2020 ANNUAL REPORT
OUR COMPANY
Hess Corporation is a leading global independent energy
company engaged in the exploration and production of crude
oil and natural gas.
Our company’s purpose is to be the world’s most trusted energy
partner. We are committed to meeting the highest standards
of corporate citizenship by protecting the health and safety of
our employees, safeguarding the environment and making a
positive impact on the communities in which we do business.
TABLE OF CONTENTS
1
2
5
9
12
Financial and Operating Highlights
Letter to Shareholders
Global Operations
Sustainability
Board of Directors
and Corporate Officers
Cover: Drilling Operations, North Dakota
Cover: Production Operations, Gulf of Thailand
FINANCIAL AND OPERATING HIGHLIGHTS
Hess Corporation
Amounts in millions, except pe r share data
FINANCIAL — for the year
Sales and other operating revenues
Net income (loss) attributable to Hess Corporation
Net income (loss) per share diluted (a)
Common stock dividends per share
Net cash provided by operating activities
Exploration & Production capital and exploratory expenditures
Midstream capital expenditures and equity investments
Weighted average diluted shares outstanding
FINANCIAL — at year end
Total assets
Cash and cash equivalents
Total debt and finance lease obligations
Total equity
2020
4,667
(3,093)
(10.15)
1.00
1,333
1,786
253
304.8
2020
18,821
1,739
8,534
6,335
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2019
6,495
(408)
(1.37)
1.00
1,642
2,743
449
301.2
2019
$ 21,782
$
$
$
1,545
7,397
9,706
Debt to capitalization ratio for debt covenants (b)
47.5%
39.6%
Common stock price
$
52.79
$
66.81
OPERATING — for the year
Net production
Crude oil and natural gas liquids (thousands of barrels per day)
United States
International
Total
Natural gas (millions of cubic feet per day)
United States
International
Total
Barrels of oil equivalent (thousands of barrels per day)
2020
2019
206
33
239
256
298
554
331
187
29
216
201
371
572
311
(a) Calculated as net income (loss) attributable to Hess Corporation less preferred stock dividends, divided by weighted average number of diluted shares.
(b) Total debt (including finance lease obligations and excluding Midstream non-recourse debt) as a percentage of Total Capitalization of Hess Corporation as
defined under Hess Corporation’s term loan and revolving credit facility financial covenants. Total Capitalization excludes the impact of noncash impairment
charges and non-controlling interests.
1
LETTER TO SHAREHOLDERS
Our company’s strategy has been – and continues to be –
further strengthened our cash and liquidity position
to grow our resource base, have a low cost of supply and
in 2020 through a $1.0 billion, three year term loan
sustain cash flow growth. By investing only in high return,
agreement. During the fourth quarter, we closed on the
low cost opportunities, we have built a differentiated
sale of our 28% interest in the Shenzi Field in the Gulf
portfolio that is balanced between short cycle and long
of Mexico for a total consideration of $505 million.
cycle assets, with Guyana as our growth engine and the
Bakken, Gulf of Mexico and Southeast Asia as our cash
engines. Guyana will become a significant cash engine as
multiple phases of low cost oil developments come online,
which we believe will drive our company’s breakeven price
below $40 per barrel Brent and provide industry leading
cash flow growth over the course of the decade.
Throughout the pandemic, our company has maintained
a constant focus on the safety of our workforce and the
communities where we operate. In response to the
pandemic’s severe impact on oil prices, our priorities
have been to preserve cash, preserve our operating
capability and preserve the long term value of our
assets. In terms of preserving cash, we came into
2020 with approximately 80% of our oil production
hedged with put options for 130,000 barrels per day
at $55 per barrel West Texas Intermediate (WTI) and
20,000 barrels per day at $60 per barrel Brent. For
2021, we have hedged 120,000 barrels per day with
$55 per barrel WTI put options and 30,000 barrels
per day with $60 per barrel Brent put options.
To enhance cash flow and maximize the value of our
production, in March and April of 2020 when U.S. oil
storage was near capacity, we chartered three very
large crude carriers (VLCCs) to store and transport
In terms of preserving capability, a key for us was
continuing to operate one rig in the Bakken in 2020.
Our Bakken team has made great progress over the
past 10 years in Lean manufacturing capabilities and
innovative practices, which have delivered significant
cost efficiencies and productivity improvements that
we want to preserve for the future.
To preserve the long term value of our assets, we
allocated more than 80% of our 2021 capital and
exploratory budget of $1.9 billion to Guyana, where
our three sanctioned oil developments have a Brent
breakeven oil price of between $25 and $35 per barrel,
and to the Bakken, where we have a large inventory
of future drilling locations that can generate attractive
financial returns at $50 per barrel WTI.
On the Stabroek Block in Guyana, where Hess has a
30% interest and ExxonMobil is the operator, 2020 was
another outstanding year. Three oil discoveries during the
year brought total discoveries on the block to 18. In
October, the estimate of gross discovered recoverable
resources on the block was increased to approximately
9 billion barrels of oil equivalent, and we continue to see
multibillion barrels of future exploration potential remaining.
Production from Liza Phase 1 reached its nameplate
more than 6 million barrels of Bakken crude oil to high
capacity of 120,000 gross barrels of oil per day in
value markets in Asia; all three cargoes were sold at
a premium to Brent.
We reduced our 2020 capital and exploratory budget
from $3 billion down to $1.8 billion, primarily by
dropping from six Bakken rigs to one. We also reduced
our 2020 cash operating costs by $275 million. We
December 2020, and the Liza Phase 2 development,
with a capacity of 220,000 gross barrels of oil per day,
is on track to achieve first oil in early 2022. In September
2020, we sanctioned our third oil development on the
Stabroek Block at the Payara Field, which will have a
capacity of 220,000 gross barrels of oil per day and is
expected to achieve first oil in 2024.
2
In the Bakken, our 2020 net production came in well
with the findings of the U.N. Intergovernmental Panel
above our original guidance for the year and 27% above
on Climate Change.
that of 2019. As WTI oil prices moved above $50 per
barrel, in February 2021 we added a second rig, which
will allow us to maintain net production in the range of
175,000 barrels of oil equivalent per day and sustain long
term cash flow generation from our largest operated asset.
Our Board and senior leadership have set aggressive
targets for greenhouse gas (GHG) emissions reduction.
In 2020, we significantly surpassed our five year targets
to reduce Scope 1 and 2 GHG emissions intensity by
25% and flaring intensity by 50% from our operated
Turning to our 2020 financial results, our adjusted net
assets – reducing GHG emissions intensity and flaring
loss was $894 million compared with an adjusted net loss
intensity by approximately 40% and 60%, respectively,
of $281 million in 2019, primarily reflecting the effects of
compared with 2014 levels. We recently announced
lower realized prices. Cash flow from operations, before
our new five year GHG reduction targets for 2025, which
changes in working capital, was $1.8 billion, compared
are to reduce operated Scope 1 and 2 GHG emissions
with $2.2 billion in the prior year. Proved reserves at the
intensity by approximately 44% and methane emissions
end of 2020 stood at 1.17 billion barrels of oil equivalent.
intensity by approximately 50% from 2017.
Net proved reserve additions and revisions in 2020 totaled
117 million barrels of oil equivalent, including negative net
price revisions of 79 million barrels of oil equivalent,
replacing 95% of 2020 production.
Sustainability
As we execute our company’s strategy, we will
In addition, we are investing in technological and scientific
advances designed to reduce, capture and store carbon
emissions, including groundbreaking work being
conducted by the Salk Institute to develop plants with
larger root systems that according to the Salk Institute
are capable of absorbing and storing potentially billions
continue to be guided by our longstanding commitment
of tons of carbon per year from the atmosphere.
to sustainability. In keeping with our Hess values, we
strive to help address societal inequities by fostering
a diverse and inclusive work environment and creating
opportunities in the communities where we operate.
We have tested the resilience of Hess’ portfolio under
the supply and demand scenarios from the International
Energy Agency (IEA). The IEA’s Sustainable Development
Scenario, which assumes all the pledges of the Paris
Our Board of Directors is climate change literate and
Climate Agreement are met, projects oil and gas will still
actively engaged in overseeing Hess’ sustainability
be 46% of the global energy mix in 2040. Our current
practices. We are committed to transparency – our
strategy and reporting are closely aligned with the
asset portfolio is robust, and our pipeline of forward
investments is projected to provide strong financial
recommendations of the Task Force on Climate-Related
returns under the Sustainable Development Scenario.
Financial Disclosures (TCFD). We are proud to have been
recognized throughout 2020 by a number of third party
organizations as an industry leader in our environmental,
social and governance performance and disclosure.
Commitment to Shareholders
We will continue to execute our strategy that has
positioned our company to deliver industry leading cash
flow growth and financial returns over the course of the
We recognize that climate change is one of the greatest
decade. We are proud of our employees for their many
scientific challenges of the 21st century that must be
accomplishments and grateful for the counsel and
addressed while at the same time providing the safe,
guidance of our Directors. Thank you, our shareholders,
affordable and reliable energy that is fundamental to
for your continued support and interest in our company.
human prosperity and world economic growth. We
support the aim of the Paris Agreement and a global
ambition to achieve net zero emissions by 2050. Our
business planning includes actions we will undertake
to continue reducing our carbon footprint in keeping
James H. Quigley
Chairman of the Board
John B. Hess
Chief Executive Officer
April 2021
3
Liza Unity FPSO, Singapore
GLOBAL OPERATIONS
Production
In 2020, our company responded quickly and decisively
in the Bakken to $6.2 million per well in 2020, down
to the pandemic, establishing clear protocols to reduce
from $6.8 million in 2019. In 2021, drilling and completion
the risks of COVID-19 in our work environment that
costs are expected to average below $6.0 million
underpinned safe and effective operations across the
through continued efficiency gains driven by Lean
Hess portfolio.
Net production averaged 331,000 barrels of oil
equivalent per day, including Libya, compared with
311,000 barrels of oil equivalent per day in 2019. The
year over year increase was the result of higher Bakken
production and the first full year of production from the
Liza Field on the Stabroek Block, offshore Guyana,
which was partially offset by lower production in Libya
and the impacts of hurricane related downtime in the
Gulf of Mexico and lower energy demand in Malaysia
and Thailand caused by COVID-19.
In the Bakken, Hess’ operated rig count averaged
2.6 in 2020, compared with 6.0 in 2019. In response
to lower oil prices, the company safely reduced activity
from six operated rigs at the start of the year to one
rig by June. We brought 111 new wells on production
in 2020, compared with 156 wells in 2019. Net
manufacturing and technological innovation. We have
fully transitioned to plug and perf completion design
and continue to optimize the development of our
acreage through a combination of well spacing and
well completion design. The overall productivity of
wells drilled in 2021 is forecast to be in line with the
2020 program, with average 180 day initial production
rates of approximately 120,000 barrels of oil. Our
estimate of net ultimate recovery from our Bakken
acreage remains at approximately 2.4 billion barrels
of oil equivalent, with approximately 2.0 billion barrels
yet to be produced.
Production from the first phase of the Liza development
on the Stabroek Block (30% interest), offshore Guyana,
reached its full capacity of 120,000 gross barrels of oil
per day in December 2020. Net production averaged
20,000 barrels of oil per day in 2020.
production from the Bakken averaged 193,000
In the deepwater Gulf of Mexico, net production
barrels of oil equivalent per day in 2020, compared
averaged 56,000 barrels of oil equivalent per day in
with 152,000 barrels of oil equivalent per day in 2019.
2020, compared with 66,000 barrels of oil equivalent
As WTI oil prices moved above $50 per barrel,
we added a second operated rig in February 2021,
which will allow us, following the planned turnaround at
per day in 2019. This decrease was primarily due to
hurricane related downtime and the sale of our interests
in the Shenzi Field.
the Tioga Gas Plant this summer, to maintain Bakken
At the Carigali Hess–operated Malaysia/Thailand
net production at approximately 175,000 barrels of oil
Joint Development Area (50% working interest), net
equivalent per day and sustain long term cash flow
production averaged 29,000 barrels of oil equivalent
generation from our largest operated asset.
per day in 2020, compared with 35,000 barrels of oil
Through the continued application of technology
and Lean manufacturing techniques, we were able
to reduce our average drilling and completion costs
equivalent per day in 2019. At the North Malay Basin
Development project, offshore Peninsular Malaysia
(50% working interest, operator), net production in
5
2020 averaged 23,000 barrels of oil equivalent per day,
Developments
compared with 28,000 barrels of oil equivalent per day
in 2019. Production at both assets was negatively
impacted by a reduction in energy demand due to
COVID-19.
In the Danish North Sea, net production from the
South Arne Field (61.5% working interest, operator)
averaged 6,000 barrels of oil equivalent per day in 2020,
compared with 7,000 barrels of oil equivalent per day in
2019, reflecting natural field declines. In the first quarter of
2021, we announced the sale of our interests in Denmark.
This transaction is expected to close in the third quarter.
Offshore Guyana, Hess holds a 30% interest in the
6.6 million acre Stabroek Block. Esso Exploration
and Production Guyana Limited, a subsidiary of
ExxonMobil, is operator and holds a 45% interest.
CNOOC Petroleum Guyana Limited, a wholly owned
subsidiary of CNOOC Limited, holds the remaining
25% interest. As a result of further exploration
and appraisal success during 2020, the estimate
of gross discovered recoverable resources on the
block was increased to approximately 9 billion
barrels of oil equivalent.
Net production from Libya averaged 4,000 barrels
of oil equivalent per day in 2020, compared with
21,000 barrels of oil equivalent in 2019. Production
operations were largely shut in during 2020 due to
a force majeure caused by civil unrest.
First oil from the second phase of the Liza development
is on track for early 2022, utilizing the Liza Unity floating
production storage and offloading vessel (FPSO) with
production capacity of approximately 220,000 gross
barrels of oil per day. A third development, at the
Production Operations, North Dakota
6
Offshore Operations, Gulf of Mexico
Payara Field, was sanctioned in September 2020
sandstone reservoir. The well, drilled in 6,342 feet
with production capacity of 220,000 gross barrels
of water, is located approximately 10 miles northeast
of oil per day; first oil is expected in 2024. We expect
of the Liza Field.
to have at least five FPSOs on the Stabroek Block
by 2026 producing more than 750,000 gross barrels
of oil per day, with the potential for up to 10 FPSOs
to develop the current discovered recoverable
resource base.
Exploration
At the Stabroek Block, offshore Guyana, Hess
has participated in 18 discoveries to date that are
estimated to contain gross discovered recoverable
resources of approximately 9 billion barrels of oil
equivalent. Three of these discoveries were
announced in 2020.
In January 2020, the Uaru-1 well encountered
approximately 94 feet of high quality, oil bearing
In September 2020, we announced the Redtail-1
and Yellowtail-2 discoveries. Redtail-1 encountered
approximately 232 feet of high quality, oil bearing
sandstone reservoir. The well is located approximately
1.5 miles northwest of the Yellowtail discovery
in 6,164 feet of water. Yellowtail-2 encountered
approximately 69 feet of high quality, oil bearing
reservoirs adjacent to and below the Yellowtail-1
discovery. The well is located approximately 1.5 miles
from the Yellowtail-1 well in 5,901 feet of water.
In 2021, an active exploration and appraisal program is
planned that will include drilling approximately 12 wells.
7
Operations, North Malay Basin
SUSTAINABILITY
Hess’ purpose – to be the world’s most trusted energy
Environment and Climate Change
partner – aligns with our longstanding commitment to
We see climate change as one of the greatest scientific
sustainability, which we believe creates value for all of our
challenges of the 21st century. We believe climate risks
stakeholders. Our strategy for environment, health, safety and
can and should be addressed while at the same time
social responsibility (EHS & SR) focuses on eight key areas:
providing the safe, affordable and reliable energy necessary
Climate Change; Community and Stakeholder Engagement;
to ensure human welfare and global economic development
Diversity, Equity and Inclusion; Emergency Preparedness and
in the context of the U.N. Sustainable Development
Response; Occupational Health and Safety; Process Safety;
Goals. We support the aim of the Paris Agreement
Supply Chain and Contractor Management; and Water
and a global ambition to achieve net zero emissions by
Management. Our EHS & SR strategy and performance are
2050. Governments, businesses and civil society must
discussed in detail in our sustainability report, available at
work together on cost effective policies. We support
www.hess.com/sustainability.
transparent carbon pricing as an economically efficient
Our sustainability culture starts at the top of our company
method for managing carbon emissions.
and is reinforced at every level. Our Board of Directors is
Our climate strategy is closely aligned with the
climate change literate and actively engaged in overseeing
recommendations of the Task Force on Climate-
Hess’ sustainability practices, working alongside senior
Related Financial Disclosures (TCFD) established by
management. The EHS Committee of our Board provides
the G20 Financial Stability Board, and its implementation
oversight and makes recommendations to the full Board
is led by senior members of our leadership team.
with respect to Hess’ policies, positions and systems for
Our efforts to support the transition to a low carbon
EHS & SR, compliance and risk management.
We regularly bring in subject matter experts to brief our
Board on climate and other sustainability issues to be
considered in the development of company strategies and
policies. The Board’s Compensation and Management
Development Committee has tied executive compensation
economy and mitigate climate change in line with TCFD
recommendations have been independently assessed
by the Transition Pathway Initiative, and we were the
only U.S. oil and gas company to be awarded a Level 4
star rating in their September 2020 report.
In 2020, we significantly surpassed our five year targets
to advancing the company’s EHS and climate change goals.
to reduce Scope 1 and 2 GHG emissions intensity by 25%
We recently completed a review and update of our EHS
& SR strategy, beginning with a materiality assessment to
prioritize and focus our strategic actions through 2025,
which will be discussed in our 2020 sustainability report.
We have established goals and targets to drive progress in
high priority areas, including climate change, and in support
of the U.N. Sustainable Development Goals. The Board’s
EHS Committee was actively involved in the update of
our EHS & SR strategy and will continue to oversee
management’s implementation.
and flaring intensity by 50% from our operated assets
– reducing GHG emissions intensity and flaring intensity
by approximately 40% and 60%, respectively, compared
with 2014 levels. As part of our updated EHS & SR
strategy, Hess leadership and our Board have set new
five year GHG reduction targets for 2025, which are to
reduce operated Scope 1 and 2 GHG emissions intensity
by approximately 44% from 2017 levels to 17 kg per
barrel of oil equivalent and methane emissions intensity
by approximately 50% from 2017 levels to an intensity
of 0.19%. These targets are designed to exceed the
22% carbon intensity reduction by 2030 in the IEA’s
9
LEAP Program, Houston, Texas
LEAP Program, Houston, Texas
Sustainable Development Scenario, which is consistent
demand through 2040, taking into account a carbon
with the Paris Agreement’s less than 2°C ambition.
constrained future. Hess’ strategic priorities – to grow
Flaring reduction – particularly from our Bakken operations
– is a key driver to reducing our overall GHG emissions
intensity. For 2021, continued Bakken flaring reduction is
one of the performance metrics in the company’s annual
incentive plan. Additional EHS & SR strategic actions will be
discussed in our sustainability report.
In addition to addressing our direct emissions, we also seek
to fund innovation with the potential to mitigate societal
emissions. In 2020, we announced a gift of $12.5 million
over five years to help fund the Salk Institute’s Harnessing
Plants Initiative, a research and development program
aimed at developing plants with larger root systems that
are capable of absorbing and storing potentially billions of
our resource base, have a low cost of supply and sustain
cash flow growth – are aligned with the energy transition
needed to achieve the Sustainable Development Scenario
and position us well for the coming decades. We also
consider physical risks associated with climate change,
such as increased severity of storms, drought and flooding,
for new projects and existing operations.
We understand that a substantive climate strategy
requires companies to look beyond a five year time
frame. We have established an executive led taskforce
to consider our medium and longer term climate
strategy for review by our Board. We will share the
results of that evaluation when completed.
tons of carbon per year from the atmosphere. We also
Safety and Health
address 100% of the indirect emissions from our purchased
We work closely with our employees and contractors to
electricity through a combination of renewable energy
generated from the grid and the purchase of renewable
energy certificates.
We account for the cost of carbon in capital investment
decisions. We conduct scenario planning that includes
the Sustainable Development Scenario developed by
the IEA to test the resilience of Hess’ portfolio against
a range of environmental policies and market conditions.
According to the IEA’s World Energy Outlook 2020, oil and
gas are essential to meeting the world’s growing energy
promote a strong safety culture and continuously improve
our performance. Since early 2020, a multidisciplinary
Hess emergency response team has been overseeing our
plans and precautions to reduce the risks of COVID-19 in
our work environment.
In 2020, our company achieved a 19% reduction in our
workforce total recordable incident rate compared with 2019,
driven by a decrease in contractor incidents, and a 50%
reduction in our workforce lost time incident rate. We reached
a five year low in our severe and significant safety incident
10
rate, achieving a nearly 10% reduction from 2019. We also
investment in education and extend programs and services
continued to improve our process safety performance in
to a third economically disadvantaged Houston community.
2020, with zero Tier 1 process safety incidents.
In North Dakota, for the third year in a row, we provided Hess
The safety performance of our contractors, who represent
toy trucks to every elementary school in the state together
approximately 70% of our total workforce hours, is critical
with a STEM (science, technology, engineering and math)
to achieving our safety goals. In 2020, we progressed our
curriculum designed by Baylor College of Medicine’s Center
engagement efforts with many of our contractors to ensure
for Educational Outreach. Hess contributed $100,000 to the
alignment on the standards expected in Hess operations
Great Plains Food Bank, which had seen an unprecedented
and to work together on opportunities for improvement.
45% increase in need across North Dakota and western
Social Responsibility
As part of our company’s commitment to social responsibility
we participate in multistakeholder initiatives designed to
advance transparency, environmental protection, human
rights and good governance. For example, we are a member
of IPIECA, the global oil and gas industry organization for
environmental and social issues, as well as the U.N.
Global Compact and the Global Compact U.S. Network,
which share best practices in sustainable business
conduct across the private sector.
In keeping with our company values and purpose, we
have a longstanding commitment to diversity, equity
and inclusion in our workplace and through social
investment programs that make a positive and lasting
Minnesota due to the pandemic.
In Malaysia, Hess supports the My Kasih Foundation “Love
My School” Student Bursary Program, which provides
financial assistance to underprivileged children. We also fund
the Fulbright English Teaching Assistant Program, which
places recent graduates from U.S. universities into public
secondary schools in the Kelantan region to teach English.
In response to the pandemic, we contributed more than
60,000 units of personal protective supplies including face
masks, hand sanitizers and medical gloves to the country’s
frontline workers and donated approximately 4,000 meals to
frontline workers and underserved communities.
In Guyana, Hess and its partners contributed more than
$3 million in 2020 as part of ongoing efforts to build capacity
impact on the communities where we operate primarily
in the local Guyanese economy as well as COVID-19 relief
through education and work skills development. In 2020,
efforts. As we move forward, we are committed to building
we also provided financial and volunteer support for a
variety of COVID-19 community relief efforts.
In Houston, Hess continued to invest in its LEAP (Learn,
Engage, Advance, Persevere) educational program and
related initiatives, making adjustments for a virtual learning
environment due to the pandemic. Since 2013, Hess has
on these initiatives in 2021 by investing an additional
$8 million into the workforce development, education,
health and agricultural programs already established.
Environmental, Social and
Governance Disclosure
We see transparency in reporting as an important part of
contributed approximately $7.4 million to support students
being a trusted energy partner. We have been publishing
in Houston’s underserved Magnolia Park and Second Ward
a sustainability report since 1997, which is prepared in
communities. In 2020, Hess also launched a scholarship
accordance with the Core option of the Global Reporting
program and awarded five minority graduating seniors in
Initiative (GRI) Standards. Our reporting aligns with a number
Houston full scholarships to pursue four year college degrees.
of frameworks including oil and gas industry metrics from
In partnership with area nonprofit Second Servings,
the Sustainability Accounting Standards Board (SASB) and
Hess employees prepared and distributed more than
TCFD recommendations.
125,000 meals in 2020 to Texas families facing food
insecurity during the pandemic. As part of the company’s
support for societal changes to address racial inequities,
Hess donated $200,000 to help establish the Program
Management Office for the Houston Complete Communities
Initiative. Plans are underway to more than double our current
In 2020, we continued to be recognized for the quality of
our ESG performance and disclosure. For example, we
achieved leadership status in the CDP’s annual Global
Climate Analysis for the 12th consecutive year and earned
a place on the Dow Jones Sustainability Index for North
America for the 11th consecutive year.
11
HESS CORPORATION
Board of Directors
James H. Quigley (1) (2) (3)
Chairman of the Board;
Former Chief Executive Officer,
Deloitte Touche Tohmatsu Limited
John B. Hess (1)
Chief Executive Officer
Terrence J. Checki (1) (2) (3) (4)
Former Executive
Vice President and Head,
Emerging Markets and
International Affairs,
Federal Reserve Bank
of New York
Leonard S. Coleman, Jr. (4) (5)
Former President, National League
of Major League Baseball;
Former Commissioner,
New Jersey Department of Energy
Joaquin Duato (3) (4)
Vice Chairman of the Executive
Committee, Johnson & Johnson
Corporate Officers
John B. Hess
Chief Executive Officer
Gregory P. Hill
Chief Operating Officer
and President,
Exploration & Production
Timothy B. Goodell
General Counsel, Corporate Secretary
and Chief Compliance Officer
John P. Rielly
Chief Financial Officer
12
Edith E. Holiday (1) (4)
Former Assistant to the
President of the United States
and Secretary of the Cabinet;
Former General Counsel,
United States Department
of the Treasury
Marc S. Lipschultz (1) (3)
Co-Founder and President,
Owl Rock Capital Partners;
Co-Chief Investment Officer,
Owl Rock Capital Advisors
David McManus (3) (5)
Former Executive Vice
President, Pioneer Natural
Resources
Dr. Kevin O. Meyers (1) (2) (5)
Former Senior Vice President
of E&P for the Americas,
ConocoPhillips
Karyn F. Ovelmen (2)
Former Gas and Power Transformation
Leader, General Electric Company; Former
Executive Vice President and Chief Financial
Officer, Flowserve Corporation
William G. Schrader (2) (5)
Former Chief Operating Officer,
TNK-BP Russia
(1) Member of Executive Committee
(2) Member of Audit Committee
(3) Member of Compensation and
Management Development Committee
(4) Member of Corporate Governance
and Nominating Committee
(5) Member of Environmental, Health and
Safety Committee
Senior Vice Presidents
Vice Presidents
Barbara Lowery-Yilmaz
C. Martin Dunagin
Richard Lynch
Gerbert Schoonman
Andrew Slentz
Jonathan C. Stein
Eric Fishman
Treasurer
Lorrie Hecker
Alex Mistri
Alex Sagebien
David Shan
Kevin B. Wilcox
Controller
Jay R. Wilson
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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 1-1204
Hess Corporation
(Exact name of Registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of
incorporation or organization)
1185 AVENUE OF THE AMERICAS,
NEW YORK, NY
(Address of principal executive offices)
13-4921002
(I.R.S. Employer
Identification Number)
10036
(Zip Code)
Registrant’s telephone number, including area code (212) 997-8500
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock (par value $1.00)
Trading Symbol(s)
HES
Name of Each Exchange on Which Registered
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
Securities registered pursuant to Section 12(g) of the Act: None
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 Exchange
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
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 such files). Yes ☑ 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
☐
Emerging Growth Company ☐
Accelerated filer
☐
Smaller reporting 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. Yes ☑ No ☐
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $14,091,000,000, computed
using the outstanding Common Stock and closing market price on June 30, 2020, the last business day of the Registrant’s most
recently completed second fiscal quarter.
At January 31, 2021, there were 306,986,553 shares of Common Stock outstanding.
Part III is incorporated by reference from the Proxy Statement for the 2021 annual meeting of stockholders.
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HESS CORPORATION
Form 10-K
TABLE OF CONTENTS
Item No.
1 and 2.
1A.
1B.
3.
4.
5.
6.
7.
7A.
8.
9.
9A.
9B.
10.
11.
12.
13.
14.
15.
PART I
Business and Properties...........................................................................................................................
Information about our Executive Officers...............................................................................................
Risk Factors.............................................................................................................................................
Unresolved Staff Comments....................................................................................................................
Legal Proceedings....................................................................................................................................
Mine Safety Disclosures..........................................................................................................................
PART II
Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of
Equity Securities......................................................................................................................................
Selected Financial Data............................................................................................................................
Management’s Discussion and Analysis of Financial Condition and Results of Operations..................
Quantitative and Qualitative Disclosures About Market Risk.................................................................
Financial Statements and Supplementary Data........................................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..................
Controls and Procedures..........................................................................................................................
Other Information....................................................................................................................................
PART III
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
Exhibits, Financial Statement Schedules.................................................................................................
Signatures.................................................................................................................................................
Page
6
17
19
23
24
25
26
28
29
49
50
100
100
100
100
100
100
100
100
101
104
Unless the context indicates otherwise, references to “Hess”, the “Corporation”, “Registrant”, “we”, “us”, “our” and “its” refer
to the consolidated business operations of Hess Corporation and its subsidiaries.
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K,
including information incorporated by reference herein, contains “forward-looking
statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. Words such as “anticipate,” “estimate,” “expect,” “forecast,” “guidance,” “could,” “may,” “should,”
“would,” “believe,” “intend,” “project,” “plan,” “predict,” “will,” “target” and similar expressions identify forward-looking
statements, which are not historical in nature. Our forward-looking statements may include, without limitation: our future financial
and operational results; our business strategy; estimates of our crude oil and natural gas reserves and levels of production; benchmark
prices of crude oil, natural gas liquids and natural gas and our associated realized price differentials; our projected budget and capital
and exploratory expenditures; expected timing and completion of our development projects; and future economic and market
conditions in the oil and gas industry.
Forward-looking statements are based on our current understanding, assessments, estimates and projections of relevant factors and
reasonable assumptions about
to certain known and unknown risks and
Forward-looking statements are subject
uncertainties that could cause actual results to differ materially from our historical experience and our current projections or
expectations of future results expressed or implied by these forward-looking statements. The following important factors could cause
actual results to differ materially from those in our forward-looking statements:
the future.
• fluctuations in market prices of crude oil, natural gas liquids and natural gas and competition in the oil and gas exploration and
production industry, including as a result of the global COVID-19 pandemic (COVID-19);
• reduced demand for our products, including due to COVID-19 or the outbreak of any other public health threat, or due to the
impact of competing or alternative energy products and political conditions and events;
• potential failures or delays in increasing oil and gas reserves, including as a result of unsuccessful exploration activity, drilling
risks and unforeseen reservoir conditions, and in achieving expected production levels;
• changes in tax, property, contract and other laws, regulations and governmental actions applicable to our business, including
legislative and regulatory initiatives regarding environmental concerns, such as measures to limit greenhouse gas emissions and
flaring as well as fracking bans;
• disruption or interruption of our operations due to catastrophic events, such as accidents, severe weather, geological events,
shortages of skilled labor, cyber-attacks or health measures related to COVID-19;
• the ability of our contractual counterparties to satisfy their obligations to us, including the operation of joint ventures under which
we may not control;
• unexpected changes in technical requirements for constructing, modifying or operating exploration and production facilities and/
or the inability to timely obtain or maintain necessary permits;
• availability and costs of employees and other personnel, drilling rigs, equipment, supplies and other required services;
• any limitations on our access to capital or increase in our cost of capital, including as a result of weakness in the oil and gas
industry or negative outcomes within commodity and financial markets;
• liability resulting from litigation, including heightened risks associated with being a general partner of Hess Midstream LP; and
• other factors described in Item 1A—Risk Factors in this Annual Report on Form 10-K and any additional risks described in our
other filings with the Securities and Exchange Commission.
As and when made, we believe that our forward-looking statements are reasonable. However, given these risks and uncertainties,
caution should be taken not to place undue reliance on any such forward-looking statements since such statements speak only as of the
date when made and there can be no assurance that such forward-looking statements will occur and actual results may differ materially
from those contained in any forward-looking statement we make. Except as required by law, we undertake no obligation to publicly
update or revise any forward-looking statements, whether because of new information, future events or otherwise.
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Glossary
Throughout this report, the following company or industry specific terms and abbreviations are used:
Appraisal well – An exploration well drilled to confirm the results of a discovery well, or a well that is used to determine the
boundaries of a productive formation.
Bbl – One stock tank barrel, which is 42 United States gallons liquid volume.
Barrel of oil equivalent or Boe – This reflects natural gas reserves converted on the basis of relative energy content of six mcf equals
one barrel of oil equivalent (one mcf represents one thousand cubic feet). Barrel of oil equivalence does not necessarily result in price
equivalence, as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the
corresponding price for crude oil over the recent past.
Boepd – Barrels of oil equivalent per day.
Bopd – Barrels of oil per day.
CGA – Clean Gulf Associates.
Condensate – A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that when
produced, is in the liquid phase at surface pressure and temperature.
DAPL – Dakota Access Pipeline.
DD&A – Depreciation, depletion and amortization.
Development well – A well drilled within the proved area of an oil and/or natural gas reservoir with the intent of producing oil and/or
natural gas from that area of the reservoir.
Dry hole – An exploratory or development well that does not find oil or natural gas in commercial quantities.
EPA – Environmental Protection Agency.
EHS & SR – Environment, health, safety and social responsibility.
Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be
productive by another reservoir.
E&P – Exploration and Production.
Fractionation – A process by which the mixture of natural gas liquids that results from natural gas processing is separated into the
NGL components, such as ethane, propane, butane, isobutane, and natural gasoline, prior to their sale to various petrochemical and
industrial end users. Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take
advantage of the difference in boiling points of separate products.
Field – An area consisting of a single reservoir or multiple reservoirs all grouped or related to the same individual geological structural
feature and/or stratigraphic condition.
FPSO – Floating production, storage, and offloading vessel.
GHG – Greenhouse gas.
Gross acres – Acreage in which a working interest is held by the Corporation.
Gross well – A well in which a working interest is held by the Corporation.
ICE – Integrity critical equipment.
JOA – Joint operating agreement.
LIBOR – The London Interbank Offered Rate.
Mcf – One thousand cubic feet of natural gas.
Mmcfd – One thousand mcf of natural gas per day.
MWCC – Marine Well Containment Company.
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MSRC – Marine Spill Response Corporation.
MTBE – Methyl tertiary butyl ether.
Net acreage or Net wells – The sum of the fractional working interests owned by the Corporation in gross acres or gross wells.
NGL or Natural gas liquids – Naturally occurring hydrocarbon substances that are separated and produced by fractionating natural
gas, including ethane, butane, isobutane, propane and natural gasoline. NGL do not sell at prices equivalent to crude oil.
Non-operated – Projects in which the Corporation has a working interest but does not perform the role of Operator.
OPEC – Organization of Petroleum Exporting Countries.
Operator – The entity responsible for conducting and managing exploration, development, and/or production operations for an oil or
gas project.
OSHA – Occupational Safety and Health Administration.
OSRL – Oil Spill Response Limited.
Plug and perf completion – A well completion technique which involves creating perforations in the well casing that penetrate the
hydrocarbon reservoir section between set plugs.
Participating interest – Reflects the proportion of exploration and production costs each party will bear as set out in an operating
agreement.
Production sharing contract – An agreement between a host government and the owners (or co-owners) of a well or field regarding
the percentage of production each party will receive after the parties have recovered a specified amount of capital and operational
expenses.
Productive well – A well that is capable of producing hydrocarbons in sufficient quantities to justify commercial exploitation.
Proved properties – Properties with proved reserves.
Proved reserves – In accordance with the Securities and Exchange Commission regulations and practices recognized in the publication
of the Society of Petroleum Engineers entitled, “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information,” those quantities of crude oil and condensate, NGL 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, regardless of whether deterministic or probabilistic
methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a reasonable time.
Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and
operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved undeveloped reserves – Proved reserves 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. Reserves on undrilled acreage shall be limited to
those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using
reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
SOFR – Secured Overnight Financing Rate.
Unproved properties – Properties with no proved reserves.
VLCC – Very large crude carrier.
Working interest – An interest in an oil and gas property that provides the owner of the interest the right to participate in the drilling
for and production of oil and gas on the relevant acreage and requires the owner to pay a share of the costs of drilling and production
operations.
WWC – Wild Well Control.
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Items 1 and 2. Business and Properties
PART I
Hess Corporation, incorporated in the State of Delaware in 1920, is a global E&P company engaged in exploration, development,
production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located
primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Denmark. We
conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname and Canada. At the
Stabroek Block (Hess 30%), offshore Guyana, we have announced eighteen significant discoveries. The Liza Phase 1 development
achieved first production in December 2019, and reached its nameplate production capacity of approximately 120,000 gross bopd in
December 2020. The Liza Phase 2 development was sanctioned in the second quarter of 2019 and is expected to achieve first
production by early 2022, with production capacity of approximately 220,000 gross bopd. A third development, Payara, was
sanctioned in the third quarter of 2020 and is expected to achieve first production in 2024, with production capacity of approximately
220,000 gross bopd. The discovered resources to date on the Stabroek Block are expected to underpin up to ten FPSOs with the first
five FPSOs producing more than 750,000 gross bopd by 2026.
Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess
Midstream LP at December 31, 2020, provides fee-based services, including gathering, compressing and processing natural gas and
fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water
handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota. See Midstream on page 12.
Exploration and Production
Proved Reserves
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an
unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual
agreements, and exclude escalations based on future conditions. Crude oil prices used in the determination of proved reserves at
December 31, 2020 were $39.77 per barrel for West Texas Intermediate (WTI) (2019: $55.73) and $43.43 per barrel for Brent (2019:
$62.54). Our total proved developed and undeveloped reserves at December 31 were as follows:
Developed
United States............................................................
Guyana (a)...............................................................
Malaysia and JDA...................................................
Other (b)..................................................................
Undeveloped
United States............................................................
Guyana (a)...............................................................
Malaysia and JDA...................................................
Other (b)..................................................................
Total
United States............................................................
Guyana (a)...............................................................
Malaysia and JDA...................................................
Other (b)..................................................................
Crude Oil
& Condensate
Natural Gas Liquids
Natural Gas
Total Barrels of Oil
Equivalent (BOE)
2020
2019
2020
2019
2020
2019
2020
2019
(Millions of bbls)
(Millions of bbls)
(Millions of mcf)
(Millions of bbls)
282
72
4
134
492
119
132
2
—
253
401
204
6
134
745
293
31
5
139
468
215
55
2
22
294
508
86
7
161
762
120
—
—
—
120
42
—
—
—
42
162
—
—
—
162
90
—
—
—
90
79
—
—
—
79
169
—
—
—
169
490
36
543
165
1,234
163
47
132
—
342
653
83
675
165
1,576
400
3
497
183
1,083
300
4
188
18
510
700
7
685
201
1,593
484
78
94
162
818
188
140
24
—
352
672
218
118
162
1,170
450
31
88
170
739
344
56
33
25
458
794
87
121
195
1,197
(a) Guyana natural gas reserves will be consumed for fuel.
(b) Other includes our interests in Denmark and Libya. At December 31, 2020, total proved reserves for Denmark and Libya were 40 million boe and 122 million
boe, respectively. At December 31, 2019, total proved reserves for Denmark and Libya were 54 million boe and 141 million boe, respectively.
Proved undeveloped reserves were 30% of our total proved reserves at December 31, 2020 on a boe basis (2019: 38%). Proved
reserves held under production sharing contracts totaled 28% of our crude oil reserves and 48% of our natural gas reserves at
December 31, 2020 (2019: 12% and 43%, respectively).
For additional information regarding our proved oil and gas reserves, see the Supplementary Oil and Gas Data to the
Consolidated Financial Statements presented on pages 91 through 99.
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Production
Worldwide crude oil, NGL, and natural gas net production was as follows:
Crude oil – Thousands of barrels
United States
North Dakota................................................................................................................................
Offshore (a)..................................................................................................................................
Total United States............................................................................................................................
Guyana...............................................................................................................................................
Malaysia and JDA.............................................................................................................................
Other (b)............................................................................................................................................
Total...................................................................................................................................................
Natural gas liquids – Thousands of barrels
United States
North Dakota................................................................................................................................
Other Onshore (c).........................................................................................................................
Total Onshore..........................................................................................................................
Offshore (a)..................................................................................................................................
Total United States............................................................................................................................
Natural gas – Thousands of mcf
United States
North Dakota................................................................................................................................
Other Onshore (c).........................................................................................................................
Total Onshore..........................................................................................................................
Offshore (a)..................................................................................................................................
Total United States............................................................................................................................
Malaysia and JDA.............................................................................................................................
Other (b)............................................................................................................................................
Total...................................................................................................................................................
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2020
2019
2018
39,047
13,961
53,008
7,457
1,287
3,358
65,110
20,514
—
20,514
1,878
22,392
65,786
—
65,786
27,985
93,771
106,618
2,540
202,929
34,299
16,628
50,927
67
1,479
9,161
61,634
15,150
—
15,150
1,942
17,092
40,222
—
40,222
33,212
73,434
128,071
7,144
208,649
28,052
15,026
43,078
—
1,397
8,885
53,360
11,497
917
12,414
1,703
14,117
27,740
14,052
41,792
24,452
66,244
128,472
7,246
201,962
Total Barrels of Oil Equivalent (in millions) (a) (b) (c)..................................................................
121
114
101
(a) In November 2020, we sold our working interest in the Shenzi Field in the deepwater Gulf of Mexico. Shenzi net production was 3.3 million boe in 2020 (2019:
4.5 million boe; 2018: 5.8 million boe).
(b) Other includes our interests in Denmark and Libya. Net production from Libya was 1.6 million boe for 2020 (2019: 7.8 million boe; 2018: 7.4 million boe). Net
production from Denmark was 2.2 million boe for 2020 (2019: 2.6 million boe; 2018: 2.7 million boe).
(c) In August 2018, we sold our interests in the Utica shale play, onshore U.S. Utica net production was 3.3 million boe in 2018.
E&P Operations
At December 31, 2020, our significant E&P assets included the following:
United States
Our production in the U.S. was from the Bakken shale play in the Williston Basin of North Dakota (Bakken) and from offshore
properties in the Gulf of Mexico.
North Dakota:
Bakken: At December 31, 2020, we held approximately 532,000 net acres in the Bakken with varying working interest
percentages. Net production averaged 193,000 boepd in 2020. We operated six rigs in the Bakken through May, before reducing to
one rig for the remainder of 2020 in response to the sharp decline in oil prices resulting from the COVID-19 pandemic. We drilled
71 wells and brought 111 wells on production, bringing the total operated production wells to 1,686 by year-end. We reduced the
average cost of a plug and perf well in 2020 to $6.2 million per well from $6.8 million per well in 2019.
During 2021, we plan to operate two rigs, drill approximately 55 wells and bring approximately 45 wells on production. We
In 2021, the Tioga Gas Plant will be shut
forecast net production to average approximately 170,000 boepd for the full year 2021.
down for approximately 45 days for a planned maintenance turnaround and tie-in of the plant expansion project completed in 2020
which will increase gas processing capacity to 400 million cubic feet per day from 250 million cubic feet per day. The shutdown is
expected to reduce 2021 average net production, mostly natural gas, by approximately 7,500 boepd.
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Offshore:
Gulf of Mexico: At December 31, 2020, we held approximately 61,000 net developed acres, with our production operations
principally at the Baldpate (Hess 50%), Conger (Hess 38%), Hack Wilson (Hess 25%), Llano (Hess 50%), Penn State (Hess 50%),
Stampede (Hess 25%) and Tubular Bells (Hess 57%) fields. At December 31, 2020, we held approximately 286,000 net undeveloped
acres, of which leases covering approximately 112,000 acres are due to expire in the next three years.
In November 2020, we completed the sale of our 28% working interest in the Shenzi Field for net proceeds of $482 million, after
closing adjustments. Our net share of production from the Shenzi Field during 2020 was 9,000 boepd.
We participated in two outside operated exploration wells that were completed in 2020, the Oldfield-1 well and the Galapagos
Deep well, both located in the Mississippi Canyon area. Both wells were unsuccessful.
Guyana
Stabroek Block: The Stabroek Block (Hess 30%), offshore Guyana, covers approximately 6.6 million acres. The operator, Esso
Exploration and Production Guyana Limited, has made eighteen significant discoveries since 2015. The discovered resources to date
on the Stabroek Block are expected to underpin the potential for up to ten FPSOs with the first five FPSOs producing more than
750,000 gross bopd by 2026.
The Liza Phase 1 development, which was sanctioned in 2017, began producing oil in December 2019 from the Liza Destiny
FPSO and reached its nameplate production capacity of 120,000 gross bopd in December 2020. The Liza Phase 2 development was
sanctioned in 2019 and will utilize the Liza Unity FPSO to produce up to 220,000 gross bopd, with first production expected by early
2022. A total of 30 wells are planned at six drill centers, including 15 production wells, nine water injection wells and six gas
In 2021, the operator plans to continue development drilling, complete installation of subsea flow lines and
injection wells.
equipment, complete installation of topside facilities on the FPSO and sail the Liza Unity FPSO from Singapore to the Liza Field.
On September 30, 2020, we announced the final investment decision to proceed with development of the Payara Field on the
Stabroek Block after the development plan received approval from the government of Guyana. Payara will utilize the Prosperity
FPSO, which will have the capacity to produce up to 220,000 gross bopd, with first production expected in 2024. Ten drill centers
with a total of 41 wells are planned, including 20 production wells and 21 injection wells. Excluding pre-sanction costs and FPSO
purchase cost, our net share of development costs is forecast to be approximately $1.8 billion.
The operator is currently utilizing four drillships for exploration, appraisal and development drilling activities, and intends to bring
in a fifth and sixth drillship in 2021.
In 2020, the following exploration and appraisal wells were drilled on the Stabroek Block (in chronological order):
Uaru: The Uaru-1 well encountered approximately 94 feet of high-quality oil-bearing sandstone reservoir and is located
approximately 10 miles northeast of the Liza Field.
Yellowtail: The Yellowtail-2 well encountered approximately 69 feet of high-quality oil-bearing reservoirs and is located
adjacent to and below the Yellowtail-1 discovery.
Redtail: The Redtail-1 well encountered approximately 232 feet of high-quality oil-bearing sandstone and is located
approximately 1.5 miles northwest of the Yellowtail discovery.
In 2021, the operator completed drilling of the Hassa-1 well. The Hassa-1 well encountered approximately 50 feet of oil bearing
reservoir in deeper geologic intervals, although the well did not encounter oil in the primary target areas. The operator plans to drill an
additional 12 to 15 exploration and appraisal wells in 2021 that will target a variety of prospects and play types. These will include
both lower risk wells near existing discoveries and higher risk step-out wells, and several penetrations that will test deeper Lower
Campanian and Santonian intervals.
Kaieteur Block: In 2018, we acquired a participating interest in the Kaieteur Block (Hess 15%), which is adjacent to the Stabroek
Block. In 2020, the operator, Esso Exploration and Production Guyana Limited, completed drilling of the Tanager-1 exploration well.
The well did encounter hydrocarbons but was not a commercial success on a stand-alone basis.
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Malaysia and JDA
Malaysia/Thailand Joint Development Area (JDA): Production comes from the Carigali Hess operated Block A-18 in the
Malaysia/Thailand joint development area in the Gulf of Thailand (Hess 50%). A multi-year drilling program is planned to commence
in the first half of 2021.
Malaysia: Our production in Malaysia comes from our interest in Block PM302 (Hess 50%) located in the North Malay Basin
(NMB), offshore Peninsular Malaysia and Block PM301 (Hess 50%), which is adjacent to and is unitized with Block A‑18 of the
JDA. In 2021, we plan to continue drilling and development activities at NMB.
Other
Denmark: Production comes from our operated interest in the South Arne Field (Hess 62%).
Libya: At the onshore Waha concession in Libya, which includes the Defa, Faregh, Gialo, North Gialo and Belhedan fields (Hess
8%), net production averaged 4,000 boepd in 2020, 21,000 boepd in 2019 and 20,000 boepd in 2018. Production was shut-in by the
operator between January and October of 2020 due to force majeure caused by civil unrest. The Company’s net investment in Libya
was approximately $85 million at December 31, 2020.
Suriname: We hold a 33% non-operated participating interest in Block 42, offshore Suriname. In 2022, the operator, a subsidiary
of Royal Dutch Shell plc, plans to drill an exploration well. We also hold a 33% non-operated participating interest in Block 59,
offshore Suriname, where the operator, ExxonMobil Exploration and Production Suriname B.V., is interpreting recently acquired 2D
seismic and is planning a 3D seismic acquisition.
Canada: We hold a 50% non-operated participating interest in four exploration licenses offshore Nova Scotia and a 25% non-
operated participating interest in three exploration licenses offshore Newfoundland. In 2023, the operator, BP Canada, plans to drill
one exploration well in Newfoundland.
Sales Commitments
We have certain long-term contracts with fixed minimum sales volume commitments for natural gas and NGL production. At the
JDA in the Gulf of Thailand, we have annual minimum net sales commitments of approximately 80 billion cubic feet of natural gas
per year through 2025 and approximately 40 billion cubic feet per year in 2026 and 2027. At the North Malay Basin development
project offshore Peninsular Malaysia, we have annual net sales commitments of approximately 55 billion cubic feet per year through
2024. Our estimated total volume of production subject to these sales commitments is approximately 710 billion cubic feet of natural
gas. We also have multiple minimum delivery commitments in the Bakken for natural gas and NGL with various end dates up
through 2032, with total commitments of approximately 100 million boe over the remaining life of the contracts.
We have not experienced any significant constraints in satisfying the committed quantities required by our sales commitments, and
we anticipate being able to meet future requirements from available proved and probable reserves, as well as projected third-party
supply in the case of NGL.
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Selling Prices and Production Costs
The following table presents our average selling prices and average production costs:
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
United States
North Dakota........................................................................................................................ $
Offshore................................................................................................................................
Total United States....................................................................................................................
Guyana......................................................................................................................................
Malaysia and JDA.....................................................................................................................
Other (b)....................................................................................................................................
Worldwide.........................................................................................................................
Crude Oil - Per Barrel (Excluding Hedging)
United States
North Dakota........................................................................................................................ $
Offshore................................................................................................................................
Total United States....................................................................................................................
Guyana......................................................................................................................................
Malaysia and JDA.....................................................................................................................
Other (b)....................................................................................................................................
Worldwide.........................................................................................................................
Natural Gas Liquids - Per Barrel
United States
North Dakota........................................................................................................................ $
Other Onshore (c).................................................................................................................
Offshore................................................................................................................................
Worldwide.........................................................................................................................
Natural Gas - Per Mcf
United States
North Dakota........................................................................................................................ $
Other Onshore (c).................................................................................................................
Offshore................................................................................................................................
Total United States....................................................................................................................
Malaysia and JDA.....................................................................................................................
Other (b)....................................................................................................................................
Worldwide.........................................................................................................................
Average production (lifting) costs per barrel of oil equivalent produced (d)
United States
North Dakota (e)................................................................................................................... $
Other Onshore (c).................................................................................................................
Offshore................................................................................................................................
Total United States....................................................................................................................
Guyana (f).................................................................................................................................
Malaysia and JDA.....................................................................................................................
Other (b)....................................................................................................................................
Worldwide.........................................................................................................................
2020
2019
2018
$
$
$
$
$
42.63
45.92
43.56
46.41
37.91
51.37
44.28
33.87
36.55
34.63
37.40
37.91
43.42
35.52
11.29
—
8.94
11.10
1.27
—
1.23
1.26
4.47
3.41
2.98
17.67
—
11.27
16.59
18.25
5.77
22.78
15.19
$
$
$
$
$
53.19
59.18
55.15
—
61.81
65.22
56.77
53.18
59.17
55.14
—
61.81
65.22
56.76
13.20
—
13.31
13.21
1.59
—
2.12
1.83
5.04
4.63
3.90
19.68
—
11.27
17.66
—
6.07
8.87
14.93
56.90
62.02
58.69
—
70.42
69.76
60.77
60.64
65.73
62.41
—
70.42
69.76
63.80
21.48
18.55
25.58
21.81
2.42
2.02
2.68
2.43
5.07
4.41
4.18
23.00
14.32
13.80
19.74
—
5.65
9.04
15.73
(a) Includes inter‑company transfers valued at approximate market prices, primarily onshore U.S., which include certain processing and distribution fees.
(b) Other includes our interests in Denmark and Libya.
(c) In August 2018, we sold our interests in the Utica shale play, onshore U.S.
(d) Production (lifting) costs consist of amounts incurred to operate and maintain our producing oil and gas wells, related equipment and facilities and
transportation costs, including Midstream tariff expense. Lifting costs do not include costs of finding and developing proved oil and gas reserves, production
and severance taxes, or the costs of related general and administrative expenses, interest expense and income taxes.
(e) Includes Midstream tariff expense of $13.42 per boe in 2020 (2019: $12.89 per boe; 2018: $14.72 per boe).
(f)
Includes pre-development costs from the operator for future phases of development and Hess internal costs totaling $5.11 per boe.
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Gross and Net Undeveloped Acreage
At December 31, 2020, gross and net undeveloped acreage amounted to:
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Undeveloped
Acreage (a)
Gross
Net
(In thousands)
United States..............................................................................................................................................................
Guyana.......................................................................................................................................................................
Malaysia and JDA......................................................................................................................................................
Denmark.....................................................................................................................................................................
Libya...........................................................................................................................................................................
Canada........................................................................................................................................................................
Suriname.....................................................................................................................................................................
Total (b)...............................................................................................................................................................
333
9,873
655
9
3,334
3,405
4,363
21,972
300
2,461
327
1
272
1,283
1,454
6,098
(a) Includes acreage held under production sharing contracts.
(b) At December 31, 2020, 59% of our net undeveloped acreage, primarily in Suriname, Canada, and Guyana, is scheduled to expire during the next three years
pending results of exploration activities.
Gross and Net Developed Acreage, and Productive Wells
At December 31, 2020 gross and net developed acreage and productive wells amounted to:
Developed Acreage
Applicable to
Productive Wells
Productive Wells (a)
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
(In thousands)
United States..................................................................................................
Guyana...........................................................................................................
Malaysia and JDA.........................................................................................
Denmark........................................................................................................
Libya..............................................................................................................
Total........................................................................................................
967
95
454
23
9,564
11,103
578
29
227
14
782
1,630
3,061
6
—
18
1,123
4,208
1,424
2
—
11
92
1,529
11
—
129
—
10
150
5
—
62
—
1
68
(a) Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 24 gross wells and 21 net wells.
Exploratory and Development Wells
Net exploratory and net development wells completed during the years ended December 31 were:
Net Exploratory Wells
Net Development Wells
2020
2019
2018
2020
2019
2018
Productive wells
United States..................................................................................................
Guyana...........................................................................................................
Malaysia and JDA.........................................................................................
Libya..............................................................................................................
Dry holes
United States..................................................................................................
Guyana (a).....................................................................................................
Malaysia and JDA.........................................................................................
Denmark........................................................................................................
Suriname (b)..................................................................................................
Canada...........................................................................................................
Total........................................................................................................
—
1
—
—
1
1
—
—
—
—
—
1
2
—
2
—
—
2
—
—
—
1
—
—
1
3
—
2
2
—
4
—
—
1
—
—
1
2
6
98
—
3
—
101
——
——
—
——
——
—
—
101
140
2
3
2
147
—
—
—
—
—
—
—
147
92
—
1
—
93
—
—
—
93
(a) Includes the Tanager-1 well at the Kaieteur Block, offshore Guyana in 2020 and the Sorubim-1 well at the Stabroek Block, offshore Guyana in 2018.
(b) Includes the Pontoenoe-1 well in Block 42, offshore Suriname in 2018.
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Number of Wells in the Process of Being Drilled
At December 31, 2020, the number of wells in the process of drilling amounted to:
United States..............................................................................................................................................................
Guyana (a)..................................................................................................................................................................
Libya...........................................................................................................................................................................
Total.....................................................................................................................................................................
187
18
8
213
34
5
1
40
Gross
Wells
Net
Wells
(a) Includes ten gross (and three net) water injection and gas injection wells in process at December 31, 2020.
Midstream
Prior to December 16, 2019, the Midstream segment was primarily comprised of Hess Infrastructure Partners LP (HIP), a 50/50
joint venture between Hess Corporation and Global Infrastructure Partners (GIP), formed to own, operate, develop and acquire a
diverse set of midstream assets to provide fee-based services to Hess and third-party customers. HIP was initially formed on May 21,
2015, with Hess selling 50% of HIP to GIP for approximately $2.6 billion on July 1, 2015.
On April 10, 2017, HIP completed an initial public offering (IPO) of 16,997,000 common units, representing 30.5% limited
partnership interests in its subsidiary Hess Midstream Partners LP (Hess Midstream Partners), for net proceeds of approximately
$365.5 million.
In connection with the IPO, HIP contributed a 20% controlling economic interest in each of Hess North Dakota
Pipeline Operations LP, Hess TGP Operations LP, and Hess North Dakota Export Logistics Operations LP, and a 100% economic
interest in Hess Mentor Storage Holdings LLC (collectively the “Contributed Businesses”).
In exchange for the contributed
businesses, Hess and GIP each received common and subordinated units representing a direct 33.75% limited partner interest in Hess
Midstream Partners and a 50% indirect ownership interest through HIP in Hess Midstream Partners’ general partner, which had a 2%
economic interest in Hess Midstream Partners plus incentive distribution rights.
On March 1, 2019, HIP acquired Hess’s existing Bakken water services business for $225 million in cash. As a result of this
transaction, we recorded an after-tax gain of $78 million in additional paid-in capital with an offsetting reduction to noncontrolling
interest to reflect the adjustment to GIP’s noncontrolling interest in HIP. On March 22, 2019, HIP and Hess Midstream Partners
acquired crude oil and gas gathering assets, and HIP acquired water gathering assets of Summit Midstream Partners LP’s Tioga
Gathering System for aggregate cash consideration of approximately $90 million, with the potential for up to an additional $10 million
of contingent payments in future periods subject to certain future performance metrics. On January 25, 2018, Hess Midstream
Partners entered into a 50/50 joint venture with Targa Resources Corp. to construct a new 200 million standard cubic feet per day gas
processing plant call Little Missouri 4. The plant, which is operated by Targa, was placed into service in the third quarter of 2019.
On December 16, 2019, Hess Midstream Partners acquired HIP, including HIP’s 80% interest in Hess Midstream Partners’ oil and
gas midstream assets, HIP’s water services business and the outstanding economic general partner interest and incentive distribution
rights in Hess Midstream Partners LP. In addition, Hess Midstream Partners’ organizational structure converted from a master limited
partnership into an “Up-C” structure in which Hess Midstream Partners’ public unitholders received newly issued Class A shares in a
new public entity named Hess Midstream LP (Hess Midstream), which is taxed as a corporation for U.S. federal and state income tax
purposes. Hess Midstream Partners changed its name to “Hess Midstream Operations LP” (HESM Opco) and became a consolidated
subsidiary of Hess Midstream, the new publicly listed entity. As consideration for the acquisition, Hess received a cash payment of
$301 million and approximately 115 million newly issued HESM Opco Class B units. After giving effect to the acquisition and
related transactions, public shareholders of Class A shares in Hess Midstream own 6% of the consolidated entity on an as-exchanged
basis and Hess and GIP each own 47% of the consolidated entity on an as-exchanged basis, primarily through the sponsors’ ownership
of Class B units in HESM Opco that are exchangeable into Class A shares of Hess Midstream on a one-for-one basis, or referred to as
“Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP”.
At December 31, 2020, Midstream assets included the following:
• Natural Gas Gathering and Compression: A natural gas gathering and compression system located primarily in McKenzie,
Williams and Mountrail Counties, North Dakota connecting Hess and third-party owned or operated wells to the Tioga Gas
Plant, Little Missouri 4 Gas Plant, and third-party pipeline facilities. This gathering system consists of approximately 1,350
miles of high and low pressure natural gas and NGL gathering pipelines with a current capacity of up to approximately 450
mmcfd, including an aggregate compression capacity of approximately 310 mmcfd.
In 2020, compression capacity was
increased by approximately 70 mmcfd by expanding two existing compressor stations and restarting two additional legacy
compression facilities. The system also includes the Hawkeye Gas Facility, which contributes approximately 50 mmcfd of
the system’s current compression capacity.
• Crude Oil Gathering: A crude oil gathering system located primarily in McKenzie, Williams and Mountrail Counties, North
Dakota, connecting Hess and third-party owned or operated wells to the Ramberg Terminal Facility, the Tioga Rail Terminal
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and the Johnson’s Corner Header System. The crude oil gathering system consists of approximately 550 miles of crude oil
gathering pipelines with a current capacity of up to approximately 240,000 bopd. The system also includes the Hawkeye Oil
Facility, which contributes approximately 75,000 bopd of the system’s current capacity.
• Tioga Gas Plant: A natural gas processing and fractionation plant located in Tioga, North Dakota, with a current processing
capacity of approximately 250 mmcfd and fractionation capacity of approximately 60,000 boepd. In 2019, Hess Midstream
LP announced plans to expand processing capacity at the plant by 150 mmcfd for total processing capacity of 400 mmcfd. In
2020, the facility construction was completed for the expansion.
Incremental gas processing capacity is expected to be
available in 2021 upon completion of a scheduled plant maintenance turnaround, during which the expansion and residue and
NGL takeaway pipelines will be tied in. The plant maintenance turnaround was originally planned to occur in the third
quarter of 2020 but was deferred to 2021 to ensure safe execution in light of the COVID-19 pandemic.
• Little Missouri 4: A natural gas processing plant
in McKenzie County, North Dakota, with processing capacity of
approximately 200 mmcfd, which was placed in service during 2019 and is operated by Targa Resources Corp. Hess
Midstream LP owns a 50% interest in Little Missouri 4 through a joint venture with Targa Resources Corp. and is entitled to
half of the plant’s processing capacity.
• Mentor Storage Terminal: A propane storage cavern and rail and truck loading and unloading facility located in Mentor,
Minnesota, with approximately 330,000 boe of working storage capacity.
• Ramberg Terminal Facility: A crude oil pipeline and truck receipt terminal located in Williams County, North Dakota with a
delivery capacity of up to approximately 285,000 bopd of crude oil into an interconnecting pipeline for transportation to the
Tioga Rail Terminal and to multiple third-party pipelines and storage facilities.
• Tioga Rail Terminal: A 140,000 bopd crude oil and 30,000 boepd NGL rail loading terminal in Tioga, North Dakota that is
connected to the Tioga Gas Plant, the Ramberg Terminal Facility and our crude oil gathering system.
• Crude Oil Rail Cars: A total of 550 crude oil rail cars, which are operated as unit trains consisting of approximately 100 to
110 crude oil rail cars. These crude oil rail cars have been constructed to DOT-117 standards.
• Johnson’s Corner Header System: A crude oil pipeline header system located in McKenzie County, North Dakota that
to third-party interstate pipeline
receives crude oil by pipeline from Hess and third parties and delivers crude oil
systems. The facility has a delivery capacity of approximately 100,000 bopd of crude oil.
• Produced Water Gathering and Disposal: A produced water gathering system located primarily in Williams and Mountrail
Counties, North Dakota, that transports produced water from the wellsite by approximately 270 miles of pipeline in gathering
systems or by third-party trucking to water handling facilities for disposal. As of December 31, 2020, five water handling
and disposal facilities with a combined capacity of 70,000 barrels per day were in service. These water handling and disposal
facilities are owned and operated by Hess Water Services Holdings LLC, an indirect wholly owned subsidiary of Hess
Midstream LP. Produced water is also transported to twelve water handling and disposal facilities operated by third parties
that have a combined permitted disposal capacity of approximately 170,000 barrels per day.
Hess Midstream has multiple long-term, fee-based commercial agreements effective January 1, 2014 with certain subsidiaries of
Hess for gas gathering, crude oil gathering, gas processing and fractionation, storage services, and terminal and export services, each
generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream.
These contracts have minimum volumes that the Hess subsidiaries are obligated to provide each calendar quarter. The minimum
volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and
projected third-party volumes that will be purchased in the Bakken. On December 30, 2020, Hess Midstream exercised its renewal
options to extend the terms of certain gas gathering, crude oil gathering, gas processing and fractionation, storage, and terminal and
export commercial agreements for the secondary term through December 31, 2033. There were no changes to any provisions of the
existing commercial agreements as a result of the exercise of the renewal options. Hess Midstream also has long-term, fee based
commercial agreements for water handling services effective January 1, 2019 with a subsidiary of Hess, with an initial 14 year term
that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. Water handling services are provided
for an agreed-upon fee per barrel or the reimbursement of third-party fees.
Competition and Market Conditions
See Item 1A. Risk Factors for a discussion of competition and market conditions.
Emergency Preparedness and Response Plans and Procedures
We have in place a series of business and asset-specific emergency preparedness, response and business continuity plans that
detail procedures for rapid and effective emergency response and environmental mitigation activities. These plans are maintained,
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reviewed and updated as necessary to confirm their accuracy and suitability. Where applicable, they are also reviewed and approved
by the relevant host government authorities.
Responder training and drills are routinely held worldwide to assess and continually improve the effectiveness of our plans. Our
contractors, service providers, representatives from government agencies and, where applicable, joint venture partners participate in
the drills to help ensure that emergency procedures are comprehensive and can be effectively implemented.
To complement internal capabilities and to help ensure coverage for our global operations, we maintain membership contracts
with a network of local, regional and global oil spill response and emergency response organizations. At the regional and global level,
these organizations include CGA, MSRC, MWCC, WWC and OSRL. CGA and MSRC are domestic spill response organizations and
MWCC provides the equipment and personnel to contain underwater well control incidents in the Gulf of Mexico. WWC provides
firefighting, well control and engineering services globally. OSRL is a global response organization and is available, when needed, to
assist us with any of our assets.
In addition to owning response assets in their own right, the organization maintains business
relationships that provide immediate access to additional critical response support services if required. OSRL’s response assets
include nearly 300 recovery and storage vessels and barges, more than 250 skimmers, over 600,000 feet of boom, nine capping stacks
and significant quantities of dispersants and other ancillary equipment, including aircraft. In addition to external well control and oil
spill response support, we have contracts with wildlife, environmental, meteorology, incident management, medical and security
resources.
If we were to engage these organizations to obtain additional critical response support services, we would fund such
services and, where appropriate, seek reimbursement under our insurance coverage, as described below. In certain circumstances, we
pursue and enter into mutual aid agreements with other companies and government cooperatives to receive and provide oil spill
response equipment and personnel support. We maintain close associations with emergency response organizations through our
representation on the Executive Committees of CGA and MSRC, as well as the Board of Directors of OSRL.
We continue to participate in several industry-wide task forces that are studying better ways to assess the risk of and prevent
onshore and offshore incidents, access and control blowouts in subsea environments, and improve containment and recovery
methods. The task forces are working closely with the oil and gas industry and international government agencies to implement
improvements and increase the effectiveness of oil spill prevention, preparedness, response and recovery processes.
Insurance Coverage and Indemnification
We maintain insurance coverage that includes coverage for physical damage to our property, third-party liability, workers’
compensation and employers’ liability, general liability, sudden and accidental pollution and other coverage. This insurance coverage
is subject to deductibles, exclusions and limitations and there is no assurance that such coverage will adequately protect us against
liability from all potential consequences and damages.
The amount of insurance covering physical damage to our property and liability related to negative environmental effects resulting
from a sudden and accidental pollution event, excluding Atlantic Named Windstorm coverage for which we are self-insured, varies by
asset, based on the asset's estimated replacement value or the estimated maximum loss. In the case of a catastrophic event, first party
coverage consists of two tiers of insurance. The first $400 million of coverage is provided through an industry mutual insurance
group. Above this $400 million threshold, insurance is carried which ranges in value up to $1.27 billion in total, depending on the
asset coverage level, as described above. The insurance programs covering physical damage to our property exclude business
interruption protection for our E&P operations. Additionally, we carry insurance that provides third-party coverage for general
liability, and sudden and accidental pollution, up to $850 million, which coverage under a standard joint operating arrangement would
be reduced to our participating interest. Our insurance policies renew at various dates each year. Future insurance coverage could
increase in cost and may include higher deductibles or retentions, or additional exclusions or limitations. In addition, some forms of
insurance may become unavailable in the future or unavailable on terms that are deemed economically acceptable.
Generally, our drilling contracts (and most of our other offshore services contracts) provide for a mutual hold harmless indemnity
structure whereby each party to the contract (the Corporation and Contractor) indemnifies the other party for injuries or damages to
their personnel and property (and, often, those of its contractors/subcontractors) regardless of fault. Variations may include indemnity
exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party. Third-party claims, on the
other hand, are generally allocated on a fault basis.
We are customarily responsible for, and indemnify the Contractor against, all claims including those from third parties, to the
extent attributable to pollution or contamination by substances originating from our reservoirs or other property and the Contractor is
responsible for and indemnifies us for all claims attributable to pollution emanating from the Contractor’s property. Variations may
include indemnity exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a
party. Additionally, we are generally liable for all of our own losses and most third-party claims associated with catastrophic losses
such as damage to reservoirs, blowouts, cratering and loss of hole, regardless of cause, although exceptions for losses attributable to
gross negligence and/or willful misconduct do exist. Lastly, some offshore services contracts include overall limitations of the
Contractor’s liability equal to a fixed negotiated amount. Variations may include exclusions of all contractual indemnities from the
liability cap.
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Under a standard JOA, each party is liable for all claims arising under the JOA, to the extent of its participating interest (operator
or non-operator). Variations include indemnity exclusions when the claim is based upon the gross negligence and/or willful
misconduct of the operator, in which case the operator is solely liable. The parties to the JOA may continue to be jointly and severally
liable for claims made by third parties in some jurisdictions. Further, under some production sharing contracts between a
governmental entity and commercial parties, liability of the commercial parties to the government entity is joint and several.
Government Regulations
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels. Regulations affecting
elements of the energy sector are under continuous review for amendment or expansion over time, which may result in incremental
costs of doing business and affect our profitability. See Regulatory, Legal and Environmental Risks in Item 1A. Risk Factors.
Compliance with various existing environmental, health and safety regulations is not expected to have a material adverse effect on our
financial condition or results of operations. However, increasingly stringent environmental regulations have resulted and will likely
continue to result in higher capital expenditures and operating expenses for us and the oil and gas industry in general and may reduce
demand for our products. We spent approximately $15 million in 2020 for environmental remediation. The level of other
expenditures to comply with federal, state, local and foreign country regulations is difficult to quantify as such costs are captured as
mostly indistinguishable components of our capital expenditures and operating expenses. For further discussion of environmental,
health and safety regulations affecting our business, see Environment, Health and Safety in Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations.
Human Capital Management
Corporate Culture and Overview
Our human capital strategy aims to attract and retain our talent by investing in their professional development and providing them
with challenging and rewarding opportunities for personal growth. Our workplace culture is guided by our Corporation’s values and
reinforced by developing quality leadership, fostering diversity and inclusion, emphasizing continuous learning, creating opportunities
for engagement, driving innovation and embracing Lean processes. We are pursuing a Life at Hess initiative to optimize the work
experience for our multigenerational workforce and unlock the discretionary effort that is required to perform at a high level on a
sustained basis. The Life at Hess framework encompasses programs, policies and practices, and a listening system that draws on in-
person dialogues, pulse polls and data analytics to help leaders understand employees’ issues and perspectives and inform their
decision making.
As of December 31, 2020, we had 1,621 employees globally, as detailed below.
United States
Guyana
Malaysia and
JDA
Other (a)
Total
Job Category
Executives and Senior Officers..................................................
First and Mid-Level Managers...................................................
Professionals..............................................................................
Other..........................................................................................
Total.............................................................................................
31
328
686
360
1,405
—
—
—
—
—
1
59
78
2
140
—
17
23
36
76
32
404
787
398
1,621
(a) Other includes our interests in Denmark and Libya.
COVID-19 Response
We prioritize the safety of our workforce. Our safety programs and practices are designed to help ensure that everyone,
everywhere gets home safe every day. Our response to COVID-19 reflects this commitment. A multidisciplinary Hess emergency
response team has been overseeing plans and precautions to reduce the risks of COVID-19 in the work environment while maintaining
business continuity based on the most current recommendations by government and public health agencies. The Corporation has
implemented a variety of health and safety measures including enhanced cleaning procedures and modified work practices such as
travel restrictions, health screenings, reduced personnel at offshore platforms and onshore work sites wherever this can be done safely,
and remote working arrangements for office workers. We continue to adapt our work policies and benefits to prioritize emotional,
mental and physical health and well-being. We are taking a deliberate and measured approach to returning to the physical work
environment in each of our office locations.
During 2020, we adapted our Life at Hess initiative for a work experience that was largely away from the office and with stringent
health and safety protocols throughout our operations, including:
• activated emergency response teams representing all Hess work locations to coordinate effective local deployment of our
COVID-19 protocols;
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• introduced policies reinforcing that COVID-19 will not negatively impact pay and benefits for employees who may miss
work due to COVID-19 exposure, quarantine or test positive;
• provided work from home guidance, technology and training to allow office-based employees to complete their tasks
effectively while working remotely;
• modified work schedules for field operations to lessen virus exposure and to accommodate quarantine protocols; and
• offered supplemental medical resources, such as at-home COVID-19 testing kits, mental wellness programs and access to
third-party medical experts, at no cost to employees.
Inclusion, Diversity and Equity
In keeping with our values and purpose, we have a longstanding commitment to inclusion and diversity. Our Corporation is
committed to providing a global workplace free from discrimination and harassment, where everyone can achieve their full potential.
We provide equal employment opportunities for all employees and job candidates regardless of race, color, religion, gender, age,
sexual orientation, gender identity, creed, national origin, genetic information, disability, veteran status or any other protected status.
Hess’ Inclusion, Diversity and Equity Council provides executive leadership and guidance in our hiring, work environment and
development activities. Our expectations for an inclusive and diverse workplace and our culture of mutual respect and trust are
spelled out in our Code of Conduct and Ethics and related policies and reinforced regularly with employees at every level of our
including training and employee
Corporation through training. Additional
engagement initiatives, is included in our annual Sustainability Report, which is available on our website at www.hess.com.
information regarding our policies and practices,
During 2020, Hess maintained or improved diversity among our first and mid-level managers and professionals. Employee
turnover, diversity, inclusion and equity, and leadership development metrics, along with qualitative data, are shared with our Board of
Directors annually, with more detailed reviews by the Compensation and Management Development Committee throughout the year.
Women
(U.S. and International)
Minorities (a)
(U.S. Based Employees)
2020
2019
2018
2020
2019
2018
13 %
23 %
32 %
17 %
26 %
16 %
22 %
31 %
18 %
26 %
16 %
21 %
33 %
19 %
26 %
13 %
20 %
27 %
16 %
22 %
13 %
19 %
26 %
17 %
22 %
10 %
18 %
27 %
17 %
22 %
Job Category
Executives and Senior Officers.......................
First and Mid-Level Managers........................
Professionals...................................................
Other...............................................................
Total..................................................................
(a) As defined by the U.S. Department of Labor.
Reward Programs
Our compensation and benefits programs are focused on attracting and retaining a highly skilled workforce in a rapidly changing
industry. We benchmark our compensation programs annually through industry specific surveys and conduct an annual review to
identify and address compensation inequities. Our Corporation maintains an annual incentive plan that applies to all employees,
including executive officers, that shares the same enterprise performance metrics for all participants.
In addition, we provide a
comprehensive wellness program that addresses physical wellness and also focuses on the financial, social and emotional well-being
of our employees.
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Information about our Executive Officers
The following table presents information as of March 1, 2021 regarding executive officers of the Corporation:
Name
John B. Hess
Gregory P. Hill
Age
66
59
Timothy B. Goodell
63
John P. Rielly
Richard Lynch
58
63
Gerbert Schoonman
55
Andrew Slentz
59
Barbara Lowery-Yilmaz
64
Office Held* and Business Experience
Chief Executive Officer and Director
Mr. Hess has been Chief Executive Officer of the Corporation since 1995 and
employed by the Corporation since 1977. He has over 40 years of experience in
the oil and gas industry.
President and Chief Operating Officer
Mr. Hill has been Chief Operating Officer since 2014 and President of the
Corporation’s worldwide Exploration and Production business since joining the
Corporation in January 2009. Prior to joining the Corporation, Mr. Hill spent 25
years at Royal Dutch Shell and its affiliates in a variety of operations, engineering,
technical and managerial roles in Asia-Pacific, Europe and the United States.
Executive Vice President, General Counsel, Corporate Secretary and Chief
Compliance Officer
Mr. Goodell has been General Counsel of the Corporation since 2009, Corporate
Secretary since 2016, Chief Compliance Officer since 2017 and Executive Vice
President since 2020. Prior to joining the Corporation in 2009, he was a partner at
the law firm of White & Case, LLP where he spent 25 years.
Executive Vice President and Chief Financial Officer
Mr. Rielly has been Chief Financial Officer of the Corporation since 2004 and
Executive Vice President since 2020. Mr. Rielly previously served as Vice
President and Controller of the Corporation from 2001 to 2004. Prior to joining
the Corporation in 2001, he was a Partner at Ernst & Young, LLP where he was
employed for 17 years.
Senior Vice President, Technology and Services
Mr. Lynch has been Senior Vice President, Technology and Services of the
Corporation since 2018. Mr. Lynch previously was Senior Vice President Global
Prior to joining the
Developments, Drilling and Completions from 2014.
Corporation in 2014, Mr. Lynch spent over 30 years in well delivery and
operations, as well as project and asset management, with BP plc and ARCO.
Senior Vice President, Global Production
Mr. Schoonman has been Senior Vice President, Global Production of the
Corporation since January 2020. Since joining the Company in 2011, he served in
various operational leadership roles, including as Vice President, Production –
Asia Pacific, from January 2011 through August 2012; Vice President, Onshore –
Bakken from September 2012 through December 2016; and most recently, as
Vice President, Offshore since January 2017. Prior to joining the Corporation, he
spent 20 years with Royal Dutch Shell where he served in operational and
leadership roles.
Senior Vice President, Human Resources and Office Management
Mr. Slentz has been Senior Vice President, Human Resources of the Corporation
since April 2016 and responsible for Office Management since 2018. Prior to
joining the Corporation in 2016, Mr. Slentz served as Executive Vice President of
Administration and Human Resources at Peabody Energy since 2010. Mr. Slentz
has over 25 years in human resources experience at large international public
companies.
Senior Vice President and Chief Exploration Officer
Ms. Lowery-Yilmaz has been the Senior Vice President, Exploration of the
Corporation since August 2014. Ms. Lowery-Yilmaz has over 30 years of oil and
gas industry experience in exploration and technology with BP plc and its
affiliates including senior leadership roles.
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Individual
Became an
Executive
Officer
1983
2009
2009
2002
2018
2020
2016
2014
* All officers referred to herein hold office in accordance with the By-laws until the first meeting of directors in connection with the annual meeting of stockholders
of the Registrant and until their successors shall have been duly chosen and qualified. Each of said officers was elected to the office opposite their name on June
2, 2020.
Except for Mr. Slentz, each of the above officers has been employed by the Corporation or its affiliates in various managerial and
executive capacities for more than five years. Prior to joining the Corporation, Mr. Slentz served in senior executive positions in
human resources at Peabody Energy and its affiliates.
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Access to Our Reports
We make available free of charge through our website, www.hess.com, our annual report on Form 10‑K, quarterly reports on
Form 10‑Q, current reports on Form 8‑K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Exchange Act, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and
Exchange Commission. The information on our website is not incorporated by reference in this report. Our Code of Business
Conduct and Ethics, Corporate Governance Guidelines, and the charters for the Audit Committee, Compensation and Management
Development Committee, Corporate Governance and Nominating Committee and Environmental, Health and Safety Committee of the
Board of Directors are available on our website and are also available free of charge upon request to Investor Relations at our principal
executive office. We also file with the New York Stock Exchange (NYSE) an annual certification that our Chief Executive Officer is
unaware of any violation of the NYSE’s corporate governance standards.
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Item 1A. Risk Factors
Our business activities and the value of our securities are subject to significant risks, including the risk factors described below.
These risk factors could negatively affect our operations, financial condition, liquidity and results of operations, and as a result,
holders and purchasers of our securities could lose part or all of their investments. It is possible that additional risks relating to our
securities may be described in a prospectus supplement if we issue securities in the future.
Market and Third-Party Risks
Our business and operating results are highly dependent on the market prices of crude oil, NGL and natural gas, which
can be very volatile. Our estimated proved reserves, revenue, operating cash flows, operating margins, liquidity, financial condition
and future earnings are highly dependent on the benchmark market prices of crude oil, NGL and natural gas, and our associated
realized price differentials, which are volatile and influenced by numerous factors beyond our control. The major foreign oil
producing countries, including members of OPEC, may exert considerable influence over the supply and price of crude oil and refined
petroleum products. Their ability to agree on a common policy on rates of production and other matters may have a significant impact
on the oil markets. Other factors include, but are not limited to: worldwide and domestic supplies of and demand for crude oil, NGL
and natural gas, political conditions and events (including weather, instability, changes in governments, armed conflict, economic
sanctions and outbreaks of infectious diseases, such as COVID-19) around the world and in particular in crude oil or natural gas
producing regions, the cost of exploring for, developing and producing crude oil, NGL and natural gas, the price and availability of
alternative fuels or other forms of energy, the effect of energy conservation and environmental protection efforts and overall economic
conditions globally. The sentiment of commodities trading markets as well as other supply and demand factors, including COVID-19,
may also influence the selling prices of crude oil, NGL and natural gas. Average benchmark prices for 2020 were $39.34 per barrel
for WTI (2019: $57.04; 2018: $64.90) and $43.21 per barrel for Brent (2019: $64.16; 2018: $71.69). In order to manage the potential
volatility of cash flows and credit requirements, we maintain significant bank credit facilities. An inability to access, renew or replace
such credit facilities or access other sources of funding as they mature would negatively impact our liquidity. Furthermore, from time
to time we have entered into, and may in the future, enter into or modify commodity price hedging arrangements to manage
commodity price volatility. These arrangements may limit potential upside from commodity price increases, or expose us to
additional risks, such as counterparty credit risk, which could adversely impact our cash flow, liquidity or financial condition.
Our business and operations have been and may continue to be adversely affected by COVID-19 or other similar public
health developments and the recent reduced demand for oil and natural gas. COVID-19 and the related actions taken by
governments and businesses to manage the pandemic, including voluntary and mandatory quarantines and travel and other restrictions,
have resulted in a significant and swift reduction in economic activity. Certain jurisdictions have begun re-opening only to return to
restrictions in the face of increases in new COVID-19 cases. As a result of COVID-19, our operations, and those of our business
partners, service companies and suppliers, have experienced and may continue to experience further adverse effects, including but not
limited to: disruptions, delays or temporary suspensions of operations and supply chains; temporary inaccessibility or closures of
facilities; and workforce impacts from illness, school closures and other community response measures. We have implemented a
variety of health and safety measures, including enhanced cleaning procedures and modified work practices, such as travel restrictions;
health screenings; reduced personnel at offshore platforms and onshore work sites, wherever such reduction can be done safely; and
remote working arrangements for office workers. There is no certainty that these or any other future measures will be sufficient to
mitigate the risks posed by the disease, including the risk of infection of key employees, and our ability to perform certain functions
could be impaired by these new business practices. For example, our reliance on technology has necessarily increased due to our
encouragement of remote communications and other work-from-home practices, which could make us more vulnerable to cyber-
attacks. To the extent we or our business partners, service companies or suppliers continue to experience restrictions or other effects,
our financial condition, results of operations and future expansion projects may be adversely affected.
In addition to the global health concerns of COVID-19, the pandemic has negatively affected the U.S. and global economy and
severely adversely impacted demand for oil and natural gas. The prolonged continuation or amplification of the outbreak of
COVID-19 could result in further economic downturn that may affect our operating results in the long-term. In addition, the effects of
COVID-19 and concerns regarding its global spread have negatively impacted the domestic and international demand for crude oil and
natural gas, which has contributed to price volatility and adversely affected the demand for and marketability of crude oil, natural gas
and NGL. Containment measures implemented to mitigate the spread of COVID-19 could continue to be widespread and lead to
sustained adoption of certain behavioral changes, such as reduced travel and work-from-home policies, which could result in further
reductions in demand for and consumption of energy commodities. The reduction in consumer demand for crude oil, natural gas and
NGL has created a supply imbalance, which could require further curtailments and shut-ins of production by the industry and further
increase the costs of commercial storage and midstream contracts.
The timeline and potential magnitude of COVID-19 remains unknown and will depend on future developments, including, among
others, the availability of vaccines and effective treatments and the extent to which normal economic and operating conditions resume.
In the event one or more of our business partners is adversely affected by COVID-19 or the current market environment, that may
impact our costs and ability to conduct business with them. In addition, we may face an increased risk of changes in the regulation
related to our business resulting from COVID-19, such as the imposition of limitations on our workforce's ability to access our
facilities. We also are subject to litigation risk and possible loss contingencies related to COVID-19, including with respect to
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commercial contracts, employee matters and insurance arrangements. We may face additional asset impairments, decreases in proved
reserves, along with other accounting charges as demand for crude oil, natural gas and NGL decreases. The current environment may
make it more difficult to comply with covenants and other restrictions in agreements governing our debt, and a lack of confidence in
our industry on the part of the financial markets may result in a lack of access to capital, any of which could lead to reduced liquidity.
As the impact from COVID-19 remains difficult to predict, the extent to which it may negatively affect our operating results is
uncertain. Any impact will depend on future developments and new information that may emerge regarding the severity and duration
of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control.
We do not always control decisions made under joint operating agreements and the parties under such agreements may
fail to meet their obligations. We conduct many of our E&P operations through joint operating agreements with other parties under
which we may not control decisions, either because we do not have a controlling interest or are not operator under the agreement.
There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with ours, and
therefore decisions may be made which are not what we believe is in our best interest. Moreover, parties to these agreements may be
unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. In either case, the value
of our investment may be adversely affected.
Our industry is highly competitive and many of our competitors are larger and have greater resources and more diverse
portfolios than we have. The petroleum industry is highly competitive and very capital intensive. We encounter competition from
numerous companies, including acquiring rights to explore for crude oil and natural gas. To a lesser extent, we are also in competition
with producers of alternative fuels or other forms of energy, including wind, solar and electric power, and in the future, could face
increasing competition due to the development and adoption of new technologies. Many competitors, including national oil
companies, are larger and have substantially greater resources to acquire and develop oil and gas assets. In addition, competition for
drilling services, technical expertise and equipment may affect the availability of technical personnel and drilling rigs, resulting in
increased capital and operating costs. Many of our competitors have a more diverse portfolio of assets, which may minimize the
impact of adverse events occurring at any one location.
Operational and Strategic Risks
If we fail to successfully increase our reserves, our future crude oil and natural gas production will be adversely impacted.
We own or have access to a finite amount of oil and gas reserves, which will be depleted over time. Replacement of oil and gas
production and reserves, including proved undeveloped reserves, is subject to successful exploration drilling, development activities,
and enhanced recovery programs. Therefore, future oil and gas production is dependent on technical success in finding and
developing additional hydrocarbon reserves. Exploration activity involves the interpretation of seismic and other geological and
geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons. Drilling risks
include unexpected adverse conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions.
Future developments may be affected by unforeseen reservoir conditions, which negatively affect recovery factors or flow rates.
Similar risks may be encountered in the production of oil and gas on properties acquired from others. In addition, replacing reserves
and developing future production are also influenced by the price of crude oil and natural gas and costs of drilling and development
activities. Lower crude oil and natural gas prices may reduce capital available for our exploration and development activities, render
certain development projects uneconomic or delay their completion, and result in negative revisions to existing reserves while
increasing drilling and development costs could negatively affect expected economic returns.
There are inherent uncertainties in estimating quantities of proved reserves and discounted future net cash flows, and
actual quantities may be lower than estimated. Numerous uncertainties exist in estimating quantities of proved reserves and future
net revenues from those reserves. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating
expenses, and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could
materially affect the estimated quantities of our proved reserves and the related future net revenues. In addition, reserve estimates may
be subject to downward or upward changes based on production performance, purchases or sales of properties, results of future
development, prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas
prices increase, and other factors. Crude oil prices declined in 2020 and 2019, relative to comparative periods, resulting in reductions
to our reported proved reserves. If crude oil prices in 2021 average below prices used to determine proved reserves at December 31,
2020, it could have an adverse effect on our estimates of proved reserve volumes and on the value of our business. See Crude Oil and
Natural Gas Reserves in Critical Accounting Policies and Estimates in Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations.
Catastrophic and other events, whether naturally occurring or man-made, may materially affect our operations and
financial condition. Our oil and gas operations are subject to numerous risks and hazards inherent to operating in the crude oil and
natural gas industry, including catastrophic events, which may damage or destroy assets, interrupt operations, result in personal injury
and have other significant adverse effects. These events include unexpected drilling conditions, pressure conditions or irregularities in
reservoir formations, equipment malfunctions or failures, derailments, fires, explosions, blowouts, cratering, pipeline interruptions and
ruptures, hurricanes, severe weather, geological events, shortages in availability of skilled labor, cyber-attacks or health measures
related to COVID-19. We maintain insurance coverage against many, but not all, potential losses and liabilities in amounts we deem
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prudent, including for property and casualty losses. There can be no assurance that such insurance will adequately protect us against
liability from all potential consequences and damages. Moreover, some forms of insurance may be unavailable in the future or be
available only on terms that are deemed economically unacceptable.
Significant time delays between the estimated and actual occurrence of critical events associated with development projects
may result in material negative economic consequences. As part of our business, we are involved in large development projects,
the completion of which may be delayed beyond what was originally planned. Such examples include, but are not limited to, delays in
receiving necessary approvals from project members or regulatory or other government agencies, timely access to necessary
equipment, availability of necessary personnel, construction delays, unfavorable weather conditions, equipment failures, and outbreaks
of infectious diseases, such as COVID-19. These delays could impact our future results of operations and cash flows.
An inability to secure personnel, drilling rigs, equipment, supplies and other required services or to retain key employees
may result in material negative economic consequences. We are dependent on oilfield service companies for items including
drilling rigs, equipment, supplies and skilled labor. The availability and cost of drilling rigs, equipment, supplies and skilled labor will
fluctuate over time given the cyclical nature of the E&P industry. As a result, we may encounter difficulties in obtaining required
services or could face an increase in cost, including as a result of changes to our industry due to COVID-19, which may impact our
ability to run our operations and deliver projects on time with the potential for material negative economic consequences. In addition,
difficulty in recruiting and retaining adequate numbers of experienced technical personnel could negatively impact our ability to
deliver on our strategic goals. Our future success also depends upon the continued service of key members of our senior management
team, who play an important role in developing and implementing our strategy. An inability to recruit and retain adequate numbers of
experienced technical and professional personnel in the necessary locations or the loss or departure of key members of senior
management may prevent us from executing our strategy in full or, in part, which could negatively impact our business.
Disruption, failure or cyber security breaches affecting or targeting computer, telecommunications systems, and
infrastructure used by the Corporation or our business partners may materially impact our business and operations.
Computers and telecommunication systems are an integral part of our exploration, development and production activities and the
activities of our business partners. We use these systems to analyze and store financial and operating data and to communicate within
our corporation and with outside business partners. Our reliance on technology has increased due to the increased use of remote
communications and other work-from-home practices in response to COVID-19. Technical system flaws, power loss, cyber security
risks, including cyber or phishing-attacks, unauthorized access, malicious software, data privacy breaches by employees or others with
authorized access, ransomware, and other cyber security issues could compromise our computer and telecommunications systems or
those of our business partners and result in disruptions to our business operations or the access, disclosure or loss of our data and
In addition, computers control oil and gas production, processing equipment, and distribution systems
proprietary information.
globally and are necessary to deliver our production to market. A disruption, failure or a cyber breach of these operating systems, or
of the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or
prevent delivery to markets, and make it difficult or impossible to accurately account for production and settle transactions. As a
result, any such disruption, failure or cyber breach and any resulting investigation or remediation costs, litigation or regulatory action
could have a material adverse impact on our cash flows and results of operations, reputation and competitiveness. We routinely
experience attempts by external parties to penetrate and attack our networks and systems. Although such attempts to date have not
resulted in any material breaches, disruptions, financial loss, or loss of business-critical information, our systems and procedures for
protecting against such attacks and mitigating such risks may prove to be insufficient in the future and such attacks could have an
adverse impact on our business and operations, including damage to our reputation and competitiveness, remediation costs, litigation
or regulatory actions. In addition, as technologies evolve and these cyber security attacks become more sophisticated, we may incur
significant costs to upgrade or enhance our security measures to protect against such attacks and we may face difficulties in fully
anticipating or implementing adequate preventive measures or mitigating potential harm.
Financial Risks
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms. The
exploration, development and production of crude oil and natural gas involve substantial costs, which may not be fully funded from
operations. Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating. Although
currently we do not have any borrowings under our long-term credit facility, a ratings downgrade, continued weakness in the oil and
gas industry or negative outcomes within commodity and financial markets could adversely impact our access to capital markets by
increasing the costs of financing, or by impacting our ability to obtain financing on satisfactory terms.
In addition, a ratings
downgrade may require that we issue letters of credit or provide other forms of collateral under certain contractual requirements.
Environmental concerns and other factors have led to lower oil and gas representation in certain key equity market indices and may
increase our costs to access the equity capital markets. Any inability to access capital markets could adversely impact our financial
adaptability and our ability to execute our strategy.
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We engage in risk management transactions designed to mitigate commodity price volatility and other risks that may
impede our ability to benefit from commodity price increases and can expose us to similar potential counterparty credit risk as
amounts due from the sale of hydrocarbons. We may enter into commodity price hedging arrangements to protect us from
commodity price declines. These arrangements may, depending on the instruments used and the level of additional hedges involved,
limit any potential upside from commodity price increases. As with accounts receivable from the sale of hydrocarbons, we may be
exposed to potential economic loss should a counterparty be unable or unwilling to perform their obligations under the terms of a
In addition, we are exposed to risks related to changes in interest rates and foreign currency values, and may
hedging agreement.
engage in hedging activities to mitigate related volatility.
The alteration or discontinuation of LIBOR may adversely affect our borrowing costs. Certain borrowings on our credit
facilities and term loan may use LIBOR as a benchmark for establishing the rate. LIBOR is the subject of recent national,
international and other regulatory guidance and proposals for reform. These reforms and other pressures may cause LIBOR to be
discontinued after 2021 or to perform differently than in the past. In the U.S., the Alternative Reference Rates Committee, which was
convened by the Federal Reserve Board and the Federal Reserve Bank of New York, has proposed SOFR as an alternative to LIBOR.
At this time, the consequences of these developments cannot be entirely predicted, but could include fluctuations in interest rates or an
increase in the cost of our credit facility borrowings.
Regulatory, Legal and Environmental Risks
Our oil and gas operations are subject to environmental risks and environmental, health and safety laws and regulations
that can result in significant costs and liabilities. Our oil and gas operations are subject to environmental risks such as oil spills,
produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for
pollution or other environmental damage. Our operations are also subject to numerous U.S. federal, state, local and foreign
environmental, health and safety laws and regulations. Non-compliance with these laws and regulations may subject us to
administrative, civil or criminal penalties, remedial clean-ups, natural resource damages and other liabilities. In addition, increasingly
stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating
expenses for us. Similarly, we have material legal obligations to dismantle, remove and abandon production facilities and wells that
will occur many years in the future, in most cases. These estimates may be impacted by future changes in regulations, solvency of
subsequent owners and partners and other uncertainties.
Concerns have been raised in certain jurisdictions where we have operations concerning the safety and environmental impact of
the drilling and development of shale oil and gas resources, particularly hydraulic fracturing, water usage, flaring of associated natural
gas and air emissions. While we believe that these operations can be conducted safely and with minimal impact on the environment,
regulatory bodies are responding to these concerns and may impose moratoriums and new regulations on such drilling operations that
would likely have the effect of prohibiting or delaying such operations and increasing their cost.
Climate change and sustainability initiatives may result in significant operational changes and expenditures, reduced
demand for our products and adversely affect our business. We recognize that climate change and sustainability is a growing
global environmental concern. Continuing political and social attention to the issue of climate change and sustainability has resulted
in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit GHG
emissions. These agreements and measures may require, or could result in future legislation and regulatory measures that require,
significant equipment modifications, operational changes, taxes, or purchase of emission credits to reduce emission of GHGs from our
In
operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs.
addition, our production is sold to third parties that produce petroleum fuels, which through normal end user consumption result in the
emission of GHGs. As a result of heightened public awareness and attention to climate change and sustainability as well as continued
regulatory initiatives to reduce the use of these fuels, demand for crude oil and other hydrocarbons may be reduced, which may have
an adverse effect on our sales volumes, revenues and margins. The imposition and enforcement of stringent GHG emissions reduction
requirements could severely and adversely impact the oil and gas industry and therefore significantly reduce the value of our business.
Shareholder activism has been recently increasing in our industry, and shareholders may attempt to effect changes to our business or
governance, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise.
In addition, certain financial
institutions, institutional investors and other sources of capital have begun to limit or eliminate their investment in oil and gas
activities due to concerns about climate change, which could make it more difficult to finance our business. Furthermore, increasing
attention to climate change risks and sustainability has resulted in governmental investigations, and public and private litigation, which
could increase our costs or otherwise adversely affect our business. For example, beginning in 2017, certain states, municipalities and
private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and
coal producers, including us, for alleged damages purportedly caused by climate change. Such actions could adversely impact our
business by distracting management and other personnel from their primary responsibilities, require us to incur increased costs, and/or
result in reputational harm.
We are subject to changing laws and regulations and other governmental actions that can significantly and adversely affect
our business. Political or regulatory developments and governmental actions, including federal, state, local, territorial and foreign
laws and regulations may adversely affect our operations and those of our counterparties with whom we have contracted, which may
affect our financial results. These requirements relate to tax increases and retroactive tax claims, disallowance of tax credits and
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deductions, including post-production deductions from royalty payments; limitations or prohibitions on the sales of new and
extensions on existing oil and gas leases; expropriation or nationalization of property; mandatory government participation,
cancellation or amendment of contract rights; imposition of capital controls or blocking of funds; changes in import and export
regulations; the imposition of tariffs; and anti-bribery or anti-corruption laws. In recent years, proposals for limitations on access to
oil and gas exploration and development opportunities and related litigation have grown in certain areas and may include efforts to
reduce access to public and private lands; restriction of exploration and production activities within government-owned and other
lands; delaying or canceling permits for drilling or pipeline construction; restrictions or changes to existing pipeline easements;
limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated
disposal; imposition of set-backs on oil and gas sites; reduction of sulfur content in bunker fuel; delaying or denying air-quality or
siting permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity;
and the use of social media channels to cause reputational harm. Costs associated with responding to these anti-development efforts or
complying with any new legal or regulatory requirements could significantly and adversely affect our business, financial condition and
results of operations. For example, if a temporary or permanent shutdown of the DAPL occurs as a result of the on-going litigation
related to use of its easement to cross under the Missouri River, we will need to use alternative means to transport approximately
55,000 bopd of crude oil production in the Bakken, which may increase Bakken price differentials because it would require the use of
additional rail cars and personnel to move any displaced DAPL barrels.
Political instability in areas where we operate can adversely affect our business. Some of the international areas in which we
operate are politically less stable than other areas and may be subject to civil unrest, conflict, insurgency, corruption, security risks and
labor unrest. Political instability and civil unrest in North Africa, South America and the Middle East has affected and may continue
to affect our interests in these areas as well as oil and gas markets generally. In addition, geographic territorial border disputes may
affect our business in certain areas, such as the border dispute between Guyana and Venezuela over a portion of the Stabroek Block.
Political instability exposes our operations to increased risks, including increased difficulty in obtaining required permits and
government approvals, enforcing our agreements in those jurisdictions and potential adverse actions by local government authorities.
The threat of terrorism around the world also poses additional risks to our operations and the operations of the oil and gas industry in
general.
One of our subsidiaries is the general partner of a publicly traded limited partnership, Hess Midstream LP. The
responsibilities associated with being a general partner expose us to a broader range of legal liabilities. Our control of Hess
Midstream LP bestows upon us additional duties and obligations including, but not limited to, the obligations associated with
managing potential conflicts of interests and additional reporting requirements from the Securities and Exchange Commission. These
heightened duties expose us to additional potential for legal claims that may have a material negative economic impact on our
shareholders. Moreover, these increased duties may lead to an increase in compliance costs.
Item 1B. Unresolved Staff Comments
None.
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Item 3. Legal Proceedings
We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in
our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If
the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is
not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing
claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in
their early stages of development or where plaintiffs seek indeterminate damages.
We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have been a party
to lawsuits and claims related to the use of MTBE in gasoline. A series of similar lawsuits, many involving water utilities or
governmental entities, were filed in jurisdictions across the U.S. against producers of MTBE and petroleum refiners who produced
gasoline containing MTBE, including us. The principal allegation in all cases was that gasoline containing MTBE was a defective
product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to
groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of
MTBE. The majority of the cases asserted against us have been settled. There are three remaining active cases, filed by Pennsylvania,
Rhode Island, and Maryland.
In June 2014, the Commonwealth of Pennsylvania filed a lawsuit alleging that we and all major oil
companies with operations in Pennsylvania, have damaged the groundwater by introducing thereto gasoline with MTBE. The
Pennsylvania suit has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. In
September 2016, the State of Rhode Island also filed a lawsuit alleging that we and other major oil companies damaged the
groundwater in Rhode Island by introducing thereto gasoline with MTBE. The suit filed in Rhode Island is proceeding in federal
court.
In December 2017, the State of Maryland filed a lawsuit alleging that we and other major oil companies damaged the
groundwater in Maryland by introducing thereto gasoline with MTBE. The suit, filed in Maryland state court, was served on us in
January 2018 and has been removed to federal court by the defendants.
In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate
contamination in the sediments of the Lower Passaic River. The NJDEP is also seeking natural resource damages. The directive,
insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned.
We and over 70 companies entered into an Administrative Order on Consent with the EPA to study the same contamination; this work
remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and agreed with the EPA to fund
remediation of a portion of the site. On March 4, 2016, the EPA issued a Record of Decision (ROD) in respect of the lower eight
miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The
ROD does not address the upper nine miles of the Lower Passaic River or the Newark Bay, which may require additional remedial
action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the
Passaic River. Given that the EPA has not selected a remedy for the entirety of the Lower Passaic River or the Newark Bay, total
remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this
matter will result in a significant liability to us because our former terminal did not store or use contaminants which are of concern in
the river sediments and could not have contributed contamination along the river’s length. Further, there are numerous other parties
who we expect will bear the cost of remediation and damages.
In March 2014, we received an Administrative Order from the EPA requiring us and 26 other parties to undertake the Remedial
Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. Our alleged liability
derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the
Canal. The remedy selected by the EPA includes dredging of surface sediments and the placement of a cap over the deeper sediments
throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. The EPA’s
original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with
the design and implementation of the remedy remain uncertain. We have complied with the EPA’s March 2014 Administrative Order
and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert.
In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin
Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation
work began in the fourth quarter of 2020. Based on currently known facts and circumstances, we do not believe that this matter will
result in a significant liability to us, and the costs will continue to be allocated amongst the parties, as they were for the Remedial
Design.
From time to time, we are involved in other judicial and administrative proceedings relating to environmental matters. We
periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to
various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For any site
for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been
fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not
material. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island
and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused
by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various
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parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations
and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused
contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The
plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly
impacted areas. The ultimate impact of the aforementioned proceedings, and of any related proceedings by private parties, on our
business or accounts cannot be predicted at this time due to the large number of other potentially responsible parties and the
speculative nature of clean-up cost estimates.
We are also involved in other judicial and administrative proceedings from time to time in addition to the matters described above,
including claims related to post-production deductions from royalty payments. We cannot predict with certainty if, how or when such
proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of
development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially
lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any
proceeding.
Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of lawsuits,
claims and proceedings, including the matters disclosed above, is not expected to have a material adverse effect on our financial
condition, results of operations or cash flows. However, we could incur judgments, enter into settlements, or revise our opinion
regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in
the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.
Item 4. Mine Safety Disclosures
None.
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PART II
Item 5. Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities
Stock Market Information, Holders and Dividends
Our common stock is traded principally on the New York Stock Exchange (ticker symbol: HES). At January 31, 2021, there were
2,867 stockholders (based on the number of holders of record) who owned a total of 306,986,553 shares of common stock. In 2020,
2019 and 2018, cash dividends on common stock totaled $1.00 per share per year ($0.25 per quarter).
Performance Graph
Set forth below is a line graph comparing the five-year shareholder returns on a $100 investment in our common stock assuming
reinvestment of dividends, against the cumulative total returns for the following:
• Standard & Poor’s (S&P) 500 Stock Index, which includes us.
• Proxy Peer Group comprising 10 oil and gas peer companies, including us, as disclosed in our 2020 Proxy Statement,
excluding Chesapeake Energy Corporation, which filed for bankruptcy in June 2020, and Noble Energy, Inc. which was
acquired in October 2020.
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
$250
$200
$150
$100
$50
$0
2015
2016
2017
2018
2019
2020
2015
2016
2017
2018
2019
2020
Hess Corporation
$100.00 $130.90 $102.01 $88.61 $148.62 $120.10
S&P 500
$100.00 $111.95 $136.38 $130.39 $171.44 $202.96
Proxy Peer Group
$100.00 $143.91 $138.85 $111.28 $117.20 $70.48
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24PARTIIItem5.MarketfortheRegistrantsCommonStock,RelatedStockholderMattersandIssuerPurchasesofEquitySecuritiesStockMarketInformation,HoldersandDividendsOurcommonstockistradedprincipallyontheNewYorkStockExchange(tickersymbol:HES).AtJanuary31,2020,therewere2,944stockholders(basedonthenumberofholdersofrecord)whoownedatotalof305,214,587sharesofcommonstock.In2019,2018and2017,cashdividendsoncommonstocktotaled$1.00pershareperyear($0.25perquarter).PerformanceGraphSetforthbelowisalinegraphcomparingthefive-yearshareholderreturnsona$100investmentinourcommonstockassumingreinvestmentofdividends,againstthecumulativetotalreturnsforthefollowing:Standard&Poors(S&P)500StockIndex,whichincludesus.Proxy Peer Group comprising 12oil andgaspeer companies, including us, asdisclosed inour 2019 Proxy Statement,excludingAnadarkoPetroleumCorporation,whichwasacquiredinAugust2019.ComparisonofFive-YearShareholderReturnsYearsEndedDecember31,201420152016201720182019HessCorporation$100.00$66.78$87.42$68.13$59.17$99.25S&P500$100.00$101.37$113.49$138.26$132.19$173.80ProxyPeerGroup$100.00$63.20$88.46$82.83$65.64$69.06$0$50$100$150$20024PARTIIItem5.MarketfortheRegistrantsCommonStock,RelatedStockholderMattersandIssuerPurchasesofEquitySecuritiesStockMarketInformation,HoldersandDividendsOurcommonstockistradedprincipallyontheNewYorkStockExchange(tickersymbol:HES).AtJanuary31,2020,therewere2,944stockholders(basedonthenumberofholdersofrecord)whoownedatotalof305,214,587sharesofcommonstock.In2019,2018and2017,cashdividendsoncommonstocktotaled$1.00pershareperyear($0.25perquarter).PerformanceGraphSetforthbelowisalinegraphcomparingthefive-yearshareholderreturnsona$100investmentinourcommonstockassumingreinvestmentofdividends,againstthecumulativetotalreturnsforthefollowing:Standard&Poors(S&P)500StockIndex,whichincludesus.Proxy Peer Group comprising 12oil andgaspeer companies, includingus, asdisclosed inour 2019Proxy Statement,excludingAnadarkoPetroleumCorporation,whichwasacquiredinAugust2019.ComparisonofFive-YearShareholderReturnsYearsEndedDecember31,201420152016201720182019HessCorporation$100.00$66.78$87.42$68.13$59.17$99.25S&P500$100.00$101.37$113.49$138.26$132.19$173.80ProxyPeerGroup$100.00$63.20$88.46$82.83$65.64$69.06$0$50$100$150$20024PARTIIItem5.MarketfortheRegistrantsCommonStock,RelatedStockholderMattersandIssuerPurchasesofEquitySecuritiesStockMarketInformation,HoldersandDividendsOurcommonstockistradedprincipallyontheNewYorkStockExchange(tickersymbol:HES).AtJanuary31,2020,therewere2,944stockholders(basedonthenumberofholdersofrecord)whoownedatotalof305,214,587sharesofcommonstock.In2019,2018and2017,cashdividendsoncommonstocktotaled$1.00pershareperyear($0.25perquarter).PerformanceGraphSetforthbelowisalinegraphcomparingthefive-yearshareholderreturnsona$100investmentinourcommonstockassumingreinvestmentofdividends,againstthecumulativetotalreturnsforthefollowing:Standard&Poors(S&P)500StockIndex,whichincludesus.Proxy Peer Group comprising 12oilandgas peercompanies, includingus, asdisclosed inour 2019 Proxy Statement,excludingAnadarkoPetroleumCorporation,whichwasacquiredinAugust2019.ComparisonofFive-YearShareholderReturnsYearsEndedDecember31,201420152016201720182019HessCorporation$100.00$66.78$87.42$68.13$59.17$99.25S&P500$100.00$101.37$113.49$138.26$132.19$173.80ProxyPeerGroup$100.00$63.20$88.46$82.83$65.64$69.06$0$50$100$150$200
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Share Repurchase Activities
Our share repurchases for the year ended December 31, 2020, were as follows:
2020
Total Number of
Shares Purchased
(a)(b)
Average
Price Paid
per Share (a)
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs (c)
March 1, 2020 through March 31, 2020..................
Total for 2020...................................................
35,202
35,202
$
$
32.34
32.34
— $
—
Maximum Approximate
Dollar Value of
Shares that May
Yet be Purchased
Under the Plans
or Programs (d)
(In millions)
650
(a) Repurchased in open-market transactions. The average price paid per share is inclusive of transaction fees.
(b) All of the shares repurchased were subsequently granted to directors in accordance with the Non-Employee Directors' Stock Award Program.
(c) Since initiation of the buyback program in August 2013, total shares repurchased through December 31, 2020 amounted to 91.9 million at a total cost of $6.85
billion including transaction fees.
(d) In March 2013, we announced that our Board of Directors approved a stock repurchase program that authorized the purchase of common stock up to a value of
$4.0 billion. In May 2014, the share repurchase program was increased to $6.5 billion and in March 2018, it was increased further to $7.5 billion.
Equity Compensation Plans
Following is information related to our equity compensation plans at December 31, 2020.
Plan Category
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights *
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*)
Equity compensation plans approved by security holders.................
4,382,243 (a)
$
Equity compensation plans not approved by security holders (c).....
—
61.57
—
13,006,658 (b)
—
(a) This amount includes 4,382,243 shares of common stock issuable upon exercise of outstanding stock options. This amount excludes 806,270 performance share
units (PSUs) for which the number of shares of common stock to be issued may range from 0% to 200%, based on our total shareholder return (TSR) relative to
the TSR of a predetermined group of peer companies over a three‑year performance period ending December 31 of the year prior to settlement of the
grant. Beginning with the PSUs granted in 2020, the Corporation's TSR is compared to the TSR of a predetermined group of peer companies and the S&P 500
index over the three-year performance period. In addition, this amount also excludes 1,917,459 shares of common stock issued as restricted stock pursuant to our
equity compensation plans.
(b) These securities may be awarded as stock options, restricted stock, PSUs or other awards permitted under our equity compensation plan.
(c) We have a Non-Employee Director’s Stock Award Plan pursuant to which each of our non-employee directors received $175,000 in value of our common
stock. These awards are made from shares we have purchased in the open market.
See Note 14, Share‑based Compensation in the Notes to Consolidated Financial Statements for further discussion of our equity
compensation plans.
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Item 6. Selected Financial Data
The following is a five‑year summary of selected financial data that should be read in conjunction with both our Consolidated
Financial Statements and Accompanying Notes, and Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations included elsewhere in this Annual Report:
2020
2019
2018
2017
2016
(In millions, except per share amounts)
Income Statement Selected Financial Data
Sales and other operating revenues
Crude oil (a)...................................................................................... $ 3,149
Natural gas liquids (a).......................................................................
297
Natural gas (a)...................................................................................
648
Other operating revenues (b).............................................................
573
Total Sales and other operating revenues.................................... $ 4,667
$ 5,233
347
876
39
$ 6,495
$ 4,960
533
965
(135)
$ 6,323
$ 4,239
457
750
20
$ 5,466
$ 3,639
264
766
93
$ 4,762
Net income (loss)................................................................................ $ (2,839)
Less: Net income (loss) attributable to noncontrolling interests.........
254
Net income (loss) attributable to Hess Corporation............................ $ (3,093) (d) $
$
$
(240)
168
(408) (e) $
(115)
167
(282) (f) $ (4,074) (g) $ (6,132) (h)
$ (3,941)
133
$ (6,076)
56
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic.................................................................................................. $ (10.15)
Diluted...............................................................................................
(10.15)
$
(1.37)
(1.37)
$
(1.10)
(1.10)
$ (13.12)
(13.12)
$ (19.92)
(19.92)
Balance Sheet Selected Financial Data
Total assets.......................................................................................... $ 18,821
Total debt and finance lease obligations (c)........................................ $ 8,534
Total equity......................................................................................... $ 6,335
$ 21,782
$ 7,397
$ 9,706
$ 21,433
$ 6,672
$ 10,888
$ 23,112
$ 6,977
$ 12,354
$ 28,621
$ 6,806
$ 15,591
Dividends Per Share
Dividends per share of common stock................................................ $
1.00
$
1.00
$
1.00
$
1.00
$
1.00
(a) Represents sales of Hess net production and purchased third-party volumes.
(b) Commencing with the adoption of Accounting Standards Codification 606, Revenue from Contracts with Customers, using the modified retrospective method
effective January 1, 2018, gains (losses) on commodity derivatives are included within Other operating revenues. Prior to January 1, 2018, gains (losses) on
commodity derivatives were included within Crude oil revenues.
(c) At December 31, 2020 includes debt from our Midstream operating segment of $1,910 million that is non-recourse to Hess Corporation (2019: $1,753 million;
2018: $981 million; 2017: $980 million; 2016: $733 million).
(d) Includes after-tax asset impairment charges of $2.0 billion, after-tax charges of $150 million primarily related to the write-off of previously capitalized
exploratory wells in the Gulf of Mexico and the write-off of leasehold costs, after-tax charges of $99 million, related to the reduction of crude oil inventories to
their net realizable value, employee termination benefits incurred, and the write-off of right of use assets and surplus materials and supplies inventories, partially
offset by an after-tax gain of $79 million related to the sale of our working interest in the Shenzi Field in the Gulf of Mexico.
(e) Includes an allocation of noncash income tax expense of $86 million that was previously a component of accumulated other comprehensive income related to our
2019 crude oil hedge contracts, an after-tax charge of $88 million related to a pension settlement, a charge after income taxes and noncontrolling interests of $16
million for transaction related costs for Hess Midstream Partners LP acquisition of HIP and corporate restructuring, and an after-tax charge of $19 million
related to a settlement on historical cost recovery balances in the JDA. These charges were partially offset by a noncash income tax benefit of $60 million to
reverse a valuation allowance against net deferred tax assets in Guyana upon achieving first production, and an after-tax gain of $22 million related to the sale of
our remaining acreage in the Utica shale play.
Includes after-tax charges of $221 million related to exit costs, settlement of legal claims related to a former downstream interest, and a loss from debt
extinguishment. These charges were, partially offset by a noncash income tax benefit of $91 million primarily related to intraperiod income tax allocation
requirements resulting from changes in fair value of our 2019 crude oil hedging program, and gains totaling $24 million related to asset sales.
(f)
(g) Includes after-tax asset impairment charges of $2,250 million, an after-tax dry hole and lease impairment charge of $280 million, a combined after-tax loss of $91
million related to asset sales (Norway, Equatorial Guinea and Permian), and after-tax charges of $52 million primarily for de-designated crude oil hedging
contracts and other exit costs.
(h) Includes noncash charges of $3,749 million to establish valuation allowances on deferred tax assets following a three-year cumulative loss and after-tax charges
of $894 million primarily for dry hole and other exploration expenses, loss on debt extinguishment, offshore rig costs, severance, and impairment of older
specification rail cars.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated
Financial Statements, which are included in this Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A.
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations omits certain discussions
of our financial condition and results of operations for the year ended December 31, 2018 compared with the year ended December 31,
2019, which can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our
2019 Annual Report on Form 10-K, which was filed with the Securities and Exchange Commission on February 20, 2020, and such
comparisons are incorporated herein by reference.
Index
Overview
Consolidated Results of Operations
Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Overview
Hess Corporation is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of
crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Guyana, the
Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Denmark. We conduct exploration activities primarily offshore
Guyana, in the U.S. Gulf of Mexico, and offshore Suriname and Canada. At the Stabroek Block (Hess 30%), offshore Guyana, we
have announced eighteen significant discoveries. The Liza Phase 1 development achieved first production in December 2019, and
reached its nameplate production capacity of approximately 120,000 gross bopd in December 2020. The Liza Phase 2 development
was sanctioned in the second quarter of 2019 and is expected to achieve first production by early 2022, with production capacity of
approximately 220,000 gross bopd. A third development, Payara, was sanctioned in the third quarter of 2020 and is expected to
achieve first production in 2024, with production capacity of approximately 220,000 gross bopd. The discovered resources to date on
the Stabroek Block are expected to underpin up to ten FPSOs with the first five FPSOs producing more than 750,000 gross bopd by
2026.
Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess
Midstream LP at December 31, 2020, provides fee-based services, including gathering, compressing and processing natural gas and
fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water
handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.
Hess Response to COVID-19 and Market Conditions
COVID-19 continues to have a profound impact on society and industry. The Corporation’s first priority in the midst of the
pandemic has been the health and safety of the Hess workforce and local communities where the Corporation operates. A
multidisciplinary Hess emergency response team has been overseeing plans and precautions to reduce the risks of COVID-19 in the
work environment while maintaining business continuity based on the most current recommendations by government and public
health agencies. The Corporation has implemented a variety of health and safety measures including enhanced cleaning procedures
and modified work practices such as travel restrictions, health screenings, reduced personnel at offshore platforms and onshore work
sites wherever this can be done safely, and remote working arrangements for office workers.
In July 2020, Hess Midstream LP
announced that the planned maintenance turnaround at the Tioga Gas Plant originally scheduled for the third quarter of 2020 will be
deferred until 2021 to ensure safe execution in light of COVID-19.
In addition to the global health concerns of COVID-19, the pandemic has severely impacted demand for oil. Our realized crude
oil selling prices, including hedging, were $44.28 per barrel in 2020 (2019: $56.77; 2018: $60.77). In response to the resulting sharp
decline in oil prices, the Corporation’s focus is on preserving cash and capability, while protecting the long-term value of its assets. In
the first quarter of 2020, we reduced our E&P capital and exploratory budget of $3.0 billion for 2020 to $1.9 billion, and we ended the
year with actual capital and exploratory expenditures of $1.8 billion. This reduction was achieved primarily by shifting from a six rig
program to one rig in the Bakken, which was accomplished in May, deferral of some 2020 development activities on the Stabroek
In March 2020, Hess entered into a $1.0 billion
Block, offshore Guyana, and deferring discretionary spending across the portfolio.
three year term loan agreement, and in November, we sold our 28% working interest in the Shenzi Field for net proceeds of $482
million, after closing adjustments.
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2021 Outlook
Our E&P capital and exploratory expenditures are projected to be approximately $1.9 billion in 2021. Capital investment for our
Midstream operations is expected to be approximately $160 million. Oil and gas net production in 2021 is forecast to be
approximately 310,000 boepd excluding Libya. For 2021, we have WTI put options with an average monthly floor price of $50 per
barrel for 120,000 bopd, and Brent put options with an average monthly floor price of $55 per barrel for 30,000 bopd.
Net cash provided by operating activities was $1,333 million in 2020, compared with $1,642 million in 2019, while net cash
provided by operating activities before changes in operating assets and liabilities was $1,803 million in 2020 and $2,237 million in
2019. Capital expenditures for 2020 and 2019 were $1,931 million and $2,992 million, respectively.
In 2021, based on current
forward strip crude oil prices, we expect cash flow from operating activities, proceeds from the first quarter 2021 sale of 4.2 million
barrels of crude oil stored on two VLCCs at year-end, and cash and cash equivalents existing at December 31, 2020 of $1.74 billion
will be sufficient to fund our capital investment program and dividends. Due to the volatile commodity price environment, we may
take any of the following steps, or a combination thereof, to improve our liquidity and financial position: reduce the planned capital
program and other cash outlays, including dividends, pursue asset sales, borrow against our committed revolving credit facility, or
issue debt or equity securities.
Consolidated Results
Net loss attributable to Hess Corporation was $3,093 million in 2020 (2019: $408 million). Excluding items affecting
comparability of earnings between periods summarized on page 33, the adjusted net loss was $894 million in 2020 (2019: $281
million). Annual net production averaged 331,000 boepd in 2020 (2019: 311,000 boepd). Total proved reserves were 1,170 million
boe at December 31, 2020 (2019: 1,197 million boe).
Significant 2020 Activities
The following is an update of significant E&P activities during 2020:
E&P assets:
• In North Dakota, net production from the Bakken shale play averaged 193,000 boepd in 2020 (2019: 152,000 boepd), with
net oil production up 15% to 107,000 bopd from 93,000 bopd primarily due to increased wells online and improved well
performance. Natural gas and NGL production also increased from higher wells online, additional natural gas captured and
processed, and approximately 7,000 boepd of additional volumes received under percentage of proceeds contracts resulting
from lower prices. During the year, we operated six rigs in the Bakken through May, before reducing to one rig for the
remainder of 2020 in response to the sharp decline in oil prices resulting from the COVID-19 pandemic. We drilled 71 wells
and brought 111 wells on production, bringing the total operated production wells to 1,686 by year-end. We reduced the
average cost of a plug and perf well in 2020 to $6.2 million per well from $6.8 million per well in 2019. We forecast net
production from the Bakken to average approximately 170,000 boepd in 2021.
In the second quarter, we chartered three VLCCs and loaded a total of 6.3 million barrels of oil for sale in Asian markets to
enhance cash flow and maximize value from our Bakken production. The first VLCC cargo of 2.1 million barrels was sold in
China in September. We have agreements in place to sell the remaining two VLCC cargos totaling 4.2 million barrels in the
first quarter of 2021. We expect to recognize net income of approximately $60 million in the first quarter of 2021 from these
sales, including associated hedging gains and costs.
• In the Gulf of Mexico, net production averaged 56,000 boepd (2019: 66,000 boepd) reflecting the effect of increased
hurricane-related downtime, higher planned maintenance and lower production from the Shenzi Field, which was sold in
November 2020, partially offset by initial production from the Esox-1 well, which commenced in February of 2020. Net
production from the Shenzi Field was 9,000 boepd in 2020 (2019: 12,000 boepd). We forecast Gulf of Mexico net
production for 2021 to average approximately 45,000 boepd.
We participated in two outside operated exploration wells that were completed in 2020, the Oldfield-1 well and the
Galapagos Deep well, both located in the Mississippi Canyon area. Both wells were unsuccessful.
• At the Stabroek Block (Hess 30%), offshore Guyana, net production from the Liza Phase 1 development averaged 20,000
bopd in 2020 following first production in December 2019 from the Liza Destiny FPSO. During the fourth quarter, the
operator Esso Exploration and Production Guyana Limited, reached its nameplate capacity of 120,000 gross bopd. For 2021,
net production from Guyana is expected to average approximately 30,000 bopd.
The Liza Phase 2 development was sanctioned in 2019 and will utilize the Liza Unity FPSO to produce up to 220,000 gross
bopd, with first production expected by early 2022. A total of 30 wells are planned at six drill centers, including 15
production wells, nine water injection wells and six gas injection wells. In 2021, the operator plans to continue development
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drilling, complete installation of subsea flow lines and equipment, complete installation of topside facilities on the FPSO and
sail the Liza Unity FPSO from Singapore to the Liza Field.
On September 30, 2020, we announced the final investment decision to proceed with development of the Payara Field on
the Stabroek Block after the development plan received approval from the government of Guyana. Payara will utilize the
Prosperity FPSO, which will have the capacity to produce up to 220,000 gross bopd, with first production expected in 2024.
Ten drill centers with a total of 41 wells are planned, including 20 production wells and 21 injection wells. Excluding pre-
sanction costs and FPSO purchase cost, our net share of development costs is forecast to be approximately $1.8 billion.
In addition to the first three developments, planning is underway for additional FPSOs. The ultimate sizing and timing of
these potential developments will be a function of further exploration and appraisal drilling.
In 2020, two successful exploration wells and one successful appraisal well were drilled on the Stabroek Block. For 2021,
the operator plans to bring in a fifth drillship in March and a sixth drillship in April and drill 12 to 15 exploration and
appraisal wells during the year.
• At the Kaieteur Block (Hess 15%), offshore Guyana, the operator, Esso Exploration and Production Guyana Limited,
completed drilling of the Tanager-1 exploration well. The well did encounter hydrocarbons but was not a commercial
success on a stand-alone basis.
• In the Gulf of Thailand, net production from Block A‑18 of the JDA averaged 29,000 boepd for the year (2019: 35,000
boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin averaged
23,000 boepd for the year (2019: 28,000 boepd). During 2020, we drilled seven production wells at North Malay Basin, and
plan to continue the drilling program and development activities in 2021. We also expect to commence a multi-year drilling
program in the first half of 2021 at the JDA. Combined net production from our JDA and North Malay Basin assets is
forecast to average approximately 60,000 boepd in 2021.
The following is an update of significant Midstream activities during 2020:
• In 2019, Hess Midstream LP announced plans to expand processing capacity at the Tioga Gas Plant by 150 mmcfd for total
processing capacity of 400 mmcfd. In 2020, the facility construction was completed for the expansion. The incremental gas
processing capacity is expected to be available in 2021 upon completion of a scheduled plant maintenance turnaround, during
which the expansion and residue and NGL takeaway pipelines will be tied in. The plant maintenance turnaround was
originally planned to occur in the third quarter of 2020 but was deferred to 2021 to ensure safe execution in light of the
COVID-19 pandemic.
• On December 30, 2020, Hess Midstream LP exercised its renewal options to extend the terms of certain gas gathering, crude
oil gathering, gas processing and fractionation, storage, and terminal and export commercial agreements for the secondary
term through December 31, 2033. There were no changes to any provisions of the existing commercial agreements as a result
of the exercise of the renewal options.
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Liquidity and Capital and Exploratory Expenditures
In 2020, net cash provided by operating activities was $1,333 million (2019: $1,642 million). At December 31, 2020, cash and
cash equivalents were $1,739 million (2019: $1,545 million), consolidated debt was $8,296 million (2019: $7,142 million), and our
debt to capitalization ratio (as defined in the credit agreement for our revolving credit facility and the term loan agreement) was 47.5%
(2019: 39.6%). Hess Midstream debt, which is nonrecourse to Hess Corporation, was $1,910 million at December 31, 2020 (2019:
$1,753 million).
Capital and exploratory expenditures were as follows (in millions):
2020
2019
2018
E&P Capital and Exploratory Expenditures:
United States
North Dakota............................................................................................................................. $
Offshore and other.....................................................................................................................
Total United States..........................................................................................................................
Guyana............................................................................................................................................
Malaysia and JDA...........................................................................................................................
Other (a)..........................................................................................................................................
E&P Capital and Exploratory Expenditures...................................................................................... $
Exploration Expenses Charged to Income Included Above:
United States................................................................................................................................... $
International....................................................................................................................................
Total Exploration Expenses Charged to Income included above................................................ $
661
258
919
743
99
25
1,786
91
17
108
$
$
$
$
1,312
471
1,783
783
109
68
2,743
105
62
167
$
$
$
$
967
411
1,378
383
123
185
2,069
106
54
160
Midstream Capital Expenditures:
Midstream Capital Expenditures (b)............................................................................................... $
253
$
416
$
271
(a) Other includes our interests in Denmark, Libya and other non-producing countries.
(b) Excludes equity investments of $33 million in 2019 and $67 million in 2018.
In 2021, we project our E&P capital and exploratory expenditures will be approximately $1.9 billion and Midstream capital
expenditures to be approximately $160 million.
Consolidated Results of Operations
Results by Segment:
The after-tax income (loss) by major operating activity is summarized below:
2020
2019
2018
(In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation:
Exploration and Production............................................................................................................. $
Midstream........................................................................................................................................
Corporate, Interest and Other..........................................................................................................
Total............................................................................................................................................. $
Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted (a)............ $
(2,841) $
230
(482)
(3,093) $
(10.15) $
$
53
144
(605)
(408) $
(1.37) $
51
120
(453)
(282)
(1.10)
(a) Calculated as net income (loss) attributable to Hess Corporation less preferred stock dividends, divided by weighted average number of diluted shares.
In the following discussion and elsewhere in this report, the financial effects of certain transactions are disclosed on an after-tax
basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment
earnings. Management believes that after-tax amounts are a preferable method of explaining variances in earnings, since they show
the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the income tax
rate in each tax jurisdiction to pre-tax amounts.
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Items Affecting Comparability of Earnings Between Periods:
The following table summarizes items of income (expense) that are included in net income (loss) and affect comparability of
earnings between periods. The items in the table below are explained on pages 38 through 41.
Items Affecting Comparability of Earnings Between Periods, After Income Taxes:
Exploration and Production............................................................................................................. $
Midstream........................................................................................................................................
Corporate, Interest and Other..........................................................................................................
Total............................................................................................................................................. $
(2,198) $
—
(1)
(2,199) $
$
63
(16)
(174)
(127) $
(86)
—
(20)
(106)
The following table presents the pre-tax amount of items affecting comparability of income (expense) by financial statement line
item in the Statement of Consolidated Income on page 57. The items in the table below are explained on pages 38 through 41.
2020
2019
2018
(In millions)
Gains on asset sales, net....................................................................................................................... $
Other, net..............................................................................................................................................
Marketing, including purchased oil and gas.........................................................................................
Operating costs and expenses...............................................................................................................
Exploration expenses, including dry holes and lease impairment.......................................................
General and administrative expenses...................................................................................................
Loss on debt extinguishment................................................................................................................
Depreciation, depletion and amortization............................................................................................
Impairment...........................................................................................................................................
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax............................. $
Reconciliations of GAAP and Non-GAAP Measures:
Before Income Taxes
2020
2019
2018
$
79
—
(53)
(20)
(153)
(6)
—
—
(2,126)
(2,279) $
$
(In millions)
22
(88)
(21)
—
—
(30)
—
—
—
(117) $
24
—
—
(19)
(3)
(130)
(53)
(16)
—
(197)
The following table reconciles reported net income (loss) attributable to Hess Corporation and adjusted net income (loss)
attributable to Hess Corporation:
Adjusted Net Income (Loss) Attributable to Hess Corporation:
Net income (loss) attributable to Hess Corporation........................................................................ $
Less: Total items affecting comparability of earnings between periods, after-tax.........................
Adjusted Net Income (Loss) Attributable to Hess Corporation............................................ $
(3,093) $
(2,199)
(894) $
(408) $
(127)
(281) $
(282)
(106)
(176)
The following table reconciles reported net cash provided by (used in) operating activities and net cash provided by (used in)
operating activities before changes in operating assets and liabilities:
2020
2019
2018
(In millions)
2020
2019
2018
(In millions)
Net cash provided by operating activities before changes in operating assets and liabilities:
Net cash provided by (used in) operating activities.......................................................................... $
Changes in operating assets and liabilities........................................................................................
Net cash provided by (used in) operating activities before changes in operating assets and
liabilities......................................................................................................................................... $
$
1,333
470
$
1,642
595
1,939
190
1,803
$
2,237
$
2,129
Adjusted net income (loss) attributable to Hess Corporation is a non-GAAP financial measure, which we define as reported net
income (loss) attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods,
which are summarized on pages 38 through 41. Management uses adjusted net income (loss) to evaluate the Corporation’s operating
performance and believes that investors’ understanding of our performance is enhanced by disclosing this measure, which excludes
certain items that management believes are not directly related to ongoing operations and are not indicative of future business trends
and operations.
Net cash provided by (used in) operating activities before changes in operating assets and liabilities presented in this report is a
non-GAAP measure, which we define as reported net cash provided by (used in) operating activities excluding changes in operating
assets and liabilities. Management uses net cash provided by (used in) operating activities before changes in operating assets and
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liabilities to evaluate the Corporation’s ability to internally fund capital expenditures, pay dividends and service debt and believes that
investors’ understanding of our ability to generate cash to fund these items is enhanced by disclosing this measure, which excludes
working capital and other movements that may distort assessment of our performance between periods.
These measures are not, and should not be viewed as, substitutes for U.S. GAAP net income (loss) and net cash provided by (used
in) operating activities.
Comparison of Results
Exploration and Production
Following is a summarized statement of income for our E&P operations:
Revenues and Non-Operating Income
Sales and other operating revenues................................................................................................. $
Gains on asset sales, net..................................................................................................................
Other, net.........................................................................................................................................
Total revenues and non-operating income................................................................................
Costs and Expenses
Marketing, including purchased oil and gas....................................................................................
Operating costs and expenses..........................................................................................................
Production and severance taxes.......................................................................................................
Midstream tariffs.............................................................................................................................
Exploration expenses, including dry holes and lease impairment..................................................
General and administrative expenses..............................................................................................
Depreciation, depletion and amortization.......................................................................................
Impairment......................................................................................................................................
Total costs and expenses...........................................................................................................
Results of Operations Before Income Taxes....................................................................................
Provision (benefit) for income taxes (a)..........................................................................................
Net Income (Loss) Attributable to Hess Corporation..................................................................... $
2020
2019
2018
(In millions)
$
4,667
79
31
4,777
1,067
895
124
946
351
206
1,915
2,126
7,630
(2,853)
(12)
(2,841) $
6,495
22
51
6,568
1,849
971
184
722
233
204
1,977
—
6,140
428
375
53
$
$
6,323
27
53
6,403
1,833
941
171
648
362
258
1,748
—
5,961
442
391
51
(a) Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation
allowance assessment basis. See footnote (a) in the table on page 87 for further details.
Excluding the E&P items affecting comparability of earnings between periods in the table on page 38, the changes in E&P results
are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs,
Midstream tariffs, DD&A, exploration expenses and income taxes, as discussed below.
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Selling Prices: Average worldwide realized crude oil selling prices, including hedging, were 22% lower in 2020 compared with
the prior year, primarily due to the decrease in Brent and WTI crude oil prices. In addition, realized worldwide selling prices for NGL
decreased in 2020 by 16% and worldwide natural gas prices decreased in 2020 by 24%, compared with the prior year. In total, lower
realized selling prices decreased financial results by approximately $780 million after income taxes, compared with 2019. Our
average selling prices were as follows:
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Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
United States
North Dakota............................................................................................................................. $
Offshore.....................................................................................................................................
Total United States..........................................................................................................................
Guyana............................................................................................................................................
Malaysia and JDA...........................................................................................................................
Other (b)..........................................................................................................................................
Worldwide............................................................................................................................
Crude Oil - Per Barrel (Excluding Hedging)
United States
North Dakota............................................................................................................................. $
Offshore.....................................................................................................................................
Total United States..........................................................................................................................
Guyana............................................................................................................................................
Malaysia and JDA...........................................................................................................................
Other (b)..........................................................................................................................................
Worldwide............................................................................................................................
Natural Gas Liquids - Per Barrel
United States
North Dakota............................................................................................................................. $
Other Onshore (c)......................................................................................................................
Offshore.....................................................................................................................................
Worldwide............................................................................................................................
Natural Gas - Per Mcf
United States
North Dakota............................................................................................................................. $
Other Onshore (c)......................................................................................................................
Offshore.....................................................................................................................................
Total United States..........................................................................................................................
Malaysia and JDA...........................................................................................................................
Other (b)..........................................................................................................................................
Worldwide............................................................................................................................
2020
2019
2018
$
$
$
$
42.63
45.92
43.56
46.41
37.91
51.37
44.28
33.87
36.55
34.63
37.40
37.91
43.42
35.52
11.29
—
8.94
11.10
1.27
—
1.23
1.26
4.47
3.41
2.98
$
$
$
$
53.19
59.18
55.15
—
61.81
65.22
56.77
53.18
59.17
55.14
—
61.81
65.22
56.76
13.20
—
13.31
13.21
1.59
—
2.12
1.83
5.04
4.63
3.90
56.90
62.02
58.69
—
70.42
69.76
60.77
60.64
65.73
62.41
—
70.42
69.76
63.80
21.48
18.55
25.58
21.81
2.42
2.02
2.68
2.43
5.07
4.41
4.18
(a) Selling prices in the United States are adjusted for certain processing and distribution fees included in Marketing expenses. Excluding these fees worldwide
selling prices for 2020 would be $47.54 per barrel for crude oil (including hedging) (2019: $59.95; 2018: $63.77), $38.78 per barrel for crude oil (excluding
hedging) (2019: $59.94; 2018: $66.80), $11.29 per barrel for NGL (2019: $13.40; 2018: $22.00) and $3.11 per mcf for natural gas (2019: $3.97; 2018: $4.25).
(b) Other includes our interests in Denmark and Libya.
(c) In August 2018, we sold our interests in the Utica shale play, onshore U.S.
Crude oil hedging activities in 2020 were a net gain of $547 million before and after income taxes, and a net gain of $1 million
before and after income taxes in 2019. For 2021, we have WTI put options with an average monthly floor price of $50 per barrel for
120,000 bopd, and Brent put options with an average monthly floor price of $55 per barrel for 30,000 bopd. We expect put option
premium amortization, which will be reflected in realized selling prices, to reduce our 2021 results by approximately $205 million.
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Production Volumes: Our daily worldwide net production was as follows:
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2020
2019
2018
(In thousands)
Crude Oil - Barrels
United States
North Dakota.............................................................................................................................
Offshore (a)...............................................................................................................................
Total United States..........................................................................................................................
Guyana............................................................................................................................................
Malaysia and JDA...........................................................................................................................
Other (b)..........................................................................................................................................
Total................................................................................................................................................
Natural Gas Liquids - Barrels
United States
North Dakota.............................................................................................................................
Other Onshore (c)......................................................................................................................
Total Onshore.......................................................................................................................
Offshore (a)...............................................................................................................................
Total United States..........................................................................................................................
Natural Gas - Mcf
United States
North Dakota.............................................................................................................................
Other Onshore (c)......................................................................................................................
Total Onshore.......................................................................................................................
Offshore (a)...............................................................................................................................
Total United States..........................................................................................................................
Malaysia and JDA...........................................................................................................................
Other (b)..........................................................................................................................................
Total................................................................................................................................................
Barrels of Oil Equivalent...................................................................................................................
107
38
145
20
4
9
178
56
—
56
5
61
180
—
180
76
256
291
7
554
331
94
46
140
—
4
25
169
42
—
42
5
47
110
—
110
91
201
351
20
572
311
77
41
118
—
4
24
146
31
3
34
5
39
76
38
114
67
181
352
20
553
277
Crude oil and natural gas liquids as a share of total production..........................................................
72 %
69 %
67 %
(a) In November 2020, we sold our working interest in the Shenzi Field in the deepwater Gulf of Mexico. Net production from the Shenzi Field was 9,000 boepd for
the year ended December 31, 2020 (2019: 12,000 boepd; 2018: 16,000 boepd).
(b) Other includes our interests in Denmark and Libya. Net production from Libya was 4,000 boepd for 2020 (2019: 21,000 boepd; 2018: 20,000 boepd). Net
production from Denmark was 6,000 boepd for 2020 (2019: 7,000 boepd; 2018: 7,000 boepd).
(c) In August 2018, we sold our interests in the Utica shale play, onshore U.S. Production was 9,000 boepd for the year ended December 31, 2018.
In 2021, we expect net production, excluding Libya, to be approximately 310,000 boepd, compared with 2020 net production,
excluding Libya and assets sold, of 318,000 boepd.
Net production variances related to 2020 and 2019 are summarized as follows:
United States: North Dakota net oil production was higher in 2020, primarily due to increased wells online and improved well
performance. North Dakota net natural gas and NGL production was higher in 2020, due to increased wells online and improved well
performance, additional natural gas captured and processed, and additional volumes received under percentage of proceeds contracts
resulting from lower prices. Offshore net production was down in 2020 compared to 2019 due to the effect of increased hurricane-
related downtime and higher planned maintenance in 2020 and lower production from the Shenzi Field, which was sold in November
2020, partially offset by initial production from the Esox-1 well, which commenced in February of 2020.
International: Net crude oil production from Guyana was higher in 2020, due to the start-up of the Liza Phase 1 development in
December 2019, while net crude oil production in Libya was largely shut in during 2020 due to force majeure caused by civil unrest.
Net natural gas production was lower from Malaysia and JDA due to COVID-19 impacts on economic activity in Malaysia and
Thailand which reduced natural gas nominations from the buyers.
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Sales Volumes: Higher sales volumes from our net production in 2020 improved after-tax results by approximately $130 million,
compared with 2019. Net worldwide sales volumes from Hess net production, which excludes sales volumes of crude oil, NGL and
natural gas purchased from third parties, were as follows:
2020
2019
2018
Crude oil – barrels (a)...........................................................................................................................
Natural gas liquids – barrels.................................................................................................................
Natural gas – mcf.................................................................................................................................
Barrels of Oil Equivalent..............................................................................................................
60,924
22,397
202,917
117,141
(In thousands)
61,061
17,067
208,665
112,906
Crude oil - barrels per day....................................................................................................................
Natural gas liquids - barrels per day.....................................................................................................
Natural gas - mcf per day.....................................................................................................................
Barrels of Oil Equivalent Per Day...............................................................................................
167
61
554
320
167
47
572
309
52,742
14,019
202,041
100,435
144
39
553
275
(a) In 2020, 6.3 million barrels of Bakken crude oil were loaded on VLCCs for sale in Asian markets. The first VLCC cargo of 2.1 million barrels was sold during the
third quarter of 2020 and the remaining two VLCC cargos totaling 4.2 million barrels have been sold for delivery in the first quarter of 2021.
Marketing, including purchased oil and gas (Marketing expense): Marketing expense is mainly comprised of costs to purchase
crude oil, NGL and natural gas from our partners in Hess operated wells or other third parties, primarily in the U.S., and transportation
and other distribution costs for U.S. marketing activities. Marketing expense was lower in 2020 compared to 2019 primarily due to
lower crude oil prices paid for purchased volumes from third parties.
Cash Operating Costs: Cash operating costs consist of operating costs and expenses, production and severance taxes and E&P
general and administrative expenses. Excluding items affecting comparability described in Items Affecting Comparability of Earnings
Between Periods below, cash operating costs decreased $159 million, or 12%, in 2020 compared to 2019 primarily from the impact of
cost reduction initiatives and lower production and severance taxes associated with lower crude oil prices. On a per-unit basis, cash
operating costs improved 17% from 2019 reflecting lower costs and the impact of higher production volumes.
Midstream Tariffs Expense: Tariffs expense increased from 2019, primarily due to higher throughput volumes and tariff rates in
2020. In 2021, we estimate Midstream tariffs expense to be in the range of $1,090 million to $1,115 million.
DD&A: DD&A expenses decreased by $62 million from 2019, primarily due to a lower portfolio average DD&A rate, due in
part to impairment charges in the first quarter of 2020, partially offset by higher production volumes. DD&A expense on a per-unit
basis was lower in 2020, compared to 2019, primarily due to the year-over-year mix of production and the impact of reduced DD&A
rates for assets impaired in the first quarter of 2020.
Unit costs: Unit cost per boe information is based on total E&P net production volumes and excludes items affecting
comparability of earnings as disclosed below. Actual and forecast unit costs are as follows:
Cash operating costs (b).................................................................... $
DD&A (c)..........................................................................................
Total Production Unit Costs........................................................ $
2020
9.91
15.80
25.71
$
$
Actual
2019
11.99
17.43
29.42
$
$
2018
12.66
17.14
29.80
Forecast range (a)
2021
$10.50 — $11.50
12.00 — 13.00
$22.50 — $24.50
(a) Forecast information excludes any contribution from Libya.
(b) Cash operating costs per boe, excluding Libya, was $9.85 in 2020 (2019: $12.54; 2018: $13.32).
(c) DD&A per boe, excluding Libya, was $15.98 in 2020 (2019: $18.52; 2018: $18.29).
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Exploration Expenses: Exploration expenses, including items affecting comparability of earnings described below, were as
follows:
Exploratory dry hole costs (a)....................................................................................................... $
Exploration lease and other impairment (b)..................................................................................
Geological and geophysical expense and exploration overhead...................................................
$
2020
2019
2018
(In millions)
49
17
167
233
$
$
$
$
192
51
108
351
165
37
160
362
(a) In 2020, dry hole costs primarily related to the Tanager-1 well in the Kaieteur Block, offshore Guyana, the Galapagos Deep and Oldfield-1 wells in the Gulf of
Mexico and the write-off of previously capitalized exploratory wells (see Items Affecting Comparability of Earnings Between Periods below). In 2019, dry hole
costs primarily related to the Jill-1 well on License 6/16 in Denmark and the Oldfield-1 well in the Gulf of Mexico. Dry hole expense for the Oldfield-1 well was
$15 million in 2019 and $12 million in 2020.
(b) In 2020, exploration lease and other impairment included impaired leasehold costs due to a reprioritization of the Corporation’s forward capital program (see
Items Affecting Comparability of Earnings Between Periods below).
In 2021, we estimate exploration expenses, excluding dry hole expense, to be in the range of $170 million to $180 million.
Income Taxes: In 2020, income tax benefit was $12 million compared with expense of $375 million in 2019, primarily due to
reduced activity in Libya resulting from force majeure on operations for the majority of the year. We are generally not recognizing
deferred tax benefit or expense in certain countries, primarily the U.S., Denmark, and Malaysia, while we maintain valuation
allowances against net deferred tax assets in these jurisdictions in accordance with the requirements of U.S. accounting standards. The
valuation allowance established against the net deferred tax asset in Guyana for the Stabroek Block was released as a result of the
positive evidence from first production in December 2019, and the significant forecasted pre-tax income from operations. The
cumulative pre-tax losses in Guyana were driven by pre-production activities. See E&P Items Affecting Comparability of Earnings
Between Periods below.
Actual effective tax rates are as follows:
Effective income tax benefit (expense) rate.........................................................................................
Adjusted effective income tax benefit (expense) rate (a).....................................................................
(a) Excludes any contribution from Libya and items affecting comparability of earnings.
2020
%
0
(5)
2019
%
(88)
(36)
2018
%
(88)
60
In 2021, we estimate income tax expense, excluding Libya and items affecting comparability of earnings between periods, to be in
the range of $80 million to $90 million.
Items Affecting Comparability of Earnings Between Periods: Reported E&P earnings include the following items affecting
comparability of income (expense):
Before Income Taxes
After Income Taxes
2020
2019
2018
2020
2019
2018
Impairment........................................................................................................ $ (2,126) $
Dry hole and lease impairment expenses..........................................................
Crude oil inventories write-down......................................................................
Exit costs and other...........................................................................................
Cost recovery settlement...................................................................................
Reversal of deferred tax asset valuation allowance..........................................
Gains on asset sales, net....................................................................................
(152)
(53)
(26)
—
—
79
$ (2,278) $
— $
—
—
—
(21)
—
22
1
$
(In millions)
— $ (2,049) $
—
—
(110)
—
—
24
(86) $ (2,198) $
(150)
(52)
(26)
—
—60
79
— $
—
—
—
(19)
—
22
63
$
—
—
—
(110)
—
24
(86)
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The pre-tax amounts of E&P items affecting comparability of income (expense) as presented in the Statement of Consolidated
Income are as follows:
Gains on asset sales, net....................................................................................................................... $
Marketing, including purchased oil and gas.........................................................................................
Operating costs and expenses...............................................................................................................
Exploration expenses, including dry holes and lease impairment.......................................................
General and administrative expenses...................................................................................................
Depreciation, depletion and amortization............................................................................................
Impairment...........................................................................................................................................
$
2020:
Before Income Taxes
2020
2019
2018
$
79
(53)
(20)
(153)
(5)
—
(2,126)
(2,278) $
(In millions)
22
(21)
—
—
—
—
—
1
$
$
24
—
(19)
(3)
(72)
(16)
—
(86)
• Impairment: We recorded noncash impairment charges totaling $2.1 billion ($2.0 billion after income taxes) related to our
oil and gas properties at North Malay Basin in Malaysia, the South Arne Field in Denmark, and the Stampede and Tubular
Bells fields in the Gulf of Mexico, primarily as a result of a lower long-term crude oil price outlook. Other charges totaling
$21 million pre-tax ($20 million after income taxes) related to drilling rig right-of-use assets in the Bakken and surplus
materials and supplies. See Note 12, Impairment in the Notes to Consolidated Financial Statements.
• Dry hole and lease impairment expenses: We incurred pre-tax charges totaling $152 million ($150 million after income
taxes) in the first quarter to write-off previously capitalized exploratory well costs of $125 million ($123 million after income
taxes) primarily related to the northern portion of the Shenzi Field in the Gulf of Mexico and to impair certain exploration
leasehold costs by $27 million ($27 million after income taxes) due to a reprioritization of our capital program.
• Crude oil inventories write-down: We incurred a pre-tax charge of $53 million ($52 million after income taxes) to adjust
crude oil inventories to their net realizable value at the end of the first quarter following the significant decline in crude oil
prices.
• Exit costs and other: We recorded a pre-tax charge of $26 million ($26 million after income taxes) for employee termination
benefits incurred related to cost reduction initiatives.
• Gains on asset sales, net: We recorded a pre-tax gain of $79 million ($79 million after income taxes) associated with the sale
of our 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico.
2019:
• Cost recovery settlement: We recorded a pre-tax charge of $21 million ($19 million after income taxes) related to a
settlement on historical cost recovery balances in the JDA that was paid in cash.
• Reversal of deferred tax asset valuation allowance: We recorded a noncash income tax benefit of $60 million, which
resulted from the reversal of a valuation allowance against net deferred tax assets in Guyana upon achieving first production
from the Liza Phase 1 development.
• Gains on asset sales, net: We recorded a pre-tax gain of $22 million ($22 million after income taxes) associated with the sale
of our remaining acreage in the Utica shale play.
2018:
• Exit costs and other: We incurred noncash pre-tax charges of $73 million ($73 million after income taxes) in connection with
vacated office space. In addition, we recorded a pre-tax charge of $37 million ($37 million after income taxes) for employee
termination benefits related to a cost reduction program undertaken to reflect the reduced scale of our business following
significant asset sales in 2017.
• Gains on asset sales, net: We recorded a pre-tax gain of $14 million ($14 million after income taxes) associated with the sale
of our joint venture interests in the Utica shale play in eastern Ohio and a pre-tax gain of $10 million ($10 million after
income taxes) associated with the sale of our interests in Ghana.
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Midstream
Following is a summarized statement of income for our Midstream operations:
2020
2019
2018
(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues................................................................................................. $
Other, net.........................................................................................................................................
Total revenues and non-operating income................................................................................
$
1,092
10
1,102
Costs and Expenses
Operating costs and expenses..........................................................................................................
General and administrative expenses..............................................................................................
Depreciation, depletion and amortization.......................................................................................
Interest expense...............................................................................................................................
Total costs and expenses...........................................................................................................
Results of Operations Before Income Taxes....................................................................................
Provision (benefit) for income taxes (a)..........................................................................................
Net income (loss).................................................................................................................................
Less: Net income (loss) attributable to noncontrolling interests.....................................................
Net Income (Loss) Attributable to Hess Corporation..................................................................... $
338
21
157
95
611
491
7
484
254
230
$
848
4
852
279
56
142
63
540
312
—
312
168
144
$
$
713
6
719
193
14
127
60
394
325
38
287
167
120
(a) Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation
allowance assessment basis. See footnote (a) in the table on page 87 for further details.
Sales and other operating revenues increased from 2019 primarily due to higher throughput volumes and tariff rates. Operating
costs and expenses increased from 2019 primarily due to increased operating and maintenance expenditures on expanded
infrastructure and initial costs incurred related to the Tioga Gas Plant turnaround planned for 2021. General and administrative
expenses decreased from 2019 as a result of expenditures incurred from Hess Midstream LP’s acquisition of HIP and its corporate
restructuring. See Items Affecting Comparability of Earnings below. DD&A expenses increased from 2019 primarily due to
additional assets placed in service. The increase in interest expense from 2019 reflects higher borrowings by the Midstream business.
In 2021, we estimate net income attributable to Hess Corporation from the Midstream segment to be in the range of $280 million
to $290 million.
Items Affecting Comparability of Earnings Between Periods:
In 2019, we recognized a pre-tax charge of $30 million ($16
million after income taxes and noncontrolling interests) in General and Administrative Expenses for transaction related costs for Hess
Midstream Partners LP’s acquisition of HIP and the associated corporate restructuring. See Note 4, Hess Midstream LP in the Notes
to Consolidated Financial Statements.
Corporate, Interest and Other
The following table summarizes Corporate, Interest and Other expenses:
Corporate and other expenses (excluding items affecting comparability)........................................... $
Interest expense....................................................................................................................................
Less: Capitalized interest.....................................................................................................................
Interest expense, net........................................................................................................................
Corporate, Interest and Other expenses before income taxes..............................................................
Provision (benefit) for income taxes...............................................................................................
Net Corporate, Interest and Other expenses after income taxes..........................................................
Items affecting comparability of earnings between periods, after income taxes............................
Total Corporate, Interest and Other Expenses After Income Taxes............................................ $
2020
2019
2018
(In millions)
114
355
(38)
317
431
—
431
174
605
$
$
$
$
114
373
—
373
487
(6)
481
1
482
97
359
(20)
339
436
(3)
433
20
453
Corporate and other expenses, excluding items affecting comparability, were comparable in 2020 compared to the corresponding
period in 2019. In 2021, after-tax Corporate and other expenses, excluding items affecting comparability of earnings between periods,
are estimated to be in the range of $130 million to $140 million.
Interest expense, net was higher in 2020 due to interest incurred on the $1.0 billion three year term loan entered into in March
In 2021, after-tax interest expense, net is estimated to be in the range of $380 million to
2020 and lower capitalized interest.
$390 million.
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Items Affecting Comparability of Earnings Between Periods: Corporate, Interest and Other results included the following items
affecting comparability of income (expense):
2020:
• Exit costs and other: We included a pre-tax charge of $1 million ($1 million after income taxes) for employee termination
benefits related to cost reduction initiatives.
2019:
• Pension settlement: We recorded a noncash pension settlement charge of $88 million ($88 million after income taxes)
associated with the purchase of a single premium annuity contract by the Hess Corporation Employees’ Pension Plan to settle
and transfer certain of its obligations to a third party. The charge is included in Other, net in the Statement of Consolidated
Income.
• Income tax: We recorded an allocation of noncash income tax expense of $86 million that was previously a component of
accumulated other comprehensive income related to our 2019 crude oil hedge contracts.
2018:
• Loss on debt extinguishment: We recorded a pre-tax charge of $53 million ($53 million after income taxes) related to the
premium paid for debt repurchases.
• Exit costs and other: We recorded a pre-tax charge of $58 million ($58 million after income taxes) resulting from the
settlement of legal claims related to former downstream interests.
• Income tax: We recorded an allocation of noncash income tax benefit of $91 million to offset the recognition of a noncash
income tax expense recorded in other comprehensive income resulting primarily from changes in fair value of our 2019 crude
oil hedge contracts.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:
Cash and cash equivalents (a)......................................................................................................................................... $
Current maturities of long-term debt...............................................................................................................................
Total debt (b)...................................................................................................................................................................
Total equity.....................................................................................................................................................................
Debt to capitalization ratio for debt covenants (c)..........................................................................................................
$
1,739
10
8,296
6,335
47.5 %
1,545
—
7,142
9,706
39.6 %
(a) Includes $4 million of cash attributable to our Midstream Segment at December 31, 2020 (2019: $3 million).
(b) Includes $1,910 million of debt outstanding from our Midstream Segment at December 31, 2020 (2019: $1,753 million) that is non-recourse to Hess Corporation.
(c) Total Consolidated Debt of Hess Corporation (including finance leases and excluding Midstream non-recourse debt) as a percentage of Total Capitalization of
Hess Corporation as defined under Hess Corporation's term loan and revolving credit facility financial covenants. Total Capitalization excludes the impact of
noncash impairment charges and non-controlling interests. See Note 7 in the Notes to Consolidated Financial Statements.
2020
2019
(In millions, except ratio)
Cash Flows
The following table sets forth a summary of our cash flows:
2020
2019
2018
(In millions)
Net cash provided by (used in):
Operating activities........................................................................................................................... $
Investing activities.............................................................................................................................
Financing activities...........................................................................................................................
Net Increase (Decrease) in Cash and Cash Equivalents............................................................ $
1,333
(1,707)
568
194
$
$
$
1,642
(2,843)
52
(1,149) $
1,939
(1,566)
(2,526)
(2,153)
Operating Activities: Net cash provided by operating activities was $1,333 million in 2020 (2019: $1,642 million), while net cash
provided by operating activities before changes in operating assets and liabilities was $1,803 million in 2020 (2019: $2,237
million). Net cash provided by operating activities before changes in operating assets and liabilities decreased from 2019 primarily
due to lower realized selling prices. Changes in operating assets and liabilities in 2020 reduced net cash provided by operating
activities by $470 million, primarily from a decrease in accounts payable and accrued liabilities, an increase in crude oil inventory
resulting from our VLCC transactions, and abandonment expenditures, partially offset by lower receivables. Changes in operating
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assets and liabilities in 2019 reduced net cash provided by operating activities by $595 million primarily related to premiums on crude
oil hedge contracts, abandonment expenditures, pension contributions and an increase in accounts receivable.
Investing Activities: Total Additions to Property, Plant and Equipment were $2,197 million in 2020 (2019: $2,829 million). The
decrease primarily reflects lower drilling activity in the Bakken, partially offset by payments in the first quarter of 2020 to settle
capital expenditures accrued in the fourth quarter of 2019.
In 2019, Midstream equity investments in its 50/50 joint venture with
Targa Resources were $33 million. Proceeds from asset sales were $493 million in 2020 (2019: $22 million).
Financing Activities: Borrowings in 2020 related to our $1.0 billion three year term loan while borrowings in 2019 related to our
Midstream operating segment. Repayments of debt were $8 million in 2019. Net borrowings (repayments) of debt with maturities of
90 days or less related to our Midstream operating segment revolving credit facilities. Common stock dividends paid were $309
million in 2020 compared to common and preferred dividends of $316 million in 2019. Net cash outflows to noncontrolling interests
were $261 million in 2020 (2019: $353 million).
Future Capital Requirements and Resources
At December 31, 2020, Hess Corporation, had $1.74 billion in cash and cash equivalents, excluding Midstream, and total
liquidity, including available committed credit facilities, of approximately $5.4 billion. Our fully undrawn $3.5 billion committed
revolving credit facility matures in May 2023, and we have no debt maturities until 2023 when the three year term loan matures.
Net production in 2021 is forecast to be approximately 310,000 boepd, excluding Libya, and we expect our 2021 E&P capital and
exploratory expenditures will be approximately $1.9 billion. For 2021, we have WTI put options with an average monthly floor price
of $50 per barrel for 120,000 bopd, and Brent put options with an average monthly floor price of $55 per barrel for 30,000 bopd.
In 2021, based on current forward strip crude oil prices, we expect cash flow from operating activities, proceeds from the first
quarter 2021 sale of 4.2 million barrels of crude oil stored on two VLCCs at year-end, and cash and cash equivalents existing at
December 31, 2020 of $1.74 billion, will be sufficient to fund our capital investment program and dividends. Due to the volatile
commodity price environment, we may take any of the following steps, or a combination thereof, to improve our liquidity and
financial position: reduce the planned capital program and other cash outlays, including dividends, pursue asset sales, borrow against
our committed revolving credit facility, or issue debt or equity securities.
The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at
December 31, 2020:
Expiration
Date
Capacity
Borrowings
Letters of
Credit
Issued
(In millions)
Total
Used
Available
Capacity
Hess Corporation
Revolving credit facility.................................................. May 2023
Committed lines.............................................................. Various (a)
Uncommitted lines.......................................................... Various (a)
Total - Hess Corporation............................................
Midstream
Revolving credit facility (b)............................................ December 2024
Total - Midstream.......................................................
$
$
$
$
3,500
175
215
3,890
1,000
1,000
$
$
$
$
— $
—
—
— $
184
184
$
$
— $
54
215
269
$
— $
— $
— $
54
215
269
$
184
184
$
$
3,500
121
—
3,621
816
816
(a) Committed and uncommitted lines have expiration dates through 2021.
(b) This credit facility may only be utilized by HESM Opco and is non-recourse to Hess Corporation.
Hess Corporation:
In 2020, we entered into a $1 billion three year term loan agreement with a maturity date of March 16, 2023. Borrowings under
the term loan generally bear interest at LIBOR plus an applicable margin of 2.25% until the term loan's first anniversary. The
applicable margin varies based on the credit rating of the Corporation’s senior unsecured long-term debt and will increase by 0.25%
on each anniversary of the term loan.
In 2019, we entered into a new $3.5 billion revolving credit facility with a maturity date of May 15, 2023, which replaced the
Corporation’s previous revolving credit facility. The new facility can be used for borrowings and letters of credit. Borrowings will
generally bear interest at 1.30% above LIBOR, though the interest rate is subject to adjustment if the Corporation’s credit rating
changes. At December 31, 2020, Hess Corporation had no outstanding borrowings or letters of credit under this facility.
The revolving credit facility and term loan are subject to customary representations, warranties, customary events of default and
covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and
its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of
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the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the
revolving credit facility and the term loan agreement). The indentures for the Corporation's fixed-rate public notes limit the ratio of
secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As of December 31, 2020, Hess
Corporation was in compliance with these financial covenants. For additional information regarding the alteration or discontinuation
of LIBOR on our borrowing costs, see Financial Risks in Item 1A. Risk Factors.
The most restrictive of the financial covenants related to our fixed-rate public notes and our term loan and revolving credit facility
would allow us to borrow up to an additional $1,730 million of secured debt at December 31, 2020.
We had $269 million in letters of credit outstanding at December 31, 2020 (2019: $272 million), which primarily relate to our
international operations. We have a shelf registration under which we may issue additional debt securities, warrants, common stock or
preferred stock.
Midstream:
At December 31, 2020, Hess Midstream Operations LP (formerly Hess Midstream Partners LP, or HESM Opco), a consolidated
subsidiary of Hess Midstream LP, had $1.4 billion of senior secured syndicated credit facilities maturing December 16, 2024,
consisting of a $1.0 billion five year revolving credit facility and a fully drawn $400 million five year term loan A facility. The
revolving credit facility can be used for borrowings and letters of credit to fund HESM Opco’s operating activities, capital
expenditures, distributions and for other general corporate purposes. Borrowings under the five year term loan A facility will
generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the five
year syndicated revolving credit facility ranges from 1.275% to 2.000%. Pricing levels for the facility fee and interest-rate margins are
based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade
credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain
covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four
fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period
following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to
EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. HESM Opco was in
compliance with these financial covenants at December 31, 2020. The credit facilities are secured by first-priority perfected liens on
substantially all the presently owned and after-acquired assets of HESM Opco and its direct and indirect wholly owned material
domestic subsidiaries, including equity interests directly owned by such entities, subject to certain customary exclusions. At
December 31, 2020, borrowings of $184 million were drawn under HESM Opco’s revolving credit facility, and borrowings of $400
million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan A facility. Borrowings under these credit
facilities are non-recourse to Hess Corporation.
Credit Ratings
Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating. Standard and Poor’s
Ratings Services affirmed our credit rating at BBB- with negative outlook in October 2020 while Fitch Ratings affirmed a BBB- credit
rating and stable outlook in August 2020. Moody’s Investors Service affirmed our credit rating at Ba1 with stable outlook, which is
below investment grade, in March 2020.
At December 31, 2020, HESM Opco’s senior unsecured debt is rated BB+ by Standard and Poor’s Ratings Services and Fitch
Ratings, and Ba3 by Moody’s Investors Service.
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Contractual Obligations and Contingencies
The following table sets forth aggregate information about certain of the Corporation's consolidated contractual obligations at
December 31, 2020:
Total
2021
Payments Due by Period
2022 and
2023
2024 and
2025
Thereafter
Total Debt (excluding deferred financing costs, discounts, and interest) (a)...
Finance Leases (b).................................................................................................
Operating Leases (b).............................................................................................
Purchase Obligations:
$
Capital expenditures (b).......................................................................................
Operating expenses (b).........................................................................................
Transportation and related contracts (b)...............................................................
Asset retirement obligations.................................................................................
Other liabilities.....................................................................................................
$
8,372
356
663
2,837
236
2,867
2,116
583
10
36
83
868
167
310
105
79
(In millions)
$
1,050
72
155
$
1,469
63
756
170
95
$
824
72
138
500
5
493
86
75
6,488
176
287
—
1
1,308
1,755
334
(a) We anticipate cash payments for interest on Total Debt of $440 million for 2021, $850 million for 2022-2023, $784 million for 2024-2025, and $3,231 million
thereafter for a total of $5,305 million. These interest payments reflect our contractual obligations at December 31, 2020.
(b) Comprises obligations, including where we, as operator, have contracted directly with suppliers.
Capital expenditures represent amounts for which we were contractually committed at December 31, 2020, and include a portion
of our planned capital expenditure program for 2021. Obligations for operating expenses include commitments for oil and gas
production expenses, seismic purchases and other normal business expenses. Other liabilities reflect contractually committed
obligations in the Consolidated Balance Sheet at December 31, 2020, including post-retirement plan liabilities for our unfunded plans
and estimates for uncertain income tax positions. The Corporation and certain of its subsidiaries primarily lease drilling rigs,
equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space for varying periods. See Note 6, Leases in the
Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements
At December 31, 2020, we had $269 million in letters of credit. See also Note 18, Guarantees, Contingencies and Commitments
in the Notes to Consolidated Financial Statements.
Foreign Operations
We conduct E&P activities outside the U.S., principally in Guyana, the Joint Development Area of Malaysia/Thailand, Malaysia,
Denmark, Libya, Suriname, and Canada. Therefore, we are subject to the risks associated with foreign operations, including political
risk, tax law changes, currency risk, corruption and acts of terrorism. See Item 1A. Risk Factors for further details.
Critical Accounting Policies and Estimates
Accounting policies and estimates affect the recognition of assets and liabilities in the Consolidated Balance Sheet and revenues
and expenses in the Statement of Consolidated Income. The accounting methods used can affect net income, equity and various
financial statement ratios. However, our accounting policies generally do not change cash flows or liquidity.
Accounting for Exploration and Development Costs:
E&P activities are accounted for using the successful efforts
method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other
related costs are capitalized. Annual
lease rentals, exploration expenses and exploratory dry hole costs are expensed as
incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are
capitalized.
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves
have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity
of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the
economic and operational viability of the project.
If either of those criteria is not met, or if there is substantial doubt about the
economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in
assessing reserves, and the economic and operating viability of a project include: commitment of project personnel, active negotiations
for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and
other factors.
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Crude Oil and Natural Gas Reserves: The determination of estimated proved reserves is a significant element in arriving at the
results of operations of E&P activities. The estimates of proved reserves affect well capitalizations, the unit of production
depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets.
For reserves to be booked as proved they must be determined with reasonable certainty to be economically producible from
known reservoirs under existing economic conditions, operating methods and government regulations. In addition, government and
project operator approvals must be obtained and, depending on the amount of the project cost, senior management or the Board of
Directors must commit to fund the project. We maintain our own internal reserve estimates that are calculated by technical staff that
work directly with the oil and gas properties. Our technical staff update reserve estimates throughout the year based on evaluations of
new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard
reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject
to internal technical audits and senior management review. We also engage an independent third-party consulting firm to audit
approximately 80% of our total proved reserves each year.
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an
unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual
agreements, excluding escalations based on future conditions. As discussed in Item 1A. Risk Factors, crude oil prices are volatile
which can have an impact on our proved reserves. If crude oil prices in 2021 are at levels below that used in determining 2020 proved
reserves, we may recognize negative revisions to our December 31, 2021 proved undeveloped reserves.
In addition, we may
recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost
structures. Conversely, price increases in 2021 above those used in determining 2020 proved reserves could result in positive
revisions to proved developed and proved undeveloped reserves at December 31, 2021. It is difficult to estimate the magnitude of any
potential net negative or positive change in proved reserves at December 31, 2021, due to numerous currently unknown factors,
including 2021 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions in proved reserves
related to 2021 reservoir performance, the levels to which industry costs will change in response to 2021 crude oil prices, and
management’s plans as of December 31, 2021 for developing proved undeveloped reserves. A 10% change in proved developed and
proved undeveloped reserves at December 31, 2020 would result in an approximate $150 million pre-tax change in depreciation,
depletion, and amortization expense for 2021 based on projected production volumes. See the Supplementary Oil and Gas Data on
pages 91 through 99 in the accompanying financial statements for additional information on our oil and gas reserves.
Impairment of Long-lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or
changes in circumstances indicate that the carrying amounts may not be recovered. Long‑lived assets are tested based on identifiable
cash flows that are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets
are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is
recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting
anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair
value measurements.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices,
which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes
and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to
be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are
consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset
impairment will generally differ from those used in the standardized measure of discounted future net cash flows, since the
standardized measure requires the use of historical twelve-month average prices.
Our impairment tests of long-lived E&P producing assets are based on our best estimates of future production volumes (including
recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each
time an impairment test is performed. As a result of the significant decline in crude oil prices due to the economic slowdown from the
COVID-19 pandemic, we reviewed our oil and gas fields and midstream operating segment asset groups for impairment at March 31,
2020. We impaired various oil and gas fields located in Malaysia, Denmark, and the Gulf of Mexico in the first quarter of 2020
primarily as a result of a lower long-term crude oil price outlook. See Note 12, Impairment in the Notes to Consolidated Financial
Statements for further details. We could experience an impairment in the future if one or a combination of the following occur: the
projected production volumes from oil and gas fields decrease, crude oil and natural gas selling prices decline below the long-term
crude oil price outlook used in the March 31, 2020 impairment test, or future estimated capital and operating costs increase
significantly.
Hess Midstream LP: We consolidate the activities of our interest in Hess Midstream LP, which qualifies as a variable interest
entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the primary beneficiary of the VIE,
as defined in the accounting standards, since we have the power through Hess Corporation’s 47% consolidated ownership interest in
Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are
obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. This
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conclusion was based on a qualitative analysis that considered Hess Midstream LP’s governance structure, the commercial agreements
between Hess Midstream LP and us, and the voting rights established between the members, which provide us the ability to control the
operations of Hess Midstream LP.
Income Taxes: Judgments are required in the determination and recognition of income tax assets and liabilities in the financial
statements. These judgments include the requirement to recognize the financial statement effect of a tax position only when
management believes it is more likely than not, based on the technical merits, that the position will be sustained upon examination.
We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets
for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax
basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If,
when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be
realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized.
The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the
In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary
evidence’s relative objectivity.
differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of
appreciated assets, estimates of future taxable income, and other factors. Estimates of future taxable income are based on assumptions
of oil and gas reserves, selling prices, and other subjective operating assumptions that are consistent with internal business
forecasts. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating
losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably
resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or
carryforward period so brief that a significant deductible temporary difference expected to reverse in a single year would limit
realization of tax benefits. Due to a sustained low commodity price environment, we remained in a three-year cumulative
consolidated loss position at December 31, 2020. A three-year cumulative consolidated loss constitutes objective negative evidence to
which the accounting standards require we assign significant weight relative to subjective evidence such as our estimates of future
taxable income. We are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S., Denmark,
and Malaysia, while we maintain valuation allowances against net deferred tax assets in these jurisdictions. In December 2019, we
reversed the valuation allowance of $60 million for Guyana upon achieving first production from the Liza Phase 1 development.
At December 31, 2020, the Consolidated Balance Sheet reflects a $5,391 million valuation allowance against the net deferred tax
assets for multiple jurisdictions based on the evaluation of the accounting standards described above. The amount of the deferred tax
asset considered realizable, however, could be adjusted if estimates of future taxable income change or if objective negative evidence
in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as expected future
growth.
Asset Retirement Obligations: We have material legal obligations to remove and dismantle long‑lived assets and to restore land
or seabed at certain E&P locations. In accordance with generally accepted accounting principles, we recognize a liability for the fair
value of required asset retirement obligations. In addition, the fair value of any legally required conditional asset retirement obligation
is recorded if the liability can be reasonably estimated. We capitalize such costs as a component of the carrying amount of the
underlying assets in the period in which the liability is incurred.
In subsequent periods, the liability is accreted, and the asset is
depreciated over the useful life of the related asset. We estimate the fair value of these obligations by discounting projected future
payments that will be required to satisfy the obligations. In determining these estimates, we are required to make several assumptions
and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors
and discount rate. In addition, there are other external factors, which could significantly affect the ultimate settlement costs or timing
for these obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs
and foreign currency exchange rates and advances in technology. As a result, our estimates of asset retirement obligations are subject
to revision due to the factors described above. Changes in estimates prior to settlement result in adjustments to both the liability and
related asset values, unless the field has ceased production, in which case changes are recognized in our Consolidated Statement of
Income. See Note 8, Asset Retirement Obligations.
Retirement Plans: We have funded non-contributory defined benefit pension plans, an unfunded supplemental pension plan and
an unfunded postretirement medical plan. We recognize the net change in the funded status of the projected benefit obligation for
these plans in the Consolidated Balance Sheet. The determination of the obligations and expenses related to these plans are based on
several actuarial assumptions. These assumptions represent estimates made by us, some of which can be affected by external
factors. The most significant assumptions relate to:
Discount rates used for measuring the present value of future plan obligations and net periodic benefit cost: The discount rates
used to estimate our projected benefit obligations and net periodic benefit cost is based on a portfolio of high‑quality, fixed income
debt instruments with maturities that approximate the expected payment of plan obligations. At December 31, 2020, a 0.25% decrease
in the discount rate assumptions would increase projected benefit obligations by approximately $145 million and would decrease
forecasted 2021 annual net periodic benefit income by approximately $10 million. The increase in the projected benefit obligations
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would decrease the funded status of our pension plans, but any decrease in the funded status would be partially mitigated by increases
in the fair value of fixed income investments in the asset portfolios.
Expected long-term rates of returns on plan assets: The expected return on plan assets is developed from the expected future
returns for each asset category, weighted by the target allocation of plan assets to that asset category. The future expected return
assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return
expectations for particular asset categories. At December 31, 2020, a 0.25% decrease in the expected long-term rates of return on plan
assets assumption would decrease forecasted 2021 annual net periodic benefit income by approximately $10 million.
Other assumptions include the rate of future increases in compensation levels and expected participant mortality.
Derivatives: We utilize derivative instruments, including futures, forwards, options and swaps, individually or in combination to
mitigate our exposure to fluctuations in the prices of crude oil and natural gas, as well as changes in interest and foreign currency
exchange rates. All derivative instruments are recorded at fair value in our Consolidated Balance Sheet. Our policy for recognizing
the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that
are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash
flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of
unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are
recorded as a component of other comprehensive income (loss). Amounts included in Accumulated other comprehensive income
(loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in
fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related
hedged item is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including
the market and income approaches. Our fair value measurements also include non-performance risk and time value of money
considerations. Counterparty credit is considered for receivable balances, and our credit is considered for accrued liabilities.
We also record certain nonfinancial assets and liabilities at fair value when required by generally accepted accounting
principles. These fair value measurements are recorded in connection with business combinations, qualifying non-monetary
exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments
or goodwill.
We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for
the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical
instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted
cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets
that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for
determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however,
the level assigned to a fair value measurement is based on the lowest significant input level within this fair value hierarchy.
Environment, Health and Safety
Our long-term vision and values provide a foundation for how we do business and define our commitment to meeting high
standards of corporate citizenship and creating a long lasting positive impact on the communities where we do business. Our strategy
is reflected in our EHS & SR policies and by a management system framework that helps protect our workforce, customers and local
communities. Our management systems are intended to promote internal consistency, adherence to policy objectives and continual
improvement in EHS & SR performance. Improved performance may, in the short‑term, increase our operating costs and could also
require increased capital expenditures to reduce potential risks to our assets, reputation and license to operate. In addition to enhanced
EHS & SR performance, improved productivity and operational efficiencies may be realized from investments in EHS & SR. We
have programs in place to evaluate regulatory compliance, audit facilities, train employees, prevent and manage risks and emergencies
and to generally meet corporate EHS & SR goals and objectives.
Environmental Matters
We recognize that climate change is a global environmental concern. We assess, monitor and take measures to reduce our carbon
footprint at existing and planned operations. The EPA has adopted a series of GHG monitoring, reporting, and emissions control rules
for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting further legislation to reduce
GHG emissions. In addition, states have taken measures to reduce emissions of GHGs, primarily through the development of GHG
emission inventories and/or regional GHG cap-and-trade programs. At the international level, the Paris Agreement on climate change
aimed to enhance global response to global temperature changes and to reduce GHG emissions, among other things. We are
committed to complying with all GHG emissions regulations that apply to our operations, including those related to venting or flaring
of natural gas, and the responsible management of GHG emissions at our facilities. While we monitor climate-related regulatory
initiatives and international public policy issues, the current state of ongoing international climate initiatives and any related domestic
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actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur
in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of
GHGs, or related measures to encourage use of low carbon energy could result in higher capital expenditures and operating expenses
for us and the oil and gas industry in general and may reduce demand for our products, as described under Regulatory, Legal and
Environmental Risks in Item 1A. Risk Factors.
We will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be
necessary include E&P facilities, sites from discontinued operations where we retained liability and, although not currently significant,
EPA “Superfund” sites where we have been named a potentially responsible party. We accrue for environmental assessment and
remediation expenses when the future costs are probable and reasonably estimable. For additional information, see Item 3. Legal
Proceedings. At December 31, 2020, our reserve for estimated remediation liabilities was approximately $65 million. We expect that
existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. Our remediation
spending was approximately $15 million in 2020 (2019: $20 million; 2018: $15 million). The amount of other expenditures incurred
to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as
mostly indistinguishable components of our capital expenditures and operating expenses.
Health and Safety Matters
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels regarding the health and
safety of E&P operations. Such laws and regulations relate to, among other matters, occupational safety, the use of hydraulic
fracturing to stimulate crude oil and natural gas production, well control and integrity, process safety and equipment integrity, and may
include permitting and disclosure requirements, operating restrictions and other conditions on the development of crude oil and natural
gas. The level of our expenditures to comply with federal, state, local and foreign country health and safety regulations is difficult to
quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. While
compliance with laws and regulations relating to health and safety matters increases the overall cost of business for us and the oil and
gas industry in general, it has not had, to date, a material adverse effect on our operations, financial condition or results of operations.
Occupational Safety: We are subject to the requirements set forth under federal workplace standards by the OSHA and
comparable state statutes that regulate the protection of the health and safety of workers. Under OSHA and other federal and state
occupational safety and health laws and laws of foreign countries in which we operate, we must develop, maintain and disclose certain
information about hazardous materials used, released, or produced in our operations.
Production and Well Integrity: Our U.S. onshore production facilities are subject to U.S. federal government, state and local
regulations regarding the use of hydraulic fracturing and well control and integrity. Our offshore production facilities in the Gulf of
Mexico are subject to the U.S. federal government’s Safety and Environmental Management System regulations, which provide a
systematic approach for identifying, managing and mitigating hazards. Adapting to new technical standards and procedures in
production and in our well integrity management system is fundamental to our aim of protecting the environment as well as the health
and safety of our workforce and the communities in which we operate, and to safeguarding our product.
Process Safety and Equipment Integrity: We are also regulated at federal, state, local and foreign government levels regarding
process safety and the integrity of our equipment, including OSHA’s Process Safety Management of Highly Hazardous Chemicals
standard. ICE are barriers and safeguards that prevent or mitigate process safety incidents through detection, isolation, containment,
control or emergency preparedness and response within our facilities. We have established ICE performance standards, which set
specific requirements and criteria for inspections and tests that help to ensure ICE barriers are effective. We conduct assessments
collaboratively with our operated assets, subject matter experts and technical authorities to evaluate compliance with corporate and
asset environment, health and safety standards and procedures, as well as with applicable regulations. For additional information on
our emergency response and incident mitigation activities, see Emergency Preparedness and Response Plans and Procedures in Items
1 and 2. Business and Properties.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil, NGL, and
natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, financial risk management
activities refer to the mitigation of these risks through hedging activities.
Controls: We maintain a control environment under the direction of our Chief Risk Officer. Controls over instruments used in
financial risk management activities include volumetric and term limits. Our Treasury department is responsible for administering and
monitoring foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging
strategies are reviewed annually by the Audit Committee of the Board of Directors.
Instruments: We primarily use forward commodity contracts, foreign exchange forward contracts, futures, swaps, and options in
our risk management activities. These contracts are generally widely traded instruments with standardized terms. The following
describes these instruments and how we use them:
• Swaps: We use financially settled swap contracts with third parties as part of our financial risk management activities. Cash
flows from swap contracts are determined based on underlying commodity prices or interest rates and are typically settled
over the life of the contract.
• Forward Foreign Exchange Contracts: We enter into forward contracts, primarily for the British Pound, Danish Krone,
Canadian Dollar and Malaysian Ringgit, which commit us to buy or sell a fixed amount of those currencies at a
predetermined exchange rate on a future date.
• Exchange-traded Contracts: We may use exchange-traded contracts, including futures, on a number of different underlying
energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position
limits.
• Options: Options on various underlying energy commodities include exchange-traded and third-party contracts and have
various exercise periods. As a seller of options, we receive a premium at the outset and bear the risk of unfavorable changes
in the price of the commodity underlying the option. As a purchaser of options, we pay a premium at the outset and have the
right to participate in the favorable price movements in the underlying commodities.
Financial Risk Management Activities
We have outstanding foreign exchange contracts with notional amounts totaling $163 million at December 31, 2020 that are used
to reduce our exposure to fluctuating foreign exchange rates for various currencies. The change in fair value of foreign exchange
contracts from a 10% strengthening or weakening in the U.S. Dollar exchange rate is estimated to be a gain or loss of less than $5
million, respectively, at December 31, 2020.
At December 31, 2020, our total long-term debt, which was substantially comprised of fixed-rate instruments, had a carrying
value of $8,296 million and a fair value of $9,647 million. A 15% increase or decrease in interest rates would decrease or increase the
fair value of debt by approximately $400 million or $430 million, respectively. Any changes in interest rates do not impact our cash
outflows associated with fixed-rate interest payments or settlement of debt principal, unless a debt instrument is repurchased prior to
maturity.
At December 31, 2020, we had WTI put options with an average monthly floor price of approximately $45 per barrel for 75,000
bopd for 2021. As of December 31, 2020, an assumed 10% increase in the forward WTI crude oil prices used in determining the fair
value of our WTI put options would reduce the fair value of these derivative instruments by approximately $20 million, while an
assumed 10% decrease in the same crude oil prices would increase the fair value of these derivative instruments by approximately $30
million. In the first quarter of 2021, we increased the average monthly floor price of 75,000 bopd of WTI put option contracts from
approximately $45 per barrel to $50 per barrel for the remainder of 2021. We also purchased additional WTI put options with an
average monthly floor price of $50 per barrel for 45,000 bopd and Brent put options with an average monthly floor price of $55 per
barrel for 30,000 bopd. As a result, we now have total purchased WTI put options of 120,000 bopd with an average monthly floor
price of $50 per barrel and total purchased Brent put options of 30,000 bopd with an average monthly floor price of $55 per barrel for
the remainder of 2021.
We have outstanding Brent crude oil swap contracts associated with the 4.2 million barrels stored on two VLCCs at year-end. As
of December 31, 2020, an assumed 10% increase in the forward Brent crude oil prices used in determining the fair value of our Brent
swaps would reduce the fair value of these derivative instruments by approximately $20 million, while an assumed 10% decrease in
the same crude oil prices would increase the fair value of these derivative instruments by approximately $20 million.
See Note 20, Financial Risk Management Activities in the Notes to Consolidated Financial Statements for further details.
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Item 8. Financial Statements and Supplementary Data
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
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Management’s Report on Internal Control over Financial Reporting.......................................................................
Reports of Independent Registered Public Accounting Firm....................................................................................
Consolidated Balance Sheet at December 31, 2020, and 2019..................................................................................
Statement of Consolidated Income for each of the Three Years in the Period Ended December 31, 2020..............
Statement of Consolidated Comprehensive Income for each of the Three Years in the Period Ended
December 31, 2020....................................................................................................................................................
Statement of Consolidated Cash Flows for each of the Three Years in the Period Ended December 31, 2020.......
Statement of Consolidated Equity for each of the Three Years in the Period Ended December 31, 2020................
Notes to Consolidated Financial Statements
Note 1 - Nature of Operations, Basis of Presentation and Summary of Accounting Policies............................
Note 2 - Inventories............................................................................................................................................
Note 3 - Property, Plant and Equipment.............................................................................................................
Note 4 - Hess Midstream LP..............................................................................................................................
Note 5 - Accrued Liabilities...............................................................................................................................
Note 6 - Leases...................................................................................................................................................
Note 7 - Debt......................................................................................................................................................
Note 8 - Asset Retirement Obligations...............................................................................................................
Note 9 - Retirement Plans...................................................................................................................................
Note 10 - Revenue..............................................................................................................................................
Note 11 - Dispositions........................................................................................................................................
Note 12 - Impairment..........................................................................................................................................
Note 13 - Exit and Disposal Costs......................................................................................................................
Note 14 - Share-based Compensation.................................................................................................................
Note 15 - Income Taxes......................................................................................................................................
Note 16 - Outstanding and Weighted Average Common Shares.......................................................................
Note 17 - Supplementary Cash Flow Information..............................................................................................
Note 18 - Guarantees, Contingencies and Commitments...................................................................................
Note 19 - Segment Information..........................................................................................................................
Note 20 - Financial Risk Management Activities...............................................................................................
Supplementary Oil and Gas Data...............................................................................................................................
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Schedules have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial
statements or the notes thereto.
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Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is
defined in Exchange Act Rules 13a‑15(f). Under the supervision and with the participation of our management, including our
principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over
financial reporting, as required by Section 404 of the Sarbanes‑Oxley Act, based on the framework in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our
evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2020.
The Corporation’s independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the
Corporation’s internal control over financial reporting as of December 31, 2020, as stated in their report, which is included herein.
By
John P. Rielly
Executive Vice President and
Chief Financial Officer
By
John B. Hess
Chief Executive Officer
March 1, 2021
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
Opinion on Internal Control over Financial Reporting
We have audited Hess Corporation and consolidated subsidiaries’ (the “Corporation”) internal control over financial reporting as
of December 31, 2020, based on criteria established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Hess Corporation and
consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31,
2020, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of the Corporation as of December 31, 2020 and 2019, the related statements of
consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31,
2020, and the related notes and our report dated March 1, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
The Corporation’s management is responsible 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 an opinion on the Corporation’s internal control over
financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and
performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
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 (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
assets of the company; (2) 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 (3) 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.
New York, New York
March 1, 2021
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Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
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The Board of Directors and Stockholders
Hess Corporation
The Board of Directors and Stockholders
Hess Corporation
Opinion on the Financial Statements
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Hess Corporation and consolidated subsidiaries (the
“Corporation”) as of December 31, 2020 and 2019, the related statements of consolidated income, comprehensive income, cash flows
We have audited the accompanying consolidated balance sheets of Hess Corporation and consolidated subsidiaries (the
and equity for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the
“Corporation”) as of December 31, 2020 and 2019, the related statements of consolidated income, comprehensive income, cash flows
In our opinion, the financial statements present fairly, in all material respects, the consolidated financial
“financial statements”).
and equity for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the
position of the Corporation at December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for each
“financial statements”).
In our opinion, the financial statements present fairly, in all material respects, the consolidated financial
of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
position of the Corporation at December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for each
of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2020, based on criteria established in
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
(PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2020, based on criteria established in
framework), and our report dated March 1, 2021 expressed an unqualified opinion thereon.
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
framework), and our report dated March 1, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
Basis for Opinion
These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on
the Corporation’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on
required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules
the Corporation’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
and regulations of the Securities and Exchange Commission (SEC) and the PCAOB.
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 (SEC) and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or
to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
statements. We believe that our audits provide a reasonable basis for our opinion.
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that
were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that
material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication
were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are
of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by
material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication
communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or
of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by
disclosures to which they relate.
communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or
disclosures to which they relate.
Description of the Matter
Description of the Matter
Depreciation, depletion and amortization of proved oil and natural gas properties
The net book value of the Corporation’s exploration and production assets was $10,993
Depreciation, depletion and amortization of proved oil and natural gas properties
million at December 31, 2020, and depreciation, depletion and amortization (DD&A)
The net book value of the Corporation’s exploration and production assets was $10,993
expense was $1,915 million for the year then ended. As described in Note 1 to the
million at December 31, 2020, and depreciation, depletion and amortization (DD&A)
financial statements, the Corporation follows the successful efforts method of accounting
expense was $1,915 million for the year then ended. As described in Note 1 to the
for its oil and gas exploration and production activities. Under the successful efforts
financial statements, the Corporation follows the successful efforts method of accounting for
method of accounting, DD&A expense is recorded using the units-of-production method,
its oil and gas exploration and production activities. Under the successful efforts method
based on proved oil and gas reserves, as estimated by petroleum engineering specialists,
of accounting, DD&A expense is recorded using the units-of-production method, based on
for property acquisition costs and proved developed oil and gas reserves, also estimated
proved oil and gas reserves, as estimated by petroleum engineering specialists, for
by petroleum engineering specialists, for oil and gas production facilities and wells.
property acquisition costs and proved developed oil and gas reserves, also estimated
Proved oil and gas reserves are based on geological and engineering evaluations of
by petroleum engineering specialists, for oil and gas production facilities and wells.
Proved oil and gas reserves are based on geological and engineering evaluations of
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awallerstein (sa1)
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How We Addressed the
Matter in Our Audit
How We Addressed the
Matter in Our Audit
Description of the
Matter
Description of the
Matter
judgment
judgment
inputs.
estimated in-place hydrocarbon volumes using financial and non-financial
is required by the Corporations’ internal engineering staff in
Significant
estimated in-place hydrocarbon volumes using financial and non-financial
inputs.
evaluating the geological and engineering data used to estimate reserves. Estimating
is required by the Corporations’ internal engineering staff in
Significant
proved reserves also requires the selection of inputs, including oil and natural gas price
evaluating the geological and engineering data used to estimate reserves. Estimating
assumptions, future operating and capital costs assumptions and tax rates by jurisdiction,
proved reserves also requires the selection of inputs, including oil and natural gas price
among others. Management used independent petroleum engineering specialists to audit
assumptions, future operating and capital costs assumptions and tax rates by jurisdiction,
approximately 92% of the Corporation’s proved reserves at December 31, 2020 as
among others. Management used independent petroleum engineering specialists to audit
prepared by the Corporation’s internal engineering staff.
approximately 92% of the Corporation’s proved reserves at December 31, 2020 as
prepared by the Corporation’s internal engineering staff.
Auditing the Corporation’s DD&A expense calculation is complex because of our need to
assess the reasonableness of management’s determination of the inputs described above
Auditing the Corporation’s DD&A expense calculation is complex because of our need to
used in estimating proved oil and gas reserves and to use the work of the internal
assess the reasonableness of management’s determination of the inputs described above
engineering staff and independent petroleum engineering specialists.
used in estimating proved oil and gas reserves and to use the work of the internal
engineering staff and independent petroleum engineering specialists.
We obtained an understanding, evaluated the design and tested the operating effectiveness
of internal controls that address the risks of material misstatement relating to the DD&A
We obtained an understanding, evaluated the design and tested the operating effectiveness
expense calculation. This included controls over the completeness and accuracy of the
of internal controls that address the risks of material misstatement relating to the DD&A
financial data used in estimating proved oil and gas reserves.
expense calculation. This included controls over the completeness and accuracy of the
financial data used in estimating proved oil and gas reserves.
Our testing of the Corporation’s DD&A expense calculation included, among other
procedures, evaluating the professional qualifications and objectivity of the Corporation’s
Our testing of the Corporation’s DD&A expense calculation included, among other
internal petroleum engineering specialist responsible for overseeing the preparation of the
procedures, evaluating the professional qualifications and objectivity of the Corporation’s
Corporation’s reserve estimates and of the independent petroleum engineering specialist
internal petroleum engineering specialist responsible for overseeing the preparation of the
used to audit the estimates. In addition, we tested the completeness and accuracy of the
Corporation’s reserve estimates and of the independent petroleum engineering specialist
financial data used in the estimation of proved oil and gas reserves by agreeing significant
used to audit the estimates. In addition, we tested the completeness and accuracy of the
inputs to source documentation, where available, on a sample basis and assessing the
financial data used in the estimation of proved oil and gas reserves by agreeing significant
inputs for reasonableness based on review of corroborative evidence and consideration of
inputs to source documentation, where available, on a sample basis and assessing the
any contrary evidence. For proved undeveloped reserves, we evaluated management’s
inputs for reasonableness based on review of corroborative evidence and consideration of
development plans for compliance with the SEC rule that undrilled locations are
any contrary evidence. For proved undeveloped reserves, we evaluated management’s
scheduled to be drilled within five years, unless specific circumstances justify a longer
development plans for compliance with the SEC rule that undrilled locations are
time, by assessing consistency of the development projection with the Corporation’s drill
scheduled to be drilled within five years, unless specific circumstances justify a longer
plan and the availability of capital relative to the drill plan. Additionally, we performed
time, by assessing consistency of the development projection with the Corporation’s drill
analytic and lookback procedures on inputs into the oil and gas reserve estimate as well as
plan and the availability of capital relative to the drill plan. Additionally, we performed
on the outputs. Finally, we tested the mathematical accuracy of the DD&A expense
analytic and lookback procedures on inputs into the oil and gas reserve estimate as well as
calculations, including comparing the proved oil and gas reserves to the Corporation’s
on the outputs. Finally, we tested the mathematical accuracy of the DD&A expense
reserve report.
calculations, including comparing the proved oil and gas reserves to the Corporation’s
reserve report.
Impairment of oil and natural gas properties
Impairment of oil and natural gas properties
The net book value of the Corporation’s exploration and production assets was $10,993
million at December 31, 2020, and impairment expense was $2,105 million for the year
The net book value of the Corporation’s exploration and production assets was $10,993
then ended. As described in Notes 1 and 12 to the financial statements, the Corporation
million at December 31, 2020, and impairment expense was $2,105 million for the year
reviews long‑lived assets, including oil and gas fields, for impairment whenever events or
then ended. As described in Notes 1 and 12 to the financial statements, the Corporation
changes in circumstances indicate that the carrying amounts may not be recovered. If the
reviews long‑lived assets, including oil and gas fields, for impairment whenever events or
carrying amounts of the long-lived assets are not expected to be recovered by estimated
changes in circumstances indicate that the carrying amounts may not be recovered. If the
undiscounted future net cash flows, the assets are impaired, and an impairment loss is
carrying amounts of the long-lived assets are not expected to be recovered by estimated
recorded. The impairments recorded in 2020 were based on estimates of fair value
undiscounted future net cash flows, the assets are impaired, and an impairment loss is
determined by discounting internally developed future net cash flows, a Level 3 fair value
recorded. The impairments recorded in 2020 were based on estimates of fair value
measurement. Significant inputs used in determining the discounted future net cash flows
determined by discounting internally developed future net cash flows, a Level 3 fair value
include future prices, which are determined with reference to recent historical prices and
measurement. Significant inputs used in determining the discounted future net cash flows
published forward prices, projected production volumes using risk adjusted oil and gas
include future prices, which are determined with reference to recent historical prices and
reserves and discount rates. The projected production volumes are based on geological
published forward prices, projected production volumes using risk adjusted oil and gas
reserves and discount rates. The projected production volumes are based on geological
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How We Addressed the
Matter in Our Audit
62540 10K
55
and engineering evaluations of estimated in-place hydrocarbon volumes using financial
and non-financial inputs including projected capital expenditures. Significant judgment is
required by the Corporations’ internal petroleum engineering staff in evaluating the
geological and engineering data used to estimate reserves.
Estimating projected
production volumes also requires the selection of inputs, including oil and natural gas
price assumptions, future operating and capital costs assumptions and tax rates by
jurisdiction, among others.
Auditing the Corporation’s impairment calculation involved a high degree of subjectivity
as the determination of fair value was based on assumptions as described above about
future market and economic conditions. In addition, the cash flows include projected
production volumes based on risk adjusted reserve estimates developed by the
Corporation’s internal engineering staff.
We obtained an understanding, evaluated the design and tested the operating effectiveness
of internal controls that address the risks of material misstatement relating to the
impairment expense calculation. This included controls over the completeness and
accuracy of the significant inputs used to estimate fair value including pricing assumptions
and projected production volumes among others.
Our testing of the Corporation’s impairment calculation included, among other procedures,
evaluating the significant assumptions used and testing the completeness and accuracy of
the underlying data. We involved our valuation specialists to assist in evaluating the
appropriateness of the methodology used in the cash flow model, as well as certain of the
inputs, including reserve risk adjustment factors and projected pricing among other market
inputs. We additionally evaluated the professional qualifications and objectivity of the
Corporation’s internal petroleum engineering specialist responsible for overseeing the
preparation of the Corporation’s reserve estimates and of the independent petroleum
engineering specialist. We performed testing procedures
including testing the
completeness and accuracy of the financial data used in the estimation of oil and gas
reserves by agreeing significant inputs to source documentation, where available, on a
sample basis and assessing the inputs for reasonableness based on review of corroborative
evidence and consideration of any contrary evidence. We also performed sensitivity
analyses and a retrospective comparison of forecasted cash flows to actual historical data.
Finally, we tested the mathematical accuracy of the impairment calculations.
We have served as the Corporation’s auditor since 1971
New York, New York
March 1, 2021
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
Assets
Current Assets:
Cash and cash equivalents.......................................................................................................................................... $
Accounts receivable:
From contracts with customers............................................................................................................................
Joint venture and other.........................................................................................................................................
Inventories..................................................................................................................................................................
Other current assets....................................................................................................................................................
Total current assets..........................................................................................................................................
Property, plant and equipment:
Total — at cost...........................................................................................................................................................
Less: Reserves for depreciation, depletion, amortization and lease impairment.......................................................
Property, plant and equipment — net..............................................................................................................
Operating lease right-of-use assets — net....................................................................................................................
Finance lease right-of-use assets — net.......................................................................................................................
Goodwill.......................................................................................................................................................................
Deferred income taxes..................................................................................................................................................
Other assets..................................................................................................................................................................
Total Assets............................................................................................................................................ $
Liabilities
Current Liabilities:
Accounts payable....................................................................................................................................................... $
Accrued liabilities......................................................................................................................................................
Taxes payable.............................................................................................................................................................
Current maturities of long-term debt..........................................................................................................................
Current portion of operating and finance lease obligations.......................................................................................
Total current liabilities....................................................................................................................................
Long-term debt.............................................................................................................................................................
Long-term operating lease obligations.........................................................................................................................
Long-term finance lease obligations............................................................................................................................
Deferred income taxes..................................................................................................................................................
Asset retirement obligations.........................................................................................................................................
Other liabilities and deferred credits............................................................................................................................
Total Liabilities..................................................................................................................................................
Equity
Hess Corporation stockholders’ equity:
Common stock, par value $1.00; Authorized — 600,000,000 shares:
62540 10K
56
December 31,
2020
2019
(In millions,
except share amounts)
1,739
$
1,545
710
150
378
104
3,081
30,519
16,404
14,115
426
168
360
59
612
18,821
200
1,251
81
10
81
1,623
8,286
478
220
342
894
643
12,486
$
$
940
230
261
180
3,156
35,820
19,006
16,814
447
299
360
80
626
21,782
411
1,803
97
—
199
2,510
7,142
353
238
415
897
521
12,076
Issued — 306,980,092 shares (2019: 304,955,472)...........................................................................................
Capital in excess of par value..................................................................................................................................
Retained earnings....................................................................................................................................................
Accumulated other comprehensive income (loss)..................................................................................................
Total Hess Corporation stockholders’ equity.....................................................................................................
Noncontrolling interests...............................................................................................................................................
Total equity........................................................................................................................................................
Total Liabilities and Equity.................................................................................................................. $
307
5,684
130
(755)
5,366
969
6,335
18,821
$
305
5,591
3,535
(699)
8,732
974
9,706
21,782
The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production
activities.
See accompanying Notes to Consolidated Financial Statements.
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED INCOME
Year Ended December 31,
2020
2019
2018
(In millions, except per share amounts)
Revenues and Non-Operating Income
Sales and other operating revenues................................................................................................. $
Gains on asset sales, net..................................................................................................................
Other, net.........................................................................................................................................
Total revenues and non-operating income................................................................................
Costs and Expenses
Marketing, including purchased oil and gas....................................................................................
Operating costs and expenses..........................................................................................................
Production and severance taxes.......................................................................................................
Exploration expenses, including dry holes and lease impairment..................................................
General and administrative expenses..............................................................................................
Interest expense...............................................................................................................................
Loss on debt extinguishment...........................................................................................................
Depreciation, depletion and amortization.......................................................................................
Impairment......................................................................................................................................
Total costs and expenses...........................................................................................................
Income (Loss) Before Income Taxes.................................................................................................
Provision (benefit) for income taxes...............................................................................................
Net Income (Loss)...............................................................................................................................
Less: Net income (loss) attributable to noncontrolling interests.....................................................
Net Income (Loss) Attributable to Hess Corporation.....................................................................
Less: Preferred stock dividends.......................................................................................................
Net Income (Loss) Attributable to Hess Corporation Common Stockholders............................. $
Net Income (Loss) Attributable to Hess Corporation Per Common Share
Basic.................................................................................................................................................. $
Diluted.............................................................................................................................................. $
Weighted Average Number of Common Shares Outstanding (Diluted).......................................
Common Stock Dividends Per Share............................................................................................... $
$
4,667
87
50
4,804
936
1,218
124
351
357
468
—
2,074
2,126
7,654
(2,850)
(11)
(2,839)
254
(3,093)
—
(3,093) $
(10.15) $
(10.15) $
304.8
1.00
$
See accompanying Notes to Consolidated Financial Statements.
$
6,495
22
(7)
6,510
1,736
1,237
184
233
397
380
—
2,122
—
6,289
221
461
(240)
168
(408)
4
(412) $
(1.37) $
(1.37) $
301.2
1.00
$
6,323
32
111
6,466
1,771
1,134
171
362
473
399
53
1,883
—
6,246
220
335
(115)
167
(282)
46
(328)
(1.10)
(1.10)
298.2
1.00
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
Net Income (Loss)............................................................................................................................... $
Other Comprehensive Income (Loss):
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income.......................................................................
Income taxes on effect of hedge (gains) losses reclassified to income.............................................
Net effect of hedge (gains) losses reclassified to income...............................................................
Change in fair value of cash flow hedges.........................................................................................
Income taxes on change in fair value of cash flow hedges...............................................................
Net change in fair value of cash flow hedges..................................................................................
Change in derivatives designated as cash flow hedges, after taxes................................................
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses.......................................................................
Income taxes on actuarial changes in plan liabilities........................................................................
(Increase) reduction in unrecognized actuarial losses, net..............................................................
Amortization of net actuarial losses..................................................................................................
Income taxes on amortization of net actuarial losses........................................................................
Net effect of amortization of net actuarial losses............................................................................
Change in pension and other postretirement plans, after taxes....................................................
Other Comprehensive Income (Loss)...............................................................................................
Comprehensive Income (Loss)..........................................................................................................
Less: Comprehensive income (loss) attributable to noncontrolling interests...................................
Comprehensive Income (Loss) Attributable to Hess Corporation................................................ $
Year Ended December 31,
2020
2019
2018
(In millions)
(2,839) $
(240) $
(115)
(547)
—
(547)
649
—
649
102
(205)
—
(205)
47
—
47
(158)
(56)
(2,895)
254
(3,149) $
(1)
—
(1)
(462)
86
(376)
(377)
(160)
—
(160)
144
—
144
(16)
(393)
(633)
168
(801) $
173
—
173
330
(86)
244
417
29
(6)
23
41
—
41
64
481
366
167
199
See accompanying Notes to Consolidated Financial Statements.
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
2020
2019
2018
(In millions)
(2,839) $
(240) $
(115)
Cash Flows From Operating Activities
Net income (loss).............................................................................................................................. $
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
(Gains) on asset sales, net............................................................................................................
Depreciation, depletion and amortization....................................................................................
Impairment...................................................................................................................................
Exploratory dry hole costs............................................................................................................
Exploration lease and other impairment.......................................................................................
Pension settlement loss.................................................................................................................
Stock compensation expense........................................................................................................
Noncash (gains) losses on commodity derivatives, net................................................................
Provision (benefit) for deferred income taxes and other tax accruals..........................................
Loss on debt extinguishment........................................................................................................
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable..............................................................................
(Increase) decrease in inventories...........................................................................................
Increase (decrease) in accounts payable and accrued liabilities..............................................
Increase (decrease) in taxes payable.......................................................................................
Changes in other operating assets and liabilities.....................................................................
Net cash provided by (used in) operating activities.....................................................
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P...........................................................................
Additions to property, plant and equipment - Midstream.................................................................
Payments for Midstream equity investments....................................................................................
Proceeds from asset sales, net of cash sold.......................................................................................
Other, net...........................................................................................................................................
Net cash provided by (used in) investing activities......................................................
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less.........................................
Debt with maturities of greater than 90 days:
Borrowings...................................................................................................................................
Repayments..................................................................................................................................
Payments on finance lease obligations..............................................................................................
Common stock acquired and retired..................................................................................................
Cash dividends paid..........................................................................................................................
Noncontrolling interests, net.............................................................................................................
Other, net...........................................................................................................................................
Net cash provided by (used in) financing activities.....................................................
(87)
2,074
2,126
192
51
—
79
260
(53)
—
267
(117)
(533)
(16)
(71)
1,333
(1,896)
(301)
—
493
(3)
(1,707)
152
1,000
—
(7)
—
(309)
(261)
(7)
568
(22)
2,122
—
49
17
93
85
116
17
—
(383)
(16)
4
16
(216)
1,642
(2,433)
(396)
(33)
22
(3)
(2,843)
32
760
(8)
(49)
(25)
(316)
(353)
11
52
Net Increase (Decrease) in Cash and Cash Equivalents.................................................................
Cash and Cash Equivalents at Beginning of Year..........................................................................
Cash and Cash Equivalents at End of Year..................................................................................... $
194
1,545
1,739
$
(1,149)
2,694
1,545
$
See accompanying Notes to Consolidated Financial Statements.
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(32)
1,883
—
165
37
4
72
182
(120)
53
(138)
(12)
88
(2)
(126)
1,939
(1,854)
(243)
(67)
607
(9)
(1,566)
—
—
(633)
—
(1,365)
(345)
(211)
28
(2,526)
(2,153)
4,847
2,694
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED EQUITY
Mandatory
Convertible
Preferred
Stock
Common
Stock
Capital
in Excess
of Par
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
(In millions)
Total Hess
Stockholders'
Equity
Noncontrolling
Interests
Total
Equity
Balance at December 31, 2017.............. $
1
$
315
$
5,824
$
5,597
$
(686) $
11,051
$
1,303
$ 12,354
Cumulative effect of adoption of new
accounting standards..............................
Net income (loss)...................................
Other comprehensive income (loss)......
Share-based compensation.....................
Dividends on preferred stock.................
Dividends on common stock.................
Common stock acquired and retired......
Noncontrolling interests, net..................
Balance at December 31, 2018.............. $
Net income (loss)...................................
Other comprehensive income (loss)......
Preferred stock conversion....................
Share-based compensation.....................
Dividends on preferred stock.................
Dividends on common stock.................
Conversion of Midstream structure.......
Sale of water business to Hess
Infrastructure Partners...........................
Noncontrolling interests, net..................
Balance at December 31, 2019.............. $
Net income (loss)...................................
Other comprehensive income (loss)......
Share-based compensation.....................
Dividends on common stock.................
Noncontrolling interests, net..................
—
—
—
—
—
—
—
—
1
—
—
(1)
—
—
—
—
—
—
—
—
—
1
—
—
(25)
—
—
—
—
103
—
—
(541)
—
101
(282)
—
—
(46)
(299)
(814)
—
(101)
—
481
—
—
—
—
—
—
(282)
481
104
(46)
(299)
(1,380)
—
—
167
—
—
—
—
—
(211)
—
(115)
481
104
(46)
(299)
(1,380)
(211)
$
291
$
5,386
$
4,257
$
(306) $
9,629
$
1,259
$ 10,888
—
—
12
2
—
—
—
—
—
—
—
(11)
123
—
—
15
78
—
(408)
—
—
—
(4)
(310)
—
—
—
—
(393)
—
—
—
—
—
—
—
(408)
(393)
—
125
(4)
(310)
15
78
—
— $
305
$
5,591
$
3,535
$
(699) $
8,732
$
—
—
—
—
—
—
—
2
—
—
—
—
93
—
—
(3,093)
—
(5)
(307)
—
—
(56)
—
—
—
(3,093)
(56)
90
(307)
—
168
—
—
—
—
—
(22)
(78)
(353)
974
254
—
—
—
(259)
(240)
(393)
—
125
(4)
(310)
(7)
—
(353)
$
9,706
(2,839)
(56)
90
(307)
(259)
Balance at December 31, 2020.............. $
— $
307
$
5,684
$
130
$
(755) $
5,366
$
969
$
6,335
See accompanying Notes to Consolidated Financial Statements.
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1. Nature of Operations, Basis of Presentation and Summary of Accounting Policies
Unless the context indicates otherwise, references to “Hess”, “the Corporation”, “Registrant”, “we”, “us” and “our” refer to
the consolidated business operations of Hess Corporation and its affiliates.
Nature of Business: Hess Corporation, incorporated in the State of Delaware in 1920, is a global E&P company engaged in
exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with
production operations located primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA),
Malaysia, and Denmark. We conduct exploration activities primarily offshore Guyana, the U.S. Gulf of Mexico, and offshore
Suriname and Canada.
Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess
Midstream LP at December 31, 2020 (see Note 4, Hess Midstream LP) provides fee-based services, including gathering, compressing
and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and
terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.
Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess
Corporation and entities in which we own more than a 50% voting interest. Commencing December 16, 2019, we consolidate Hess
Midstream LP, a variable interest entity that acquired Hess Infrastructure Partners LP (HIP), based on our conclusion that we have the
power through Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP to direct those activities that most
significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive
benefits that could potentially be significant to Hess Midstream LP. Prior to December 16, 2019, we consolidated HIP, also a variable
interest entity based on the conclusion that we had the power to direct the activities that most significantly impacted the economic
performance of HIP, and were obligated to absorb losses or had the right to receive benefits that could potentially be significant to
HIP. Our undivided interests in unincorporated oil and gas E&P ventures are proportionately consolidated. Investments in affiliated
companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are
accounted for using the equity method.
Estimates and Assumptions:
In preparing financial statements in conformity with GAAP, management makes estimates and
assumptions that affect the reported amounts of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in
the Statement of Consolidated Income. Actual results could differ from those estimates. Estimates made by management include oil
and gas reserves, asset and other valuations, depreciable lives, pension liabilities, legal and environmental obligations, asset retirement
obligations and income taxes.
Revenue Recognition:
Exploration and Production
The E&P segment recognizes revenue from the sale of crude oil, NGL, and natural gas as performance obligations under contracts
with customers are satisfied. Our responsibilities to deliver each unit of quantity of crude oil, NGL, and natural gas under these
contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control
of each unit of quantity transfers to the customer. Generally, the control of each unit of quantity transfers to the customer upon the
transfer of legal title at the point of physical delivery. Pricing is variable and is determined with reference to a particular market or
pricing index, plus or minus adjustments reflecting quality or location differentials.
For long-term international natural gas contracts with ship-or-pay provisions, our obligation to stand-ready to provide a minimum
volume over each commitment period represents separate, distinct performance obligations. Penalties owed against future deliveries
of natural gas due to delivery of volumes below minimum delivery commitments are recognized as reductions to revenue in the
commitment period when the shortfall occurs. Long-term international natural gas contracts may also contain take-or-pay provisions
whereby the customer is required to pay for volumes not taken that are below minimum volume commitments but the customer has
certain make-up rights to receive shortfall volumes in subsequent periods. Shortfall payments received from customers when volumes
purchased are below the minimum volume commitment are deferred upon receipt as a contract liability. Revenue is recognized at the
earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their
make-up rights.
Certain crude oil, NGL, and natural gas volumes are purchased by Hess from third parties, including working interest partners and
royalty owners in certain Hess-operated properties, before they are sold to customers. Where control over the crude oil, NGL, or
natural gas transfers to Hess before the volumes are transferred to the customer, revenue and the associated cost of purchased volumes
are presented on a gross basis in the Statement of Consolidated Income within Sales and other operating revenues and Marketing,
including purchased oil and gas, respectively. Where control of crude oil, NGL, or natural gas is not transferred to Hess, revenue is
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presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated
Income.
Contract Duration and Pricing:
Contracts with customers for the sale of U.S. crude oil, NGL, and natural gas primarily include those contracts that
involve the short-term sale of volumes during a specified period, and those contracts that automatically renew on a periodic
basis until either party cancels. We have certain long-term contracts with customers for the sale of U.S. natural gas and NGL
that have remaining durations ranging from one to twelve years.
Contracts with customers for the sale of international crude oil involve the short-term sale of volumes during a specified
period. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting
quality or location differentials, shortly after control of the volumes transfers to the customer.
International contracts with
customers for the sale of natural gas are in the form of natural gas sales agreements with government entities that have
durations that are aligned with the durations of production sharing contracts or other contractual arrangements with host
governments. Pricing is determined using contractual formulas that are based on the price of alternative fuels as obtained
from price indices and other factors.
Contract Balances:
Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in
situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights. At
December 31, 2020 and 2019, there were no contract assets or contract liabilities.
Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil,
NGL, or natural gas.
Transaction Price Allocated to Remaining Performance Obligations:
The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is
variable. Further, many of our contracts with customers have durations of less than twelve months. Accordingly, we have
elected under the provisions of Accounting Standards Codification (ASC) 606 the exemption from disclosure of revenue
recognizable in future periods as these performance obligations are satisfied.
Sales-based Taxes:
We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with
customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers
and remitted to taxing authorities.
Midstream
Our Midstream segment provides gathering, compression, processing,
fractionation, storage,
terminaling,
loading and
transportation, and water handling services.
The Midstream segment has multiple long-term, fee-based commercial agreements with certain subsidiaries of Hess, each
generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of Hess
Midstream. These contracts have minimum volumes the customer is obligated to provide each calendar quarter. The minimum
volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and
projected third-party volumes that will be purchased in the Bakken. As the minimum volume commitments are subject to fluctuation,
and as these contracts contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price at
contract inception is variable. The midstream segment also has long-term, fee based commercial agreements for water handling
services with a subsidiary of Hess with an initial 14 year term that can be extended for an additional ten-year term at the unilateral
right of Hess Midstream. Water handling services are provided for an agreed-upon fee per barrel or the reimbursement of third-party
fees.
The Midstream segment’s responsibilities to provide each of the above services for each year under each of the commercial
agreements are considered separate, distinct performance obligations. Revenue is recognized for each performance obligation under
these commercial agreements over-time as services are rendered using the output method, measured using the amount of volumes
serviced during the period. The Midstream segment has elected the practical expedient under the provisions of ASC 606, Revenue
from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. If the commercial agreements have ship-
or-pay provisions,
the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly
commitment period represent separate, distinct performance obligations. Shortfall payments received under ship-or-pay provisions are
recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar
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quarter end of the quarterly commitment period. All revenues, receivables, and contract balances arising from the commercial
agreements between the Midstream segment and the Hess subsidiaries that are the counterparty to the commercial agreements are
eliminated upon consolidation.
On December 30, 2020, Hess Midstream exercised its renewal options to extend the terms of certain gas gathering, crude oil
gathering, gas processing and fractionation, storage, and terminal and export commercial agreements for the secondary term through
December 31, 2033. There were no changes to any provisions of the existing commercial agreements as a result of the exercise of the
renewal options.
Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring
unproved and proved oil and gas leasehold acreage,
related costs are
capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and
equipping productive wells, including development dry holes, and related production facilities are capitalized.
including lease bonuses, brokers’
fees and other
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves
have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity
of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the
economic and operational viability of the project.
If either of those criteria is not met, or if there is substantial doubt about the
economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in
assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations
for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and
other factors.
Depreciation, Depletion and Amortization: We record depletion expense for acquisition costs of proved properties using the
units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production facilities
and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of
undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is
determined on the straight-line method based on estimated useful lives.
Capitalized Interest:
Interest from external borrowings is capitalized on material projects using the weighted average cost of
outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first
production from the field. Capitalized interest is depreciated in the same manner as the depreciation of the underlying assets.
Impairment of Long‑lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or
changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are
not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is
recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting
anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair
value measurements.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices,
which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes
and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to
be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are
consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset
impairment will generally differ from those used in the standardized measure of discounted future net cash flows reported in
Supplementary Oil and Gas Data, since the standardized measure requires the use of historical twelve-month average prices. As a
result of the significant decline in crude oil prices in the first quarter of 2020, we tested our oil and gas properties for impairment at
March 31, 2020. See Note 12, Impairment.
Impairment of Goodwill: Goodwill is tested for impairment annually on October 1st or when events or circumstances indicate
that the carrying amount of the goodwill may not be recoverable. To determine whether goodwill is impaired, the fair value of a
reporting unit is compared with its carrying amount, including goodwill.
If the fair value of the reporting unit exceeds its carrying
value, goodwill is not impaired.
If the carrying value of the reporting unit exceeds its fair value, an impairment charge would be
recorded for the excess of the carrying value over fair value, limited by the amount of goodwill allocated to the reporting unit. At
December 31, 2020, goodwill of $360 million relates to the Midstream operating segment.
Cash and Cash Equivalents: Cash and cash equivalents primarily comprises cash on hand and on deposit, as well as highly
liquid investments that are readily convertible into cash and have maturities of three months or less when acquired.
Inventories: Produced and unsold crude oil and NGL are valued at the lower of cost or net realizable value. Cost is determined
using the average cost of production plus any transport cost incurred in bringing the volumes to their present location. Materials and
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supplies are valued at cost. Obsolete or surplus materials identified during periodic reviews are valued at the lower of cost or
estimated net realizable value.
Leases: We determine if an arrangement is a lease at inception by evaluating whether the contract conveys the right to control an
identified asset during the period of use. Right-of-use (ROU) assets represent our right to use an identified asset for the lease term and
lease obligations represent our obligation to make payments as set forth in the lease arrangement. ROU assets and lease liabilities are
recognized in the Consolidated Balance Sheet as operating leases or finance leases at the commencement date based on the present
value of the minimum lease payments over the lease term. Where the implicit discount rate in a lease is not readily determinable, we
use our incremental borrowing rate based on information available at the commencement date for determining the present value of the
minimum lease payments. The lease term used in measurement of our lease obligations includes options to extend or terminate the
lease when, in our judgment, it is reasonably certain that we will exercise that option. Variable lease payments that depend on an
index or a rate are included in the measurement of lease obligations using the index or rate at the commencement date. Variable lease
payments that vary because of changes in facts or circumstances after the commencement date of the lease are not included in the
minimum lease payments used to measure lease obligations. We have agreements that include financial obligations for lease and
nonlease components. For purposes of measuring lease obligations, we have elected not to separate nonlease components from lease
components for the following classes of assets: drilling rigs, office space, offshore vessels, and aircraft. We apply a portfolio
approach to account for operating lease ROU assets and liabilities for certain vehicles, railcars, field equipment and office equipment
leases.
Finance lease cost is recognized as amortization of the ROU asset and interest expense on the lease liability. Operating lease cost
is generally recognized on a straight-line basis. Operating lease costs for drilling rigs used to drill development wells and successful
exploration wells are capitalized. Operating lease cost for other ROU assets used in oil and gas producing activities are either
capitalized or expensed on a straight-line basis based on the nature of operation for which the ROU asset is utilized.
Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842. We recognize
lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases include one or more options to
renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless
we are reasonably certain at the commencement date of the lease, to renew the lease.
Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or
credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits. Additionally, we have
deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular
assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting
standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to
reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all
available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of
positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods,
the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. In
evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax
credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved,
would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward
period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax
benefits. We assign cumulative historical losses significant weight in the evaluation of realizability relative to more subjective
evidence such as forecasts of future income.
In addition, we recognize the financial statement effect of a tax position only when
management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon
examination. We are no longer indefinitely reinvested with respect to the book in excess of tax basis in the investment in our foreign
subsidiaries. Because of U.S. tax reform we expect that the future reversal of such temporary differences will occur free of material
taxation. We classify interest and penalties associated with uncertain tax positions as income tax expense. We account for the U.S.
tax effect of global intangible low-taxed income earned by foreign subsidiaries in the period that such income is earned. We utilize
the aggregate approach for releasing disproportionate income tax effects from Accumulated other comprehensive income (loss).
Asset Retirement Obligations: We have material legal obligations to remove and dismantle long‑lived assets and to restore land
or the seabed at certain E&P locations. We initially recognize a liability for the fair value of legally required asset retirement
obligations in the period in which the retirement obligations are incurred and capitalize the associated asset retirement costs as part of
the carrying amount of the long‑lived assets.
In subsequent periods, the liability is accreted, and the asset is depreciated over the
useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future
abandonment expenditures. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values,
unless the field has ceased production, in which case changes are recognized in the Statement of Consolidated Income.
Retirement Plans: We recognize the funded status of defined benefit postretirement plans in the Consolidated Balance
Sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. We
recognize the net changes in the funded status of these plans in the year in which such changes occur. Actuarial gains and losses in
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excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service
period of active employees or the remaining average expected life if a plan’s participants are predominantly inactive.
Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures,
forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural
gas, as well as changes in interest and foreign currency exchange rates.
All derivative instruments are recorded at fair value in the Consolidated Balance Sheet. Our policy for recognizing the changes in
fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not
designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or
forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized
firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a
component of other comprehensive income (loss). Amounts included in Accumulated other comprehensive income (loss) for cash
flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of
derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged item is
recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including
the market and income approaches. Our fair value measurements also include non-performance risk and time value of money
considerations. Counterparty credit is considered for receivable balances, and our credit is considered for accrued liabilities. We also
record certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in
connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and
any impairment of long‑lived assets, equity method investments or goodwill. We determine fair value in accordance with the fair
value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of
the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates
determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived
indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs
are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same
market. Multiple inputs may be used to measure fair value; however, the level assigned to a fair value measurement is based on the
lowest significant input level within this fair value hierarchy.
Details on the methods and assumptions used to determine the fair values are as follows:
Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical
instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative
of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity.
Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices
from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative
instruments that are priced on an exchange-traded curve but have contractual terms that are not identical to exchange-traded contracts.
Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market
data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. Fair
values determined using discounted cash flows and other unobservable data are also classified as Level 3.
Netting of Financial Instruments: We generally enter into master netting arrangements to mitigate legal and counterparty credit
risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the
same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of
certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known
as the “safe harbor” provisions.
If a master netting arrangement provides for termination and netting upon the counterparty’s
bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right
of offset and our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of
derivative assets and liabilities on a net basis.
In the normal course of business, we rely on legal and credit risk mitigation clauses
providing for adequate credit assurance as well as close‑out netting, including two‑party netting and single counterparty multilateral
netting. As applied to us, “two‑party netting” is the right to net amounts owing under safe harbor transactions between a single
defaulting counterparty entity and a single Hess entity, and “single counterparty multilateral netting” is the right to net amounts owing
under safe harbor transactions among a single defaulting counterparty entity and multiple Hess entities. We are reasonably assured
that these netting rights would be upheld in a bankruptcy proceeding in the U.S. in which the defaulting counterparty is a debtor under
the U.S. Bankruptcy Code.
Share-based Compensation: We account for share-based compensation based on the fair value of the award on the date of
grant. The fair value of all share‑based compensation is recognized over the requisite service period for the entire award, whether the
award was granted with ratable or cliff vesting terms, net of actual forfeitures. We estimate fair value at the date of grant using a
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Black‑Scholes valuation model for employee stock options and a Monte Carlo simulation model for performance share units
(PSUs). Fair value of restricted stock is based on the market value of the underlying shares at the date of grant.
Foreign Currency Translation: The U.S. Dollar is the functional currency (primary currency in which business is conducted) for
our foreign operations. Adjustments resulting from remeasuring monetary assets and liabilities that are denominated in a currency
other than the functional currency are recorded in Other, net in the Statement of Consolidated Income.
Maintenance and Repairs: Maintenance and repairs are expensed as incurred. Capital improvements are recorded as additions
in Property, plant and equipment.
Environmental Expenditures: We accrue and expense the undiscounted environmental costs necessary to remediate existing
conditions related to past operations when the future costs are probable and reasonably estimable. At year‑end 2020, our reserve for
estimated remediation liabilities was approximately $65 million. Environmental expenditures that increase the life or efficiency of
property or reduce or prevent future adverse impacts to the environment are capitalized.
New Accounting Pronouncements:
In the first quarter of 2020, we adopted Accounting Standards Update (ASU) 2016-13,
Financial Instruments – Credit Losses. This ASU makes changes to the impairment model for trade receivables, net investments in
leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss" model
compared with the prior "incurred loss" model. We calculate expected credit losses for our receivables using the probability of default
and the expected loss given default. Historical data, current market conditions, and forecasts of future economic conditions are used to
determine the probability of default and the expected loss given default. The adoption of this ASU did not have a material impact to
our financial statements.
2. Inventories
Inventories at December 31 were as follows:
2020
2019
Crude oil and natural gas liquids..................................................................................................................................... $
Materials and supplies.....................................................................................................................................................
Total Inventories........................................................................................................................................................ $
$
(In millions)
226
152
378
$
92
169
261
In the first quarter of 2020, we recognized charges of $53 million ($52 million after income taxes) recorded in Marketing,
including purchased oil and gas to reflect crude oil inventories at net realizable value at March 31, 2020.
In 2020, we chartered three VLCCs to load and transport a total of 6.3 million barrels of Bakken crude oil for sale in Asian
markets. The first VLCC cargo of 2.1 million barrels was sold in September 2020. We have entered into agreements for the sale of
the remaining 4.2 million barrels of crude oil loaded on the second and third VLCCs in the first quarter of 2021. At December 31,
2020, crude oil inventories included $164 million associated with the cost of these volumes.
3. Property, Plant and Equipment
Property, plant and equipment at December 31 were as follows:
Exploration and Production
Unproved properties................................................................................................................................................ $
Proved properties.....................................................................................................................................................
Wells, equipment and related facilities...................................................................................................................
Midstream......................................................................................................................................................................
Corporate and Other....................................................................................................................................................
Total — at cost........................................................................................................................................................
Less: Reserves for depreciation, depletion, amortization and lease impairment....................................................
Property, Plant and Equipment — Net.................................................................................................................. $
2020
2019
(In millions)
164
2,930
23,224
26,318
4,163
38
30,519
16,404
14,115
$
$
168
3,304
28,404
31,876
3,904
40
35,820
19,006
16,814
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Capitalized Exploratory Well Costs: The following table discloses the amount of capitalized exploratory well costs pending
determination of proved reserves at December 31 and the changes therein during the respective years:
Balance at January 1.......................................................................................................................... $
Additions to capitalized exploratory well costs pending the determination of proved reserves.....
Reclassifications to wells, facilities and equipment based on the determination of proved
reserves............................................................................................................................................
Capitalized exploratory well costs charged to expense...................................................................
Balance at December 31..................................................................................................................... $
Number of Wells at December 31.....................................................................................................
2020
2019
2018
$
(In millions)
418
224
$
(58)
—
584
31
$
$
584
111
(111)
(125)
459
22
304
128
—
(14)
418
24
During the three years ended December 31, 2020, additions to capitalized exploratory well costs primarily related to drilling at the
Stabroek Block, offshore Guyana. Other drilling activity included the Esox prospect in the Gulf of Mexico during 2019 and the Bunga
prospect in the North Malay Basin, offshore Peninsular Malaysia during 2018.
Reclassifications to wells, facilities and equipment based on the determination of proved reserves in 2020 resulted from sanctions
of the Payara Field development on the Stabroek Block, offshore Guyana, and an additional phase of development at the North Malay
In 2019, reclassifications to wells, facilities and equipment resulted from sanction of the Liza
Basin, offshore Peninsular Malaysia.
Phase 2 development on the Stabroek Block and the Esox tieback well to the Tubular Bells Field in the Gulf of Mexico.
Capitalized exploratory well costs charged to expense in 2020 included $125 million, primarily related to the northern portion of
the Shenzi Field (Hess 28%) in the Gulf of Mexico due to reprioritization of our forward capital program in response to the significant
decline in crude oil prices.
In 2018, in Canada, offshore Nova Scotia (Hess 50% participating interest), the operator, BP Canada,
completed drilling of the Aspy exploration well, which did not encounter commercial quantities of hydrocarbons. As a result, we
expensed well costs totaling $120 million in 2018, of which $14 million was incurred in 2017. The preceding table excludes well
costs incurred and expensed during 2020 of $67 million (2019: $49 million; 2018: $151 million).
Exploratory well costs capitalized for greater than one year following completion of drilling were $342 million at December 31,
2020, separated by year of completion as follows (in millions):
2019...................................................................................................................................................................................................... $
2018......................................................................................................................................................................................................
2017......................................................................................................................................................................................................
2016......................................................................................................................................................................................................
2015......................................................................................................................................................................................................
$
173
105
27
—
37
342
Guyana: Approximately 85% of the capitalized well costs in excess of one year relate to successful exploration wells where
hydrocarbons were encountered on the Stabroek Block (Hess 30%), offshore Guyana. The operator plans further appraisal drilling
and is conducting pre-development planning for additional phases of development beyond the three previously sanctioned
development projects on the Block.
JDA: Approximately 10% of the capitalized well costs in excess of one year relates to the JDA (Hess 50%) in the Gulf of
Thailand, where hydrocarbons were encountered in three successful exploration wells drilled in the western part of Block A-18. The
operator has submitted a development plan concept to the regulator to facilitate ongoing commercial negotiations for an extension of
the existing gas sales contract to include development of the western part of the Block.
Malaysia: Approximately 5% of the capitalized well costs in excess of one year relates to North Malay Basin (Hess 50%),
offshore Peninsular Malaysia, where hydrocarbons were encountered in one successful exploration well. Subsurface evaluation and
pre-development studies for future phases of development are ongoing.
4. Hess Midstream LP
Prior to December 16, 2019, the Midstream segment was primarily comprised of HIP, a 50/50 joint venture between Hess
Corporation and Global Infrastructure Partners (GIP), formed to own, operate, develop and acquire a diverse set of midstream assets to
provide fee-based services to Hess and third-party customers. HIP was initially formed on May 21, 2015, with Hess selling 50% of
HIP to GIP for approximately $2.6 billion on July 1, 2015.
On April 10, 2017, HIP completed an initial public offering (IPO) of 16,997,000 common units, representing 30.5% limited
partnership interests in its subsidiary Hess Midstream Partners LP (Hess Midstream Partners), for net proceeds of approximately
67
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$365.5 million.
In connection with the IPO, HIP contributed a 20% controlling economic interest in each of Hess North Dakota
Pipeline Operations LP, Hess TGP Operations LP, and Hess North Dakota Export Logistics Operations LP, and a 100% economic
In exchange for the contributed
interest in Hess Mentor Storage Holdings LLC (collectively the “Contributed Businesses”).
businesses, Hess and GIP each received common and subordinated units representing a direct 33.75% limited partner interest in Hess
Midstream Partners and a 50% indirect ownership interest through HIP in Hess Midstream Partners’ general partner, which had a 2%
economic interest in Hess Midstream Partners plus incentive distribution rights.
On March 1, 2019, HIP acquired Hess’s existing Bakken water services business for $225 million in cash. As a result of this
transaction, we recorded an after-tax gain of $78 million in additional paid-in capital with an offsetting reduction to noncontrolling
interest to reflect the adjustment to GIP’s noncontrolling interest in HIP. On March 22, 2019, HIP and Hess Midstream Partners
acquired crude oil and gas gathering assets, and HIP acquired water gathering assets of Summit Midstream Partners LP’s Tioga
Gathering System for aggregate cash consideration of approximately $90 million, with the potential for an additional $10 million of
contingent payments in future periods subject to certain future performance metrics. On January 25, 2018, Hess Midstream Partners
entered into a 50/50 joint venture with Targa Resources Corp. to construct a new 200 million standard cubic feet per day gas
processing plant called Little Missouri 4 (LM4). The plant, which is operated by Targa, was placed into service in the third quarter of
2019.
On December 16, 2019, Hess Midstream Partners acquired HIP, including HIP’s 80% interest in Hess Midstream Partners’ oil
and gas midstream assets, HIP’s water services business and the outstanding economic general partner interest and incentive
distribution rights in Hess Midstream Partners LP. In addition, Hess Midstream Partners’ organizational structure converted from a
master limited partnership into an “Up-C” structure in which Hess Midstream Partners’ public unitholders received newly issued Class
A shares in a new public entity named Hess Midstream LP (Hess Midstream), which is taxed as a corporation for U.S. federal and
state income tax purposes. Hess Midstream Partners changed its name to “Hess Midstream Operations LP” (HESM Opco) and
became a consolidated subsidiary of Hess Midstream, the new publicly listed entity. As consideration for the acquisition, Hess
received a cash payment of $301 million and approximately 115 million newly issued HESM Opco Class B units. After giving effect
to the acquisition and related transactions, public shareholders of Class A shares in Hess Midstream own 6% of the consolidated entity
on an as-exchanged basis and Hess and GIP each own 47% of the consolidated entity on an as-exchanged basis, primarily through the
sponsors’ ownership of Class B units in HESM Opco that are exchangeable into Class A shares of Hess Midstream on a one-for-one
basis, or referred to as “Hess Corporation’s 47% consolidated ownership in Hess Midstream LP”.
At December 31, 2020, Hess Midstream liabilities totaling $2,026 million (2019: $1,941 million) are on a nonrecourse basis to
Hess Corporation, while Hess Midstream assets available to settle the obligations of Hess Midstream included Cash and cash
equivalents totaling $3 million (2019: $3 million), Property, plant and equipment, net totaling $3,111 million (2019: $3,010 million)
and an equity-method investment of $108 million (2019: $108 million) in LM4.
5. Accrued Liabilities
The following table provides detail of our accrued liabilities at December 31:
2020
2019
Accrued capital expenditures..................................................................................................................................... $
Accrued operating and marketing expenditures........................................................................................................
Accrued payments to royalty and working interest owners......................................................................................
Accrued interest on debt............................................................................................................................................
Accrued compensation and benefits..........................................................................................................................
Current portion of asset retirement obligations.........................................................................................................
Other accruals............................................................................................................................................................
Total Accrued Liabilities .......................................................................................................................................... $
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(In millions)
345
325
170
126
117
105
63
1,251
$
616
479
260
126
166
127
29
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6. Leases
Operating and finance lease obligations at December 31 included in the Consolidated Balance Sheet were as follows:
Operating Leases
Finance Leases
2020
2019
2020
2019
Right-of-use assets — net (a)................................................................................... $
Lease obligations:
Current................................................................................................................... $
Long-term..............................................................................................................
Total lease obligations............................................................................................ $
426
63
478
541
$
$
$
(In millions)
447
$
182
353
535
$
$
168
18
220
238
$
$
$
299
17
238
255
(a) At December 31, 2020, finance lease ROU assets had a cost of $212 million (2019: $381 million) and accumulated amortization of $44 million (2019: $82
million).
Lease obligations represent 100% of the present value of future minimum lease payments in the lease arrangement. Where we
have contracted directly with a lessor in our role as operator of an unincorporated oil and gas venture, we bill our partners their
proportionate share for reimbursements as payments under lease agreements become due pursuant to the terms of our joint operating
and other agreements.
The nature of our leasing arrangements at December 31, 2020 was as follows:
Operating leases:
In the normal course of business, we primarily lease drilling rigs, equipment, logistical assets (offshore
vessels, aircraft, and shorebases), and office space.
Finance leases:
In 2018, we entered into a sale and lease-back arrangement for a floating storage and offloading vessel
(FSO) to handle produced condensate at North Malay Basin, offshore Peninsular Malaysia. At December 31, 2020, the remaining
lease term for the FSO was 12.8 years.
Maturities of lease obligations at December 31, 2020 were as follows:
Operating
Leases
Finance
Leases
(In millions)
2021........................................................................................................................................................................... $
2022...........................................................................................................................................................................
2023...........................................................................................................................................................................
2024...........................................................................................................................................................................
2025...........................................................................................................................................................................
Remaining years.........................................................................................................................................................
Total lease payments...............................................................................................................................................
Less: Imputed interest..........................................................................................................................................
Total lease obligations.............................................................................................................................................. $
83
83
72
71
67
287
663
(122)
541
$
$
36
36
36
36
36
176
356
(118)
238
The following information relates to the Operating and Finance leases at December 31:
Operating Leases
Finance Leases
Weighted average remaining lease term.........................................
Range of remaining lease terms...................................................... 0.1 - 15.5 years
Weighted average discount rate......................................................
4.0%
2020
10.3 years
2019
5.4 years
0.1 - 16.1 years
4.3%
2020
12.8 years
12.8 years
7.9%
2019
13.8 years
13.8 years
7.9%
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The components of lease costs for the years ended December 31, 2020 and 2019 were as follows:
Operating lease cost................................................................................................................................................... $
Finance lease cost:
Amortization of leased assets...............................................................................................................................
Interest on lease obligations.................................................................................................................................
Short-term lease cost (a)............................................................................................................................................
Variable lease cost (b)................................................................................................................................................
Sublease income (c)...................................................................................................................................................
Total lease cost (d)...................................................................................................................................................... $
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2020
2019
(In millions)
200
$
31
20
199
38
(15)
473
$
414
43
21
164
89
(12)
719
(a) Short-term lease cost is primarily attributable to equipment used in global exploration, development, production, and crude oil marketing activities. Future short-
term lease costs will vary based on activity levels of our operated assets.
(b) Variable lease costs for drilling rigs result from differences in the minimum rate and the actual usage of the ROU asset during the lease period. Variable lease
costs for logistical assets result from differences in stated monthly rates and total charges reflecting the actual usage of the ROU asset during the lease
period. Variable lease costs for our office leases represent common area maintenance charges which have not been separated from lease components.
(c) We sublease certain of our office space to third parties under our head lease.
(d) Prior to the adoption of ASC 842, we incurred total rental expense of $154 million and income from subleases of $8 million in 2018.
The above lease costs represent 100% of the lease payments due for the period, including where we as operator have contracted
directly with suppliers. As the payments under lease agreements where we are operator become due, we bill our partners their
proportionate share for reimbursement pursuant to the terms of our joint operating agreements. Reimbursements are not reflected in
the table above. Certain lease costs above associated with exploration and development activities are included in capital expenditures.
Supplemental cash flow information related to leases for the years ended December 31, 2020 and 2019 were as follows:
Cash paid for amounts included in the measurement of lease obligations:
Operating cash flows (a)....................................................................................... $
Financing cash flows (a).......................................................................................
Noncash transactions:
Leased assets recognized for new lease obligations incurred..............................
Changes in leased assets and lease obligations due to lease modifications (b)....
(a) Amounts represent gross lease payments before any recovery from partners.
(b) Primarily related to negotiated extensions of an office lease and offshore drilling rig leases.
Operating Leases
Finance Leases
2020
2019
2020
2019
(In millions)
$
$
419
—
14
14
218
—
51
123
$
20
17
—
—
21
55
—
—
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7. Debt
Total debt at December 31 consisted of the following:
Debt - Hess Corporation:
Fixed-rate public notes:
3.5% due 2024......................................................................................................................................................... $
4.3% due 2027.........................................................................................................................................................
7.9% due 2029.........................................................................................................................................................
7.3% due 2031.........................................................................................................................................................
7.1% due 2033.........................................................................................................................................................
6.0% due 2040.........................................................................................................................................................
5.6% due 2041.........................................................................................................................................................
5.8% due 2047.........................................................................................................................................................
Total fixed-rate public notes........................................................................................................................................
Term loan due March 2023..........................................................................................................................................
Fair value adjustments - interest rate hedging..............................................................................................................
Total Debt - Hess Corporation............................................................................................................................. $
Debt - Midstream:
Fixed-rate notes: 5.625% due 2026 - Hess Midstream Operations LP....................................................................... $
Fixed-rate notes: 5.125% due 2028 - Hess Midstream Operations LP.......................................................................
Term loan A facility - Hess Midstream Operations LP...............................................................................................
Revolving credit facility - Hess Midstream Operations LP.........................................................................................
Total Debt - Midstream........................................................................................................................................ $
Total Debt:
Current maturities of long-term debt............................................................................................................................ $
Long-term debt.............................................................................................................................................................
Total Debt............................................................................................................................................................... $
At December 31, 2020, the maturity profile of total debt was as follows:
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2020
2019
(In millions)
299
994
464
628
537
741
1,236
494
5,393
988
5
6,386
789
542
395
184
1,910
10
8,286
8,296
$
$
$
$
$
$
298
992
463
628
537
741
1,235
494
5,388
—
1
5,389
787
540
394
32
1,753
—
7,142
7,142
2021................................................................................................................................................... $
2022...................................................................................................................................................
2023...................................................................................................................................................
2024...................................................................................................................................................
2025...................................................................................................................................................
Thereafter...........................................................................................................................................
Total Borrowings...............................................................................................................................
Less: Deferred financing costs and discounts....................................................................................
Total Debt (excluding interest).................................................................................................... $
No interest was capitalized in 2020 (2019: $38 million; 2018: $20 million).
Debt – Hess Corporation:
Senior unsecured fixed-rate public notes:
Total
Hess
Corporation
(In millions)
Midstream
10
20
1,030
824
—
6,488
8,372
(76)
8,296
$
$
— $
—
1,000
300
—
5,138
6,438
(52)
6,386
$
10
20
30
524
—
1,350
1,934
(24)
1,910
At December 31, 2020, Hess Corporation’s fixed-rate public notes had a gross principal amount of $5,438 million (2019:
$5,438 million) and a weighted average interest rate of 5.9% (2019: 5.9%). The indentures for our fixed-rate public notes limit the
ratio of secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As of December 31,
2020, Hess Corporation was in compliance with this financial covenant.
Term loan and credit facility:
In 2020, we entered into a $1 billion three year term loan agreement with a maturity date of March 16, 2023. Borrowings under
the term loan generally bear interest at LIBOR plus an applicable margin of 2.25% until the term loan's first anniversary. The
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applicable margin varies based on the credit rating of the Corporation’s senior unsecured long-term debt and will increase by 0.25%
on each anniversary of the term loan.
In 2019, we entered into a new $3.5 billion revolving credit facility with a maturity date of May 15, 2023, which replaced the
Corporation’s previous revolving credit facility. The new facility can be used for borrowings and letters of credit. Borrowings will
generally bear interest at 1.30% above LIBOR, though the interest rate is subject to adjustment if the Corporation’s credit rating
changes. At December 31, 2020, Hess Corporation had no outstanding borrowings or letters of credit under this facility.
Both the term loan and revolving credit facility are subject to customary representations, warranties, customary events of default
and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation
and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible
Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for
the revolving credit facility and the term loan agreement). As of December 31, 2020, Hess Corporation was in compliance with these
financial covenants.
The most restrictive of the financial covenants related to our fixed-rate public notes and our term loan and revolving credit facility
would allow us to borrow up to an additional $1,730 million of secured debt at December 31, 2020.
Other outstanding letters of credit at December 31 were as follows:
Committed lines (a).................................................................................................................................................... $
Uncommitted lines (a)................................................................................................................................................
Total..................................................................................................................................................................... $
(a) At December 31, 2020, committed and uncommitted lines have expiration dates through 2021.
Debt - Midstream:
Senior unsecured fixed-rate public notes:
2020
2019
(In millions)
54
215
269
$
$
54
218
272
In November 2017, HIP issued $800 million of 5.625% senior unsecured notes due in 2026. In December 2019, in connection
with the acquisition of HIP and corporate restructuring described in Note 4, Hess Midstream LP, HESM Opco assumed $800 million
of outstanding HIP senior notes in a par-for-par exchange. The senior notes are guaranteed by certain subsidiaries of HESM Opco. In
addition, in December 2019, HESM Opco issued $550 million of 5.125% senior unsecured notes due in 2028. The notes are
guaranteed by HESM Opco’s direct and indirect wholly owned material domestic subsidiaries. Proceeds of the new notes were used
to finance the acquisition of HIP and repay outstanding borrowings under HIP’s credit facilities.
Credit facilities:
Prior to the closing of the December 2019 transaction, HIP had a $600 million 5-year senior secured revolving credit facility and a
$200 million senior secured Term Loan A facility, while Hess Midstream Partners LP had a $300 million 4-year senior secured
syndicated revolving credit facility. In connection with the acquisition of HIP, both HIP and Hess Midstream Partners LP retired their
existing senior secured revolving credit facilities and HESM Opco entered into a new 5-year senior secured syndicated revolving
credit facility in the amount of $1.0 billion. HIP also retired its senior secured Term Loan A facility, which had borrowings of
$190 million excluding deferred issuance costs, and HESM Opco entered into a fully drawn $400 million 5-year Term Loan A facility,
receiving cash of $210 million at closing. The new revolving credit facility can be used for borrowings and letters of credit to fund
HESM Opco’s operating activities, capital expenditures, distributions and for other general corporate purposes. Borrowings under the
5-year Term Loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the
applicable margin for the 5-year syndicated revolving credit facility ranges from 1.275% to 2.000%. Pricing levels for the facility fee
and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA as defined in the credit facilities. If HESM Opco
obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time.
The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA for the prior four fiscal
quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following
certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the
prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. The credit facilities are secured by
first-priority perfected liens on substantially all the presently owned and after-acquired assets of HESM Opco and its direct and
indirect wholly owned material domestic subsidiaries, including equity interests directly owned by such entities, subject to certain
customary exclusions. At December 31, 2020, borrowings of $184 million were drawn under HESM Opco’s revolving credit facility,
and borrowings of $400 million, excluding deferred issuance costs, were drawn under HESM Opco’s Term Loan A
facility. Borrowings under these credit facilities are non-recourse to Hess Corporation.
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8. Asset Retirement Obligations
The following table describes changes to our asset retirement obligations:
Balance at January 1..................................................................................................................................................... $
Liabilities incurred.......................................................................................................................................................
Liabilities settled or disposed of...................................................................................................................................
Accretion expense........................................................................................................................................................
Revisions of estimated liabilities..................................................................................................................................
Foreign currency remeasurement.................................................................................................................................
Balance at December 31................................................................................................................................................ $
Total Asset Retirement Obligations at December 31:
Current portion of asset retirement obligations............................................................................................................ $
Long-term asset retirement obligations........................................................................................................................
Total at December 31............................................................................................................................................... $
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2020
2019
(In millions)
1,024
36
(161)
46
52
2
999
105
894
999
$
$
$
$
857
72
(75)
40
129
1
1,024
127
897
1,024
The liabilities incurred in 2020 and 2019 primarily relate to operations in Guyana, the U.S. and Malaysia. The liabilities settled or
disposed of in 2020 primarily reflect an asset sale in the Gulf of Mexico and abandonment activity completed in the Gulf of Mexico,
the Bakken and the U.K. North Sea, while 2019 primarily relates to abandonment activity in the Gulf of Mexico and the
Bakken. Revisions of estimated liabilities in 2020 and 2019 reflect an acceleration of planned abandonment activity in the Gulf of
Mexico and changes in service and equipment rates.
Sinking fund deposits that are legally restricted for purposes of settling asset retirement obligations, which are reported in non-
current Other assets in the Consolidated Balance Sheet, were $207 million at December 31, 2020 (2019: $178 million).
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9. Retirement Plans
We have funded noncontributory defined benefit pension plans for a significant portion of our employees. In addition, we have
an unfunded supplemental pension plan covering certain employees, which provides incremental payments that would have been
payable from our principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined
benefits based on years of service and final average salary to U.S. employees hired prior to January 1, 2017 and to U.K.
employees. U.S. employees hired on or after January 1, 2017 participate under a cash accumulation formula and receive credits to a
notional account based on a percentage of pensionable wages.
Interest accrues on the balance in the notional account at a rate
determined in accordance with plan provisions. Additionally, we maintain an unfunded postretirement medical plan that provides
health benefits to certain U.S. qualified retirees from ages 55 through 65. The measurement date for all retirement plans is
December 31.
The following table summarizes the benefit obligations, the fair value of plan assets, and the funded status of our pension and
postretirement medical plans:
Funded
Pension Plans
Unfunded
Pension Plan
Postretirement
Medical Plan
2020
2019
2020
2019
2020
2019
Change in Benefit Obligation
Balance at January 1, ..................................................................................... $ 2,667
Service cost ..................................................................................................
37
68
Interest cost ..................................................................................................
Actuarial (gains) loss (a) ..............................................................................
385
Single premium annuity contract payment...................................................
—
(93)
Benefit payments (b) ...................................................................................
21
Foreign currency exchange rate changes .....................................................
Balance at December 31, (c)...........................................................................
3,085
Change in Fair Value of Plan Assets
Balance at January 1,...................................................................................... $ 2,732
378
Actual return on plan assets .........................................................................
Employer contributions ...............................................................................
4
Single premium annuity contract payment...................................................
—
(93)
Benefit payments (b) ...................................................................................
22
Foreign currency exchange rate changes .....................................................
Balance at December 31,................................................................................
3,043
$ 2,492
33
82
401
(249)
(113)
21
2,667
$ 2,568
462
40
(249)
(113)
24
2,732
Funded Status (Plan assets greater (less) than benefit obligations) at
December 31,.................................................................................................... $
(42) $
65
Unrecognized Net Actuarial (Gains) Losses.................................................. $
900
$
756
(In millions)
$
242
13
5
26
—
(17)
—
269
— $
—
17
—
(17)
—
—
$
216
11
7
22
—
(14)
—
242
— $
—
14
—
(14)
—
—
$
75
3
1
(8)
—
(6)
—
65
— $
—
6
—
(6)
—
—
59
2
2
19
—
(7)
—
75
—
—
7
—
(7)
—
—
(269) $
(242) $
(65) $
(75)
86
$
65
$
(19) $
(12)
$
$
$
$
(a) Changes in discount rates resulted in actuarial losses of $387 million in 2020 (2019: $465 million). Changes in mortality assumptions resulted in actuarial gains
of $18 million in 2020 (2019: $13 million).
(b) Benefit payments include lump-sum settlement payments of $23 million in 2020 (2019: $27 million).
(c) At December 31, 2020, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $2,993 million and $228 million,
respectively (2019: $2,580 million and $194 million, respectively).
Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following:
Funded
Pension Plans
Unfunded
Pension Plan
Postretirement
Medical Plan
2020
2019
2020
2019
2020
2019
Noncurrent assets........................................................................................ $
Current liabilities........................................................................................
Noncurrent liabilities..................................................................................
Pension assets / (accrued benefit liability)......................................... $
$
45
—
(87)
(42) $
71
—
(6)
65
Accumulated other comprehensive loss, pre-tax (a)..................................... $
900
$
756
(In millions)
— $
(49)
(220)
(269) $
— $
(32)
(210)
(242) $
— $
(7)
(58)
(65) $
—
(8)
(67)
(75)
86
$
65
$
(19) $
(12)
$
$
$
(a) The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $759 million at December 31, 2020 (2019: $601 million deficit).
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The net periodic benefit cost for funded and unfunded pension plans, and the postretirement medical plan, is as follows:
Pension Plans
Postretirement Medical Plan
2020
2019
2018
2020
2019
2018
(In millions)
Service cost .................................................................................................... $
Interest cost ....................................................................................................
Expected return on plan assets .......................................................................
Amortization of unrecognized net actuarial losses (gains).............................
Settlement loss ...............................................................................................
Curtailment gain.............................................................................................
Net Periodic Benefit Cost / (Income) (a)................................................ $
$
50
73
(180)
48
—
—
(9) $
44
89
(180)
52
93
—
98
$
$
$
42
91
(194)
39
4
—
(18) $
3
1
—
(1)
—
——
3
$
$
$
2
2
—
(1)
—
(2)
$
3
2
3
—
(2)
—
1
(a) Net non-service cost, which are included in Other, net in the Statement of Consolidated Income, were income of $59 million in 2020 (2019: $55 million of
expense; 2018: $61 million of income).
In 2019, the trust for the Hess Corporation Employees’ Pension Plan (the “Plan”) purchased a single premium annuity contract at
a cost of $249 million using assets of the Plan to settle and transfer certain of its obligations to a third party. The settlement
transaction resulted in a noncash charge of $88 million to recognize unamortized pension actuarial losses that is included in Other, net
in the Statement of Consolidated Income.
In 2021, we forecast service cost for our pension and postretirement medical plans to be approximately $55 million and net non-
service cost of approximately $85 million of income, which is comprised of interest cost of approximately $55 million, amortization of
unrecognized net actuarial losses of approximately $55 million, and estimated expected return on plan assets of approximately $195
million.
Assumptions: The weighted average actuarial assumptions used to determine benefit obligations at December 31 and net periodic
benefit cost for the three years ended December 31 for our funded and unfunded pension plans were as follows:
Benefit Obligations:
Discount rate .................................................................................................................................
Rate of compensation increase .....................................................................................................
Net Periodic Benefit Cost:
Discount rate
Service cost..............................................................................................................................
Interest cost..............................................................................................................................
Expected return on plan assets ......................................................................................................
Rate of compensation increase .....................................................................................................
2020
2.2%
3.8%
3.2%
2.6%
6.7%
3.8%
2019
2.9%
3.8%
3.9%
3.4%
7.1%
3.8%
2018
3.9%
3.8%
3.9%
3.3%
7.2%
4.5%
The actuarial assumptions used to determine benefit obligations at December 31 for the postretirement medical plan were as
follows:
Discount rate .................................................................................................................................
Initial health care trend rate ..........................................................................................................
Ultimate trend rate ........................................................................................................................
Year in which ultimate trend rate is reached ................................................................................
2020
1.9%
6.0%
4.5%
2038
2019
2.8%
6.5%
4.5%
2038
2018
3.9%
6.9%
4.5%
2038
The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while
the assumptions used to determine benefit obligations were established at each year‑end. The net periodic benefit cost and the
actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount
rate is developed based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected
payment of plan obligations.
The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the
target allocation of pension assets to that asset category. The future expected return assumptions for individual asset categories are
largely based on inputs from various investment experts regarding their future return expectations for particular asset categories.
Our investment strategy is to maximize long‑term returns at an acceptable level of risk through broad diversification of plan assets
in a variety of asset classes. Asset classes and target allocations are determined by our investment committee and include domestic
and foreign equities, fixed income, and other investments, including hedge funds, real estate and private equity. Investment managers
are prohibited from investing in securities issued by us unless indirectly held as part of an index strategy. The majority of plan assets
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are highly liquid, providing ample liquidity for benefit payment requirements. The current target allocations for plan assets are 45%
equity securities, 35% fixed income securities (including cash and short‑term investment funds) and 20% to all other types of
investments. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of
target levels.
Fair value: The following tables provide the fair value of the financial assets of the funded pension plans at December 31, 2020
and 2019 in accordance with the fair value measurement hierarchy described in Note 1, Nature of Operations, Basis of Presentation
and Summary of Accounting Policies.
Level 1
Level 2
Level 3
Net Asset
Value (c)
Total
(In millions)
44
$
— $
— $
— $
December 31, 2020
Cash and Short-Term Investment Funds ........................................... $
Equities:
U.S. equities (domestic) .......................................................................
International equities (non-U.S.) ..........................................................
Global equities (domestic and non-U.S.) .............................................
Fixed Income:
Treasury and government related (a) ...................................................
Mortgage-backed securities (b) ............................................................
Corporate ..............................................................................................
Other:
Hedge funds ..........................................................................................
Private equity funds ..............................................................................
Real estate funds ...................................................................................
Total investments................................................................................... $
December 31, 2019
Cash and Short-Term Investment Funds ........................................... $
Equities:
U.S. equities (domestic) .......................................................................
International equities (non-U.S.) ..........................................................
Global equities (domestic and non-U.S.) .............................................
Fixed Income:
Treasury and government related (a) ...................................................
Mortgage-backed securities (b) ............................................................
Corporate ..............................................................................................
Other:
Hedge funds ..........................................................................................
Private equity funds ..............................................................................
Real estate funds ...................................................................................
Total investments................................................................................... $
585
94
—
—
—
—
—
—
23
746
57
638
80
—
—
—
—
—
—
27
802
$
$
$
—
43
8
350
116
381
—
—
—
898
—
37
8
372
141
293
—
—
—
851
—
—
—
—
—
—
164
352
217
49
70
62
—
—
—
—
—
—
—
302
196
56
30
82
44
749
489
225
399
186
443
57
638
419
204
428
171
375
—
—
—
— $
73
251
161
1,399
$
73
251
184
3,043
$
— $
— $
— $
—
—
—
— $
65
191
157
1,079
$
65
191
184
2,732
$
(a) Includes securities issued and guaranteed by U.S. and non‑U.S. governments, and securities issued by governmental agencies and municipalities.
(b) Comprised of U.S. residential and commercial mortgage-backed securities.
(c) Includes certain investments that have been valued using the net asset value (NAV) practical expedient, and therefore have not been categorized in the fair value
hierarchy. The inclusion of such amounts in the above table is intended to aid reconciliation of investments categorized in the fair value hierarchy to total
pension plan assets.
The following describes the financial assets of the funded pension plans:
Cash and short‑term investment funds - Consists of cash on hand and short-term investment funds that provide for daily
investments and redemptions which are classified as Level 1.
Equities - Consists of individually held U.S. and international equity securities. This investment category also includes funds
that consist primarily of U.S. and international equity securities. Equity securities, which are individually held and are traded actively
on exchanges, are classified as Level 1. Certain funds, consisting primarily of equity securities, are classified as Level 2 if the NAV is
determined and published daily, and is the basis for current transactions. Commingled funds, consisting primarily of equity securities,
are valued using the NAV per fund share.
Fixed income investments - Consists of individually held securities issued by the U.S. government, non-U.S. governments,
governmental agencies, municipalities and corporations, and agency and non-agency mortgage backed securities. This investment
category also includes funds that consist of fixed income securities. Individual fixed income securities are generally priced based on
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evaluated prices from independent pricing services, which are monitored and provided by the third-party custodial firm responsible for
safekeeping assets of the particular plan and are classified as Level 2. Certain funds, consisting primarily of fixed income securities,
are classified as Level 2 if the NAV is determined and published daily, and is the basis for current transactions. Commingled funds,
consisting primarily of fixed income securities, are valued using the NAV per fund share.
Other investments - Consists of exchange‑traded real estate investment
trust securities, which are classified as
Level 1. Commingled funds and limited partnership investments in hedge funds, private equity and real estate funds are valued at the
NAV per fund share.
Contributions and estimated future benefit payments: To preserve cash in 2021, we are minimizing non-required cash
contributions to funded pension plans. In 2021, we expect to contribute approximately $4 million to our funded pension plans.
Estimated future benefit payments by the funded and unfunded pension plans, and the postretirement medical plan, which reflect
expected future service, are as follows (in millions):
2021.....................................................................................................................................................................................................
2022.....................................................................................................................................................................................................
2023.....................................................................................................................................................................................................
2024.....................................................................................................................................................................................................
2025.....................................................................................................................................................................................................
Years 2026 to 2030.............................................................................................................................................................................
$
151
134
133
137
130
687
We also have defined contribution plans for certain eligible employees. Employees may contribute a portion of their
compensation to these plans and we match a portion of the employee contributions. We recorded expense of $22 million in 2020 for
contributions to these plans (2019: $20 million; 2018: $19 million).
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10. Revenue
Revenue from contracts with customers on a disaggregated basis was as follows (in millions):
Exploration and Production
Midstream Eliminations
Total
United
States
Guyana
Malaysia
and JDA Other (a)
E&P
Total
2020
Sales of our net production volumes:
Crude oil revenue.................................................... $ 1,898
Natural gas liquids revenue.....................................
253
Natural gas revenue.................................................
144
831
Sales of purchased oil and gas.....................................
Intercompany revenue..................................................
—
Total revenues from contracts with customers............
3,126
Other operating revenues (b).......................................
478
Total sales and other operating revenues............. $ 3,604
$
$
278
—
—
5
—
283
67
350
$
$
2019
Sales of our net production volumes:
Crude oil revenue.................................................... $ 2,981
229
Natural gas liquids revenue.....................................
Natural gas revenue.................................................
150
Sales of purchased oil and gas.....................................
1,644
Intercompany revenue..................................................
—
5,004
Total revenues from contracts with customers............
Other operating revenues (b).......................................
39
Total sales and other operating revenues............. $ 5,043
$ — $
—
—
—
—
—
—
$ — $
2018
Sales of our net production volumes:
Crude oil revenue.................................................... $ 2,832
Natural gas liquids revenue.....................................
308
176
Natural gas revenue.................................................
Sales of purchased oil and gas.....................................
1,661
Intercompany revenue..................................................
—
4,977
Total revenues from contracts with customers............
(135)
Other operating revenues (b).......................................
Total sales and other operating revenues............. $ 4,842
$ — $
—
—
—
—
—
—
$ — $
34
—
477
—
—
511
—
511
113
—
646
3
—
762
—
762
104
—
651
14
—
769
—
769
$
$
$
$
$
$
153
—
10
11
—
174
28
202
566
—
33
91
—
690
—
690
587
—
32
93
—
712
—
712
$ 2,363
253
631
847
—
4,094
573
$ 4,667
$ 3,660
229
829
1,738
—
6,456
39
$ 6,495
$ 3,523
308
859
1,768
—
6,458
(135)
$ 6,323
$
$
$
$
$
$
— $
—
—
—
1,092
1,092
—
1,092
$
— $ 2,363
253
—
631
—
847
—
(1,092)
—
4,094
(1,092)
573
—
(1,092) $ 4,667
— $
—
—
—
848
848
—
848
$
— $
—
—
—
713
713
—
713
$
— $ 3,660
229
—
—
829
1,738
—
(848)
—
6,456
(848)
39
—
(848) $ 6,495
— $ 3,523
308
—
859
—
1,768
—
(713)
—
6,458
(713)
(135)
—
(713) $ 6,323
(a) Other includes our interests in Denmark and Libya.
(b) Includes gains (losses) on commodity derivatives of $547 million in 2020, $1 million in 2019, and $(183) million in 2018.
11. Dispositions
2020: We completed the sale of our 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico for proceeds of
$482 million, after normal closing adjustments, and recognized a pre-tax gain of $79 million ($79 million after income taxes).
2019: We completed the sale of our remaining acreage in the Utica shale play in eastern Ohio for proceeds of $22 million, after
normal closing adjustments, and recognized a pre-tax gain of $22 million ($22 million after income taxes).
2018: We completed the sale of our joint venture interests in the Utica shale play in eastern Ohio for proceeds of $396 million,
In addition, we
after normal closing adjustments, and recognized a pre-tax gain of $14 million ($14 million after income taxes).
completed the sale of our interests in Ghana for total consideration of $100 million, consisting of a $25 million payment that was
received at closing and a further payment of $75 million that is payable to us upon the buyer receiving government approval for a Plan
of Development on the Deepwater Tano Cape Three Points Block. The receipt of proceeds at closing resulted in a pre-tax gain of $10
million ($10 million after income taxes).
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12. Impairment
Oil and Gas Properties:
As a result of the significant decline in crude oil prices due to the global economic slowdown from the COVID-19 pandemic, we
reviewed our oil and gas properties within the Exploration and Production operating segment for impairment in the first quarter of
2020. We recognized pre-tax impairment charges in the first quarter of 2020 to reduce the carrying value of our oil and gas properties
and certain related right-of-use assets at the North Malay Basin in Malaysia by $755 million ($755 million after income taxes), the
South Arne Field in Denmark by $670 million ($594 million after income taxes), and in the Gulf of Mexico, the Stampede Field by
$410 million ($410 million after income taxes) and the Tubular Bells Field by $270 million ($270 million after income taxes)
primarily as a result of a lower long-term crude oil price outlook. The impairment charges were based on estimates of fair value at
March 31, 2020 determined by discounting internally developed future net cash flows, a Level 3 fair value measurement. The total of
the fair value estimates was approximately $1.05 billion. Significant inputs used in determining the discounted future net cash flows
include future prices, projected production volumes using risk adjusted oil and gas reserves, and discount rates. The future pricing
assumptions used were based on forward strip crude oil prices as of March 31, 2020 for the remainder of 2020 through 2022, and $50
per barrel for WTI ($55 per barrel for Brent) in 2023 and thereafter to the end of field life. The weighted average crude oil benchmark
price based on total projected crude oil volumes for the impaired assets was $48.82 per barrel. A discount rate of 10% was used in
each of the fair value measurements which represents the estimated discount rate a market participant would use. We determined the
discount rate by considering the weighted average cost of capital for a group of peer companies.
Other Assets:
In the first quarter of 2020, we recognized impairment charges totaling $21 million pre-tax ($20 million after income taxes)
related to drilling rig right-of-use assets in the Bakken and surplus materials and supplies.
13. Exit and Disposal Costs
We incurred employee termination costs of $27 million in 2020 and $38 million in 2018 related to cost reduction initiatives and
asset sales in 2018. All charges were based on amounts incurred under ongoing severance arrangements or other statutory
requirements, plus amounts earned under enhanced benefit arrangements. Payments for termination costs were $20 million in 2020
(2019: $4 million; 2018: $40 million).
14. Share-based Compensation
We have established and maintain long term incentive plans (LTIP) for the granting of restricted common shares, performance
share units (PSUs) and stock options to our employees. At December 31, 2020, the total number of authorized common stock under
the LTIP was 51.5 million shares, of which we have 13.0 million shares available for issuance. Share‑based compensation expense
consisted of the following:
Restricted stock............................................................................................................................... $
Performance share units..................................................................................................................
Stock options...................................................................................................................................
Share-based compensation expense before income taxes....................................................... $
Income tax benefit on share-based compensation expense.................................................... $
2020
2019
2018
$
(In millions)
53
22
10
85
$
— $
$
51
18
10
79
$
— $
40
22
10
72
—
Based on share‑based compensation awards outstanding at December 31, 2020, unearned compensation expense, before income
taxes, will be recognized in future years as follows (in millions): 2021: $49, 2022: $26 and 2023: $4.
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Our share-based compensation plans can be summarized as follows:
Restricted stock:
Restricted stock generally vests equally on an annual basis over a three-year term and is valued based on the prevailing market
price of our common stock on the date of grant. The following is a summary of restricted stock award activity in 2020:
Outstanding at January 1, 2020..............................................................................................................................
Granted....................................................................................................................................................................
Vested (a).................................................................................................................................................................
Forfeited...................................................................................................................................................................
Outstanding at December 31, 2020.........................................................................................................................
(a) In 2020, restricted stock with fair values of $51 million were vested (2019: $102 million; 2018: $54 million).
Performance share units:
Shares of
Restricted
Common
Stock
Weighted -
Average Price
on Date of
Grant
(In thousands, except per share
amounts)
2,014
1,122
(1,028)
(191)
1,917
$
$
53.61
49.71
52.67
52.54
51.94
PSUs generally vest three years from the date of grant and are valued using a Monte Carlo simulation on the date of grant. The
number of shares of common stock to be issued under a PSU agreement is based on a comparison of the Corporation’s total
shareholder return (TSR) to the TSR of a predetermined group of peer companies over a three-year performance period ending
December 31 of the year prior to settlement of the grant. Beginning with the PSUs granted in 2020, the Corporation's TSR is
compared to the TSR of a predetermined group of peer companies and the S&P 500 index over the three-year performance period.
Payouts of the performance share awards will range from 0% to 200% of the target awards based on the Corporation’s TSR ranking
within the peer group. Dividend equivalents for the performance period will accrue on performance shares but will only be paid out
on earned shares after the performance period. The following is a summary of PSU activity in 2020:
Performance
Share Units
Weighted -
Average Fair
Value on Date
of Grant
Outstanding at January 1, 2020..............................................................................................................................
Granted....................................................................................................................................................................
Vested (a).................................................................................................................................................................
Forfeited...................................................................................................................................................................
Outstanding at December 31, 2020.........................................................................................................................
(a) In 2020, PSU’s with fair value of $48 million were vested (2019: $16 million; 2018: $9 million).
The following weighted average assumptions were utilized to estimate the fair value of PSU awards:
$
(In thousands, except per share
amounts)
929
308
(416)
(15)
806
59.57
58.14
52.86
66.63
62.36
$
Risk free interest rate.......................................................................................................................
Stock price volatility.......................................................................................................................
Contractual term in years................................................................................................................
Grant date price of Hess common stock.......................................................................................... $
2020
2019
2018
0.52 %
0.374
3.0
2.48 %
0.369
3.0
2.39 %
0.400
3.0
49.72
$
56.74
$
48.48
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Stock options:
Stock options vest over three years from the date of grant, have a 10‑year term, and the exercise price equals the market price of
our common stock on the date of grant. The following is a summary of stock options activity in 2020:
Outstanding at January 1, 2020...................................................................................................
Granted.........................................................................................................................................
Exercised......................................................................................................................................
Cancelled......................................................................................................................................
Forfeited.......................................................................................................................................
Outstanding at December 31, 2020..............................................................................................
Number of
options
(In thousands)
4,301
686
(261)
(301)
(43)
4,382
Weighted
Average
Exercise Price
per Share
$
$
63.24
49.72
59.88
61.13
52.70
61.57
Weighted
Average
Remaining
Contractual
Term
4.8 years
5.1 years
At December 31, 2020, there were 4.4 million outstanding stock options (3.2 million exercisable) with a weighted average
remaining contractual life of 5.1 years (3.8 years for exercisable options) and an aggregated intrinsic value of $9.3 million ($6.3
million for exercisable options).
The following weighted average assumptions were utilized to estimate the fair value of stock options:
Risk free interest rate....................................................................................................................
Stock price volatility.....................................................................................................................
Dividend yield..............................................................................................................................
Expected life in years...................................................................................................................
Weighted average fair value per option granted........................................................................... $
2020
2019
2018
0.64 %
0.372
2.01 %
6.0
2.55 %
0.359
1.76 %
6.0
2.74 %
0.322
2.06 %
6.0
14.30
$
18.08
$
13.69
In estimating the fair value of PSUs and stock options, the risk-free interest rate is based on the vesting period of the award and is
obtained from published sources. The stock price volatility is determined from the historical stock prices of the Corporation using the
expected term.
15. Income Taxes
The provision (benefit) for income taxes consisted of:
United States
Federal
Current............................................................................................................................................. $
Deferred taxes and other accruals...................................................................................................
State...................................................................................................................................................
Foreign
Current (a).......................................................................................................................................
Deferred taxes and other accruals...................................................................................................
Provision (Benefit) For Income Taxes......................................................................................... $
(a) Primarily comprised of Libya in 2019 and 2018.
Income (loss) before income taxes consisted of the following:
2020
2019
2018
(In millions)
(4) $
6
(1)
1
48
(60)
(12)
(11) $
(1) $
72
16
87
447
(73)
374
461
$
1
(74)
(45)
(118)
455
(2)
453
335
2020
2019
2018
(In millions)
United States (a)................................................................................................................................... $
Foreign.................................................................................................................................................
Income (Loss) Before Income Taxes............................................................................................ $
(1,509) $
(1,341)
(2,850) $
(338) $
559
221
$
(219)
439
220
(a) Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities.
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The difference between our effective income tax rate and the U.S. statutory rate is reconciled below:
2020
2019
2018
U.S. statutory rate...........................................................................................................................
Effect of foreign operations (a).......................................................................................................
State income taxes, net of federal income tax.................................................................................
Valuation allowance on current year operations.............................................................................
Release valuation allowance against previously unbenefited deferred tax assets..........................
Noncontrolling interests in Midstream...........................................................................................
Intraperiod allocation......................................................................................................................
Credits.............................................................................................................................................
Equity and executive compensation................................................................................................
Other...............................................................................................................................................
Total.............................................................................................................................................
21.0 %
12.1
0.1
(36.5)
—
1.7
—
2.0
(0.1)
0.1
0.4 %
21.0 %
142.9
5.8
41.8
(24.5)
(16.0)
33.7
—
2.2
1.2
208.1 %
21.0 %
141.2
(18.9)
55.2
—
(15.9)
(37.3)
—
7.4
(0.3)
152.4 %
(a) The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high, primarily Libya,
and low tax rate jurisdictions.
The components of deferred tax liabilities and deferred tax assets at December 31, were as follows:
Deferred Tax Liabilities
Property, plant and equipment and investments........................................................................................................... $
Other.............................................................................................................................................................................
Total Deferred Tax Liabilities.................................................................................................................................
Deferred Tax Assets
Net operating loss carryforwards.................................................................................................................................
Tax credit carryforwards..............................................................................................................................................
Property, plant and equipment and investments...........................................................................................................
Accrued compensation, deferred credits and other liabilities......................................................................................
Asset retirement obligations.........................................................................................................................................
Other.............................................................................................................................................................................
Total Deferred Tax Assets.......................................................................................................................................
Valuation allowances (a)..............................................................................................................................................
Total deferred tax assets, net of valuation allowances..........................................................................................
Net Deferred Tax Assets (Liabilities).................................................................................................................. $
(a) In 2020, the valuation allowance increased by $657 million (2019: decrease of $143 million; 2018: decrease of $322 million).
2020
2019
(In millions)
(847) $
(45)
(892)
5,037
135
55
196
252
325
6,000
(5,391)
609
(283) $
(1,318)
(45)
(1,363)
4,733
66
206
179
261
317
5,762
(4,734)
1,028
(335)
In the Consolidated Balance Sheet, deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at
December 31, as follows:
Deferred income taxes (long-term asset)...................................................................................................................... $
Deferred income taxes (long-term liability).................................................................................................................
Net Deferred Tax Assets (Liabilities)................................................................................................................... $
2020
2019
(In millions)
$
59
(342)
(283) $
80
(415)
(335)
At December 31, 2020, we have recognized a gross deferred tax asset related to net operating loss carryforwards of $5,037 million
before application of valuation allowances. The deferred tax asset is comprised of $1,121 million attributable to foreign net operating
losses which begin to expire in 2025, $3,277 million attributable to U.S. federal operating losses which begin to expire in 2034, and
$639 million attributable to losses in various U.S. states which begin to expire in 2021. The deferred tax asset attributable to foreign
net operating losses, net of valuation allowances, is $155 million. A full valuation allowance is established against the deferred tax
asset attributable to U.S. federal and state net operating losses, except for $3 million U.S. federal and $1 million U.S. state deferred tax
asset attributable to Midstream activities. At December 31, 2020, we have U.S. federal, state and foreign alternative minimum tax
credit carryforwards of $49 million, which can be carried forward indefinitely, and approximately $83 million of other business credit
carryforwards. The deferred tax asset attributable to these credits, net of valuation allowances was not significant. A full valuation
allowance is established against our foreign tax credit carryforwards of $3 million, which begin to expire in 2021.
At December 31, 2020, the Consolidated Balance Sheet reflects a $5,391 million valuation allowance against the net deferred tax
assets for multiple jurisdictions based on application of the relevant accounting standards. Hess continues to maintain a full valuation
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allowance against its deferred tax assets in the U.S., Denmark, and Malaysia. Management assesses the available positive and
negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The
the three-year period ending December 31, 2020 constitutes significant objective negative
cumulative loss incurred over
evidence. Such objective negative evidence limits our ability to consider subjective positive evidence, such as our projections of
future taxable income, resulting in the recognition of a valuation allowance against
the net deferred tax assets for these
jurisdictions. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable
income change or if objective negative evidence in the form of cumulative losses is no longer present and additional weight can be
given to subjective evidence. At December 31, 2019 the valuation allowance established against the net deferred tax asset in Guyana
for the Stabroek Block was released as a result of the positive evidence from first production in December 2019, and the significant
forecasted pre-tax income from operations. The cumulative pre-tax losses in Guyana were driven by pre-production activities.
Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits:
Balance at January 1.......................................................................................................................... $
Additions based on tax positions taken in the current year...............................................................
Additions based on tax positions of prior years................................................................................
Reductions based on tax positions of prior years..............................................................................
Reductions due to settlements with taxing authorities......................................................................
Reductions due to lapses in statutes of limitation.............................................................................
Balance at December 31..................................................................................................................... $
2020
2019
2018
(In millions)
168
2
1
(1)
—
(2)
168
$
$
$
$
168
2
1
(2)
(1)
(2)
166
205
19
36
(78)
(10)
(4)
168
The December 31, 2020 balance of unrecognized tax benefits includes $16 million that, if recognized, would impact our effective
income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease
between zero and $41 million due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of
limitation. At December 31, 2020, our accrued interest and penalties related to unrecognized tax benefits is $6 million (2019: $7
million).
We file income tax returns in the U.S. and various foreign jurisdictions. We are no longer subject to examinations by income tax
authorities in most jurisdictions for years prior to 2010.
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16. Outstanding and Weighted Average Common Shares
The Net income (loss) and weighted average number of common shares used in basic and diluted earnings per share computation
were as follows:
2020
2019
2018
(In millions except per share amounts)
Net Income (Loss) Attributable to Hess Corporation Common Stockholders:
Net income (loss).............................................................................................................................. $
Less: Net income (loss) attributable to noncontrolling interests.....................................................
Less: Preferred stock dividends.......................................................................................................
Net income (loss) attributable to Hess Corporation Common Stockholders.................................... $
(2,839) $
254
—
(3,093) $
(240) $
168
4
(412) $
Weighted Average Number of Common Shares Outstanding:
Basic..................................................................................................................................................
Effect of dilutive securities
Restricted common stock................................................................................................................
Stock options...................................................................................................................................
Performance share units..................................................................................................................
Mandatory convertible preferred stock...........................................................................................
Diluted...............................................................................................................................................
304.8
—
—
—
—
304.8
301.2
—
—
—
—
301.2
(115)
167
46
(328)
298.2
—
—
—
—
298.2
Net Income (Loss) Attributable to Hess Corporation per Common Share:
Basic.................................................................................................................................................. $
Diluted............................................................................................................................................... $
(10.15) $
(10.15) $
(1.37) $
(1.37) $
(1.10)
(1.10)
Antidilutive shares excluded from the computation of diluted shares:
Restricted common stock..................................................................................................................
Stock options.....................................................................................................................................
Performance share units....................................................................................................................
Common shares from conversion of preferred stock........................................................................
2.1
4.3
1.1
—
2.2
4.7
1.7
—
2.9
5.5
1.1
12.7
The following table provides the changes in our outstanding common shares:
Balance at January 1.............................................................................................................................
Conversion of preferred stock...........................................................................................................
Activity related to restricted stock awards, net.................................................................................
Stock options exercised.....................................................................................................................
PSUs vested.......................................................................................................................................
Shares repurchased............................................................................................................................
Balance at December 31.......................................................................................................................
Preferred Stock Issuance:
2020
2019
2018
304.9
—
1.0
0.3
0.8
—
307.0
(In millions)
291.4
11.6
0.9
0.7
0.3
—
304.9
315.1
—
0.8
0.6
0.1
(25.2)
291.4
In February 2016, we issued depository shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred
Stock (Preferred Stock), par value $1 per share, with a liquidation preference of $1,000 per share. On January 31, 2019, the Preferred
Stock automatically converted into shares of common stock and the net number of common shares issued by the Corporation was
approximately 11.6 million shares.
Common Stock Repurchase Plan:
In 2018, we repurchased 25.2 million shares of our common stock for $1,380 million at an average cost per share of $54.85. At
December 31, 2020, we are authorized, but not required, to purchase additional common stock up to a value of $650 million.
Common Stock Dividends:
In 2020, 2019 and 2018, cash dividends declared on common stock totaled $1.00 per share ($0.25 per quarter).
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17. Supplementary Cash Flow Information
The following information supplements the Statement of Consolidated Cash Flows:
2020
2019
2018
(In millions)
Cash Flows From Operating Activities
Interest paid..................................................................................................................................... $
Net income taxes (paid) refunded...................................................................................................
(460) $
(64)
(380) $
(417)
(394)
(463)
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P:
Capital expenditures incurred - E&P................................................................................................ $
Increase (decrease) in related liabilities............................................................................................
Additions to property, plant and equipment - E&P.................................................................. $
(1,678) $
(218)
(1,896) $
(2,576) $
143
(2,433) $
(1,909)
55
(1,854)
Additions to property, plant and equipment - Midstream:
Capital expenditures incurred - Midstream....................................................................................... $
Increase (decrease) in related liabilities............................................................................................
Additions to property, plant and equipment - Midstream........................................................ $
(253) $
(48)
(301) $
(416) $
20
(396) $
(271)
28
(243)
In December 2019, as part of HESM Opco’s acquisition of HIP (see Note 4, Hess Midstream LP), HESM Opco assumed
$800 million of outstanding HIP notes (see Note 7, Debt).
18. Guarantees, Contingencies and Commitments
Guarantees and Contingencies
We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in
our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If
the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is
not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing
claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in
their early stages of development or where plaintiffs seek indeterminate damages.
We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have been a party
to lawsuits and claims related to the use of MTBE in gasoline. A series of similar lawsuits, many involving water utilities or
governmental entities, were filed in jurisdictions across the U.S. against producers of MTBE and petroleum refiners who produced
gasoline containing MTBE, including us. The principal allegation in all cases was that gasoline containing MTBE was a defective
product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to
groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of
MTBE. The majority of the cases asserted against us have been settled. There are three remaining active cases, filed by Pennsylvania,
Rhode Island, and Maryland.
In June 2014, the Commonwealth of Pennsylvania filed a lawsuit alleging that we and all major oil
companies with operations in Pennsylvania, have damaged the groundwater by introducing thereto gasoline with MTBE. The
Pennsylvania suit has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. In
September 2016, the State of Rhode Island also filed a lawsuit alleging that we and other major oil companies damaged the
groundwater in Rhode Island by introducing thereto gasoline with MTBE. The suit filed in Rhode Island is proceeding in federal
court.
In December 2017, the State of Maryland filed a lawsuit alleging that we and other major oil companies damaged the
groundwater in Maryland by introducing thereto gasoline with MTBE. The suit, filed in Maryland state court, was served on us in
January 2018 and has been removed to federal court by the defendants.
In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate
contamination in the sediments of the Lower Passaic River. The NJDEP is also seeking natural resource damages. The directive,
insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned.
We and over 70 companies entered into an Administrative Order on Consent with the EPA to study the same contamination; this work
remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and agreed with the EPA to fund
remediation of a portion of the site. On March 4, 2016, the EPA issued a Record of Decision (ROD) in respect of the lower eight
miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The
ROD does not address the upper nine miles of the Lower Passaic River or the Newark Bay, which may require additional remedial
action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the
Passaic River. Given that the EPA has not selected a remedy for the entirety of the Lower Passaic River or the Newark Bay, total
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remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this
matter will result in a significant liability to us because our former terminal did not store or use contaminants which are of concern in
the river sediments and could not have contributed contamination along the river’s length. Further, there are numerous other parties
who we expect will bear the cost of remediation and damages.
In March 2014, we received an Administrative Order from the EPA requiring us and 26 other parties to undertake the Remedial
Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. Our alleged liability
derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the
Canal. The remedy selected by the EPA includes dredging of surface sediments and the placement of a cap over the deeper sediments
throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. The EPA’s
original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with
the design and implementation of the remedy remain uncertain. We have complied with the EPA’s March 2014 Administrative Order
and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert.
In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin
Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation
work began in the fourth quarter of 2020. Based on currently known facts and circumstances, we do not believe that this matter will
result in a significant liability to us, and the costs will continue to be allocated amongst the parties, as they were for the Remedial
Design.
From time to time, we are involved in other judicial and administrative proceedings relating to environmental matters. We
periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to
various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For any site
for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been
fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not
material. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island
and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused
by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various
parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations
and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused
contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The
plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly
impacted areas. The ultimate impact of the aforementioned proceedings, and of any related proceedings by private parties, on our
business or accounts cannot be predicted at this time due to the large number of other potentially responsible parties and the
speculative nature of clean-up cost estimates.
We are also involved in other judicial and administrative proceedings from time to time in addition to the matters described above,
including claims related to post-production deductions from royalty payments. We cannot predict with certainty if, how or when such
proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of
development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially
lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any
proceeding.
Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of lawsuits,
claims and proceedings, including the matters disclosed above, is not expected to have a material adverse effect on our financial
condition, results of operations or cash flows. However, we could incur judgments, enter into settlements, or revise our opinion
regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in
the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.
Unconditional Purchase Obligations and Commitments
The following table shows aggregate information for certain unconditional purchase obligations and commitments at
December 31, 2020, which are not included elsewhere within these Consolidated Financial Statements:
Capital expenditures........................................................................................ $
Operating expenses..........................................................................................
Transportation and related contracts................................................................
$
2,837
236
2,867
(In millions)
1,469
$
63
756
$
868
167
310
$
500
5
493
—
1
1,308
Total
2021
Payments Due by Period
2024 and
2022 and
2025
2023
Thereafter
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19. Segment Information
We currently have two operating segments, E&P and Midstream. The E&P operating segment explores for, develops, produces,
purchases and sells crude oil, NGL and natural gas. Production operations over the three years ended December 31, 2020 were in the
United States (U.S.), Malaysia and the JDA, Denmark, Libya, and Guyana commencing December 2019. The Midstream operating
segment provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of
NGL, transportation of crude oil by rail car, terminaling and loading crude oil and NGL, storing and terminaling propane, and water
handling services primarily in the Bakken shale play of North Dakota. All unallocated costs are reflected under Corporate, Interest
and Other.
The following table presents operating segment financial data (in millions):
Exploration
and
Production
Midstream
Corporate,
Interest and
Other
Eliminations
Total
2020
Sales and Other Operating Revenues - Third parties....................... $
Intersegment Revenues....................................................................
Sales and Other Operating Revenues............................................... $
Net Income (Loss) Attributable to Hess Corporation...................... $
Interest Expense...............................................................................
Depreciation, Depletion and Amortization......................................
Impairment.......................................................................................
Provision (Benefit) for Income Taxes (a)........................................
Investment in Affiliates....................................................................
Identifiable Assets............................................................................
Capital Expenditures........................................................................
$
4,667
—
4,667
$
(2,841) $
—
1,915
2,126
(12)
104
13,688
1,678
2019
Sales and Other Operating Revenues - Third parties....................... $
Intersegment Revenues....................................................................
Sales and Other Operating Revenues............................................... $
Net Income (Loss) Attributable to Hess Corporation...................... $
Interest Expense...............................................................................
Depreciation, Depletion and Amortization......................................
Provision (Benefit) for Income Taxes (a)........................................
Investment in Affiliates....................................................................
Identifiable Assets............................................................................
Capital Expenditures........................................................................
2018
Sales and Other Operating Revenues - Third parties....................... $
Intersegment Revenues....................................................................
Sales and Other Operating Revenues............................................... $
Net Income (Loss) Attributable to Hess Corporation...................... $
Interest Expense...............................................................................
Depreciation, Depletion and Amortization......................................
Provision (Benefit) for Income Taxes (a)........................................
Capital Expenditures........................................................................
$
$
$
$
$
$
6,495
—
6,495
53
—
1,977
375
114
16,790
2,576
6,323
—
6,323
51
—
1,748
391
1,909
— $
$
$
1,092
1,092
230
95
157
—
7
108
3,599
253
— $
$
$
848
848
144
63
142
—
108
3,499
416
— $
$
$
713
713
120
60
127
38
271
— $
—
— $
(482) $
373
2
—
(6)
—
1,534
—
— $
—
— $
(605) $
317
3
86
—
1,493
—
— $
—
— $
(453) $
339
8
(94)
—
— $
(1,092)
(1,092) $
— $
—
—
—
—
—
—
—
— $
(848)
(848) $
— $
—
—
—
—
—
—
— $
(713)
(713) $
— $
—
—
—
—
4,667
—
4,667
(3,093)
468
2,074
2,126
(11)
212
18,821
1,931
6,495
—
6,495
(408)
380
2,122
461
222
21,782
2,992
6,323
—
6,323
(282)
399
1,883
335
2,180
(a) Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation
allowance assessment basis. In 2018, the provision for income taxes in the Midstream segment was presented before consolidating its operations with other U.S.
activities of the Corporation and prior to evaluating realizability of net U.S. deferred taxes. An offsetting impact was presented in the E&P segment.
If 2018
segment results were prepared on a basis consistent with 2020 and 2019, Midstream segment net income attributable to Hess Corporation would have been
$158 million and E&P net income attributable to Hess Corporation would have been $13 million.
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The following table presents financial information by major geographic area:
United States
Guyana
Malaysia
and JDA
Other
(In millions)
Corporate,
Interest and
other
Total
2020
Sales and Other Operating Revenues........................................ $
3,604
$
350
$
511
$
Property, Plant and Equipment (Net) (a)...................................
10,384
2,114
1,067
2019
Sales and Other Operating Revenues........................................ $
5,043
$
— $
762
$
Property, Plant and Equipment (Net) (a)...................................
12,182
1,507
1,890
$
202
539
690
$
1,223
— $
11
— $
12
4,667
14,115
6,495
16,814
2018
Sales and Other Operating Revenues........................................ $
4,842
$
— $
769
$
712
$
— $
6,323
(a) Property, plant and equipment in the United States, in 2020, includes $7,273 million (2019: $9,172 million) attributable to the E&P segment and $3,111 million
(2019: $3,010 million) attributable to the Midstream segment.
20. Financial Risk Management Activities
In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural
gas, as well as changes in interest rates and foreign currency values.
In the disclosures that follow, corporate financial risk
management activities refer to the mitigation of these risks through hedging activities. We maintain a control environment for all of
our financial risk management activities under the direction of our Chief Risk Officer. Our Treasury department is responsible for
administering foreign exchange rate and interest
rate hedging programs using similar controls and processes, where
applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors.
Corporate Financial Risk Management Activities: Financial risk management activities include transactions designed to reduce
risk in the selling prices of crude oil or natural gas we produce or by reducing our exposure to foreign currency or interest rate
movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price of a portion of our crude oil or
natural gas production. Swaps may also be used to fix the difference between current selling prices and forward selling prices in
periods of contango for crude oil production that will be stored and sold in the future. Forward contracts may also be used to purchase
certain currencies in which we conduct business with the intent of reducing exposure to foreign currency fluctuations. At
December 31, 2020,
these forward contracts relate to the British Pound, Danish Krone, Canadian Dollar and Malaysian
Ringgit. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.
The notional amounts of outstanding financial risk management derivative contracts were as follows:
December 31,
2020
December 31,
2019
Commodity - crude oil put options (millions of barrels)................................................................................................
Foreign exchange forwards............................................................................................................................................. $
Interest rate swaps........................................................................................................................................................... $
(In millions)
27.4
163
100
$
$
54.9
90
100
At December 31, 2020, we had WTI put options with an average monthly floor price of approximately $45 per barrel for 75,000
bopd for 2021. In the first quarter of 2021, we increased the average monthly floor price of 75,000 bopd of WTI put option contracts
from approximately $45 per barrel to $50 per barrel for the remainder of 2021. We also purchased additional WTI put options with an
average monthly floor price of $50 per barrel for 45,000 bopd and Brent put options with an average monthly floor price of $55 per
barrel for 30,000 bopd. As a result, we now have total purchased WTI put options of 120,000 bopd with an average monthly floor
price of $50 per barrel and total purchased Brent put options of 30,000 bopd with an average monthly floor price of $55 per barrel for
the remainder of 2021.
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The table below reflects the gross and net fair values of risk management derivative instruments:
December 31, 2020
Derivative Contracts Designated as Hedging Instruments:
Crude oil put options.................................................................................................................................................. $
Crude oil swaps..........................................................................................................................................................
Interest rate swaps......................................................................................................................................................
Total derivative contracts designated as hedging instruments...................................................................................
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange forwards........................................................................................................................................
Total derivative contracts not designated as hedging instruments.............................................................................
Gross fair value of derivative contracts......................................................................................................................
Gross amount offset in the Consolidated Balance Sheet............................................................................................
Net Amounts Presented in the Consolidated Balance Sheet................................................................................... $
December 31, 2019
Derivative Contracts Designated as Hedging Instruments:
Crude oil put options.................................................................................................................................................. $
Interest rate swaps......................................................................................................................................................
Total derivative contracts designated as hedging instruments...................................................................................
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange forwards........................................................................................................................................
Total derivative contracts not designated as hedging instruments.............................................................................
Gross fair value of derivative contracts......................................................................................................................
Gross amount offset in the Consolidated Balance Sheet............................................................................................
Net Amounts Presented in the Consolidated Balance Sheet................................................................................... $
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Assets
Liabilities
(In millions)
64
—
5
69
—
—
69
(13)
56
125
1
126
—
—
126
—
126
$
$
$
$
—
(54)
—
(54)
(1)
(1)
(55)
13
(42)
—
—
—
(1)
(1)
(1)
—
(1)
In 2020, we chartered three VLCCs to load and transport a total of 6.3 million barrels of Bakken crude oil for sale in Asian
markets. The first VLCC cargo of 2.1 million barrels was sold in September 2020. We have entered into agreements for the sale of
the remaining 4.2 million barrels of crude oil in the first quarter of 2021. In connection with this activity, we entered into Brent swap
transactions intended to fix the difference between Brent prices in the month of production and the forward Brent price for the
expected month of sale. At December 31, 2020, net realized and unrealized losses from the Brent swaps of $16 million were deferred
in Accumulated other comprehensive income, and the liability for unrealized losses from the Brent swaps was $54 million.
In
addition, total net realized gains from WTI put options associated with the VLCCs of $40 million were deferred in Accumulated other
comprehensive income at December 31, 2020.
The fair value of our crude oil put options and crude oil swaps is presented within Other current assets and Accrued liabilities,
respectively, in our Consolidated Balance Sheet. The fair value of our interest rate swaps is presented within Other assets in our
Consolidated Balance Sheet. The fair value of our foreign exchange forwards is presented within Accrued liabilities in our
Consolidated Balance Sheet. All fair values in the table above are based on Level 2 inputs.
Derivative contracts designated as hedging instruments:
Crude oil derivatives: In 2020, crude oil price hedging contracts increased Sales and other operating revenues by $547 million
(2019: increase of $1 million; 2018: decrease of $161 million). At December 31, 2020, pre-tax deferred gains in Accumulated other
comprehensive income (loss) related to outstanding crude oil price hedging contracts were $4 million, of which all will be reclassified
into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.
Interest rate swaps designated as fair value hedges: At December 31, 2020, we had interest rate swaps with gross notional
amounts of $100 million (2019: $100 million), which were designated as fair value hedges and relate to long-term debt where we have
converted interest payments from fixed to floating rates. Changes in the fair value of interest rate swaps and the hedged fixed‑rate
debt are recorded in Interest expense in the Statement of Consolidated Income. In 2020, the change in fair value of interest rate swaps
was an increase in the asset of $4 million (2019: $3 million decrease in liability; 2018: $1 million increase in liability) with a
corresponding adjustment in the carrying value of the hedged fixed‑rate debt.
Derivative contracts not designated as hedging instruments:
Foreign exchange: Total foreign exchange gains and losses were losses of $6 million in 2020 (2019: gain of $3 million; 2018:
loss of $5 million) and are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income. A
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component of foreign exchange gains or losses is the result of foreign exchange derivative contracts that are not designated as hedges,
which amounted to a gain of $2 million in 2020 (2019: loss of $2 million; 2018: loss of $2 million).
Crude oil collars:
In 2018, noncash adjustments to de-designated crude oil price hedging contracts decreased Sales and other
operating revenues by $22 million.
Credit Risk: We are exposed to credit risks that may at times be concentrated with certain counterparties, groups of counterparties
or customers. Accounts receivable are generated from a diverse domestic and international customer base. At December 31, 2020,
our Accounts receivable were concentrated with the following counterparty industry segments:
Integrated companies — 39%,
Independent E&P companies — 39%, Refining and marketing companies — 8%, National oil companies — 5%, Storage and
transportation companies — 5%, and Others — 4%. We reduce risk related to certain counterparties, where applicable, by using
master netting arrangements and requiring collateral, generally cash or letters of credit.
At December 31, 2020, we had outstanding letters of credit totaling $269 million (2019: $272 million).
Fair Value Measurement: At December 31, 2020, our total long-term debt, which was substantially comprised of fixed rate debt
instruments, had a carrying value of $8,296 million and a fair value of $9,647 million, based on Level 2 inputs in the fair value
measurement hierarchy. We also have short-term financial instruments, primarily cash equivalents, accounts receivable and accounts
payable, for which the carrying value approximated fair value at December 31, 2020 and December 31, 2019.
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
The Supplementary Oil and Gas Data that follows is presented in accordance with ASC 932, Disclosures about Oil and Gas
Producing Activities, and includes (1) costs incurred, capitalized costs and results of operations relating to oil and gas producing
activities, (2) net proved oil and gas reserves and (3) a standardized measure of discounted future net cash flows relating to proved oil
and gas reserves, including a reconciliation of changes therein.
During the three-year period ended December 31, 2020, we produced crude oil, NGL and natural gas in the United States (U.S.),
Malaysia and the JDA, Denmark, Libya, and Guyana commencing December 2019. Exploration and/or development activities were
also conducted in certain of these producing areas as well as offshore Suriname and Canada.
Costs Incurred in Oil and Gas Producing Activities
For the Years Ended December 31
2020
Property acquisitions
Unproved.....................................................................................
Proved..........................................................................................
Exploration....................................................................................
Production and development capital expenditures (a)..................
2019
Property acquisitions
Unproved.....................................................................................
Proved..........................................................................................
Exploration....................................................................................
Production and development capital expenditures (a)..................
2018
Property acquisitions
Unproved.....................................................................................
Proved..........................................................................................
Exploration....................................................................................
Production and development capital expenditures (a)..................
$
$
$
Total
United
States
Malaysia and
JDA
Other
Guyana
(In millions)
— $
—
307
1,567
$
$
26
—
455
2,463
51
43
442
1,577
— $
—
169
804
$
$
26
—
174
1,735
43
43
111
1,239
— $
—
130
630
— $
—
239
585
$
8
—
131
244
— $
—
2
106
— $
—
4
114
— $
—
32
92
—
—
6
27
—
—
38
29
—
—
168
2
(a) Includes an increase of $88 million for asset retirement obligations related to net accruals and revisions in 2020 (2019: $201 million increase; 2018: $44 million
increase).
Capitalized Costs Relating to Oil and Gas Producing Activities
At December 31,
2020
2019
Unproved properties..................................................................................................................................... $
Proved properties..........................................................................................................................................
Wells, equipment and related facilities.........................................................................................................
Total costs..................................................................................................................................................
Less: Reserve for depreciation, depletion, amortization and lease impairment........................................
Net Capitalized Costs............................................................................................................................ $
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(In millions)
164
2,930
23,224
26,318
15,325
10,993
$
168
3,304
28,404
31,876
18,084
13,792
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Results of Operations for Oil and Gas Producing Activities
The results of operations shown below exclude non‑oil and gas producing activities, primarily gains (losses) on sales of oil and
gas properties, sales of purchased crude oil, NGL and natural gas from third parties, interest expense and non-operating income.
Therefore, these results are on a different basis than the net income (loss) from E&P operations reported in Management’s Discussion
and Analysis of Financial Condition and Results of Operations and in Note 19, Segment Information in the Notes to Consolidated
Financial Statements. Other includes results for Denmark, Libya, Canada and Suriname.
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For the Years Ended December 31
2020
Sales and Other Operating Revenues................................................. $
Costs and Expenses
Operating costs and expenses...........................................................
Production and severance taxes........................................................
Midstream tariffs..............................................................................
Exploration expenses, including dry holes and lease impairment...
General and administrative expenses...............................................
Depreciation, depletion and amortization........................................
Impairment.......................................................................................
Total Costs and Expenses...............................................................
Results of Operations Before Income Taxes......................................
Provision (benefit) for income taxes................................................
Results of Operations...........................................................................
$
Total
United
States
Malaysia
and JDA
Other
Guyana (a)
(In millions)
3,794
$
2,747
$
345
$
511
$
191
895
124
946
351
206
1,915
2,126
6,563
(2,769)
(4)
(2,765) $
564
118
946
284
176
1,480
697
4,265
(1,518)
—
(1,518) $
136
—
—
25
9
130
—
300
45
9
36
$
109
6
—
—
12
268
755
1,150
(639)
22
(661) $
2019
Sales and Other Operating Revenues................................................. $
Costs and Expenses
Operating costs and expenses...........................................................
Production and severance taxes........................................................
Midstream tariffs..............................................................................
Exploration expenses, including dry holes and lease impairment...
General and administrative expenses...............................................
Depreciation, depletion and amortization........................................
Total Costs and Expenses...............................................................
Results of Operations Before Income Taxes......................................
Provision (benefit) for income taxes................................................
Results of Operations...........................................................................
$
4,719
$
3,361
$
— $
759
$
971
184
722
233
204
1,977
4,291
428
325
103
$
693
176
722
144
176
1,489
3,400
(39)
—
(39) $
47
—
—
47
7
1
102
(102)
(60)
(42) $
139
8
—
3
12
413
575
184
13
171
$
86
—
—
42
9
37
674
848
(657)
(35)
(622)
599
92
—
—
39
9
74
214
385
372
13
2018
Sales and Other Operating Revenues................................................. $
Costs and Expenses
Operating costs and expenses...........................................................
Production and severance taxes........................................................
Midstream tariffs..............................................................................
Exploration expenses, including dry holes and lease impairment...
General and administrative expenses...............................................
Depreciation, depletion and amortization........................................
Total Costs and Expenses...............................................................
Results of Operations Before Income Taxes......................................
Provision (benefit) for income taxes................................................
Results of Operations...........................................................................
$
4,515
$
3,141
$
— $
755
$
619
941
171
648
362
258
1,748
4,128
387
337
50
$
697
165
648
119
230
1,297
3,156
(15)
(63)
48
$
24
—
—
40
4
—
68
(68)
—
(68) $
129
6
—
6
10
395
546
209
11
198
$
91
—
—
197
14
56
358
261
389
(128)
(a) Production from Liza Phase 1 commenced in December 2019. Operating costs and expenses also include pre-development costs from the operator for future
phases of development and Hess internal costs.
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Proved Oil and Gas Reserves
Our proved oil and gas reserves are calculated in accordance with the Securities and Exchange Commission (SEC) regulations
and the requirements of the Financial Accounting Standards Board. Proved oil and gas reserves are quantities, which by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs
under existing economic conditions, operating methods and government regulations. Our estimation of net recoverable quantities of
liquid hydrocarbons and natural gas is a highly technical process performed by our internal teams of geoscience and reservoir
engineering professionals. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and
evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented
in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information (Revision as of June 25, 2019).” The method or combination of methods used in the analysis of each reservoir
is based on the maturity of the reservoir, the completeness of the subsurface data available at the time of the estimate, the stage of
reservoir development and the production history. Subsurface data used included well logs, reservoir core and fluid samples,
production and pressure testing, static and dynamic pressure information, and reservoir surveillance. Where applicable, reliable
technologies may be used in reserve estimation, as defined in the SEC regulations. These technologies, including computational
methods, must have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the
formation being evaluated or in an analogous formation. In some cases, where appropriate, use of empirical and analytical methods,
combined with analog data were used. Analytic tools, including reservoir simulation, geologic modeling and seismic processing, have
been used in the interpretation of the subsurface data. These technologies were used to increase the quality and confidence in the
reserves estimates.
In order for reserves to be classified as proved, any required government approvals must be obtained and depending on the cost
of the project, either senior management or the Board of Directors must commit to fund the development. Our proved reserves are
subject to certain risks and uncertainties, which are discussed in Item 1A. Risk Factors of this Form 10‑K.
Internal Controls
The Corporation maintains internal controls over its oil and gas reserve estimation processes, which are administered by our
Global Reserves group and our Chief Financial Officer. Estimates of reserves are prepared by technical staff who work directly with
the oil and gas properties using industry standard reserve estimation principles, definitions and methodologies. Each year, reserve
estimates of the Corporation’s assets are subject to internal technical audits and reviews.
In addition, an independent third-party
reserve engineer reviews and audits a significant portion of the Corporation’s reported reserves (see pages 93 through 97). Reserve
estimates are reviewed by senior management and the Board of Directors.
Qualifications
The person primarily responsible for overseeing the preparation of the Corporation’s oil and gas reserves during 2020 was the
Senior Manager, Global Reserves. He is a member of the Society of Petroleum Engineers and has 18 years of experience in the oil
and gas industry with a MSc degree in Petroleum Engineering. His experience has been primarily focused on oil and gas subsurface
understanding and reserves estimation in both domestic and international areas. He is also responsible for the Corporation’s Global
Reserves group, which is the internal organization that establishes the policies and processes used within the operating units to
estimate reserves and perform internal technical reserve audits and reviews.
Reserves Audit
We engaged the consulting firm of DeGolyer and MacNaughton (D&M) to perform an audit of the internally prepared reserve
estimates on certain fields aggregating 92% of 2020 year‑end reported reserve quantities on a barrel of oil equivalent basis (2019:
80%). The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates
and compliance with SEC regulations. The D&M report, dated February 3, 2021, on the Corporation’s estimated oil and gas reserves
was prepared using standard geological and engineering methods generally recognized in the petroleum industry. D&M is an
independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for
over 70 years. D&M’s letter report on the Corporation’s December 31, 2020 oil and gas reserves is included as an exhibit to this
Form 10‑K. While the D&M report should be read in its entirety, the report concludes that for the properties reviewed by D&M, the
total net proved reserve estimates prepared by Hess and audited by D&M, in the aggregate, differed by less than 1% (2019: less than
1%) of total audited net proved reserves on a barrel of oil equivalent basis. The report also includes among other information, the
qualifications of the technical person primarily responsible for overseeing the reserve audit.
Crude Oil Prices Used to Estimate Proved Reserves
Proved reserves are calculated using the average price during the twelve-month period before December 31 determined as an
unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by
contractual agreements, excluding escalations based on future conditions. Crude oil prices used in the determination of proved
reserves at December 31, 2020 were $39.77 per barrel for WTI (2019: $55.73; 2018: $65.55) and $43.43 per barrel for Brent (2019:
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$62.54; 2018: $72.08). New York Mercantile Exchange (NYMEX) natural gas prices used were $2.16 per mcf in 2020 (2019: $2.54;
2018: $3.01).
At December 31, 2020, spot prices for WTI oil closed at $48.52 per barrel. If crude oil prices in 2021 are at levels below that
used in determining 2020 proved reserves, we may recognize negative revisions to our December 31, 2021 proved undeveloped
reserves. In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to
differing operating cost structures. Conversely, price increases in 2021 above those used in determining 2020 proved reserves could
result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2021. It is difficult to estimate the
magnitude of any potential net negative or positive change in proved reserves at December 31, 2021, due to numerous currently
unknown factors, including 2021 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions in
proved reserves related to 2021 reservoir performance, the levels to which industry costs will change in response to 2021 crude oil
prices, and management’s plans as of December 31, 2021 for developing proved undeveloped reserves.
Following are the Corporation’s proved reserves:
Crude Oil & Condensate
Natural Gas Liquids
United
States
Guyana
Malaysia
and
JDA
Other (a)
Total
(Millions of bbls)
United
States
Total
(Millions of bbls)
Net Proved Reserves
At January 1, 2018........................................................
Revisions of previous estimates....................................
Extensions, discoveries and other additions..................
Purchase of minerals in place........................................
Sales of minerals in place..............................................
Production.....................................................................
At December 31, 2018...................................................
Revisions of previous estimates....................................
Extensions, discoveries and other additions..................
Production.....................................................................
At December 31, 2019...................................................
Revisions of previous estimates ...................................
Extensions, discoveries and other additions..................
Sales of minerals in place..............................................
Production.....................................................................
At December 31, 2020...................................................
Net Proved Developed Reserves
At January 1, 2018..........................................................
At December 31, 2018....................................................
At December 31, 2019....................................................
At December 31, 2020...................................................
Net Proved Undeveloped Reserves
At January 1, 2018..........................................................
At December 31, 2018....................................................
At December 31, 2019....................................................
At December 31, 2020...................................................
(a) Other includes our interests in Denmark and Libya.
433
(3)
114
3
(3)
(43)
501
(54)
112
(51)
508
(94)
58
(18)
(53)
401
239
266
293
282
194
235
215
119
43
(3)
—
—
—
—
40
13
33
—
86
78
48
—
(8)
204
—
—
31
72
43
40
55
132
6
1
2
—
—
(1)
8
—
1
(2)
7
—
—
—
(1)
6
5
4
5
4
1
4
2
2
177
(12)
9
—
—
(9)
165
(6)
11
(9)
161
(24)
—
—
(3)
134
157
149
139
134
20
16
22
—
659
(17)
125
3
(3)
(53)
714
(47)
157
(62)
762
(40)
106
(18)
(65)
745
401
419
468
492
258
295
294
253
171
(14)
39
1
(8)
(14)
175
(29)
40
(17)
169
(2)
18
(1)
(22)
162
87
85
90
120
84
90
79
42
171
(14)
39
1
(8)
(14)
175
(29)
40
(17)
169
(2)
18
(1)
(22)
162
87
85
90
120
84
90
79
42
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United
States
Guyana
Natural Gas
Malaysia
and
JDA
Other (b)
Total
United
States
Guyana
Total
Malaysia
and
JDA
Other (b)
Total
(Millions of mcf)
(Millions of boe)
62540 10K
95
Net Proved Reserves
At January 1, 2018
Revisions of previous estimates.....
Extensions, discoveries and other
additions.........................................
Purchase of minerals in place........
Sales of minerals in place..............
Production (a).................................
At December 31, 2018....................
Revisions of previous estimates.....
Extensions, discoveries and other
additions.........................................
Production (a).................................
At December 31, 2019....................
Revisions of previous estimates ....
Extensions, discoveries and other
additions.........................................
Sales of minerals in place..............
Production (a).................................
At December 31, 2020....................
Net Proved Developed Reserves
At January 1, 2018...........................
At December 31, 2018.....................
At December 31, 2019.....................
At December 31, 2020....................
Net Proved Undeveloped Reserves
At January 1, 2018...........................
At December 31, 2018.....................
At December 31, 2019.....................
At December 31, 2020....................
880
(24)
177
—
(145)
(75)
813
(197)
164
(80)
700
(17)
78
(5)
(103)
653
526
432
400
490
354
381
300
163
12
—
—
—
—
—
12
(7)
2
—
7
68
9
—
(1)
83
—
—
3
36
12
12
4
47
833
(21)
104
—
—
(132)
784
31
3
(133)
685
216
1,941
(13)
11
—
—
(8)
206
(11)
15
(9)
201
(58)
292
—
(145)
(215)
1,815
(184)
184
(222)
1,593
81
(32)
100
20
—
(111)
675
696
585
497
543
137
199
188
132
—
—
(4)
165
197
192
183
165
19
14
18
—
107
(5)
(219)
1,576
1,419
1,209
1,083
1,234
522
606
510
342
751
(21)
183
4
(35)
(70)
812
(116)
179
(81)
794
(99)
89
(20)
(92)
672
414
423
450
484
337
389
344
188
45
(3)
—
—
—
—
42
12
33
—
87
89
50
—
(8)
218
—
—
31
78
45
42
56
140
145
(2)
19
—
—
(23)
139
4
2
(24)
121
14
3
—
(20)
118
121
102
88
94
24
37
33
24
213
1,154
(15)
11
—
—
(10)
199
(7)
14
(11)
195
(29)
—
—
(4)
162
190
181
170
162
23
18
25
—
(41)
213
4
(35)
(103)
1,192
(107)
228
(116)
1,197
(25)
142
(20)
(124)
1,170
725
706
739
818
429
486
458
352
(a) Natural gas production in 2020 includes 16 million mcf used for fuel (2019: 14 million mcf; 2018: 13 million mcf).
(b) Other includes our interests in Denmark and Libya.
Extensions, discoveries and other additions (‘Additions’)
2020: Total Additions were 142 million boe, of which 12 million boe (8 million barrels of crude oil, 2 million barrels of NGL and
14 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves primarily resulted
from drilling activity in the Bakken shale play in North Dakota. Additions to proved undeveloped reserves were 130 million boe
(98 million barrels of crude oil, 16 million barrels of NGL and 93 million mcf of natural gas) and are discussed in further detail on
page 96.
2019: Total Additions were 228 million boe, of which 25 million boe (13 million barrels of crude oil, 6 million barrels of NGL
and 35 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves primarily
resulted from new wells drilled in the Bakken shale play in North Dakota. Additions in the U.S. also included two wells drilled in
the Gulf of Mexico. Additions to proved undeveloped reserves were 203 million boe (144 million barrels of crude oil, 34 million
barrels of NGL and 149 million mcf of natural gas) and are discussed in further detail on page 97.
2018: Total Additions were 213 million boe, of which 6 million boe (3 million barrels of crude oil and 18 million mcf of natural
gas) related to proved developed reserves. Additions to proved developed reserves were primarily from drilling activity in the
Bakken shale play in North Dakota. Additions to proved undeveloped reserves were 207 million boe (122 million barrels of crude
oil, 39 million barrels of NGL and 274 million mcf of natural gas) and are discussed in further detail on page 97.
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Revisions of previous estimates
2020: Total revisions of previous estimates of proved reserves amounted to a net decrease of 25 million boe, of which revisions
of proved developed reserves amounted to an increase of 108 million boe (38 million barrels of crude oil, 30 million barrels of
NGL and 237 million mcf of natural gas).
In the U.S., revisions to proved developed reserves from the Bakken were a net
increase of 55 million boe, comprised of positive revisions of 77 million boe and negative price revisions of 22 million boe. The
positive revisions resulted from well performance (50%), updated yield and decline factors (30%) and other changes (20%),
primarily driven by cost reductions. In the Gulf of Mexico, net negative revisions were 8 million boe, including 2 million boe of
negative price revisions.
In Guyana, revisions increased proved developed reserves by 47 million boe related to performance
(55%), improved recovery associated with water injection (35%), and increased natural gas for consumption (10%). In Malaysia
and JDA, net revisions to proved developed reserves were an increase of 18 million boe due to performance at North Malay Basin
and JDA (80%) and the impact of lower crude oil prices on entitlement allocations in the production sharing contract at JDA
(20%). Other had negative revisions to proved developed reserves of 4 million boe, primarily in Libya. Revisions associated with
proved undeveloped reserves are discussed in further detail on page 97.
2019: Total revisions of previous estimates amounted to a net decrease of 107 million boe, of which revisions of proved
developed reserves amounted to a net decrease of 19 million boe (7 million barrels of NGL and 72 million mcf of natural
gas). Revisions to proved developed reserves from the Bakken were a net decrease of 25 million boe with approximately 80%
relating to changes in expected recoveries of NGL and natural gas and approximately 20% relating to the impact of lower
prices. Net revisions from international assets were an increase of 6 million boe. Revisions associated with proved undeveloped
reserves are discussed in further detail on page 97.
2018: Total revisions of previous estimates amounted to a net decrease of 41 million boe, of which revisions of proved developed
reserves amounted to a net increase of 3 million boe (4 million barrels of crude oil increase, 4 million barrels of NGL decrease
and 20 million mcf of natural gas increase). Revisions to proved developed reserves primarily relate to the Bakken. Revisions
associated with proved undeveloped reserves are discussed in further detail on page 97.
Sales of minerals in place (‘Asset sales’)
2020: Asset sales relate to the divestiture of our 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico.
2018: Asset sales primarily include our former interests in the Utica Basin of Ohio.
Proved Undeveloped Reserves
Following are the Corporation’s proved undeveloped reserves:
Net Proved Undeveloped Reserves
At January 1, 2018.........................................................................
Revisions of previous estimates....................................................
Extensions, discoveries and other additions..................................
Transfers to proved developed reserves........................................
Sales of minerals in place..............................................................
At December 31, 2018....................................................................
Revisions of previous estimates....................................................
Extensions, discoveries and other additions..................................
Transfers to proved developed reserves........................................
At December 31, 2019....................................................................
Revisions of previous estimates....................................................
Extensions, discoveries and other additions..................................
Transfers to proved developed reserves........................................
Sales of minerals in place..............................................................
At December 31, 2020....................................................................
(a) Other includes our interests in Denmark and Libya.
Extensions, discoveries and other additions (‘Additions’)
United
States
Guyana
Malaysia and
JDA
(Millions of boe)
Other (a)
Total
337
(22)
178
(97)
(7)
389
(91)
154
(108)
344
(146)
78
(85)
(3)
188
45
(3)
—
—
—
42
9
34
(29)
56
42
50
(8)
—
140
24
(6)
19
—
—
37
—
—
(4)
33
(4)
2
(7)
—
24
23
(13)
10
(2)
—
18
(6)
15
(2)
25
(25)
—
—
—
—
429
(44)
207
(99)
(7)
486
(88)
203
(143)
458
(133)
130
(100)
(3)
352
2020: In the United States, additions from the Bakken shale play in North Dakota were 78 million boe, which primarily resulted
from new wells planned to be drilled in the next five years, including the impact of optimizing locations in the development plan.
In Guyana, additions of 50 million boe were due to the sanction of the Payara project. In Malaysia, additions at the North Malay
Basin were due to additional planned wells to be drilled.
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2019: In the United States, additions from the Bakken shale play in North Dakota were 154 million boe, of which approximately
25% of the change results from additional planned wells to be drilled in the next five years, and approximately 75% results from
new wells moved into the five-year plan associated with optimization of drilling locations. Additions in Guyana totaling 34
million boe are from the sanction of Phase 2 development at the Liza Field on the Stabroek Block, offshore Guyana. Other
additions were at the South Arne Field in Denmark and in Libya due to additional planned wells to be drilled.
2018: In the United States, additions from the Bakken shale play in North Dakota were 168 million boe, of which approximately
40% of the change results from additional planned wells to be drilled in the next five years, approximately 35% results from
performance associated with improved well completion designs, and approximately 25% results from other changes, primarily the
impact of higher crude oil prices. Additions in the Gulf of Mexico were 10 million boe due to additional planned drilling at the
Tubular Bells Field. Additions in Malaysia and JDA include 11 million boe at North Malay Basin and 8 million boe at the JDA
relating to additional planned wells to be drilled within the next five years.
Revisions of previous estimates
2020: In the United States, negative reserve revisions of 146 million boe were from the Bakken, which included negative price
revisions of 77 million boe, and a decrease of 121 million boe from wells moved outside our management and Board approved
five-year plan due to a reduction in planned rig count and optimization of drilling locations in response to the decline in crude oil
prices in 2020. These decreases were partially offset by positive revisions of 52 million boe, primarily due to optimized
In Guyana, net positive reserve revisions for Liza Phase 1 and Phase 2
development spacing and increased well productivity.
totaling 42 million boe resulted from improved recovery associated with water injection (45%), the impact of lower crude oil
prices on entitlement allocations in the production sharing contract (40%) and increased natural gas for consumption (15%). For
Other, net negative reserves revisions were 14 million boe in Libya and 11 million boe in Denmark due to moving planned wells
outside our five-year plan in response to the decline in crude oil prices in 2020.
2019: Negative reserve revisions in the United States of 91 million boe were largely from the Bakken (94 million boe), of which
approximately 75% resulted from wells moved outside our five-year plan associated with optimization of drilling locations. The
remaining 25% of negative revisions in the Bakken were caused by lower commodity prices. The net positive reserve revisions in
Guyana of 9 million boe relate to the Liza Phase 1 development due to the impact of lower crude oil prices on entitlement
allocations in the production sharing agreement.
2018: Negative reserve revisions in the United States totaling 22 million boe, primarily resulted from optimizing drilling plans at
the Bakken. Negative reserve revisions in international assets primarily resulted from updates in drilling plans in Denmark and
North Malay Basin, and the impact of crude oil price changes on our production sharing agreement in Guyana.
Transfers to proved developed reserves (‘Transfers’)
2020: Transfers from proved undeveloped reserves resulting from drilling activity included 83 million boe in the Bakken, 2
million boe in the Gulf of Mexico, 8 million boe for Liza Phase 1 in Guyana, and 7 million boe in the North Malay Basin.
2019: Transfers from proved undeveloped reserves included 100 million boe in the Bakken associated with drilling activity, 29
million boe at the Stabroek Block in Guyana where first production was achieved in 2019, and 8 million boe at the Tubular Bells
Field in the Gulf of Mexico associated with drilling activity.
2018: Transfers from proved undeveloped reserves included 75 million boe in the Bakken associated with drilling activity, and
22 million boe at the Stampede Field in the Gulf of Mexico where first production was achieved in 2018.
In 2020, capital expenditures of $1,090 million were incurred to convert proved undeveloped reserves to proved developed
reserves (2019: $1,750 million; 2018: $1,070 million).
At December 31, 2020, projects that have proved reserves that have been classified as undeveloped for a period in excess of
five years totaled 4.7 million boe, or less than 1% of total proved reserves, primarily related to the multi-phase development at North
Malay Basin, offshore Malaysia.
Production Sharing Contracts
The Corporation’s proved reserves include crude oil and natural gas reserves relating to long‑term agreements with governments
or authorities in which the Corporation has the legal right to produce or has a revenue interest in the production. The Corporation's
operations with these production sharing arrangements include those in Guyana, Malaysia, and the JDA. Proved reserves for each of
the three years ended December 31, 2020, as well as volumes produced and received during 2020, 2019 and 2018 from these
production sharing contracts are presented in the proved reserve tables on pages 94 and 95. Revisions resulting from the entitlement
impact of price changes in production sharing contracts increased proved reserves by 22 million boe in 2020 (2019: 5 million boe
increase; 2018: 7 million boe decrease).
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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future net cash flows are calculated by applying prescribed oil and gas selling prices used in determining year‑end reserve
estimates (adjusted for price changes provided by contractual arrangements) to estimated future production of proved oil and gas
reserves, less estimated future development and production costs, which are based on year‑end costs and existing economic
assumptions. Future income tax expenses are computed by applying the appropriate year‑end statutory tax rates to the pre‑tax net cash
flows, as well as including the effect of tax deductions and tax credits and allowances relating to the Corporation’s proved oil and gas
reserves. Future net cash flows are discounted at the prescribed rate of 10%.
The prices used for the discounted future net cash flows in 2020 were $39.77 per barrel for WTI (2019: $55.73; 2018: $65.55) and
$43.43 per barrel for Brent (2019: $62.54; 2018: $72.08) and do not include the effects of commodity hedges. NYMEX natural gas
prices used were $2.16 per mcf in 2020 (2019: $2.54; 2018: $3.01). Selling prices have in the past, and can in the future, fluctuate
significantly. As a result, selling prices used in the disclosure of future net cash flows may not be representative of future selling
prices. In addition, the discounted future net cash flow estimates do not include exploration expenses, interest expense or corporate
general and administrative expenses. The amount of tax deductions, credits, and allowances relating to the Corporation’s proved oil
and gas reserves can change year to year due to factors including changes in proved reserves, variances in actual pre-tax cash flows
from forecasted pre-tax cash flows in historical periods, and the impact to year-end carryforward tax attributes associated with
deducting in the Corporation’s income tax returns exploration expenses, interest expense, and corporate general and administrative
expenses that are not contemplated in the standardized measure computations. The future net cash flow estimates could be materially
different if other assumptions were used.
At December 31
2020
Future revenues...............................................................................................
Less:
Future production costs............................................................................
Future development costs.........................................................................
Future income tax expenses......................................................................
Future net cash flows......................................................................................
Less: Discount at 10% annual rate.................................................................
Standardized Measure of Discounted Future Net Cash Flows...................
$
Total
United
States
Guyana
(In millions)
Malaysia
and
JDA
Other (a)
$
28,745
$
11,757
$
8,362
$
2,578
$
6,048
12,360
6,322
4,135
22,817
5,928
2,343
3,585
$
6,887
2,593
45
9,525
2,232
1,205
1,027
$
2,784
2,617
380
5,781
2,581
935
1,646
$
1,073
677
110
1,860
718
123
595
$
1,616
435
3,600
5,651
397
80
317
2019
Future revenues...............................................................................................
Less:
Future production costs............................................................................
Future development costs.........................................................................
Future income tax expenses......................................................................
Future net cash flows......................................................................................
Less: Discount at 10% annual rate.................................................................
Standardized Measure of Discounted Future Net Cash Flows...................
2018
Future revenues...............................................................................................
Less:
Future production costs............................................................................
Future development costs.........................................................................
Future income tax expenses......................................................................
Future net cash flows......................................................................................
Less: Discount at 10% annual rate.................................................................
Standardized Measure of Discounted Future Net Cash Flows...................
$
44,778
$
25,223
$
5,326
$
3,473
$
10,756
14,176
8,267
8,560
31,003
13,775
5,390
8,385
$
10,189
5,104
1,291
16,584
8,639
3,872
4,767
$
931
1,549
505
2,985
2,341
539
1,802
$
1,238
823
162
2,223
1,250
270
980
$
1,818
791
6,602
9,211
1,545
709
836
50,948
$
31,460
$
2,826
$
4,443
$
12,219
13,636
8,427
10,950
33,013
17,935
7,285
10,650
$
9,718
6,132
2,641
18,491
12,969
5,437
7,532
$
605
596
334
1,535
1,291
553
738
$
1,324
949
233
2,506
1,937
492
1,445
$
1,989
750
7,742
10,481
1,738
803
935
$
$
$
(a) Other includes our interests in Denmark and Libya.
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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
For the Years Ended December 31
2020
2019
2018
Standardized Measure of Discounted Future Net Cash Flows at January 1.......................................
$
8,385
(In millions)
10,650
$
$
6,356
Changes during the year:
Sales and transfers of oil and gas produced during the year, net of production costs............................
Development costs incurred during the year..........................................................................................
Net changes in prices and production costs............................................................................................
Net change in estimated future development costs................................................................................
Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs.
Revisions of previous oil and gas reserve estimates...............................................................................
Net purchases (sales) of minerals in place, before income taxes...........................................................
Accretion of discount..............................................................................................................................
Net change in income taxes....................................................................................................................
Revision in rate or timing of future production and other changes........................................................
Total..................................................................................................................................................
Standardized Measure of Discounted Future Net Cash Flows at December 31..................................
$
(1,829)
1,479
(10,141)
1,860
543
364
(500)
1,220
2,091
113
(4,800)
3,585
$
(2,842)
2,262
(5,761)
(186)
1,591
(281)
—
1,635
1,305
12
(2,265)
8,385
$
(2,755)
1,533
7,076
(1,119)
2,129
(630)
(83)
929
(2,662)
(124)
4,294
10,650
99
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) as of December 31, 2020, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer,
concluded that these disclosure controls and procedures were effective as of December 31, 2020.
There was no change in internal controls over financial reporting identified in the evaluation required by paragraph (d) of
Rules 13a-15 or 15d-15 in the quarter ended December 31, 2020 that has materially affected, or is reasonably likely to materially
affect, internal controls over financial reporting.
Management’s report on internal control over financial reporting and the attestation report on the Corporation’s internal controls
over financial reporting are included in Item 8. Financial Statements and Supplementary Data of this annual report on Form 10‑K.
Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and Corporate Governance
PART III
For information regarding our executive officers, see Part I of this Annual Report on Form 10-K. Additional information required
by this item is incorporated herein by reference to the Corporation’s definitive proxy statement for the 2021 annual meeting of
stockholders.
The Corporation has adopted a Code of Business Conduct and Ethics applicable to the Corporation’s directors, officers (including
the Corporation’s principal executive officer and principal financial officer) and employees. The Code of Business Conduct and
Ethics is available on the Corporation’s website. In the event that we amend or waive any of the provisions of the Code of Business
Conduct and Ethics that relate to any element of the code of ethics definition enumerated in Item 406(b) of Regulation S‑K, we intend
to disclose the same on the Corporation’s website at www.hess.com.
Item 11. Executive Compensation
Information relating to executive compensation is incorporated herein by reference to the Corporation’s definitive proxy statement
for the 2021 annual meeting of stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information pertaining to security ownership of certain beneficial owners and management is incorporated herein by reference to
the Corporation’s definitive proxy statement for the 2021 annual meeting of stockholders.
See Equity Compensation Plans in Item 5. Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer
Purchases of Equity Securities for information pertaining to securities authorized for issuance under equity compensation plans.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information relating to this item is incorporated herein by reference to the Corporation’s definitive proxy statement for the
2021 annual meeting of stockholders.
Item 14. Principal Accounting Fees and Services
Information relating to this item is incorporated herein by reference to the Corporation’s definitive proxy statement for the
2021 annual meeting of stockholders.
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PART IV
PART IV
PART IV
PART IV
PART IV
Item 15. Exhibits, Financial Statement Schedules
Item 15. Exhibits, Financial Statement Schedules
Item 15. Exhibits, Financial Statement Schedules
Item 15. Exhibits, Financial Statement Schedules
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are made a part of this Annual Report on Form 10-K:
(a) The following documents are made a part of this Annual Report on Form 10-K:
(a) The following documents are made a part of this Annual Report on Form 10-K:
(a) The following documents are made a part of this Annual Report on Form 10-K:
(a) The following documents are made a part of this Annual Report on Form 10-K:
1. and 2. Financial statements and financial statement schedules
1. and 2. Financial statements and financial statement schedules
1. and 2. Financial statements and financial statement schedules
1. and 2. Financial statements and financial statement schedules
1. and 2. Financial statements and financial statement schedules
The financial statements filed as part of this Annual Report on Form 10‑K are listed in the accompanying index to financial
The financial statements filed as part of this Annual Report on Form 10‑K are listed in the accompanying index to financial
The financial statements filed as part of this Annual Report on Form 10‑K are listed in the accompanying index to financial
The financial statements filed as part of this Annual Report on Form 10‑K are listed in the accompanying index to financial
statements and schedules in Item 8. Financial Statements and Supplementary Data.
The financial statements filed as part of this Annual Report on Form 10‑K are listed in the accompanying index to financial
statements and schedules in Item 8. Financial Statements and Supplementary Data.
statements and schedules in Item 8. Financial Statements and Supplementary Data.
statements and schedules in Item 8. Financial Statements and Supplementary Data.
statements and schedules in Item 8. Financial Statements and Supplementary Data.
All other financial statement schedules required under SEC rules that are not included in this Annual Report on Form 10-K, are
All other financial statement schedules required under SEC rules that are not included in this Annual Report on Form 10-K, are
All other financial statement schedules required under SEC rules that are not included in this Annual Report on Form 10-K, are
All other financial statement schedules required under SEC rules that are not included in this Annual Report on Form 10-K, are
omitted either because they are not applicable or the required information is contained in Item 8. Financial Statements and
All other financial statement schedules required under SEC rules that are not included in this Annual Report on Form 10-K, are
omitted either because they are not applicable or the required information is contained in Item 8. Financial Statements and
omitted either because they are not applicable or the required information is contained in Item 8. Financial Statements and
Supplementary Data.
omitted either because they are not applicable or the required information is contained in Item 8. Financial Statements and
omitted either because they are not applicable or the required information is contained in Item 8. Financial Statements and
Supplementary Data.
Supplementary Data.
Supplementary Data.
Supplementary Data.
3. Exhibits
3. Exhibits
3. Exhibits
3. Exhibits
3. Exhibits
Index is incorporated herein by reference.
Index is incorporated herein by reference.
Index is incorporated herein by reference.
Index is incorporated herein by reference.
Index is incorporated herein by reference.
The exhibits required to be filed pursuant to Item 15(b) of Form 10‑K are listed in the Exhibit Index filed herewith, which Exhibit
The exhibits required to be filed pursuant to Item 15(b) of Form 10‑K are listed in the Exhibit Index filed herewith, which Exhibit
The exhibits required to be filed pursuant to Item 15(b) of Form 10‑K are listed in the Exhibit Index filed herewith, which Exhibit
The exhibits required to be filed pursuant to Item 15(b) of Form 10‑K are listed in the Exhibit Index filed herewith, which Exhibit
The exhibits required to be filed pursuant to Item 15(b) of Form 10‑K are listed in the Exhibit Index filed herewith, which Exhibit
3(1)
3(1)
3(1)
3(1)
3(1)
3(2)
3(2)
3(2)
3(2)
3(2)
3(3)
3(3)
3(3)
3(3)
3(4)
3(3)
3(4)
3(4)
3(4)
3(4)
3(5)
3(5)
3(5)
3(5)
3(5)
4(1)
4(1)
4(1)
4(1)
4(1)
4(2)
4(2)
4(2)
4(2)
4(2)
4(3)
4(3)
4(3)
4(3)
4(3)
4(4)
4(4)
4(4)
4(4)
4(4)
4(5)
4(5)
4(5)
4(5)
4(5)
4(6)
4(6)
4(6)
4(6)
4(6)
4(7)
4(7)
4(7)
4(7)
4(7)
4(8)
4(8)
4(8)
4(8)
4(8)
4(9)
4(9)
4(9)
4(9)
4(9)
4(10)
4(10)
4(10)
4(10)
4(10)
4(11)
4(11)
4(11)
4(11)
4(11)
4(12)
4(12)
4(12)
4(12)
4(12)
including amendment
including amendment
including amendment
including amendment
including amendment
thereto dated May 3, 2006
Restated Certificate of Incorporation of Registrant,
thereto dated May 3, 2006
Restated Certificate of Incorporation of Registrant,
thereto dated May 3, 2006
Restated Certificate of Incorporation of Registrant,
incorporated by reference to Exhibit 3(1) of Registrant’s Form 10‑Q for the three months ended June 30,
thereto dated May 3, 2006
Restated Certificate of Incorporation of Registrant,
incorporated by reference to Exhibit 3(1) of Registrant’s Form 10‑Q for the three months ended June 30,
incorporated by reference to Exhibit 3(1) of Registrant’s Form 10‑Q for the three months ended June 30,
thereto dated May 3, 2006
Restated Certificate of Incorporation of Registrant,
2006.
incorporated by reference to Exhibit 3(1) of Registrant’s Form 10‑Q for the three months ended June 30,
2006.
2006.
incorporated by reference to Exhibit 3(1) of Registrant’s Form 10‑Q for the three months ended June 30,
2006.
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, dated May 22, 2013,
2006.
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, dated May 22, 2013,
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, dated May 22, 2013,
incorporated by reference to Exhibit 3(1) of Form 8‑K of Registrant filed on May 22, 2013.
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, dated May 22, 2013,
incorporated by reference to Exhibit 3(1) of Form 8‑K of Registrant filed on May 22, 2013.
incorporated by reference to Exhibit 3(1) of Form 8‑K of Registrant filed on May 22, 2013.
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, dated May 22, 2013,
incorporated by reference to Exhibit 3(1) of Form 8‑K of Registrant filed on May 22, 2013.
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, effective May 12, 2014,
incorporated by reference to Exhibit 3(1) of Form 8‑K of Registrant filed on May 22, 2013.
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, effective May 12, 2014,
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, effective May 12, 2014,
incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 13, 2014.
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, effective May 12, 2014,
incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 13, 2014.
incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 13, 2014.
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, effective May 12, 2014,
incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 13, 2014.
Certificate of Elimination of 8.00% Series A Mandatory Convertible Preferred Stock of Registrant,
incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 13, 2014.
Certificate of Elimination of 8.00% Series A Mandatory Convertible Preferred Stock of Registrant,
Certificate of Elimination of 8.00% Series A Mandatory Convertible Preferred Stock of Registrant,
incorporated by reference to Exhibit 3(4) of Form 10-K of Registrant for the year ended December 31, 2019.
Certificate of Elimination of 8.00% Series A Mandatory Convertible Preferred Stock of Registrant,
incorporated by reference to Exhibit 3(4) of Form 10-K of Registrant for the year ended December 31, 2019.
incorporated by reference to Exhibit 3(4) of Form 10-K of Registrant for the year ended December 31, 2019.
Certificate of Elimination of 8.00% Series A Mandatory Convertible Preferred Stock of Registrant,
incorporated by reference to Exhibit 3(4) of Form 10-K of Registrant for the year ended December 31, 2019.
By-Laws of Hess Corporation (as amended effective May 6, 2020) incorporated by reference to Exhibit 3(1)
incorporated by reference to Exhibit 3(4) of Form 10-K of Registrant for the year ended December 31, 2019.
By-Laws of Hess Corporation (as amended effective May 6, 2020) incorporated by reference to Exhibit 3(1)
By-Laws of Hess Corporation (as amended effective May 6, 2020) incorporated by reference to Exhibit 3(1)
of Form 10-Q of Registrant for the three months ended March 31, 2020.
By-Laws of Hess Corporation (as amended effective May 6, 2020) incorporated by reference to Exhibit 3(1)
of Form 10-Q of Registrant for the three months ended March 31, 2020.
of Form 10-Q of Registrant for the three months ended March 31, 2020.
By-Laws of Hess Corporation (as amended effective May 6, 2020) incorporated by reference to Exhibit 3(1)
of Form 10-Q of Registrant for the three months ended March 31, 2020.
Credit Agreement, dated as of April 18, 2019, among Hess Corporation, the subsidiary party thereto, the
of Form 10-Q of Registrant for the three months ended March 31, 2020.
Credit Agreement, dated as of April 18, 2019, among Hess Corporation, the subsidiary party thereto, the
Credit Agreement, dated as of April 18, 2019, among Hess Corporation, the subsidiary party thereto, the
lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to
Credit Agreement, dated as of April 18, 2019, among Hess Corporation, the subsidiary party thereto, the
lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to
lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to
Credit Agreement, dated as of April 18, 2019, among Hess Corporation, the subsidiary party thereto, the
Exhibit 10(1) of Form 8-K of the Registrant, filed on April 23, 2019.
lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to
Exhibit 10(1) of Form 8-K of the Registrant, filed on April 23, 2019.
Exhibit 10(1) of Form 8-K of the Registrant, filed on April 23, 2019.
lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to
Exhibit 10(1) of Form 8-K of the Registrant, filed on April 23, 2019.
Indenture dated as of October 1, 1999, between Registrant and The Chase Manhattan Bank, as Trustee,
Exhibit 10(1) of Form 8-K of the Registrant, filed on April 23, 2019.
Indenture dated as of October 1, 1999, between Registrant and The Chase Manhattan Bank, as Trustee,
Indenture dated as of October 1, 1999, between Registrant and The Chase Manhattan Bank, as Trustee,
incorporated by reference to Exhibit 4(1) of Form 10‑Q of Registrant for the three months ended
Indenture dated as of October 1, 1999, between Registrant and The Chase Manhattan Bank, as Trustee,
incorporated by reference to Exhibit 4(1) of Form 10‑Q of Registrant for the three months ended
incorporated by reference to Exhibit 4(1) of Form 10‑Q of Registrant for the three months ended
Indenture dated as of October 1, 1999, between Registrant and The Chase Manhattan Bank, as Trustee,
September 30, 1999.
incorporated by reference to Exhibit 4(1) of Form 10‑Q of Registrant for the three months ended
September 30, 1999.
September 30, 1999.
incorporated by reference to Exhibit 4(1) of Form 10‑Q of Registrant for the three months ended
September 30, 1999.
First Supplemental Indenture, dated as of October 1, 1999, between Registrant and The Chase Manhattan
September 30, 1999.
First Supplemental Indenture, dated as of October 1, 1999, between Registrant and The Chase Manhattan
First Supplemental Indenture, dated as of October 1, 1999, between Registrant and The Chase Manhattan
Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by
First Supplemental Indenture, dated as of October 1, 1999, between Registrant and The Chase Manhattan
Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by
Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by
First Supplemental Indenture, dated as of October 1, 1999, between Registrant and The Chase Manhattan
reference to Exhibit 4(2) of Form 10‑Q of Registrant for the three months ended September 30, 1999.
Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by
reference to Exhibit 4(2) of Form 10‑Q of Registrant for the three months ended September 30, 1999.
reference to Exhibit 4(2) of Form 10‑Q of Registrant for the three months ended September 30, 1999.
Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by
reference to Exhibit 4(2) of Form 10‑Q of Registrant for the three months ended September 30, 1999.
Prospectus Supplement, dated August 8, 2001, to Prospectus dated July 27, 2001 relating to Registrant’s
reference to Exhibit 4(2) of Form 10‑Q of Registrant for the three months ended September 30, 1999.
Prospectus Supplement, dated August 8, 2001, to Prospectus dated July 27, 2001 relating to Registrant’s
Prospectus Supplement, dated August 8, 2001, to Prospectus dated July 27, 2001 relating to Registrant’s
5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031,
Prospectus Supplement, dated August 8, 2001, to Prospectus dated July 27, 2001 relating to Registrant’s
5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031,
5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031,
Prospectus Supplement, dated August 8, 2001, to Prospectus dated July 27, 2001 relating to Registrant’s
incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act
5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031,
incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act
incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act
5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031,
of 1933, as amended, on August 9, 2001.
incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act
of 1933, as amended, on August 9, 2001.
of 1933, as amended, on August 9, 2001.
incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act
of 1933, as amended, on August 9, 2001.
Prospectus Supplement, dated February 28, 2002, to Prospectus dated July 27, 2001 relating to Registrant’s
of 1933, as amended, on August 9, 2001.
Prospectus Supplement, dated February 28, 2002, to Prospectus dated July 27, 2001 relating to Registrant’s
Prospectus Supplement, dated February 28, 2002, to Prospectus dated July 27, 2001 relating to Registrant’s
to
7.125% Notes due 2033,
Prospectus Supplement, dated February 28, 2002, to Prospectus dated July 27, 2001 relating to Registrant’s
to
7.125% Notes due 2033,
to
7.125% Notes due 2033,
Prospectus Supplement, dated February 28, 2002, to Prospectus dated July 27, 2001 relating to Registrant’s
Rule 424(b)(4) under the Securities Act of 1933, as amended, on March 1, 2002.
to
7.125% Notes due 2033,
Rule 424(b)(4) under the Securities Act of 1933, as amended, on March 1, 2002.
Rule 424(b)(4) under the Securities Act of 1933, as amended, on March 1, 2002.
to
7.125% Notes due 2033,
Rule 424(b)(4) under the Securities Act of 1933, as amended, on March 1, 2002.
Indenture dated as of March 1, 2006, between Registrant and The Bank of New York Mellon, as successor to
Rule 424(b)(4) under the Securities Act of 1933, as amended, on March 1, 2002.
Indenture dated as of March 1, 2006, between Registrant and The Bank of New York Mellon, as successor to
Indenture dated as of March 1, 2006, between Registrant and The Bank of New York Mellon, as successor to
JP Morgan Chase Bank, N.A., as Trustee, including form of Note, incorporated by reference to Exhibit 4 to
Indenture dated as of March 1, 2006, between Registrant and The Bank of New York Mellon, as successor to
JP Morgan Chase Bank, N.A., as Trustee, including form of Note, incorporated by reference to Exhibit 4 to
JP Morgan Chase Bank, N.A., as Trustee, including form of Note, incorporated by reference to Exhibit 4 to
Indenture dated as of March 1, 2006, between Registrant and The Bank of New York Mellon, as successor to
Registrant’s Form S‑3ASR filed on March 1, 2006.
JP Morgan Chase Bank, N.A., as Trustee, including form of Note, incorporated by reference to Exhibit 4 to
Registrant’s Form S‑3ASR filed on March 1, 2006.
Registrant’s Form S‑3ASR filed on March 1, 2006.
JP Morgan Chase Bank, N.A., as Trustee, including form of Note, incorporated by reference to Exhibit 4 to
Registrant’s Form S‑3ASR filed on March 1, 2006.
Form of 6.00% Note due 2040, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
Registrant’s Form S‑3ASR filed on March 1, 2006.
Form of 6.00% Note due 2040, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
Form of 6.00% Note due 2040, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
December 15, 2009.
Form of 6.00% Note due 2040, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
December 15, 2009.
December 15, 2009.
Form of 6.00% Note due 2040, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
December 15, 2009.
Form of 5.60% Note due 2041, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
December 15, 2009.
Form of 5.60% Note due 2041, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
Form of 5.60% Note due 2041, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
August 12, 2010.
Form of 5.60% Note due 2041, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
August 12, 2010.
August 12, 2010.
Form of 5.60% Note due 2041, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
August 12, 2010.
Form of 3.50% Note due 2024, incorporated by reference to Exhibit 4(3) to Form 8‑K of Registrant filed on
August 12, 2010.
Form of 3.50% Note due 2024, incorporated by reference to Exhibit 4(3) to Form 8‑K of Registrant filed on
Form of 3.50% Note due 2024, incorporated by reference to Exhibit 4(3) to Form 8‑K of Registrant filed on
June 25, 2014.
Form of 3.50% Note due 2024, incorporated by reference to Exhibit 4(3) to Form 8‑K of Registrant filed on
June 25, 2014.
June 25, 2014.
Form of 3.50% Note due 2024, incorporated by reference to Exhibit 4(3) to Form 8‑K of Registrant filed on
June 25, 2014.
Form of 4.30% Note due 2027, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
June 25, 2014.
Form of 4.30% Note due 2027, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
Form of 4.30% Note due 2027, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
September 28, 2016.
Form of 4.30% Note due 2027, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
September 28, 2016.
September 28, 2016.
Form of 4.30% Note due 2027, incorporated by reference to Exhibit 4(1) to Form 8‑K of Registrant filed on
September 28, 2016.
Form of 5.80% Note due 2047, incorporated by reference to Exhibit 4(2) to Form 8‑K of Registrant filed on
September 28, 2016.
Form of 5.80% Note due 2047, incorporated by reference to Exhibit 4(2) to Form 8‑K of Registrant filed on
Form of 5.80% Note due 2047, incorporated by reference to Exhibit 4(2) to Form 8‑K of Registrant filed on
September 28, 2016.
Form of 5.80% Note due 2047, incorporated by reference to Exhibit 4(2) to Form 8‑K of Registrant filed on
September 28, 2016.
September 28, 2016.
Form of 5.80% Note due 2047, incorporated by reference to Exhibit 4(2) to Form 8‑K of Registrant filed on
September 28, 2016.
September 28, 2016.
Description of Hess Corporation’s Securities Registered Pursuant to Section 12 of the Securities Exchange
Description of Hess Corporation’s Securities Registered Pursuant to Section 12 of the Securities Exchange
Description of Hess Corporation’s Securities Registered Pursuant to Section 12 of the Securities Exchange
Act of 1934 incorporated by reference to Exhibit 4(12) of Form 10-K of Registrant for the year ended
Description of Hess Corporation’s Securities Registered Pursuant to Section 12 of the Securities Exchange
Act of 1934 incorporated by reference to Exhibit 4(12) of Form 10-K of Registrant for the year ended
Act of 1934 incorporated by reference to Exhibit 4(12) of Form 10-K of Registrant for the year ended
Description of Hess Corporation’s Securities Registered Pursuant to Section 12 of the Securities Exchange
December 31, 2019.
Act of 1934 incorporated by reference to Exhibit 4(12) of Form 10-K of Registrant for the year ended
December 31, 2019.
December 31, 2019.
Act of 1934 incorporated by reference to Exhibit 4(12) of Form 10-K of Registrant for the year ended
December 31, 2019.
December 31, 2019.
incorporated by reference to Registrant’s prospectus filed pursuant
incorporated by reference to Registrant’s prospectus filed pursuant
incorporated by reference to Registrant’s prospectus filed pursuant
incorporated by reference to Registrant’s prospectus filed pursuant
incorporated by reference to Registrant’s prospectus filed pursuant
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4(13)
4(14)
10(1)*
10(2)*
10(3)*
10(4)*
10(5)*
10(6)*
10(7)*
10(8)*
10(9)*
10(10)*
10(11)*
10(12)*
10(13)*
10(14)*
10(15)*
10(16)*
10(17)*
10(18)*
10(19)*
incorporated by reference to
Loan Agreement, dated as of March 16, 2020, among Hess Corporation, the lenders party thereto, and
JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to Exhibit 10(1) of Form 8-K
of the Registrant, filed on March 17, 2020.
Amendment No. 1 dated as of June 9, 2020 to the Term Loan Agreement dated as of March 16, 2020, among
Hess Corporation, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent
incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended June 30,
2020.
Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated
subsidiaries are not being filed since the total amount of securities authorized under each such instrument
does not exceed 10% of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant
agrees to furnish to the Securities and Exchange Commission a copy of any instruments defining the rights of
holders of long‑term debt of Registrant and its subsidiaries upon request.
Annual Cash Incentive Plan description incorporated by reference to Item 5.02 of Form 8‑K of Registrant
filed on March 6, 2020.
Annual Cash Incentive Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant
filed on June 5, 2020.
Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10‑K of
Registrant for the fiscal year ended December 31, 2004.
Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10‑K of
Registrant for the fiscal year ended December 31, 2006.
Hess Corporation Pension Restoration Plan, dated January 19, 1990,
Exhibit 10(9) of Form 10‑K of Registrant for the fiscal year ended December 31, 1989. (P)
Amendment, dated December 31, 2006, to Hess Corporation Pension Restoration Plan, incorporated by
reference to Exhibit 10(10) of Form 10‑K of Registrant for the fiscal year ended December 31, 2006.
Letter Agreement, dated May 17, 2001, between Registrant and John P. Rielly relating to Mr. Rielly’s
participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18)
of Form 10‑K of Registrant for the fiscal year ended December 31, 2002.
Amended and Restated 2008 Long‑term Incentive Plan, incorporated by reference to exhibit 10(1) of Form 8-
K of the Registrant filed on May 12, 2015.
Forms of Awards under Registrant’s 2008 Long‑term Incentive Plan,
Exhibit 10(14) of Form 10‑K of Registrant for the fiscal year ended December 31, 2009.
Form of Restricted Stock Award Agreement under Registrant’s Amended and Restated 2008 Long‑term
Incentive Plan, incorporated by reference to Exhibit 10(2) of Form 10-Q of Registrant for the three months
ended March 31, 2015.
Compensation program description for non‑employee directors, incorporated by reference to Item 1.01 of
Form 8‑K of Registrant filed on January 4, 2007.
Form of Amended and Restated Change in Control Termination Benefits Agreement, dated as of May 29,
2009, incorporated by reference to Exhibit 10(1) of Form 10‑Q of Registrant for the three months ended
June 30, 2009. A substantially identical agreement (differing only in the signatories thereto) was entered into
between Registrant and John B. Hess.
Amended and Restated Change in Control Termination Benefits Agreement, dated as of May 29, 2009,
between Registrant and John P. Rielly, incorporated by reference to Exhibit 10(17) of Form 10‑K of
Registrant for the fiscal year ended December 31, 2009. Substantially identical agreements (differing only in
the signatories thereto) were entered into between Registrant and other executive officers (including the
named executive officers, other than Michael Turner and John B. Hess).
Form of Change in Control Termination Benefits Agreement, dated as of August 3, 2015, between the
Registrant and Michael R. Turner, incorporated by reference to Exhibit 10(3) of Form 10‑Q of Registrant for
the three months ended June 30, 2015. Substantially identical agreements (differing only in the signatories
thereto) were entered into between the Registrant and four other senior officers.
Agreement between Registrant and Gregory P. Hill, relating to Mr. Hill’s compensation and other terms of
employment, incorporated by reference to Item 5.02 of Form 8‑K of Registrant filed January 7, 2009.
Agreement between Registrant and Timothy B. Goodell, relating to Mr. Goodell’s compensation and other
terms of employment, incorporated by reference to Exhibit 10(20) of Registrant’s Form 10‑K for the fiscal
year ended December 31, 2009.
Deferred Compensation Plan of Registrant, dated December 1, 1999,
Exhibit 10(16) of Form 10‑K of Registrant for the fiscal year ended December 31, 1999.
incorporated by reference to
incorporated by reference to
Hess Corporation 2017 Long-Term Incentive Plan, incorporated by reference to Exhibit 10(1) of Form 8-K of
Registrant filed on June 13, 2017.
Form of Restricted Stock Award Agreement under the 2017 Long-Term Incentive Plan incorporated by
reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended March 31, 2020.
Substantially identical agreements were entered into by the Registrant during 2018 and 2019.
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10(20)*
10(21)*
10(22)*
10(23)*
21
24
23(1)
23(2)
31(1)
31(2)
32(1)
32(2)
99(1)
Form of Stock Option Award Agreement under the 2017 Long-Term Incentive Plan incorporated by
reference to Exhibit 10(2) of Form 10-Q of Registrant for the three months ended March 31, 2020.
Substantially identical agreements were entered into by the Registrant during 2018 and 2019.
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Form of Performance Award Agreement under the 2017 Long-Term Incentive Plan,
reference to Exhibit 10(3) of Form 10-Q of Registrant
2019. Substantially identical agreements were entered into by the Registrant during 2018.
Form of 2020 Performance Award Agreement under the 2017 Long-Term Incentive Plan incorporated by
reference to Exhibit 10(3) of Form 10-Q of Registrant for the three months ended March 31, 2020.
Separation Agreement, dated November 6, 2019, between Registrant and Michael R. Turner incorporated by
reference to Exhibit 10(21) of Form 10-K of Registrant for the year ended December 31, 2019.
incorporated by
the three months ended March 31,
for
Subsidiaries of Registrant.
Power of Attorney (included on the signatures page of this Annual Report on Form 10-K).
Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated March 1, 2021.
Consent of DeGolyer and MacNaughton dated March 1, 2021.
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b))
and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b))
and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
Letter report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consulting Firm, dated
February 3, 2021, on proved reserves audit as of December 31, 2020 of certain properties attributable to
Registrant.
101(INS)
Inline XBRL Instance Document
101(SCH)
Inline XBRL Schema Document
101(CAL)
101(LAB)
101(PRE)
101(DEF)
104
Inline XBRL Calculation Linkbase Document
Inline XBRL Labels Linkbase Document
Inline XBRL Presentation Linkbase Document
Inline XBRL Definition Linkbase Document
The cover page from the Company’s Annual Report on Form 10-K for the fiscal year ended December 31,
2020 has been formatted in Inline XBRL.
* These exhibits relate to executive compensation plans and arrangements.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 1st day of March 2021.
SIGNATURES
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HESS CORPORATION
(Registrant)
By
(John P. Rielly)
Executive Vice President and
Chief Financial Officer
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POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints John B. Hess, Timothy B. Goodell and John P. Rielly or any
of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in
his or her name, place and stead, in any and all capacities, to sign any and all amendments to Annual Report on Form 10-K, and to file
the same, with all exhibits thereto, and other documents in connection therewith with the Securities and Exchange Commission,
granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and to perform each and every act and
thing requisite and necessary to be done in and about the premises, as fully and to all intents and purposes as he or she might or would
do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute
or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons
on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
/s/ John B. Hess
John B. Hess
/s/ James H. Quigley
James H. Quigley
/s/ Terrence J. Checki
Terrence J. Checki
/s/ Leonard S. Coleman Jr.
Leonard S. Coleman Jr.
/s/ Joaquín Duato
Joaquín Duato
/s/ Edith E. Holiday
Edith E. Holiday
/s/ Marc S. Lipschultz
Marc S. Lipschultz
/s/ David McManus
David McManus
/s/ Dr. Kevin O. Meyers
Dr. Kevin O. Meyers
/s/ Karyn F. Ovelmen
Karyn F. Ovelmen
/s/ John P. Rielly
John P. Rielly
/s/ William G. Schrader
William G. Schrader
Title
Director and
Chief Executive Officer
(Principal Executive Officer)
Director and
Chairman of the Board
Director
Director
Director
Director
Director
Director
Director
Director
Executive Vice President and Chief
Financial Officer
(Principal Financial and Accounting
Officer)
Date
March 1, 2021
March 1, 2021
March 1, 2021
March 1, 2021
March 1, 2021
March 1, 2021
March 1, 2021
March 1, 2021
March 1, 2021
March 1, 2021
March 1, 2021
Director
March 1, 2021
105
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Exhibit 21
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUBSIDIARIES OF THE REGISTRANT
Name of Company
Registrant ownership %
Jurisdiction
Hess Asia Holdings Inc.
Hess Bakken Investments II, LLC
Hess Bakken Investments III, LLC
Hess Bakken Investments IV, LLC
Hess Bakken Processing LLC
Hess Baldpate-Penn State LLC
Hess Canada (Aspy) Exploration Limited
Hess Canada Exploration Limited
Hess Canada Oil and Gas ULC
Hess Capital Limited
Hess Capital Services Holdings, LLC
Hess Capital Services LLC
Hess Conger LLC
Hess Denmark ApS
Hess Energy Exploration LLC
Hess Equatorial Guinea Investments Limited
Hess Exploration & Production Holdings Limited
Hess Exploration and Production Malaysia B.V.
Hess Exploration Services, Inc.
Hess Finance
Hess GOM Deepwater LLC
Hess GOM Deepwater Sub-Holdings LLC
Hess GOM Exploration LLC
Hess Guyana (Block B) Exploration Limited
Hess Guyana (Liza) Exploration Limited
Hess Guyana Exploration Limited
Hess Holdings EG Limited
Hess Holdings GOM Ventures LLC
Hess Holdings West Africa Limited
Hess (Indonesia-VIII) Holdings Limited
Hess Infrastructure Partners LP
Hess International Holdings Corporation
Hess International Holdings Limited
Hess International Receivables Limited
Hess International Sales LLC
Hess Libya (Waha) Limited
Hess Libya Exploration Limited
Hess Limited
Hess Llano LLC
Hess Middle East New Ventures Limited
100%
100%
100%
100%
47%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
47%
100%
100%
100%
100%
100%
100%
100%
100%
100%
Cayman Islands
Delaware
Delaware
Delaware
Delaware
Delaware
Cayman Islands
Cayman Islands
Nova Scotia, Canada
Cayman Islands
Delaware
Delaware
Delaware
Denmark
Delaware
Cayman Islands
Delaware
The Netherlands
Delaware
England & Wales
Delaware
Delaware
Delaware
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Delaware
Cayman Islands
Cayman Islands
Delaware
Delaware
Cayman Islands
Cayman Islands
Delaware
Cayman Islands
Cayman Islands
England & Wales
Delaware
Cayman Islands
K
0
1
0
4
5
2
6
6
0
1
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Name of Company
Hess Midstream Operations LP
Hess Midstream Partners GP LP
Hess (Netherlands) Oil and Gas Holdings C.V.
Hess New Ventures Exploration Limited
Hess North Dakota Export Logistics Holdings LLC
Hess North Dakota Export Logistics LLC
Hess North Dakota Export Logistics Operations LP
Hess North Dakota Pipelines Holdings LLC
Hess North Dakota Pipelines LLC
Hess NWE Holdings
Hess Offshore Response Company, LLC
Hess Ohio Developments, LLC
Hess Ohio Holdings, LLC
Hess Ohio Sub-Holdings LLC
Hess Oil & Gas Sdn. Bhd.
Hess Oil and Gas Holdings Inc.
Hess Oil Company of Thailand (JDA) Limited
Hess Oil Company of Thailand Ltd. Co.
Hess Services UK Limited
Hess Stampede LLC
Hess Suriname Exploration Limited
Hess Tank Cars Holdings II LLC
Hess Tank Cars II LLC
Hess Tank Cars LLC
Hess TGP Finance Company LLC
Hess TGP Holdings LLC
Hess TGP Operations LP
Hess Tioga Gas Plant LLC
Hess Trading Corporation
Hess Tubular Bells LLC
Hess Water Services LLC
Hess West Africa Holdings Limited
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Jurisdiction
Delaware
Delaware
The Netherlands
Cayman Islands
Delaware
Delaware
Delaware
Delaware
Delaware
England & Wales
Delaware
Delaware
Delaware
Delaware
Malaysia
Cayman Islands
Cayman Islands
Texas
England & Wales
Delaware
Cayman Islands
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Cayman Islands
Registrant ownership %
47%
47%
100%
100%
47%
47%
47%
47%
47%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
47%
47%
47%
100%
47%
47%
47%
100%
100%
47%
100%
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Exhibit 23(1)
We consent to the incorporation by reference in the following Registration Statements:
Consent of Independent Registered Public Accounting Firm
a. Registration Statement (Form S-8 No. 333-43569) pertaining to the Hess Corporation Employees’ Savings Plan,
b. Registration Statement (Form S-8 No. 333-150992) pertaining to the Hess Corporation Amended and Restated 2008 Long-
Term Incentive Plan and the Hess Corporation 2017 Long-Term Incentive Plan,
c. Registration Statement (Form S-8 No. 333-167076) pertaining to the Hess Corporation Amended and Restated 2008 Long-
Term Incentive Plan and the Hess Corporation 2017 Long-Term Incentive Plan,
d. Registration Statement (Form S-8 No. 333-181704) pertaining to the Hess Corporation Amended and Restated 2008 Long-
Term Incentive Plan and the Hess Corporation 2017 Long-Term Incentive Plan,
e. Registration Statement (Form S-8 No. 333-204929) pertaining to the Hess Corporation Amended and Restated 2008 Long-
Term Incentive Plan and the Hess Corporation 2017 Long-Term Incentive Plan,
f. Registration Statement (Form S-8 No. 333-219113) pertaining to the Hess Corporation 2017 Long-Term Incentive Plan, and
g. Registration Statement (Form S-3 No. 333-223279) of Hess Corporation;
of our reports dated March 1, 2021, with respect to the consolidated financial statements of Hess Corporation and the effectiveness of
internal control over financial reporting of Hess Corporation included in this Annual Report (Form 10-K) of Hess Corporation for the
year ended December 31, 2020.
New York, New York
March 1, 2021
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Exhibit 23(2)
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Hess Corporation
1185 Avenue of the Americas
New York, New York 10036
Ladies and Gentlemen:
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
March 1, 2021
We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton as an
independent petroleum engineering consulting firm, to references to our report of third party dated February 3, 2021, containing our
opinion on the estimated proved reserves, as of December 31, 2020, attributable to certain properties in which Hess Corporation has
represented it holds an interest (our “Report”) under the heading “Proved Oil and Gas Reserves-Reserves Audit,” and to the inclusion
of our Report as an exhibit in Hess Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020. We also
consent to all such references, including under the heading “Experts,” and to the incorporation by reference of our Report in the
Registration Statements filed by Hess Corporation on Form S-3 (No. 333-223279) and Form S-8 (No. 333-43569, No. 333-150992,
No. 333‑167076, No. 333-181704, No. 333-204929, and No. 333-219113).
Very truly yours,
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
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I, John B. Hess, certify that:
1. I have reviewed this annual report on Form 10-K of Hess Corporation;
62540 10K
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Exhibit 31(1)
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of
an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of
Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
By
John B. Hess
Chief Executive Officer
Date: March 1, 2021
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I, John P. Rielly, certify that:
1. I have reviewed this annual report on Form 10-K of Hess Corporation;
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Exhibit 31(2)
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of
an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of
Directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
By
John P. Rielly
Executive Vice President and
Chief Financial Officer
Date: March 1, 2021
111
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Exhibit 32(1)
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Hess Corporation (the Corporation) on Form 10-K for the period ended
December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, John B. Hess,
Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act
of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition
and results of operations of the Corporation.
By
John B. Hess
Chief Executive Officer
Date: March 1, 2021
A signed original of this written statement required by Section 906 has been provided to the Corporation and will be
retained by the Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
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Exhibit 32(2)
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Hess Corporation (the Corporation) on Form 10-K for the period ended
December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, John P. Rielly,
Executive Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act
of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition
and results of operations of the Corporation.
By
John P. Rielly
Executive Vice President and
Chief Financial Officer
Date: March 1, 2021
A signed original of this written statement required by Section 906 has been provided to the Corporation and will be
retained by the Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
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Exhibit 99.1
DeGolyer and MacNaughton
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Board of Directors
Hess Corporation
1185 Avenue of the Americas
New York, New York 10036
Ladies and Gentlemen:
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 3, 2021
Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2020, of the net
proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which Hess Corporation (Hess) has
represented it holds an interest to determine the reasonableness of Hess’ estimates. This evaluation was completed on February 3,
2021. Hess has represented to us that these properties account for approximately 92.0 percent on a net equivalent barrel basis of Hess’
net proved reserves, as of December 31, 2020, and that the net proved reserves estimates have been prepared in accordance with the
reserves definitions of Rules 4-10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United
States. It is our opinion that the procedures and methodologies employed by Hess for the preparation of its proved reserves estimates
as of December 31, 2020, comply with the current requirements of the SEC. We have reviewed information provided to us by Hess
that it represents to be Hess’ estimates of the net reserves, as of December 31, 2020, for the same properties as those which we
evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used
for inclusion in certain SEC filings by Hess.
Reserves estimates included herein are expressed as net reserves as represented by Hess. Gross reserves are defined as the
total estimated petroleum remaining to be produced from these properties after December 31, 2020. Net reserves are defined as that
portion of the gross reserves attributable to the interests held by Hess after deducting all interests held by others.
Certain properties in which Hess has represented that it holds an interest are subject to the terms of production sharing
contracts (PSC). The terms of these PSCs generally allow for working interest participants to be reimbursed for portions of capital
costs and operating expenses and to share in the profits. The reimbursements and profit proceeds are converted to a barrel of oil
equivalent or standard cubic foot of gas equivalent by dividing by product prices to estimate the “entitlement quantities.” These
entitlement quantities are equivalent in principle to net reserves and are used to calculate an equivalent net share, termed an
“entitlement interest.” In this report, Hess’ net reserves or interest for the properties subject to these PSCs is the entitlement based on
Hess’ working interest.
Estimates of reserves should be regarded only as estimates that may change as further production history and additional
information become available. Not only are such estimates based on that information which is currently available, but such estimates
are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Information used in the preparation of this report was obtained from Hess. In the preparation of this report we have relied,
without independent verification, upon such information furnished by Hess with respect to the property interests being evaluated,
production from such properties, current costs of operation and development, current prices for production, agreements relating to
current and future operations and sale of production, and various other information and data that were accepted as represented. A field
examination was not considered necessary for the purposes of this report.
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Definition of Reserves
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Petroleum reserves estimated by Hess included in this report are classified as proved. Only proved reserves have been
evaluated for this report. Reserves classifications used by Hess in this report are in accordance with the reserves definitions of Rules
4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known
reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using
conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the
limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the
effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not
including escalations based upon future conditions. The petroleum reserves are classified as follows:
Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and 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, regardless of
whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited
by fluid contacts, if any; and, (B) Adjacent undrilled portions of the reservoir that can, with reasonable
certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis
of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known
hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and
reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and
the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher
portions of the reservoir only if geoscience, engineering, or performance data and reliable technology
establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques
(including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than
in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir,
or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis
on which the project or program was based; and, (B) The project has been approved for development by all
necessary parties and entities, including governmental entities.
(v) Existing economic and operating conditions include prices and costs at which economic producibility from a
reservoir is to be determined. The price shall be the average price 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, unless prices are defined by contractual arrangements, excluding escalations based upon
future conditions.
Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be
recovered:
(i) 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; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves
estimate if the extraction is by means not involving a well.
Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category 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.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that
are reasonably certain of production when drilled, unless evidence using reliable technology exists that
establishes reasonable certainty of economic producibility at greater distances.
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(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has
been adopted indicating that they are scheduled to be drilled within five years, unless the specific
circumstances justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for
which an application of fluid injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as
defined in [Section 210.4–10(a) Definitions], or by other evidence using reliable technology establishing
reasonable certainty.
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Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and
techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with
practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled
“Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE
Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The
method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of
development, quality and completeness of basic data, and production history.
Based on the current stage of field development, production performance, the development plans provided by Hess, and
analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by
Hess.
Hess has represented that its senior management is committed to the development plan provided by Hess and that Hess has
the financial capability to execute the development plan, including the drilling and completion of wells and the installation of
equipment and facilities.
For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and
petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics,
(2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include
data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for
all well groupings (or type-curve areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles,
including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based
analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well
performance, and complex situations sourced by the nature of unconventional reservoirs.
When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place
(OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume.
Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate
representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-
balance methods were used to estimate OOIP or OGIP.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were
based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the
properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate
recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid
properties.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other
diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships.
In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined under the
Definition of Reserves heading of this report or the expiration of the fiscal agreement, as appropriate.
In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which
more complete data were available.
In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for
which more complete historical performance data were available.
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Data provided by Hess from wells drilled through December 31, 2020, and made available for this evaluation were used to
prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available only
through August 2020. Estimated cumulative production, as of December 31, 2020, was deducted from the estimated gross ultimate
recovery to estimate gross reserves. This required that production be estimated for up to 4 months.
Oil and condensate reserves estimated herein are to be recovered by normal field separation. NGL reserves estimated herein
include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane
fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are
expressed in millions of barrels (106bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and
condensate reserves have been estimated separately and are presented herein as a summed quantity.
Gas quantities estimated herein are expressed as fuel gas and marketable gas. Marketable gas is defined as the total gas
produced from the reservoir after reduction for shrinkage resulting from field separation; processing, including removal of the
nonhydrocarbon gas to meet pipeline specifications; and flare and other losses but not from fuel usage. Fuel gas is that portion of the
gas consumed in field operations. Gas reserves estimated herein are reported as marketable gas; therefore, fuel gas is included as
reserves. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.7 pounds per
square inch absolute (psia). Gas quantities included in this report are expressed in billions of cubic feet (109ft3).
Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial
reservoir conditions with no oil present in the reservoir. Associated gas includes both gas-cap gas and solution gas. Gas-cap gas is gas
at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial
reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.
At the request of Hess, marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent
factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
Primary Economic Assumptions
This report has been prepared using initial prices, expenses, and costs provided by Hess in United States dollars (U.S.$).
Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The
following economic assumptions were used for estimating the reserves reported herein:
Oil and Condensate Prices
Hess has represented that the oil and condensate prices were based on a reference price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month
period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The
12-month average reference prices used were U.S.$39.77 per barrel for West Texas Intermediate and U.S.
$43.43 per barrel for Brent. Hess supplied appropriate differentials by field to the relevant reference prices
and the prices were held constant thereafter. The volume-weighted average price attributable to the
estimated proved reserves over the lives of the properties was U.S.$37.99 per barrel.
NGL Prices
Hess has represented that the NGL prices were based on a reference price, calculated as the unweighted
arithmetic average of the first-day-of-the-month price for each month within the 12‑month period prior to
the end of the reporting period, unless prices are defined by contractual arrangements. The volume-
weighted average price attributable to the estimated proved reserves over the lives of the properties was
U.S.$10.82 per barrel of NGL.
Gas Prices
Hess has represented that gas prices were based on reference prices, calculated as the unweighted
arithmetic average of the first-day-of- the-month price for each month within the 12-month period prior to
the end of the reporting period, unless prices are defined by contractual arrangements. The 12-month
average reference price for NYMEX was U.S.$2.16 per million Btu and the UK International Petroleum
Exchange reference price was U.S.$3.22 per million Btu. The gas prices were adjusted for each property
using differentials to the NYMEX or UK International Petroleum Exchange reference prices furnished by
Hess and held constant thereafter. The volume-weighted average price attributable to the estimated proved
reserves was U.S.$2.52 per thousand cubic feet of gas.
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Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses, provided by Hess and based on current expenses, were held constant for
the lives of the properties. Future capital expenditures were estimated using 2020 values, provided by Hess,
and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current
expenditures, may have been used because of anticipated changes in operating conditions, but no general
escalation that might result from inflation was applied. Abandonment costs, which are those costs
associated with the removal of equipment, plugging of wells, and reclamation and restoration associated
with the abandonment, were provided by Hess and were not adjusted for inflation. Operating expenses,
capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability
of the developed non-producing and undeveloped reserves.
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In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and gas contained in this report
has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932□ 235-50-9 of the Accounting
Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures
(January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and
1203(a) of Regulation S–K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are
not presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature,
we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance
therewith or sufficient therefor.
Summary of Conclusions
Hess has represented that its estimated net proved reserves attributable to the evaluated properties were based on the
definition of proved reserves of the SEC. Hess’ estimates of the net proved reserves, as of December 31, 2020, attributable to these
properties, which represent 92.0 percent of Hess’ reserves on a net equivalent basis, are summarized as follows, expressed in millions
of barrels (106bbl), billions of cubic feet (109ft3), and millions of barrels of oil equivalent (106boe):
Estimated by Hess
Net Proved Reserves as of December 31, 2020
Oil and
Condensate
(106bbl)
NGL
(106bbl)
Marketable
Gas
(109ft3)
Oil Equivalent
(106boe)
United States
Guyana
Malaysia and JDA
Other International
Total
378
204
6
88
676
158
0
0
0
158
601
83
675
101
1,460
636
218
118
105
1,077
Notes:
1.
2.
3.
Marketable gas reserves estimated herein were converted to oil equivalent using an
energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
Net proved fuel gas reserves included as a portion of marketable gas reserves were
estimated to be 190 109ft3.
Joint Development Area is abbreviated JDA.
In comparing the detailed net proved reserves estimates by field prepared by DeGolyer and MacNaughton and by Hess,
differences have been found, both positive and negative, resulting in an aggregate difference of less than 1 percent when compared on
the basis of net equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the total net proved reserves estimates prepared by
Hess, as of December 31, 2020, on the properties evaluated and referred to above, when compared on the basis of net equivalent
barrels, do not differ materially from those prepared by DeGolyer and MacNaughton.
Hess’ oil and gas reserves were estimated assuming the continuation of the current regulatory environment. Foreign oil-
producing countries, including members of the Organization of Petroleum Exporting Countries (OPEC), may impose production
quotas which limit the supply of oil that can be produced. Generally, these production quotas affect the timing of production, rather
than the total volume of oil or gas reserves estimated.
Changes in the regulatory environment by host governments may affect the operating environment and oil and gas reserves
estimates of industry participants. Such regulatory changes could include increased mandatory government participation in producing
contracts, changes in royalty terms, cancellation or amendment of contract rights, or expropriation or nationalization of property.
While the oil and gas industry is subject to regulatory changes that could affect an industry participant’s ability to recover its reserves,
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neither we nor Hess are aware of any such governmental actions which restrict the recovery of the December 31, 2020, estimated
reserves.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum
consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock
ownership, in Hess. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Hess.
DeGolyer and MacNaughton has used all data, procedures, assumptions and methods that it considers necessary to prepare this report.
[SEAL]
Submitted,
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
Thomas C. Pence, P.E.
Senior Vice President
DeGolyer and MacNaughton
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CERTIFICATE of QUALIFICATION
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I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas,
Texas, 75244 U.S.A., hereby certify:
1. That I am a Senior Vice President of DeGolyer and MacNaughton, which firm did prepare the report of third party addressed
to Hess Corporation dated February 3, 2021, and that I, as Senior Vice President, was responsible for the preparation of this
report of third party.
2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in
1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum
Engineers; and that I have in excess of 38 years of experience in oil and gas reservoir studies and reserves evaluations.
[SEAL]
Thomas C. Pence, P.E.
Senior Vice President
DeGolyer and MacNaughton
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CORPORATE INFORMATION
Common Stock
Documents Available
Listed New York Stock Exchange
(ticker symbol: HES)
Copies of the corporation’s 2020 Annual Report on Form
10-K, Quarterly Reports on Form 10-Q, Current Reports
on Form 8-K and annual proxy statement filed with the
Transfer Agent and Registrar
Securities and Exchange Commission (SEC), as well as the
Computershare
P.O. Box 505000
Louisville, KY 40233-5000
Telephone: 866-203-6215
For overnight deliveries:
Computershare
462 South 4th Street, Suite 1600
Louisville, KY 40202
Shareholder website:
www.computershare.com/investor
Shareholder online inquiries:
www-us.computershare.com/investor/contact
corporation’s Code of Business Conduct and Ethics, Corporate
Governance Guidelines, and charters of the Audit Committee,
Compensation and Management Development Committee and
Corporate Governance and Nominating Committee of the
Board of Directors, are available, without charge, on our
website (www.hess.com) or upon written request to the
Corporate Secretary, email: corporatesecretary@hess.com.
The corporation has also filed with the New York Stock
Exchange (NYSE) its annual certification that the corporation’s
chief executive officer is not aware of any violation of the
NYSE’s corporate governance standards. The corporation
has also filed with the SEC the certifications of its chief
executive officer and chief financial officer required under
SEC Rule 13a-14(a) as exhibits to its 2020 Form 10-K.
Dividend Reinvestment Plan
Information concerning the Dividend Reinvestment Plan
available to holders of Hess Corporation common stock
may be obtained at www.computershare.com/investor, by
writing to Computershare, Dividend Reinvestment Department,
P.O. Box 505000, Louisville, KY 40233-5000, or by calling
1-866-203-6215.
Hess website:
www.hess.com
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to Forest Stewardship Council (FSC) standards.
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