,138)
(559)
5,876
8,508
28,627
—
52
(5,958)
5,726
4,792
71,287
(645)
(2,287)
2,101
8,673
19,642
12,723
—
93
742
4,418
18,135
144,730
(852)
(15)
134
48,256
12,258
716
—
1
(324)
2,983
352
23,754
(225)
(609)
(190)
92,640
15,162
1,672
—
21
393
1,731
879
34,848
1,277
(100)
(21)
8,529
6,099
685
—
—
440
1,221
2,543
17,839
686
(69)
651
14,562
3,881
694
—
—
272
592
3,514
20,220
(3,296)
(35)
(384)
38
221
892
49
991
(1,197)
671
(443)
20,072
(22,440)
(20,253)
1,732
178,574
—
46,009
49
1,158
(5,632)
17,342
29,772
332,750
536
282
9,364
10,893
6,162
—
54
(151)
10,404
5,313
95,750
13,906
4,534
13,779
30,864
9,305
—
34
5,509
7,347
17,736
151,181
1,717
196
70,523
22,416
674
—
1
465
2,685
319
23,442
606
19
134,460
24,775
832
—
9
361
1,777
1,062
37,133
206
(4)
9,723
7,864
555
—
—
58
1,344
1,835
16,544
386
818
17,693
5,905
621
—
1
305
589
3,335
20,376
(3,017)
(404)
41
224
849
84
731
(1,265)
758
(309)
18,171
14,340
5,441
255,583
—
18,998
84
830
5,282
24,904
29,291
362,597
1,739
608
10,359
8,683
6,024
—
77
104
7,119
4,566
90,310
12,340
5,816
15,158
29,659
9,257
—
31
8,149
7,974
16,337
148,914
2,962
156
74,327
21,954
684
—
2
946
1,152
293
17,898
3,048
(6)
147,007
29,888
890
—
12
1,008
1,595
1,162
34,024
1,642
48
12,239
9,044
405
—
—
566
1,146
870
14,904
1,709
1,113
20,204
7,217
606
—
1
245
348
3,431
21,131
(2,600)
(380)
38
205
879
64
643
(1,486)
717
(277)
19,015
20,840
7,355
279,332
—
18,745
64
766
9,532
20,051
26,382
346,196
101
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Geographic
Sales and other operating revenue
United States
Non-U.S.
Total
Significant non-U.S. revenue sources include: (1)
Canada
United Kingdom
Singapore
France
Italy
Belgium
Australia
2020
2019
2018
(millions of dollars)
62,663
115,911
178,574
89,612
165,971
255,583
96,930
182,402
279,332
13,093
11,055
9,442
8,676
7,091
6,231
5,839
19,735
17,479
12,128
12,740
10,459
11,644
7,941
22,672
18,702
13,689
13,637
13,396
15,664
8,780
(1) Revenue is determined by primary country of operations. Excludes certain sales and other operating revenues in Non-U.S.
operations where attribution to a specific country is not practicable.
Long-lived assets
United States
Non-U.S.
Total
Significant non-U.S. long-lived assets include:
Canada
Australia
Singapore
Kazakhstan
Papua New Guinea
Nigeria
United Arab Emirates
Russia
Angola
December 31,
2020
2019
2018
(millions of dollars)
94,732
114,372
108,147
132,821
138,646
138,954
227,553
253,018
247,101
36,232
14,792
12,129
8,882
7,803
6,345
5,381
4,616
4,405
39,130
13,933
11,645
9,315
8,057
7,640
5,262
5,135
5,784
37,433
14,548
11,148
9,726
8,269
8,421
4,859
5,456
7,021
102
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19. Income and Other Taxes
2020
2019
2018
U.S.
Non-U.S.
Total
U.S.
Non-U.S.
Total
U.S.
Non-U.S.
Total
(millions of dollars)
Income tax expense (benefit)
Federal and non-U.S.
Current
Deferred - net
U.S. tax on non-U.S. operations
Total federal and non-U.S.
State
Total income tax expense
(benefit)
All other taxes and duties
Other taxes and duties
Included in production
and manufacturing expenses
Included in SG&A expenses
Total other taxes and duties
Total
262
2,908
3,170
(6,045) (2,007) (8,052)
13
(5,770)
(763)
(6,533)
—
901
—
901
13
(4,869)
(763)
(5,632)
(121) 6,171
(255)
89
(420)
—
(287) 5,751
(182)
—
(469) 5,751
6,050
(675)
89
5,464
(182)
5,282
459
518
42
1,019
126
1,145
9,001
(614)
—
8,387
—
8,387
9,460
(96)
42
9,406
126
9,532
3,108
23,014
26,122
3,566
26,959
30,525
3,498
29,165
32,663
663
1,148
328
164
4,420
24,005
(2,113) 24,906
1,811
492
28,425
22,793
1,385
160
5,111
4,642
811
305
28,075
33,826
2,196
465
33,186
38,468
1,245
153
4,896
6,041
857
312
30,334
38,721
2,102
465
35,230
44,762
The above provisions for deferred income taxes include net benefits of $25 million in 2020, $740 million in 2019, and $289 million in
2018 related to changes in tax laws and rates, and a benefit of $6.3 billion in 2020 related to asset impairments.
103
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The reconciliation between income tax expense (credit) and a theoretical U.S. tax computed by applying a rate of 21 percent for 2020,
2019 and 2018 is as follows:
Income (Loss) before income taxes
United States
Non-U.S.
Total
Theoretical tax
Effect of equity method of accounting
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1)(2)
State taxes, net of federal tax benefit (1)
Enactment-date effects of U.S. tax reform
Other
Total income tax expense (credit)
Effective tax rate calculation
Income tax expense (credit)
ExxonMobil share of equity company income taxes
Total income tax expense (credit)
Net income (loss) including noncontrolling interests
Total income (loss) before taxes
Effective income tax rate
2020
2019
2018
(millions of dollars)
(27,704)
(1,179)
(28,883)
(6,065)
(364)
1,606
(603)
—
(206)
(5,632)
(5,632)
861
(4,771)
(23,251)
(28,022)
(53)
20,109
20,056
4,212
(1,143)
2,573
(144)
—
(216)
5,282
5,282
2,490
7,772
14,774
22,546
5,200
25,753
30,953
6,500
(1,545)
4,626
100
(291)
142
9,532
9,532
3,142
12,674
21,421
34,095
17 %
34 %
37 %
(1) 2020 includes the impact of an increase in valuation allowance of $647 million in non-U.S. and $115 million in U.S. state
jurisdictions.
(2) 2019 includes taxes less than the theoretical U.S. tax of $773 million from Norway operations and the sale of upstream assets,
$657 million from a tax rate change in Alberta, Canada, and $268 million from an adjustment to a prior year tax position.
104
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial
reporting purposes and such amounts recognized for tax purposes.
Deferred tax liabilities/(assets) are comprised of the following at December 31:
Tax effects of temporary differences for:
Property, plant and equipment
Other liabilities
Total deferred tax liabilities
Pension and other postretirement benefits
Asset retirement obligations
Tax loss carryforwards
Other assets
Total deferred tax assets
Asset valuation allowances
Net deferred tax liabilities
2020
2019
(millions of dollars)
28,778
6,427
35,205
(4,703)
(3,150)
(8,982)
(7,095)
(23,930)
2,731
14,006
36,029
7,653
43,682
(4,712)
(3,403)
(7,404)
(7,735)
(23,254)
1,924
22,352
In 2020, asset valuation allowances of $2,731 million increased by $807 million and included net provisions of $762 million and
foreign currency effects of $41 million.
Balance sheet classification
Other assets, including intangibles, net
Deferred income tax liabilities
Net deferred tax liabilities
2020
2019
(millions of dollars)
(4,159)
18,165
14,006
(3,268)
25,620
22,352
The Corporation’s undistributed earnings from subsidiary companies outside the United States include amounts that have been
retained to fund prior and future capital project expenditures. Deferred income taxes have not been recorded for potential future tax
obligations, such as foreign withholding tax and state tax, as these undistributed earnings are expected to be indefinitely reinvested for
the foreseeable future. As of December 31, 2020, it is not practicable to estimate the unrecognized deferred tax liability. However,
unrecognized deferred taxes on remittance of these funds are not expected to be material.
105
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unrecognized Tax Benefits. The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax
benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the
financial statements. The following table summarizes the movement in unrecognized tax benefits:
Gross unrecognized tax benefits
Balance at January 1
Additions based on current year's tax positions
Additions for prior years' tax positions
Reductions for prior years' tax positions
Reductions due to lapse of the statute of limitations
Settlements with tax authorities
Foreign exchange effects/other
Balance at December 31
2020
2019
2018
(millions of dollars)
8,844
253
218
(201)
(237)
(113)
—
8,764
9,174
287
120
(97)
(279)
(538)
177
8,844
8,783
375
240
(125)
(5)
(68)
(26)
9,174
The gross unrecognized tax benefit balances shown above are predominantly related to tax positions that would reduce the
Corporation’s effective tax rate if the positions are favorably resolved. Unfavorable resolution of these tax positions generally would
not increase the effective tax rate. The 2020, 2019 and 2018 changes in unrecognized tax benefits did not have a material effect on the
Corporation’s net income.
Resolution of these tax positions through negotiations with the relevant tax authorities or through litigation will take many years to
complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the
Corporation. In the United States, the Corporation has various ongoing U.S. federal income tax positions at issue with the Internal
Revenue Service (IRS) for tax years beginning in 2006. The Corporation filed a refund suit for tax years 2006-2009 in U.S. federal
district court (District Court) with respect to the positions at issue for those years. These positions are reflected in the unrecognized tax
benefits table above. On February 24, 2020, the Corporation received an adverse ruling on this suit. The IRS has asserted penalties
associated with several of those positions. The Corporation has not recognized the penalties as an expense because the Corporation
does not expect the penalties to be sustained under applicable law. On January 13, 2021, the District Court ruled that no penalties
apply to the Corporation's positions in this suit. Proceedings in the District Court are continuing. Unfavorable resolution of all
positions at issue with the IRS would not have a material adverse effect on the Corporation’s operations or financial condition.
It is reasonably possible that the total amount of unrecognized tax benefits could increase or decrease by 10 percent in the next 12
months.
The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:
Country of Operation
Abu Dhabi
Angola
Australia
Belgium
Canada
Equatorial Guinea
Indonesia
Iraq
Malaysia
Nigeria
Norway
Papua New Guinea
Russia
United Kingdom
United States
Open Tax Years
2018 — 2020
2018 — 2020
2010 — 2020
2017 — 2020
2001 — 2020
2007 — 2020
2007 — 2020
2015 — 2020
2011 — 2020
2006 — 2020
2010 — 2020
2008 — 2020
2018 — 2020
2015 — 2020
2006 — 2020
The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related
penalties as operating expense.
For 2020, the Corporation's net interest expense was a credit of $6 million on income tax reserves. The Corporation incurred $0
million and $3 million in interest expense on income tax reserves in 2019 and 2018, respectively. The related interest payable balances
were $61 million and $71 million at December 31, 2020, and 2019, respectively.
106
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
20. Restructuring Activities
During 2020, ExxonMobil conducted an extensive global review of staffing levels and subsequently commenced targeted workforce
reductions within a number of countries to improve efficiency and reduce costs. The programs, which are expected to be substantially
completed by the end of 2021, include both voluntary and involuntary employee separations and reductions in contractors.
In 2020 the Corporation recorded before-tax charges of $450 million, consisting primarily of employee separation costs, associated
with announced workforce reduction programs in Europe, North America, and Australia. These costs are captured in “Selling, general
and administrative expenses” on the Statement of Income and reported in the Corporate and financing segment. The Corporation
estimates additional charges of up to $200 million in 2021 related to planned workforce reduction programs.
The following table summarizes the reserves and charges related to the workforce reduction programs, which are recorded in
“Accounts payable and accrued liabilities.”
Balance at January 1
Additions/adjustments
Payments made
Balance at December 31
2020
(millions of dollars)
—
450
(47)
403
107
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes
in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and
power operations, technical service agreements, other nonoperating activities and adjustments for noncontrolling interests. These
excluded amounts for both consolidated and equity companies totaled $274 million in 2020, $3,502 million in 2019 and
$1,484 million in 2018. Oil sands mining operations are included in the results of operations in accordance with Securities and
Exchange Commission and Financial Accounting Standards Board rules.
Results of Operations
Consolidated Subsidiaries
2020 - Revenue
Sales to third parties
Transfers
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for consolidated
subsidiaries
Equity Companies
2020 - Revenue
Sales to third parties
Transfers
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for equity companies
United
States
Canada/
Other
Americas
Europe
Africa
Asia
(millions of dollars)
Australia/
Oceania
Total
2,933
4,943
7,876
3,877
51
27,489
615
(5,650)
1,034
3,938
4,972
3,928
573
5,118
106
(944)
536
362
898
786
33
828
32
(343)
262
4,603
4,865
1,911
371
2,788
390
(258)
1,632
5,584
7,216
1,471
112
2,171
692
2,130
1,983
509
2,492
483
145
733
152
241
8,380
19,939
28,319
12,456
1,285
39,127
1,987
(4,824)
(18,506)
(3,809)
(438)
(337)
640
738
(21,712)
410
308
718
545
—
560
34
—
(421)
—
—
—
—
—
—
—
—
—
513
12
525
674
2
224
22
(246)
(151)
—
—
—
6
—
—
—
(1)
(5)
6,289
60
6,349
421
—
543
2,274
1,126
1,985
—
—
—
—
—
—
—
—
—
7,212
380
7,592
1,646
2
1,327
2,330
879
1,408
Total results of operations
(18,927)
(3,809)
(589)
(342)
2,625
738
(20,304)
108
Results of Operations
Consolidated Subsidiaries
2019 - Revenue
Sales to third parties
Transfers
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for consolidated
subsidiaries
Equity Companies
2019 - Revenue
Sales to third parties
Transfers
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for equity companies
United
States
Canada/
Other
Americas
Europe
Africa
Asia
(millions of dollars)
Australia/
Oceania
Total
5,070
6,544
11,614
4,697
120
5,916
998
(29)
1,452
5,979
7,431
4,366
498
1,975
122
(423)
2,141
1,345
3,486
1,196
118
601
113
(20)
802
7,892
8,694
2,387
234
3,019
682
1,188
2,393
8,706
11,099
1,597
119
2,264
1,182
4,238
3,132
628
3,760
637
180
703
250
599
14,990
31,094
46,084
14,880
1,269
14,478
3,347
5,553
(88)
893
1,478
1,184
1,699
1,391
6,557
664
530
1,194
595
1
379
33
—
186
—
—
—
—
—
—
—
—
—
1,248
6
1,254
570
4
231
75
180
194
—
—
—
6
—
—
—
(1)
(5)
10,536
464
11,000
555
—
528
3,634
2,275
4,008
—
—
—
—
—
—
—
—
—
12,448
1,000
13,448
1,726
5
1,138
3,742
2,454
4,383
Total results of operations
98
893
1,672
1,179
5,707
1,391
10,940
Consolidated Subsidiaries
2018 - Revenue
Sales to third parties
Transfers
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for consolidated
subsidiaries
Equity Companies
2018 - Revenue
Sales to third parties
Transfers
Production costs excluding taxes
Exploration expenses
Depreciation and depletion
Taxes other than income
Related income tax
Results of producing activities for equity companies
5,914
5,822
11,736
3,915
237
5,775
953
250
1,491
4,633
6,124
4,211
434
1,803
133
(121)
3,680
1,573
5,253
1,348
140
665
128
1,934
1,136
8,844
9,980
2,454
318
2,788
799
1,766
2,431
8,461
10,892
1,501
209
2,088
1,155
4,008
3,256
873
4,129
680
128
809
335
622
17,908
30,206
48,114
14,109
1,466
13,928
3,503
8,459
606
(336)
1,038
1,855
1,931
1,555
6,649
747
588
1,335
535
1
248
33
—
518
—
—
—
—
—
—
—
—
—
1,420
8
1,428
745
4
172
61
271
175
—
—
—
5
—
—
—
(1)
(4)
12,028
935
12,963
409
5
462
4,104
2,726
5,257
—
—
—
—
—
—
—
—
—
14,195
1,531
15,726
1,694
10
882
4,198
2,996
5,946
Total results of operations
1,124
(336)
1,213
1,851
7,188
1,555
12,595
109
Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are $13,206 million less at year-end 2020 and $13,082
million less at year-end 2019 than the amounts reported as investments in property, plant and equipment for the Upstream in Note 9.
This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to LNG operations.
Assets related to oil sands and oil shale mining operations are included in the capitalized costs in accordance with Financial
Accounting Standards Board rules.
Capitalized Costs
Consolidated Subsidiaries
As of December 31, 2020
Property (acreage) costs – Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for consolidated subsidiaries
Equity Companies
As of December 31, 2020
Property (acreage) costs – Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for equity companies
Consolidated Subsidiaries
As of December 31, 2019
Property (acreage) costs – Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for consolidated subsidiaries
Equity Companies
As of December 31, 2019
Property (acreage) costs – Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for equity companies
United
States
Canada/
Other
Americas
Europe
Africa
Asia
(millions of dollars)
Australia/
Oceania
Total
51
37
88
20,286
1,446
21,820
19,193
2,627
4
—
4
5,932
34
5,970
5,462
508
49
37
86
18,982
1,514
20,582
17,544
3,038
4
—
4
5,413
19
5,436
4,778
658
1,332
213
1,545
55,556
1,975
59,076
46,567
12,509
286
3,134
3,420
—
721
4,141
—
4,141
988
166
1,154
55,436
2,717
59,307
43,743
15,564
308
3,112
3,420
—
650
4,070
—
4,070
2,979
181
3,160
43,394
3,050
49,604
24,701
24,903
—
—
—
8,547
10,527
19,074
5,911
13,163
2,971
181
3,152
41,181
4,299
48,632
22,497
26,135
—
—
—
7,731
9,581
17,312
5,380
11,932
771
2,642
3,413
15,348
1,972
20,733
8,628
12,105
25,343
33,680
59,023
291,786
18,582
369,391
215,125
154,266
—
—
—
—
—
—
—
—
388
3,138
3,526
21,454
11,420
36,400
15,227
21,173
719
2,638
3,357
13,670
1,811
18,838
7,235
11,603
26,352
33,860
60,212
278,616
20,742
359,570
175,885
183,685
—
—
—
—
—
—
—
—
411
3,118
3,529
19,969
10,462
33,960
13,446
20,514
18,059
23,255
41,314
104,650
5,549
151,513
89,401
62,112
2,151
7,352
9,503
52,552
4,590
66,645
26,635
40,010
98
4
102
6,975
138
7,215
3,854
3,361
—
—
—
—
—
—
—
—
19,046
23,725
42,771
99,405
6,086
148,262
63,333
84,929
2,579
7,113
9,692
49,942
4,315
63,949
21,533
42,416
99
6
105
6,825
212
7,142
3,288
3,854
—
—
—
—
—
—
—
—
110
Oil and Gas Exploration and Production Costs (continued)
The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred
also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement
obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2020 were $11,254
million, down $7,986 million from 2019, due primarily to lower development costs including lower asset retirement obligation cost
estimates mainly in Angola. In 2019, costs were $19,240 million, up $2,912 million from 2018, due primarily to higher development
costs, partially offset by lower acquisition costs of unproved properties. Total equity company costs incurred in 2020 were $2,012
million, down $904 million from 2019, due primarily to lower development costs.
Costs Incurred in Property Acquisitions,
Exploration and Development Activities
United
States
Canada/
Other
Americas
Europe
Africa
Asia
(millions of dollars)
Australia/
Oceania
Total
During 2020
Consolidated Subsidiaries
Property acquisition costs – Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for consolidated subsidiaries
Equity Companies
Property acquisition costs – Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for equity companies
During 2019
Consolidated Subsidiaries
Property acquisition costs – Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for consolidated subsidiaries
Equity Companies
Property acquisition costs – Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for equity companies
During 2018
Consolidated Subsidiaries
Property acquisition costs – Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for consolidated subsidiaries
Equity Companies
Property acquisition costs – Proved
– Unproved
Exploration costs
Development costs
Total costs incurred for equity companies
—
—
40
316
356
—
—
2
20
22
—
1
155
809
965
—
—
5
15
20
—
—
147
96
243
—
—
4
40
44
344
47
232
(239)
384
—
—
—
71
71
—
20
252
1,066
1,338
—
—
—
69
69
—
1
342
791
1,134
—
—
—
66
66
7
—
110
974
1,091
—
—
—
1,784
1,784
26
—
111
1,317
1,454
—
—
—
2,585
2,585
321
—
217
1,104
1,642
—
—
5
2,452
2,457
—
—
83
730
813
—
—
—
—
—
—
—
194
484
678
—
—
—
—
—
—
—
174
256
430
—
—
—
—
—
382
130
1,227
9,515
11,254
—
—
2
2,010
2,012
38
352
1,953
16,897
19,240
—
—
6
2,910
2,916
331
2,348
2,228
11,421
16,328
21
—
10
3,000
3,031
1
80
60
5,675
5,816
—
—
—
135
135
12
226
134
10,275
10,647
—
—
1
241
242
7
238
235
7,440
7,920
21
—
1
442
464
30
3
702
2,059
2,794
—
—
—
—
—
—
105
1,107
2,946
4,158
—
—
—
—
—
3
2,109
1,113
1,734
4,959
—
—
—
—
—
111
Oil and Gas Reserves
The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2018, 2019 and
2020.
The definitions used are in accordance with the Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X.
Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data,
can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and
under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing
the right to operate expire, unless evidence indicates that renewal is reasonably certain. In some cases, substantial new investments in
additional wells and related facilities will be required to recover these proved reserves.
In accordance with the Securities and Exchange Commission’s (SEC) rules, the Corporation’s year-end reserves volumes as well as
the reserves change categories shown in the following tables are required to be calculated on the basis of average prices during the 12-
month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-
day-of-the-month price for each month within such period. These reserves quantities are also used in calculating unit-of-production
depreciation rates and in calculating the standardized measure of discounted net cash flows.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the
evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production
data or (3) changes in the average of first-of-month oil and natural gas prices and/or costs that are used in the estimation of reserves.
Revisions can also result from significant changes in either development strategy or production equipment/facility capacity.
During the first and second quarters of 2020, the balance of supply and demand for petroleum and petrochemical products experienced
two significant disruptive effects. On the demand side, the COVID-19 pandemic spread rapidly through most areas of the world
resulting in substantial reductions in consumer and business activity and significantly reduced demand for crude oil, natural gas, and
petroleum products. This reduction in demand coincided with announcements of increased production in certain key oil-producing
countries which led to increases in inventory levels and sharp declines in prices for crude oil, natural gas, and petroleum products.
Market conditions continued to reflect considerable uncertainty throughout 2020.
Primarily as a result of very low prices during 2020 and the effects of reductions in capital expenditures, under the SEC definition of
proved reserves, certain quantities of crude oil, bitumen, and natural gas that qualified as proved reserves in prior years did not qualify
as proved reserves at year-end 2020. Amounts no longer qualifying as proved reserves include 3.1 billion barrels of bitumen at Kearl,
0.6 billion barrels of bitumen at Cold Lake, and 0.5 billion oil-equivalent barrels in the United States. The Corporation's near-term
reduction in capital expenditures resulted in a net reduction to estimates of proved reserves of approximately 1.5 billion oil-equivalent
barrels, mainly related to unconventional drilling in the United States. Among the factors that could result in portions of these amounts
being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, cost reductions, operating
efficiencies, and increases in planned capital spending.
Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and ExxonMobil’s ownership
percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Natural gas reserves exclude
the gaseous equivalent of liquids expected to be removed from the natural gas on leases, at field facilities and at gas processing plants.
These liquids are included in net proved reserves of crude oil and natural gas liquids.
In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, the Corporation
does not view equity company reserves any differently than those from consolidated companies.
Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by
the specific fiscal terms in the agreement. The production and reserves reported for these types of arrangements typically vary
inversely with oil and natural gas price changes. As oil and natural gas prices increase, the cash flow and value received by the
company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the
higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total liquids and natural gas proved
reserves (consolidated subsidiaries plus equity companies) at year-end 2020 that were associated with production sharing contract
arrangements was 15 percent of liquids, 14 percent of natural gas and 15 percent on an oil-equivalent basis (natural gas is converted to
an oil-equivalent basis at six billion cubic feet per one million barrels).
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and
operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved
undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion.
Crude oil, natural gas liquids, and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and
natural gas reserves. The natural gas quantities differ from the quantities of natural gas delivered for sale by the producing function as
reported in the Operating Information due to volumes consumed or flared and inventory changes.
112
Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves
Crude Oil
Natural
Gas
Liquids
United
States
Canada/
Other
Americas
Europe
Africa
Asia
Australia/
Oceania
Total Worldwide
(millions of barrels)
Bitumen
Canada/
Other
Americas
Synthetic
Oil
Canada/
Other
Americas
Total
Net proved developed and
undeveloped reserves of
consolidated subsidiaries
January 1, 2018
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2018
Attributable to noncontrolling interests
Proportional interest in proved
reserves of equity companies
January 1, 2018
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2018
Total liquids proved reserves at
December 31, 2018
Net proved developed and
undeveloped reserves of
consolidated subsidiaries
January 1, 2019
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2019
Attributable to noncontrolling interests
Proportional interest in proved
reserves of equity companies
January 1, 2019
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2019
Total liquids proved reserves at
December 31, 2019
2,695
61
—
8
(11)
595
(144)
3,204
729
119
63
23
—
—
(9)
13
—
(2) —
9
(138)
604
(37)
166
3,496
4
—
—
—
3
(146)
3,357
410
28
—
—
—
113
(22)
529
44
110 7,559
153
36
8
(13)
720
(498)
6
—
—
—
—
(11)
105 7,965
1,258
1,012
(16) 3,286
—
—
—
2
—
(13)
—
238
(113)
(65)
1,404
4
4,185
962
10,302
473
3,438
15
36
—
10
—
(26)
—
—
958
(22) (698)
14,020
466
142
245
28
—
—
—
1
(20)
254
—
—
—
—
—
—
—
—
15
1
—
—
—
—
6
—
—
—
—
—
(1) —
6
15
1,097
6
—
—
—
—
(83)
1,020
— 1,363
—
35
— —
— —
— —
—
1
(104)
—
— 1,295
364
1
—
—
—
—
(23)
342
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,727
36
—
—
—
1
(127)
1,637
3,458
529
181
610
4,377
105 9,260
1,746
4,185
466
15,657
3,204
(677)
—
20
(1)
710
(168)
3,088
604
(25)
166
20
—
—
—
—
(117) —
—
—
(30)
39
(132)
447
3,357
136
—
—
—
—
(158)
3,335
529
(66)
—
—
—
125
(31)
557
21
(612)
105 7,965
—
— —
—
20
(118)
—
835
—
(11)
(530)
94 7,560
1,404
(305)
—
12
(27)
263
(72)
4,185
(213)
—
—
—
—
(114)
1,275
3
3,858
894
254
15
—
—
—
1
(19)
251
—
—
—
—
—
—
—
—
15
—
—
—
—
—
6
—
—
—
—
—
(1) —
6
14
1,020
(38)
—
—
—
—
(85)
897
(23)
— 1,295
—
— —
— —
— —
1
—
—
(105)
— 1,168
342
3
—
—
—
—
(23)
322
—
—
—
—
—
—
—
—
466
14,020
(27) (1,157)
—
—
—
32
—
(145)
1,098
—
(24) (740)
13,108
415
126
—
—
—
—
—
—
—
—
1,637
(20)
—
—
—
1
(128)
1,490
3,339
557
53
453
4,232
94 8,728
1,597
3,858
415
14,598
113
Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)
Crude Oil
Natural
Gas
Liquids
United
States
Canada/
Other
Americas
Europe
Africa
Asia
Australia/
Oceania
Total Worldwide
(millions of barrels)
Bitumen
Canada/
Other
Americas
Synthetic
Oil
Canada/
Other
Americas
Total
Net proved developed and
undeveloped reserves of
consolidated subsidiaries
January 1, 2020
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2020
Attributable to noncontrolling interests
Proportional interest in proved
reserves of equity companies
January 1, 2020
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2020
Total liquids proved reserves at
December 31, 2020
3,088
(1,139)
—
—
(1)
187
(176)
1,959
557
(14)
—
—
—
—
(2) —
1
—
(45)
497
7
39
(9)
447
19
—
—
—
—
3,335
(20)
—
—
—
—
(8) (110) (165)
3,150
22
356
94 7,560
(10) (1,173)
— —
— —
—
—
(10)
74 6,058
188
(514)
(3)
3,858
1,275
(209) (3,653)
—
—
(3)
65
(74)
1,054
1
—
—
—
1
(125)
81
25
415
13,108
(79) (5,114)
—
—
—
—
(6)
—
387
133
(738)
(25)
7,637
444
135
—
—
—
—
—
—
—
—
81
—
—
—
—
—
—
—
—
1,490
(124)
—
—
—
—
(118)
1,248
444
8,885
251
(102)
—
—
—
—
(18)
131
—
—
—
—
—
—
—
—
—
—
—
—
14
6
(4) —
—
—
—
—
(1) —
6
9
897
4
—
—
—
—
(76)
825
(102)
— 1,168
—
— —
— —
— —
— —
—
—
(95)
971
322
(22)
—
—
—
—
(23)
277
2,090
497
31
362
3,975
74 7,029
1,331
114
Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)
Crude Oil and Natural Gas Liquids
United
States
Canada/
Other
Americas
Europe
Africa
Asia
Australia/
Oceania
Total
(millions of barrels)
Bitumen
Canada/
Other
Americas
Synthetic
Oil
Canada/
Other
Americas
Total
Proved developed reserves, as of
December 31, 2018
Consolidated subsidiaries
Equity companies
1,696
208
153
—
123
15
578
—
2,285
919
118
—
4,953
1,142
3,880
—
466
—
9,299
1,142
Proved undeveloped reserves, as of
December 31, 2018
Consolidated subsidiaries
Equity companies
Total liquids proved reserves at
December 31, 2018
Proved developed reserves, as of
December 31, 2019
2,616
56
403
—
78
—
111
6
1,173
433
35
—
4,416
495
305
—
—
—
4,721
495
4,576
556
216
695
4,810
153
11,006
4,185
466
15,657
Consolidated subsidiaries
Equity companies
1,655
200
195
—
23
13
419
—
2,309
727
90
—
4,691
940
3,528
—
415
—
8,634
940
Proved undeveloped reserves, as of
December 31, 2019
Consolidated subsidiaries
Equity companies
Total liquids proved reserves at
December 31, 2019
2,474
60
4,389
381
—
576
29
1
66
Proved developed reserves, as of
December 31, 2020
68
6
1,157
483
35
—
4,144
550
330
—
—
—
4,474
550
493
4,676
125
10,325
3,858
415
14,598
Consolidated subsidiaries
Equity companies
1,473
111
293
—
13
8
345
—
2,299
646
67
—
4,490
765
Proved undeveloped reserves, as of
December 31, 2020
Consolidated subsidiaries
Equity companies
Total liquids proved reserves at
December 31, 2020
1,342
24
2,950
209
—
502
16
1
38
42
6
975
452
38
—
2,622
483
393
4,372
105
8,360
(1)
76
—
5
—
81
311
—
4,877
765
133
—
2,760
483
444
8,885
(1) See previous pages for natural gas liquids proved reserves attributable to consolidated subsidiaries and equity companies. For additional
information on natural gas liquids proved reserves see Item 2. Properties in ExxonMobil’s 2020 Form 10-K.
115
Natural Gas and Oil-Equivalent Proved Reserves
Natural Gas
Net proved developed and undeveloped
reserves of consolidated subsidiaries
January 1, 2018
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2018
Attributable to noncontrolling interests
Proportional interest in proved reserves
of equity companies
January 1, 2018
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2018
Total proved reserves at December 31, 2018
Net proved developed and undeveloped
reserves of consolidated subsidiaries
January 1, 2019
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2019
Attributable to noncontrolling interests
Proportional interest in proved reserves
of equity companies
January 1, 2019
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2019
Total proved reserves at December 31, 2019
United
States
Canada/
Other
Americas
Europe
Africa
(billions of cubic feet)
Asia
Australia/
Oceania
Total
Oil-Equivalent
Total
All Products (1)
(millions of oil-
equivalent
barrels)
19,033
(98)
—
104
(264)
3,658
(1,030)
21,403
223
12
—
—
—
2
(12)
225
21,628
21,403
(3,213)
—
85
(297)
2,151
(1,103)
19,026
225
(1)
—
—
—
1
(12)
213
19,239
1,368
306
—
—
(4)
3
(361)
1,312
1,372
(29)
—
—
(3)
506
(102)
1,744
334
595
38
—
—
—
—
(45)
588
4,340
(147)
—
—
—
1
(353)
3,841
6,894
1,065
—
—
—
7
(504)
7,462
33,602
1,135
—
104
(271)
4,175
(2,395)
36,350
—
—
—
—
—
—
—
—
1,744
6,164
(4,801)
—
—
(38)
—
(268)
1,057
2,369
914
(51)
—
—
—
—
—
863
1,451
14,248
102
—
—
—
—
(1,029)
13,321
17,162
—
—
—
—
—
—
—
—
7,462
21,549
(4,738)
—
—
(38)
2
(1,309)
15,466
51,816
1,312
41
—
—
(416)
—
(316)
621
1,744
(301)
—
—
(29)
166
(114)
1,466
256
588
(171)
—
—
—
—
(40)
377
3,841
953
—
—
—
—
(361)
4,433
7,462
39
—
—
—
—
(500)
7,001
36,350
(2,652)
—
85
(742)
2,317
(2,434)
32,924
—
—
—
—
—
—
—
—
1,466
1,057
(238)
—
—
—
—
(238)
581
1,202
863
45
—
—
—
—
—
908
1,285
13,321
142
—
—
—
—
(1,009)
12,454
16,887
—
—
—
—
—
—
—
—
7,001
15,466
(52)
—
—
—
1
(1,259)
14,156
47,080
15,903
3,626
36
27
(71)
1,654
(1,097)
20,078
5,318
(753)
—
—
(6)
1
(345)
4,215
24,293
20,078
(1,599)
—
47
(269)
1,484
(1,145)
18,596
4,215
(29)
—
—
—
1
(338)
3,849
22,445
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.
116
Natural Gas and Oil-Equivalent Proved Reserves (continued)
Natural Gas
United
States
Canada/
Other
Americas
Europe
Africa
(billions of cubic feet)
Asia
Australia/
Oceania
Total
Oil-Equivalent
Total
All Products (1)
(millions of oil-
equivalent
barrels)
Net proved developed and undeveloped
reserves of consolidated subsidiaries
January 1, 2020
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2020
Attributable to noncontrolling interests
Proportional interest in proved reserves
of equity companies
January 1, 2020
Revisions
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2020
Total proved reserves at December 31, 2020
19,026
(4,904)
—
—
(35)
433
(1,081)
13,439
213
(99)
—
—
—
—
(12)
102
13,541
621
(4)
—
—
—
1
(177)
441
377
(23)
—
—
—
—
(34)
320
4,433
245
—
—
—
—
(369)
4,309
7,001
(405)
—
—
—
—
(462)
6,134
32,924
(5,844)
—
—
(65)
435
(2,246)
25,204
1,466
(753)
—
—
(30)
1
(123)
561
84
—
—
—
—
—
—
—
—
561
581
(95)
—
—
—
—
(126)
360
801
908
9
—
—
—
—
—
917
1,237
12,454
(106)
—
—
—
—
(971)
11,377
15,686
—
—
—
—
—
—
—
—
6,134
14,156
(291)
—
—
—
—
(1,109)
12,756
37,960
18,596
(6,088)
—
—
(17)
459
(1,113)
11,837
3,849
(172)
—
—
—
—
(303)
3,374
15,211
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.
117
Natural Gas and Oil-Equivalent Proved Reserves (continued)
Natural Gas
United
States
Canada/
Other
Americas
Europe
Africa
(billions of cubic feet)
Asia
Australia/
Oceania
Total
Oil-Equivalent
Total
All Products (1)
(millions of oil-
equivalent
barrels)
Proved developed reserves, as of
December 31, 2018
Consolidated subsidiaries
12,538
605
1,116
581
3,618
4,336
22,794
Equity companies
152
—
988
—
11,951
—
13,091
Proved undeveloped reserves, as of
December 31, 2018
Consolidated subsidiaries
8,865
1,139
Equity companies
73
—
196
69
7
223
3,126
13,556
863
1,370
—
2,375
Total proved reserves at December 31, 2018
21,628
1,744
2,369
1,451
17,162
7,462
51,816
13,098
3,324
6,980
891
24,293
502
377
3,508
3,765
20,647
505
—
9,859
—
10,507
12,075
2,691
Proved developed reserves, as of
December 31, 2019
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves, as of
December 31, 2019
Consolidated subsidiaries
Equity companies
11,882
143
7,144
70
613
—
853
—
Total proved reserves at December 31, 2019
19,239
1,466
1,202
1,285
16,887
7,001
47,080
119
—
925
3,236
12,277
76
908
2,595
—
3,649
6,521
1,158
22,445
Proved developed reserves, as of
December 31, 2020
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves, as of
December 31, 2020
Consolidated subsidiaries
Equity companies
10,375
83
3,064
19
Total proved reserves at December 31, 2020
13,541
472
—
89
—
561
399
318
3,323
3,344
18,231
293
—
8,992
—
9,368
7,915
2,326
42
67
2
986
2,790
6,973
917
2,385
—
3,388
801
1,237
15,686
6,134
37,960
3,922
1,048
15,211
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels.
118
Standardized Measure of Discounted Future Cash Flows
As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed
by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to net
proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The
Corporation believes the standardized measure does not provide a reliable estimate of the Corporation’s expected future cash flows to
be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The
standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices,
which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
Standardized Measure of Discounted
Future Cash Flows
United
States
Canada/
Other
Americas (1)
Consolidated Subsidiaries
As of December 31, 2018
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
265,527
96,489
54,457
25,365
89,216
49,176
40,040
204,596
125,469
29,759
9,024
40,344
22,315
18,029
Equity Companies
As of December 31, 2018
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
17,730
6,474
3,359
—
7,897
4,104
3,793
—
—
—
—
—
—
—
2,640
7,264
2,157
1,165
1,612
2,330
713
1,617
Europe
Africa
Asia
(millions of dollars)
Australia/
Oceania
Total
23,263
5,023
7,351
8,255
2,634
(6)
47,557
16,019
8,356
10,491
12,691
2,957
9,734
241,410
61,674
13,907
124,043
41,786
21,509
20,277
67,041
18,081
8,047
10,499
30,414
15,030
15,384
849,394
322,755
121,877
187,677
217,085
110,981
106,104
3,777
249
370
964
2,194
1,712
482
165,471
61,331
10,295
30,662
63,183
31,503
31,680
—
—
—
—
—
—
—
194,242
70,211
15,189
33,238
75,604
38,032
37,572
Total consolidated and equity interests in
standardized measure of discounted
future net cash flows
43,833
18,029
4,257
10,216
51,957
15,384
143,676
(1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of
$2,823 million in 2018.
119
Standardized Measure of Discounted
Future Cash Flows (continued)
United
States
Canada/
Other
Americas (1)
Europe
Africa
Asia
(millions of dollars)
Australia/
Oceania
Total
Consolidated Subsidiaries
As of December 31, 2019
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
208,981
90,448
53,641
12,530
52,362
30,499
21,863
190,604
133,606
31,158
5,888
19,952
7,728
12,224
5,789
3,209
4,397
(594)
(1,223)
(1,265)
42
30,194
10,177
6,756
5,374
7,887
872
7,015
215,837
58,255
14,113
108,316
35,153
18,658
16,495
43,599
12,980
8,109
5,158
17,352
7,491
9,861
695,004
308,675
118,174
136,672
131,483
63,983
67,500
Equity Companies
As of December 31, 2019
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
15,729
6,848
3,681
—
5,200
2,721
2,479
—
—
—
—
—
—
—
3,194
1,302
1,182
346
364
41
323
2,509
246
247
555
1,461
1,112
349
115,451
48,259
11,463
17,891
37,838
18,573
19,265
—
—
—
—
—
—
—
136,883
56,655
16,573
18,792
44,863
22,447
22,416
Total consolidated and equity interests in
standardized measure of discounted
future net cash flows
Consolidated Subsidiaries
As of December 31, 2020
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Equity Companies
As of December 31, 2020
Future cash inflows from sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Total consolidated and equity interests in
standardized measure of discounted
future net cash flows
24,342
12,224
365
7,364
35,760
9,861
89,916
93,520
53,635
27,668
(2,509)
14,726
8,564
6,162
38,193
19,971
10,991
851
6,380
1,116
5,264
2,734
1,815
4,244
(1,121)
(2,204)
(1,565)
(639)
138,080
15,411
42,378
6,527
13,432
6,223
62,223
916
1,745
20,047
(511) 10,557
9,490
2,256
19,794
3,188
7,580
1,381
7,645
3,624
4,021
307,732
127,514
70,138
61,741
48,339
21,785
26,554
5,304
3,467
2,243
—
(406)
(378)
(28)
—
—
—
—
—
—
—
1,511
694
1,054
(115)
(122)
(86)
(36)
740
247
163
42
288
258
30
63,105
29,170
9,929
8,088
15,918
7,443
8,475
—
—
—
—
—
—
—
70,660
33,578
13,389
8,015
15,678
7,237
8,441
6,134
5,264
(675)
2,286
17,965
4,021
34,995
(1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of
$1,064 million in 2019 and $(150) million in 2020.
120
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated and Equity Interests
2018
Consolidated
Subsidiaries
Share of Equity
Method Investees
Total Consolidated
and Equity Interests
(millions of dollars)
Discounted future net cash flows as of December 31, 2017
65,201
25,003
90,204
Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs
Development costs incurred during the year
Net change in prices, lifting and development costs
Revisions of previous reserves estimates
Accretion of discount
Net change in income taxes
Total change in the standardized measure during the year
9,472
(134)
9,338
(31,706)
11,500
56,798
14,515
8,793
(28,469)
40,903
(9,956)
2,762
23,582
(2,091)
3,043
(4,637)
12,569
(41,662)
14,262
80,380
12,424
11,836
(33,106)
53,472
Discounted future net cash flows as of December 31, 2018
106,104
37,572
143,676
Consolidated and Equity Interests
2019
Consolidated
Subsidiaries
Share of Equity
Method Investees
Total Consolidated
and Equity Interests
(millions of dollars)
Discounted future net cash flows as of December 31, 2018
106,104
37,572
143,676
Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs
Development costs incurred during the year
Net change in prices, lifting and development costs
Revisions of previous reserves estimates
Accretion of discount
Net change in income taxes
Total change in the standardized measure during the year
(1,252)
4
(1,248)
(29,159)
16,544
(66,455)
4,906
11,433
25,379
(38,604)
(8,202)
2,927
(21,046)
657
3,956
6,548
(15,156)
(37,361)
19,471
(87,501)
5,563
15,389
31,927
(53,760)
Discounted future net cash flows as of December 31, 2019
67,500
22,416
89,916
121
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated and Equity Interests (continued)
2020
Consolidated
Subsidiaries
Share of Equity
Method Investees
Total Consolidated
and Equity Interests
(millions of dollars)
Discounted future net cash flows as of December 31, 2019
67,500
22,416
89,916
Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs
Development costs incurred during the year
Net change in prices, lifting and development costs
Revisions of previous reserves estimates
Accretion of discount
Net change in income taxes
Total change in the standardized measure during the year
169
—
169
(15,048)
9,969
(80,444)
2,614
10,786
31,008
(40,946)
(3,818)
1,760
(21,739)
680
3,011
6,131
(13,975)
(18,866)
11,729
(102,183)
3,294
13,797
37,139
(54,921)
Discounted future net cash flows as of December 31, 2020
26,554
8,441
34,995
122
OPERATING INFORMATION (unaudited)
Production of crude oil, natural gas liquids, bitumen and synthetic oil
Net production
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Worldwide
Natural gas production available for sale
Net production
United States
Canada/Other Americas
Europe
Africa
Asia
Australia/Oceania
Worldwide
Oil-equivalent production (1)
Refinery throughput
United States
Canada
Europe
Asia Pacific
Other Non-U.S.
Worldwide
Petroleum product sales (2)
United States
Canada
Europe
Asia Pacific and other Eastern Hemisphere
Latin America
Worldwide
Gasoline, naphthas
Heating oils, kerosene, diesel oils
Aviation fuels
Heavy fuels
Specialty petroleum products
Worldwide
Chemical prime product sales (2)
United States
Non-U.S.
Worldwide
2020
2019
2018
(thousands of barrels daily)
685
536
30
312
742
44
2,349
646
467
108
372
748
45
2,386
(millions of cubic feet daily)
2,691
277
789
9
3,486
1,219
8,471
2,778
258
1,457
7
3,575
1,319
9,394
551
438
132
387
711
47
2,266
2,574
227
1,653
13
3,613
1,325
9,405
(thousands of oil-equivalent barrels daily)
3,761
3,952
3,833
(thousands of barrels daily)
1,549
340
1,173
553
158
3,773
2,154
418
1,253
1,014
56
4,895
1,994
1,751
213
249
688
4,895
1,532
353
1,317
598
181
3,981
2,292
476
1,479
1,156
49
5,452
2,220
1,867
406
270
689
5,452
1,588
392
1,422
706
164
4,272
2,210
510
1,556
1,200
36
5,512
2,217
1,840
402
395
658
5,512
(thousands of metric tons)
9,010
16,439
25,449
9,127
17,389
26,516
9,824
17,045
26,869
Operating statistics include 100 percent of operations of majority-owned subsidiaries; for other companies, crude production, gas,
petroleum product and chemical prime product sales include ExxonMobil’s ownership percentage and refining throughput includes
quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment is
made in kind or cash.
(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
(2) Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty.
123
STOCK PERFORMANCE GRAPHS (unaudited)
Annual total return to ExxonMobil shareholders was -36.0 percent in 2020; the 5-year return through 2020 was -7.7 percent
and the 10-year return was -1.9 percent. Total returns mean share price increase plus dividends paid, with dividends
reinvested. The graphs below show the relative investment performance of ExxonMobil common stock, the S&P 500,
and an industry competitor group over the last five and ten years. The industry competitor group consists of four other
international integrated oil companies: BP, Chevron, Royal Dutch Shell, and Total.
FIVE-YEAR CUMULATIVE TOTAL RETURNS
(value of $100 invested at year-end 2015)
$250
200
150
100
50
0
S&P 500
Industry Group
ExxonMobil
ExxonMobil
S&P 500
Industry Group
2015
100
100
100
2016
120
112
130
2017
115
136
154
2018
98
130
144
2019
105
172
159
2020
67
203
110
Fiscal years ended December 31
TEN-YEAR CUMULATIVE TOTAL RETURNS
(value of $100 invested at year-end 2010)
$400
300
200
100
0
S&P 500
Industry Group
ExxonMobil
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
ExxonMobil
S&P 500
Industry Group
100
100
100
119
102
111
124
119
114
149
157
135
140
178
123
123
181
102
147
202
132
141
247
157
120
236
147
129
310
162
82
367
112
Fiscal years ended December 31
124
FREQUENTLY USED TERMS
Listed below are definitions of several of ExxonMobil’s key business and financial performance measures and
other terms. These definitions are provided to facilitate understanding of the terms and their calculation. In the case
of financial measures that we believe constitute “non-GAAP financial measures” under Securities and Exchange
Commission Regulation G, we provide a reconciliation to the most comparable Generally Accepted Accounting
Principles (GAAP) measure and other information required by that rule.
Capital and exploration expenditures (Capex) • Represents the combined total of additions at cost to property, plant and
equipment, and exploration expenses on a before-tax basis from the Consolidated statement of income. ExxonMobil’s Capex
includes its share of similar costs for equity companies. Capex excludes assets acquired in nonmonetary exchanges, the value
of ExxonMobil shares used to acquire assets, and depreciation on the cost of exploration support equipment and facilities
recorded to property, plant and equipment when acquired. While ExxonMobil’s management is responsible for all investments
and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures.
Cash operating costs and cash operating expenses (cash Opex, structural efficiencies, or structural reductions) • Cash
operating costs consist of (1) Production and manufacturing expenses, (2) Selling, general and administrative expenses, and
(3) Exploration expenses, including dry holes from ExxonMobil’s Consolidated statement of income. The sums of these
income statement lines serve as an indication of cash operating costs and do not reflect the total cash operating costs of the
Corporation. Cash operating expenses are a proxy for this measure that include equity company cash expenses and which
are stewarded internally to support management’s oversight of spending over time. This measure is useful for investors to
understand the Corporation’s efforts to optimize cash through disciplined expense management. For information concerning
the calculation and reconciliation of cash operating expenses see the Frequently Used Terms available on the Investors page
of our website at www.exxonmobil.com under the heading News & Resources.
Returns, rate of return, IRR • Unless referring specifically to external data, references to returns, rate of return, IRR, and
similar terms mean future discounted cash flow returns on future capital investments based on current company estimates.
Investment returns exclude prior exploration and acquisition costs.
Heavy oil and oil sands • Heavy oil, for the purpose of this report, includes heavy oil, extra heavy oil, and bitumen, as
defined by the World Petroleum Congress in 1987 based on American Petroleum Institute (API) gravity and viscosity at
reservoir conditions. Heavy oil has an API gravity between 10 and 22.3 degrees. The API gravity of extra heavy oil and
bitumen is less than 10 degrees. Extra heavy oil has a viscosity less than 10,000 centipoise, whereas the viscosity of
bitumen is greater than 10,000 centipoise. The term “oil sands” is used to indicate heavy oil (generally bitumen) that is
recovered in a mining operation.
Project • The term “project” can refer to a variety of different activities and does not necessarily have the same meaning
as in any government payment transparency reports.
Resources, resource base, and recoverable resources • Along with similar terms used in this report, these refer to the
total remaining estimated quantities of oil and natural gas that are expected to be ultimately recoverable. ExxonMobil refers
to new discoveries and acquisitions of discovered resources as resource additions. The resource base includes quantities of
oil and natural gas classified as proved reserves, as well as quantities that are not yet classified as proved reserves, but that
are expected to be ultimately recoverable. The term “resource base” or similar terms are not intended to correspond to SEC
definitions such as “probable” or “possible” reserves. The term “in-place” refers to those quantities of oil and natural gas
estimated to be contained in known accumulations and includes recoverable and unrecoverable amounts.
125
FOOTNOTES (pages I through XVI)
1. Cash Operating Expenses are a proxy for Cash Operating Costs that include equity company cash expenses.
2. Preliminary analysis assumes performance from OBO assets is similar to 2019.
3. Emission reduction plans announced in December 2020 include a 15 to 20 percent reduction in greenhouse gas intensity
of Upstream operations compared to 2016 levels. Plans cover Scope 1 and Scope 2 emissions, and are expected to result
in a 30 percent reduction in absolute Upstream greenhouse gas emissions from assets operated by the Company by the
end of 2025.
4. CO2 captured since 1970. Global CCS Institute 2020 report and ExxonMobil analysis of 2020 facility data. Further
details are available in the ExxonMobil 2021 Energy and Carbon Summary.
5. Represents currently identified future investment opportunities, consistent with past practice, results, and announced
plans.
6. Home equivalency calculated with the U.S. EPA GHG Equivalencies Calculator.
7. IEA World Energy Outlook (2020).
8. IEA; and UN human development data (1990-2017).
9. ExxonMobil Outlook for Energy (2019).
10. Homi Kharas, The Brookings Institution, Feb 2017, The Unprecedented Expansion of the Global Middle Class -
An Update, p2.
11. ExxonMobil Energy and Carbon Summary (2021).
12. Based on public announcements and ExxonMobil analysis of U.S. projects.
13. Includes lost-time injuries and illnesses.
14. Cash operating costs consist of (1) Production and manufacturing expenses, (2) Selling, general and administrative
expenses, and (3) Exploration expenses, including dry holes from ExxonMobil’s consolidated statement of income.
15. Resource value includes Midland, Delaware and minor conventional operations in the Central Basin Platform.
16. Kline & Company (2019).
17. NPD Group (October 2020, year-to-date).
18. Through our collaboration with Meituan Waimai, HeyTea, TRASHAUS and Rhino, Vistamaxx™ performance
polymers turned 1,900 discarded milk tea cups into 3,800 phone cases with improved toughness, durability, and
comfortable touch.
19. IHS Markit 2020 Capacity Ranking data and ExxonMobil estimates based on available data.
20. IHS Markit Chemical Supply & Demand data for polyethylene, polypropylene, and paraxylene.
21. ExxonMobil Sustainability Report (2021).
22. For 2021 Board nominees as of February 1, 2021. S&P 500 average per 2020 Spencer Stuart Board Index.
23. As of February 1, 2021.
Exxon Mobil Corporation has numerous affiliates, many with names that include ExxonMobil, Exxon, Mobil, Esso, and
XTO. For convenience and simplicity, those terms and terms such as Corporation, company, our, we, and its are sometimes
used as abbreviated references to specific affiliates or affiliate groups. Abbreviated references describing global or regional
operational organizations, and global or regional business lines are also sometimes used for convenience and simplicity.
Similarly, ExxonMobil has business relationships with thousands of customers, suppliers, governments, and others. For
convenience and simplicity, words such as venture, joint venture, partnership, co-venturer, and partner are used to indicate
business and other relationships involving common activities and interests, and those words may not indicate precise legal
relationships.
The following are trademarks, service marks, or proprietary process names of Exxon Mobil Corporation or one of its
affiliates: Exxon, ExxonMobil, ExxonMobil Low Carbon Solutions, ExxonMobil Rewards+, Mobil, Mobil 1, Mobil 1 Car
Care, and Vistamaxx. The following third-party trademarks or service marks referred to in the text of the report are owned
by Amazon.com, Inc.: Alexa. The following third-party trademarks or service marks referred to in the text of the report are
owned by Apple Inc.: Apple Pay. The following third-party trademarks or service marks referred to in the text of the report
are owned by Google LLC: Google Pay.
126
I N V E S T O R I N F O R M AT I O N
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STOCK SYMBOL: XOM
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Important shareholder information is available at
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Outlook for Energy:
A Perspective to 2040
Energy & Carbon Summary
Sustainability Report
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