2018 ANNUAL REPORT
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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 Financial and Operating Highlights
2 Letter to Shareholders
5 Global Operations
9 Sustainability
12 Board of Directors and Corporate Officers
Cover: Production Operations, Gulf of Thailand
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FINANCIAL AND
OPERATING HIGHLIGHTS
HESS CORPORATION
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
E&P 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
Total equity
Debt to capitalization ratio (b)
Common stock price
Operating — for the year
Net production
2018
2017
$ 6,323
$
5,466
$
(282)
$ (4,074)
$ (1.10)
$ (13.12)
$
1.00
$ 1,939
$ 2,069
$
338
298.2
$
$
$
$
1.00
945
2,047
121
314.1
2018
2017
$ 21,433
$ 23,112
$ 2,694
$ 6,672
$
$
4,847
6,977
$ 10,888
$ 12,354
38.0%
36.1%
$ 40.50
$
47.47
2018
2017
Crude oil and natural gas liquids (thousands of barrels per day)
United States
International
Total
Natural gas (thousands of MCF per day)
United States
International
Total
Barrels of oil equivalent (thousands of barrels per day)
157
28
185
181
372
553
277
(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 as a percentage of the sum of total debt and total equity.
153
66
219
211
309
520
306
1
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LETTER TO
SHAREHOLDERS
Our company enters 2019 with significant momentum
investment phase in 2019 to a free cash flow generation
following continued strong strategic execution and
phase beginning in 2020 with the startup of the Liza
operational performance in 2018. As a result, we are
Phase 1 development offshore Guyana, which is
uniquely positioned to deliver increasing financial returns,
expected to produce up to 120,000 gross barrels of
visible and low risk production growth and accelerating
oil per day utilizing the Liza Destiny floating production,
free cash flow well into the next decade.
storage and offloading (FPSO) vessel. This important
We have built a balanced, focused portfolio with
Guyana and the Bakken as our growth engines and
the deepwater Gulf of Mexico and the Gulf of Thailand
as our cash engines. Our portfolio is positioned to
deliver approximately 20 percent compound annual
cash flow growth and more than 10 percent
compound annual production growth through 2025
at a $65 per barrel Brent oil price, with a portfolio
breakeven of less than $40 per barrel Brent by 2025.
Our strategic priorities are clear. First, we will invest only
in high return, low cost opportunities. In December 2018,
we announced a 2019 Exploration and Production (E&P)
capital and exploratory budget of $2.9 billion. We expect
to maintain capital expenditures of approximately $3 billion
per year through 2025, with plans to allocate about
75 percent to developments in Guyana and the Bakken –
two of the best investments in the oil and gas industry.
Second, we will continue to ensure that we have the
financial capacity to fund our world class investment
opportunities and maintain an investment grade credit
rating. We entered 2019 with $2.7 billion of cash on the
balance sheet, 95,000 barrels of oil per day hedged in
2019 with $60 per barrel West Texas Intermediate (WTI)
put options, and the spending flexibility to reduce our
capital program by up to $1 billion should oil prices
move lower in future years.
Third, we will remain focused on growing free cash flow
in a disciplined and reliable manner. Our company is
at an exciting inflection point, transitioning from an
milestone will be followed by our Bakken asset growing
to 200,000 net barrels of oil equivalent per day by 2021,
and then startup of the Liza Phase 2 development
offshore Guyana by mid 2022, which will use a second
FPSO designed to produce up to 220,000 gross barrels
of oil per day. A third FPSO is expected to begin
production at the Payara development as early as 2023,
with an additional FPSO planned in Guyana in 2024 and
2025. As our portfolio generates increasing free cash
flow, we will prioritize the return of capital to shareholders
through dividends and opportunistic share repurchases.
A key driver of our strategy is Guyana, where Hess
has a 30 percent interest in the Stabroek Block and
ExxonMobil is the operator. In February 2019, we
announced discoveries at the Tilapia-1 and Haimara-1
wells offshore Guyana, bringing the total number of
discoveries on the Stabroek Block to 12. In March
2019, the estimate of gross discovered recoverable
resources for the block was increased to more than
5.5 billion barrels of oil equivalent, with multibillion
barrels of additional exploration potential remaining on
the block. The growing resource base on the Stabroek
Block underpins the potential for at least five FPSO
vessels producing more than 750,000 gross barrels of
oil per day by 2025.
In the Bakken, Hess is a top tier operator with a 15 year
inventory of high return drilling locations. Our transition
to plug and perf completions from our previous 60 stage
sliding sleeve design is expected to increase the net
present value of the asset by approximately $1 billion.
Bakken net production is expected to grow approximately
2
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20 percent per year to 200,000 barrels of oil equivalent
in overseeing Hess’ sustainability practices, working
per day by 2021, generating approximately $1 billion of
alongside senior management to evaluate various
annual free cash flow post 2020 at $60 per barrel WTI.
sustainability risks and global scenarios in making
Turning to our 2018 financial results, our adjusted net
loss was $176 million, compared with an adjusted net
loss of $1.4 billion in 2017. Cash flow from operations,
before changes in working capital, was $2.1 billion, up
strategic decisions. We are committed to transparency,
and our strategy and reporting are closely aligned with
the recommendations of the Task Force on Climate-
Related Financial Disclosures.
from $1.7 billion the prior year. In 2018, we delivered
We have tested the robustness of Hess’ portfolio under
proved reserve additions of 172 million net barrels of oil
the supply and demand scenarios of the International
equivalent, representing an organic replacement rate of
Energy Agency (IEA), including the ambitious greenhouse
166 percent at a finding and development cost of just
gas (GHG) emission reductions assumed within the IEA’s
under $12 per barrel of oil equivalent. The majority of
Sustainable Development Scenario. Our strategy is
these additions were in the Bakken. Proved reserves at
consistent with the energy transition needed to achieve
the end of the year stood at 1.19 billion barrels of oil
the Sustainable Development Scenario, in which oil and
equivalent, and our reserve life was 11.5 years.
gas will continue to be essential to meeting the world’s
Pro forma for asset sales and Libya, full year production
was 248,000 net barrels of oil equivalent per day in
2018 – 10 percent higher than the pro forma 224,000
net barrels of oil equivalent per day produced in 2017.
growing energy demand. Our current asset portfolio
is resilient, and our pipeline of forward investments
provides strong financial returns under the Sustainable
Development Scenario.
In the Bakken, 2018 net production averaged 117,000
Our business planning includes actions we will undertake
barrels of oil equivalent per day, up from 105,000 barrels
to continue reducing our carbon footprint in keeping with
of oil equivalent per day the prior year.
the findings of the U.N. Intergovernmental Panel on
SUSTAINABILITY
We see sustainability as fundamental to our long term
strategy and performance, supporting our purpose to
be the world’s most trusted energy partner. We are
proud to have been recognized once again in 2018 by
a number of third-party organizations for the quality of
our environmental, social and governance performance
and disclosure.
Climate change is a significant global challenge that
requires governments, businesses and civil society to
work together on cost-effective policies. We believe
climate risks can and should be addressed while also
providing the safe, affordable and reliable energy
necessary to ensure human welfare and global economic
development in the context of the United Nations (U.N.)
Sustainable Development Goals.
Climate Change and the aim of the Paris Agreement to
limit global average temperature rise to well below 2°C.
Our Board of Directors and senior leadership have set
aggressive targets for GHG emission reductions, and
over the past 10 years, our company has reduced our
equity GHG emissions by approximately 63 percent.
COMMITMENT TO SHAREHOLDERS
We will continue to execute our strategy that has
positioned our company to deliver long term value and
increasing returns to shareholders. We are proud of our
employees for their many accomplishments in 2018 and
grateful for the counsel and guidance of our Directors.
Thank you, our shareholders, for your continued support
and interest in our company.
Our company is committed to helping meet the world’s
James H. Quigley
John B. Hess
growing energy needs in a safe, environmentally
Chairman of the Board
Chief Executive Officer
responsible, socially sensitive and profitable way. Our
Board is climate change literate and actively engaged
April 2019
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Drilling Operations, North Dakota
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GLOBAL
OPERATIONS
PRODUCTION
In 2018, net production averaged 277,000 barrels of
oil equivalent per day, including Libya, compared with
306,000 barrels of oil equivalent per day in 2017.
The decline in production year over year was primarily
the result of asset sales associated with the strategic
reshaping of the company’s portfolio in 2017 and 2018
and was partially offset by increased production from
the Bakken, North Malay Basin and the Gulf of Mexico.
The net production impact from the sale of our higher
cost, mature assets in the Permian Basin, Equatorial
Guinea and Norway in 2017 and our joint venture
interests in the Utica in 2018 was approximately
63,000 barrels of oil equivalent per day.
In the Bakken, where Hess has a 15 year inventory
of high return drilling locations, our operated rig count
averaged 4.8 in 2018, compared with an average
rig count of 3.5 in 2017. The company ended the
year with six rigs and brought 104 new wells on
production in 2018, compared with 68 new wells
in 2017. Net production from the Bakken averaged
117,000 barrels of oil equivalent per day in 2018,
compared with 105,000 in 2017.
Field trials and an independent Bakken study in 2018
confirmed that our transition to plug and perf
completions from our previous 60 stage sliding sleeve
design should increase the asset’s net present value
by approximately $1 billion. The transition is expected
to enable the company to grow net production in
the Bakken to approximately 200,000 barrels of oil
equivalent per day by 2021, after which we plan to
drop down to four rigs and the asset is expected
to generate approximately $1 billion of free cash flow
annually, at $60 per barrel WTI, through the middle
of the next decade.
Based on the positive results from our plug and perf
completion design, we expect to achieve a 15 to 20
percent uplift in 180-day cumulative initial production
rates and a 5 to 10 percent uplift in estimated ultimate
recovery per well, compared with the previous 60 stage
sliding sleeve completion design. As a result, we have
increased our estimate of net ultimate recovery from our
Bakken acreage to 2.3 billion barrels of oil equivalent
from our previous estimate of 2.0 billion barrels of oil
equivalent. Of the 2.3 billion barrels of oil equivalent,
approximately 2 billion barrels are yet to be produced.
In the deepwater Gulf of Mexico, net production
averaged 57,000 barrels of oil equivalent per day in
2018, compared with 54,000 barrels of oil equivalent
per day in 2017. This increase was primarily due to the
Stampede development (25 percent working interest,
operator) and Penn State Deep 6 well (100 percent
working interest, operator) coming online in early
2018 and was partially offset by unplanned downtime
following a fire at the Shell-operated Enchilada
platform and natural field declines.
At the North Malay Basin in the Gulf of Thailand (50 percent
working interest, operator), full field development was
completed and first gas achieved in July 2017. In 2018,
net production reached its planned plateau rate and
averaged 27,000 barrels of oil equivalent per day,
compared with 11,000 barrels of oil equivalent per day in
2017, establishing the asset as a significant long term,
low cost generator of free cash flow for the company.
At the Carigali Hess operated Malaysia/Thailand Joint
Development Area (50 percent working interest), net
production averaged 36,000 barrels of oil equivalent
per day in 2018, compared with 37,000 barrels of oil
equivalent per day in 2017.
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XXXXXXXXXXXXXXXXXXXXXX
Planning Meeting, Houston, Texas
XXXXXXXXXXXXXXXXXXXXXX
In the Danish North Sea, net production from the South
Noble Bob Douglas drillship. First production from the
Arne Field (61.5 percent working interest, operator)
Liza Phase 1 development is expected by early 2020.
averaged 7,500 barrels of oil equivalent per day in 2018,
compared with 10,000 barrels of oil equivalent per day
in 2017, reflecting natural field declines.
DEVELOPMENTS
Planning for a second phase of development at Liza is
underway and expected to utilize an FPSO vessel with
gross production capacity of approximately 220,000
barrels of oil per day. First oil from the Liza Phase 2
Offshore Guyana, Hess holds a 30 percent interest in the
development is targeted for mid 2022. A third phase
6.6 million acre Stabroek Block. Esso Exploration and
of development will focus on the Payara area and is
Production Guyana Limited, a subsidiary of ExxonMobil,
expected to commence production in 2023.
is operator and holds a 45 percent interest. CNOOC
Petroleum Guyana Limited, a wholly owned subsidiary of
CNOOC Limited, holds the remaining 25 percent interest.
EXPLORATION
At the Stabroek Block, offshore Guyana, Hess has
participated in 12 discoveries to date that are estimated
In June 2017, the first phase of the Liza development
to contain gross recoverable resources of more than
on the Stabroek Block was sanctioned. The project
5.5 billion barrels of oil equivalent. Five of these
will develop approximately 500 million barrels of oil on
discoveries – Ranger, Pacora, Longtail, Hammerhead and
a gross basis through an FPSO vessel with capacity
Pluma – were announced in 2018.
of approximately 120,000 barrels of oil per day.
Development drilling commenced in 2018 using the
In January 2018, the Ranger-1 exploration well,
located approximately 60 miles northwest of the Liza
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development, encountered approximately 230 feet of
of high quality, hydrocarbon bearing sandstone reservoir.
high quality, oil bearing carbonate reservoir. In February
The well is located approximately 17 miles south of the
2018, the Pacora-1 exploration well encountered
Turbot-1 well.
approximately 65 feet of high quality, oil bearing
sandstone reservoir. The well is located approximately
4 miles west of the Payara-1 well.
In addition, the Liza-5 appraisal well was drilled in July
2018 and successfully tested the northern portion of
the Liza field. This additional resource along with the
In June 2018, the Longtail-1 well, located approximately
giant Payara field and Pacora discovery will support
5 miles west of the Turbot-1 well, encountered
a third phase of development in the Stabroek Block.
approximately 256 feet of high quality, oil bearing
sandstone reservoir. The Longtail discovery added
significant additional resources in the Turbot area,
which will contribute to the evaluation of development
options in the eastern portion of the block.
In February 2019, the 11th and 12th discoveries on the
Stabroek Block were announced. The Haimara-1 well,
located 19 miles east of the Pluma-1 discovery,
encountered approximately 207 feet of high quality, gas
condensate bearing sandstone reservoir. The Tilapia-1
In August 2018, the Hammerhead-1 well, located
well, located 3 miles west of the Longtail discovery,
approximately 13 miles southwest of the Liza-1 well,
encountered approximately 305 feet of high quality,
encountered approximately 197 feet of high quality,
oil bearing sandstone reservoir. Additional exploration
oil bearing sandstone reservoir and proved a new play
drilling is planned on the Stabroek Block for 2019,
concept for potential development. In December 2018,
including appraisal drilling and well testing.
the Pluma-1 well encountered approximately 121 feet
Liza Destiny FPSO Vessel Under Construction, Singapore
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LEAP Program, Houston, Texas
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SUSTAINABILITY
Sustainability is fundamental to Hess’ long term strategy
by a 69 percent decrease in our severe dropped
and an integral part of our operations. We believe that
object incident rate compared with 2017. Our 2018
sustainable practices create value for our shareholders
total recordable incident rate (TRIR) of 0.31 was up
and position us to continuously improve business
slightly from our 2017 rate of 0.24, which was the
performance. Our environment, health, safety and social
best TRIR in our company’s history. While our TRIR
responsibility strategy focuses our efforts on the areas
remains first quartile for our industry, our leadership
most material to our business, including health and
team is emphasizing the vital importance of safety in
safety, climate change, community and stakeholder
companywide site visits and employee meetings to
engagement, human rights and transparency.
address this trend. We are encouraged that our lost
Hess’ commitment to sustainability starts at the top
of our company, and our culture and values reinforce
time incident rate remained flat in 2018 compared to
the low rate we achieved in 2017.
it at every level. Our Board of Directors is climate
Our process safety management systems are an
change literate and actively engaged in overseeing
integral part of our business and play a critical role
Hess’ sustainability practices, working alongside senior
in mitigating risk. In 2018 we built on the outcome of
management. The Environment, Health and Safety (EHS)
the enterprisewide assessment of our process safety
Subcommittee of the Board’s Audit Committee provides
systems completed in 2017. For example, we began
oversight and makes recommendations to the full Board
a multiyear process to standardize our approach to
of Directors with respect to Hess’ policies, positions
competency assurance and training for safety critical
and systems for environment, health, safety, social
positions across the company. While each of our
responsibility, compliance and risk management. To
assets has already implemented worker competency
ensure potential risks are considered in the development
programs, standardization of assessment and training
of company strategies and policies, we bring in
programs will make the programs more efficient
subject matter experts to brief our Board on current
and effective and enable use of a common online
and developing sustainability issues, including climate
competency management system. We have also
change. The Board’s Compensation Committee has tied
continued to enhance our integrity management
executive compensation to advancing the company’s
program by standardizing our approach to tracking,
environmental, health and safety goals.
inspecting and performing maintenance on integrity
SAFETY AND HEALTH
The safety of our workforce and the communities
where we operate is Hess’ top priority, and we are
critical equipment that provides isolation, containment,
prevention, detection, control, mitigation or emergency
preparedness and response within our facilities.
committed to continuously improving our performance.
ENVIRONMENT AND CLIMATE CHANGE
In 2018 we achieved a 43 percent year-over-year
Climate change is a significant global challenge that
reduction in our severe safety incident rate, a key metric
requires governments, businesses and civil society to
that tracks incidents with the potential to result in severe
work together on cost-effective policies. We believe
consequences. This improvement was supported
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climate risks can and should be addressed while
best practices in sustainable business conduct across
also providing the safe, affordable and reliable energy
the private sector.
necessary to ensure human welfare and global
economic development in the context of the U.N.
Sustainable Development Goals.
Stakeholder engagement processes are integrated into
our enterprise risk workshops and asset business plans.
In 2018, following the company’s reorganization, we
Hess is committed to developing oil and gas resources
updated our stakeholder management planning
in an environmentally responsible and sustainable
process to more clearly define accountabilities for
manner. Our climate change strategy is closely
identifying and monitoring issues.
aligned with the recommendations of the Task Force
on Climate-Related Financial Disclosures (TCFD)
established by the G20 Financial Stability Board.
As one of our key strategic actions, our company
has established 2020 reduction targets for GHGs
and flaring. Between 2008 and 2018, we reduced
our equity GHG emissions by approximately 7 million
tonnes through improved operating practices and asset
closures and divestitures.
Hess’ community investments support programs in
a number of areas. In terms of workforce development,
Hess in 2014 committed $5 million over five years
to support the Collaborative Energy Complex at the
University of North Dakota’s College of Engineering –
a program that has grown from four students in 2010
to more than 200 in 2018. In Guyana, we are working
with our joint venture partners Esso Exploration and
Production Guyana Limited and CNOOC Petroleum
In addition, we are accounting for the cost of carbon
Guyana Limited to build capacity among the local
in our business decisions. To fully align with the TCFD
workforce and supplier companies. The joint venture
framework, we recently conducted a scenario planning
established a Business Training Centre in 2017 that
exercise that included the ambitious Sustainable
provides Guyanese businesses with mentoring,
Development Scenario developed by the International
coaching and access to financial aid, as well as
Energy Agency (IEA) to test the resilience of Hess’
information on safety, technical standards and
portfolio against a range of environmental policies and
procurement opportunities.
market conditions. Based on the IEA’s 2018 World
Energy Outlook, oil and gas are essential to meet the
world’s growing energy demand through 2040, even
assuming a carbon-constrained future. Hess’ strategic
priority to be a low cost oil producer positions us well
for the coming decades. We plan to disclose further
details on the results of our analysis later this year.
SOCIAL RESPONSIBILITY
In education, we continued our LEAP (Learn, Engage,
Advance, Persevere) program, which provides a range
of services that help at-risk students in Houston’s
Greater East End stay in school. In 2018, the fifth year
of a six-year, $6.4 million commitment, we broadened
LEAP’s scope to include more than 4,700 students
at the elementary, middle and high school levels.
In Malaysia, we support the Fulbright English Teaching
In 2018, we participated in multistakeholder initiatives
Assistant Program, which places recent graduates from
designed to advance transparency, environmental
U.S. universities into Malaysian secondary schools to
protection, human rights and good governance.
help students boost their confidence and improve
We are a participating member of IPIECA, the global
their proficiency in English. In 2018 the program
oil and gas industry organization for environmental and
benefited approximately 6,000 Malaysian students.
social issues, as well as the U.N. Global Compact
In North Dakota, we donated Hess toy trucks along
and the Global Compact U.S. Network, which share
with a science, technology, engineering and mathematics
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curriculum designed by Baylor College of Medicine’s
Center for Educational Outreach to every public
ENVIRONMENTAL, SOCIAL AND
GOVERNANCE DISCLOSURE
elementary school in the state.
In the area of environmental stewardship, Hess led
the development of North Dakota’s Intelligent Pipeline
Integrity Project, or iPIPE, to advance new technologies
that prevent and detect pipeline leaks, in cooperation
with five industry partners and the North Dakota
Industrial Commission. In Louisiana, Hess is a member
of the LA1 Coalition, a public–private partnership that
is funding the rebuilding of state highway LA1 above
storm surge levels to ensure a safe evacuation route
when hurricanes or flooding occur. LA1 is the only
roadway connecting workers and supplies to Port
Fourchon, America’s busiest intermodal energy port,
and the only land-based hurricane evacuation route for
Port Fourchon and Grand Isle, a nearby barrier island.
Beneficial sediment disposition during construction will
create 100-plus acres of wetlands.
Hess’ purpose is to be the most trusted energy partner
in the world, and we believe that transparency in
reporting is an important part of that commitment.
In 2018 we continued to be recognized for the quality
of our environmental, social and governance disclosures,
reinforcing our position as a top quartile performer in our
industry. The CDP, an international nonprofit working to
drive sustainable economies, has recognized Hess as
a leader in climate change transparency for the past 10
years. We were also named to Corporate Responsibility
Magazine’s list of 100 Best Corporate Citizens for the
11th consecutive year and were recognized as the top
oil and gas company on the list in 2018. Hess also was
included in the Dow Jones Sustainability Index North
America for the ninth consecutive year.
Additional detail on our environmental, social and gover-
nance programs and progress, as well as performance
data, can be found in our annual sustainability report.
Fulbright English Teaching Assistant Program, Kelantan, Malaysia
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HESS
CORPORATION
BOARD OF DIRECTORS
James H. Quigley (1) (3)
Chairman of the Board;
Former Chief Executive Officer,
Deloitte Touche Tohmatsu Limited
John B. Hess (1)
Chief Executive Officer
Rodney F. Chase (2) (4) (5)
Former Deputy Group
Chief Executive, BP
Terrence J. Checki (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
CORPORATE OFFICERS
John B. Hess
Chief Executive Officer
Gregory P. Hill
Chief Operating Officer
and President,
Exploration & Production
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 (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 (2) (5)
Former Senior Vice President
of E&P for the Americas,
ConocoPhillips
Dr. Risa Lavizzo-Mourey (1) (3)
Penn Integrates Knowledge Professor,
University of Pennsylvania;
Former President and Chief Executive Officer,
The Robert Wood Johnson Foundation
Fredric G. Reynolds (1) (2) (4) (5)
Former Executive Vice
President and Chief Financial
Officer, CBS 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 EHS Subcommittee
Senior Vice Presidents
Vice Presidents
Timothy B. Goodell
General Counsel and
Corporate Secretary
Barbara Lowery-Yilmaz
Richard Lynch
John P. Rielly
Chief Financial Officer
Andrew Slentz
Michael R. Turner
C. Martin Dunagin
Eric Fishman
Treasurer
Lorrie Hecker
Alex Mistri
Alex Sagebien
David Shan
Jonathan C. Stein
Kevin B. Wilcox
Controller
Jay R. Wilson
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ANNUAL REPORT
FORM 10-K
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(cid:59)
(cid:133)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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, N.Y.
(Address of principal executive offices)
13-4921002
(I.R.S. Employer
Identification Number)
10036
(Zip Code)
(Registrant’s telephone number, including area code, is (212) 997-8500)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock (par value $1.00)
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 (cid:59) No (cid:133)
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 (cid:133) No (cid:59)
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 (cid:59) No (cid:133)
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 (cid:59) No (cid:133)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. (cid:59)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company or 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 (cid:59)(cid:3)
Non-accelerated filer (cid:133)(cid:3)
Emerging Growth Company (cid:133)
Accelerated filer (cid:133)
Smaller reporting company (cid:133)
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. (cid:133)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:133) No (cid:59)
The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $17,510,000,000, computed using
the outstanding common shares and closing market price on June 29, 2018, the last business day of the Registrant’s most recently
completed second fiscal quarter.
At January 31, 2019, there were 303,034,262 shares of Common Stock outstanding.
Part III is incorporated by reference from the Proxy Statement for the 2019 annual meeting of stockholders.
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Item No.
HESS CORPORATION
Form 10-K
TABLE OF CONTENTS
PART I
Page
1 and 2. Business and Properties .....................................................................................................................................
1A. Risk Factors .......................................................................................................................................................
1B. Unresolved Staff Comments ..............................................................................................................................
3. Legal Proceedings ..............................................................................................................................................
4. Mine Safety Disclosures ....................................................................................................................................
PART II
5.
Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity
Securities ...................................................................................................................................................................
6. Selected Financial Data .....................................................................................................................................
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ............................
7A. Quantitative and Qualitative Disclosures About Market Risk ...........................................................................
8. Financial Statements and Supplementary Data ..................................................................................................
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............................
9A. Controls and Procedures ....................................................................................................................................
9B. Other Information ..............................................................................................................................................
PART III
10. Directors, Executive Officers and Corporate Governance .................................................................................
11. Executive Compensation ...................................................................................................................................
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters ..........
13. Certain Relationships and Related Transactions, and Director Independence ...................................................
14. Principal Accounting Fees and Services ............................................................................................................
4
14
17
17
18
19
21
22
42
43
94
94
94
94
96
96
96
96
15. Exhibits, Financial Statement Schedules ...........................................................................................................
97
Signatures .......................................................................................................................................................... 100
PART IV
Unless the context indicates otherwise, references to “Hess”, the “Corporation”, the “Company”, “Registrant”, “we”,
“us”, “our” and “its” refer to the consolidated business operations of Hess Corporation and its subsidiaries.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain sections in this Annual Report on Form 10-K, including information incorporated by reference herein, and those
made under the captions Business and Properties, Management’s Discussion and Analysis of Financial Condition and Results
of Operations and Quantitative and Qualitative Disclosures about Market Risk contain “forward-looking” statements, as
defined under the Private Securities Litigation Reform Act of 1995. Generally, the words “anticipate,” “estimate,” “expect,”
“forecast,” “guidance,” “could,” “may,” “should,” “would,” “believe,” “intend,” “project,” “plan,” “predict,” “will,” “target”
and similar expressions identify forward-looking statements, which generally are not historical in nature. Forward-looking
statements related to our operations are based on our current understanding, assessments, estimates and projections of relevant
factors and reasonable assumptions about the future. Forward-looking statements are subject to certain known and unknown
risks and 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. As and when made, we
believe that these forward-looking statements are reasonable. However, given these 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. Risk factors
that could materially impact future actual results are discussed under Item 1A. Risk Factors within this document.
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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.
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.
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 or dry well – An exploratory or development well that does not find oil or natural gas in commercial quantities.
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.
Fractionation – Fractionation is the 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.
Gross acreage – 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.
Mcf – One thousand cubic feet of natural gas.
Mmcfd – One thousand mcf of natural gas per day.
Net acreage or Net wells – The sum of the fractional working interests owned by us in gross acres or gross wells.
NGLs or Natural gas liquids – Naturally occurring substances that are separated and produced by fractionating natural gas,
including ethane, butane, isobutane, propane and natural gasoline. NGLs 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.
Participating interest – Reflects the proportion of exploration and production costs each party will bear or the proportion of
production each party will receive, as set out in an operating agreement.
Production entitlement – The share of gross production the Corporation is entitled to receive under the terms of a production
sharing contract.
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.
2
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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, NGLs 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.
Unproved properties – Properties with no proved reserves.
Working interest – An interest in an oil and gas property that provides the owner of the interest the right to drill for and produce
oil and gas on the relevant acreage and requires the owner to pay a share of the costs of drilling and production operations.
3
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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 Exploration and Production (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.), Denmark, the Malaysia/Thailand Joint
Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana, Suriname, Canada and
in the U.S. Gulf of Mexico. At the Stabroek Block (Hess 30%), offshore Guyana, we have participated in twelve significant
discoveries. The Liza Phase 1 development was sanctioned in 2017 and is expected to startup in early 2020 with production
reaching up to 120,000 gross bopd. The discovered resources to date on the Stabroek Block are expected to underpin the
potential for at least five FPSOs producing more than 750,000 gross bopd by 2025.
Our Midstream operating segment provides fee-based services, including gathering, compressing and processing natural gas
and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane,
and water handling services primarily in the Bakken and Three Forks Shale plays in the Williston Basin area of North Dakota.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for further details.
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, 2018 were $65.55 per barrel for West Texas Intermediate (WTI) (2017: $51.19) and $72.08
per barrel for Brent (2017: $54.87). Our total proved developed and undeveloped reserves at December 31 were as follows:
Crude Oil
& Condensate
2018
2017
(Millions of bbls)
Natural Gas Liquids
2018
2017
(Millions of bbls)
Natural Gas
2018
2017
(Millions of mcf)
Total Barrels of Oil
Equivalent (BOE)
2017
(Millions of bbls)
2018
Developed
United States .................................................
Europe ..........................................................
Africa ............................................................
Asia and other ...............................................
Undeveloped
United States .................................................
Europe ..........................................................
Africa ............................................................
Asia and other (a) .........................................
Total
United States .................................................
Europe ..........................................................
Africa ............................................................
Asia and other (a) .........................................
266
38
111
4
419
235
1
15
44
295
501
39
126
48
714
239
45
112
5
401
194
4
16
44
258
433
49
128
49
659
85
—
—
—
85
90
—
—
—
90
175
—
—
—
175
526
432
87
80
77
—
117
115
—
—
696
585
87 1,209 1,419
84
—
—
—
84
381
1
13
211
606
354
12
7
149
522
423
51
130
102
706
389
1
17
79
486
414
58
132
121
725
337
6
17
69
429
171
—
—
—
751
64
149
190
171 1,815 1,941 1,192 1,154
880
92
124
845
812
52
147
181
813
78
128
796
(a) Asia and other includes proved undeveloped reserves in Guyana of 42 million boe at December 31, 2018 (2017: 45 million boe).
Proved undeveloped reserves were 41% of our total proved reserves at December 31, 2018 on a boe basis (2017: 37%).
Proved reserves held under production sharing contracts totaled 7% of our crude oil reserves and 44% of our natural gas reserves
at December 31, 2018 (2017: 7% and 44%, 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 82 through 92.
4
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Production
Worldwide crude oil, natural gas liquids, and natural gas net production was as follows:
2018
2017
2016
Crude oil - Thousands of barrels
United States
Bakken ..................................................................................................................
Other Onshore (a) .................................................................................................
Total Onshore .................................................................................................
Offshore ................................................................................................................
Total United States .....................................................................................................
Europe
Norway (a) ............................................................................................................
Denmark ...............................................................................................................
Africa
Equatorial Guinea (a) ...........................................................................................
Libya ....................................................................................................................
Asia
JDA ......................................................................................................................
Malaysia ...............................................................................................................
Total ...........................................................................................................................
Natural gas liquids - Thousands of barrels
United States
Bakken .................................................................................................................
Other Onshore (a) .................................................................................................
Total Onshore .................................................................................................
Offshore ...............................................................................................................
Total United States .....................................................................................................
Europe - Norway (a) ...................................................................................................
Total ...........................................................................................................................
Natural gas - Thousands of mcf
United States
Bakken .................................................................................................................
Other Onshore (a) .................................................................................................
Total Onshore .................................................................................................
Offshore ...............................................................................................................
Total United States .....................................................................................................
Europe
Norway (a) ...........................................................................................................
Denmark ...............................................................................................................
Asia and Other
JDA ......................................................................................................................
Malaysia (b) .........................................................................................................
Other ....................................................................................................................
Total ...........................................................................................................................
27,663
389
28,052
15,026
43,078
—
2,231
2,231
—
6,654
6,654
546
851
1,397
53,360
10,767
1,647
12,414
1,703
14,117
—
14,117
25,625
16,167
41,792
24,452
66,244
—
2,958
2,958
68,477
59,995
4,288
132,760
201,962
24,439
2,053
26,492
14,411
40,903
7,236
2,988
10,224
9,201
3,542
12,743
586
289
875
64,745
10,107
2,972
13,079
1,733
14,812
340
15,152
22,621
33,478
56,099
20,987
77,086
6,739
5,124
11,863
73,444
27,225
—
100,669
189,618
24,881
3,209
28,090
16,649
44,739
8,387
3,636
12,023
11,898
387
12,285
616
152
768
69,815
9,701
4,205
13,906
1,724
15,630
408
16,038
22,312
48,597
70,909
23,603
94,512
8,541
7,128
15,669
68,031
13,151
—
81,182
191,363
Total Barrels of Oil Equivalent (in millions) (a) (b) .................................................
101
112
118
(a)(cid:3) In August 2018, the Corporation sold its Utica Assets, onshore U.S. Utica production averaged 9,000 boepd for calendar year 2018 (2017: 19,000 boepd;
2016: 29,000 boepd). In 2017, the Corporation sold its assets in Equatorial Guinea (November), Norway (December), and the Permian, onshore U.S.
(August). Permian production averaged 4,000 boepd for calendar year 2017 (2016: 7,000 boepd).
(b)(cid:3) Includes 6,442 thousand mcf of production for 2018 (2017: 4,256 thousand mcf; 2016: 3,624 thousand mcf) from Block PM301 which is unitized into
Block A-18 of the JDA.
5
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E&P Operations
At December 31, 2018, our significant E&P assets included the following:
United States
Our production in the U.S. was from onshore properties, principally in the Bakken oil shale play in the Williston Basin of
North Dakota (Bakken) and from offshore properties in the Gulf of Mexico.
Onshore:
Bakken: At December 31, 2018, we held approximately 543,000 net acres in the Bakken with varying working interest
percentages. During 2018, we operated an average of 4.8 rigs, drilled 121 wells, completed 118 wells, and brought 104 wells
on production, bringing the total operated production wells to 1,414 by year-end. During 2018, we transitioned from utilizing
sliding sleeve completion designs to plug and perf completions. During 2019, we plan to operate six rigs, drill approximately
170 wells and bring approximately 160 wells on production. From 2019, all production wells will use plug and perf
completions, which we expect will allow us to increase peak net production to approximately 200,000 boepd by 2021. We
forecast net production for full year 2019 to be in the range of 135,000 boepd to 145,000 boepd, compared to production of
117,000 boepd in 2018.
Offshore:
Gulf of Mexico: At December 31, 2018, we held approximately 75,000 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%), Shenzi (Hess 28%), Stampede (Hess 25%) and Tubular Bells (Hess 57%) Fields. At December 31, 2018, we held
approximately 270,000 net undeveloped acres, of which leases covering approximately 37,000 acres are due to expire in the
next three years.
Production from the Baldpate, Conger, Llano, and Penn State Fields were shut-in following a fire at the third-party operated
Enchilada platform in November 2017. In 2018, production restarted at the Baldpate, Llano, and Penn State Fields in the first
quarter, and at the Conger Field in the third quarter. At the Hess operated Stampede Field, production commenced in January
2018. In 2019, we plan to drill one production well and two water injection wells at the Stampede Field, one production well
at the Llano Field, and one exploration well at the Esox prospect which, if successful, can be tied back into production facilities
at the Tubular Bells Field.
Asia
Malaysia/Thailand Joint Development Area (JDA): At the Carigali Hess operated offshore Block A-18 in the Gulf of
Thailand (Hess 50%), no drilling is planned for 2019 as contracted volumes are expected to be met from the booster
compression project that came online in 2016.
Malaysia: Our production in Malaysia comes from our interest in Block PM301 (Hess 50%), which is adjacent to and is
unitized with Block A-18 of the JDA and our 50% interest in Block PM302 located in the North Malay Basin (NMB), offshore
Peninsular Malaysia. Production from full-field development commenced in July 2017. In 2019, we plan to continue the
drilling program and development activities.
Europe
Denmark: Production comes from our operated interest in the South Arne Field (Hess 62%). In 2018, we decided to retain
our interest in the field after offers received in a previously announced sale process did not meet our value expectations. During
2019, we plan to drill an exploration well on License 06/16, located approximately 19 miles from South Arne.
Africa
Libya: At the onshore Waha concession in Libya, which includes the Defa, Faregh, Gialo, North Gialo and Belhedan Fields
(Hess 8%), net production averaged approximately 20,000 boepd in 2018, 10,000 boepd in 2017, and 1,000 boepd in 2016.
Production was shut-in by the operator for extended periods in 2016 due to force majeure caused by civil unrest. The
Company’s net investment in Libya was approximately $55 million at December 31, 2018.
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Other Non-Producing Countries
Guyana: At the Stabroek Block (Hess 30%), which covers approximately 6.6 million acres offshore Guyana, the operator
Esso Exploration and Production Guyana Limited has made twelve significant discoveries to date. The first phase of the Liza
Field development, which was sanctioned in 2017, is expected to begin producing oil by early 2020. Phase 1 will use the Liza
Destiny FPSO to produce up to 120,000 gross bopd. Drilling of development wells in the Liza Field is continuing, subsea
equipment is being prepared for installation, and the topside facilities modules have been installed on the Liza Destiny FPSO
in Singapore, which is expected to arrive offshore Guyana in the third quarter of 2019. Preparations are also underway for the
installation of subsea umbilicals, risers and flowlines at the Liza Field in the spring of 2019.
Phase 2 of the Liza Field development is expected to start production by mid-2022. Pending government and regulatory
approvals, project sanction for Phase 2 is expected by the operator in the first quarter of 2019 and will include a second FPSO
vessel designed to produce up to 220,000 gross bopd. Project sanction for a third phase of development at the Payara Field is
expected in 2019 with first production expected to start up as early as 2023. In addition to the first three phases, development
planning is underway for additional FPSOs. The ultimate sizing and timing will be a function of further exploration and
appraisal drilling.
The operator is currently utilizing three drillships on the block. The Stena Carron and the Noble Tom Madden, which arrived
in the third quarter of 2018, are involved in exploration and appraisal drilling. The Noble Bob Douglas is drilling development
wells for Liza Phase 1. In 2018, the following explorations wells were drilled on the Stabroek Block (in chronological order):
Ranger-1: The well, located approximately 60 miles northwest of the Liza discovery, encountered approximately 230 feet
of high-quality, oil-bearing carbonate reservoir.
Pacora-1: The well encountered approximately 65 feet of high-quality, oil-bearing sandstone reservoir, and is located
approximately four miles west of the Payara-1 well, which was drilled in 2017. The operator plans to integrate this discovery
into the Payara Field development.
Liza-5: The well encountered 77 feet of high-quality, oil-bearing sandstone reservoir and is located approximately six miles
northwest of the Liza-1 well, which was drilled in 2016.
Sorubim-1: The well did not encounter commercial quantities of hydrocarbons.
Longtail-1: The well encountered approximately 256 feet of high-quality, oil-bearing sandstone reservoir and is located
approximately five miles west of the Turbot-1 well, which was drilled in 2017.
Hammerhead-1: The well encountered approximately 197 feet of high-quality, oil-bearing sandstone reservoir and is located
approximately 13 miles to the southwest of the Liza-1 well.
Pluma-1: The well encountered approximately 121 feet of high-quality, hydrocarbon-bearing sandstone reservoir and
represents the tenth discovery on the Block. The well is located approximately 17 miles south of the Turbot-1 well.
In February 2019, the operator announced the eleventh and twelfth discoveries on the Stabroek Block at the Tilapia-1 and
Haimara-1 wells. The Tilapia-1 well encountered approximately 305 feet of high-quality, oil-bearing sandstone reservoir, and
is located approximately three miles west of the Longtail-1 well. The Haimara-1 well encountered approximately 207 feet of
high-quality, gas condensate-bearing sandstone reservoir, and is located approximately 19 miles east of the Pluma-1 well.
In 2019, additional drilling is planned, including appraisal of the Hammerhead, Ranger and Turbot discoveries, as well as a
wider exploration program that will target additional prospects and play types on the block.
In 2018, we acquired a participating interest in the Kaieteur Block (Hess 15%), which is adjacent to the Stabroek Block.
The operator, Esso Exploration and Production Guyana Limited, expects to complete a 2D seismic shoot in 2019.
Suriname: We hold a 33% non-operated participating interest in Block 42, offshore Suriname. In 2018, the operator,
Kosmos Energy Ltd., completed drilling operations on the Pontoenoe-1 exploration well. Commercial quantities of
hydrocarbons were not discovered and well results will be integrated into the ongoing evaluation for future exploration on the
block. We also hold a 33% non-operated participating interest in Block 59, offshore Suriname, where the operator ExxonMobil
Exploration and Production Suriname B.V. commenced a seismic program in 2018.
Canada: We hold a 50% participating interest in four exploration licenses offshore Nova Scotia. In 2018, the operator, BP
Canada, completed drilling of the Aspy exploration well, which did not encounter commercial quantities of hydrocarbons. In
January 2019, the partnership relinquished 50% of the Nova Scotia acreage in accordance with the license agreement timeline.
The retained acreage of approximately 1.75 million gross acres remains under evaluation. We also hold a 25% participating
interest in three BP Canada operated exploration licenses offshore Newfoundland.
7
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Sales Commitments
We have certain long-term contracts with fixed minimum sales volume commitments for natural gas and NGLs
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 950 billion cubic feet of natural gas. We also have NGLs minimum delivery commitments, primarily in the
Bakken through 2023, of approximately 10 million barrels per year, or approximately 55 million barrels 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 and
projected third-party supply.
8
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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
Onshore ................................................................................................................
Offshore ................................................................................................................
Total United States .....................................................................................................
Europe (b) ...................................................................................................................
Africa ..........................................................................................................................
Asia .............................................................................................................................
Worldwide ............................................................................................................
Crude oil - per barrel (excluding hedging)
United States
Onshore ................................................................................................................
Offshore ................................................................................................................
Total United States .....................................................................................................
Europe (b) ...................................................................................................................
Africa ..........................................................................................................................
Asia .............................................................................................................................
Worldwide ............................................................................................................
Natural gas liquids - per barrel
United States
Onshore ................................................................................................................
Offshore ................................................................................................................
Total United States .....................................................................................................
Europe (b) ...................................................................................................................
Worldwide ............................................................................................................
Natural gas - per mcf
United States
Onshore ................................................................................................................
Offshore ................................................................................................................
Total United States .....................................................................................................
Europe (b) ...................................................................................................................
Asia and other .............................................................................................................
Worldwide ............................................................................................................
Average production (lifting) costs per barrel of oil equivalent produced (c)
United States
Onshore (d) ...........................................................................................................
Offshore ................................................................................................................
Total United States .....................................................................................................
Europe (b) ...................................................................................................................
Africa ..........................................................................................................................
Asia and other .............................................................................................................
Worldwide ............................................................................................................
$
$
$
$
$
2018
2017
2016
56.90 $
62.02
58.69
70.08
69.64
70.42
60.77
60.64 $
65.73
62.41
70.08
69.64
70.42
63.80
46.04 $
47.34
46.50
55.03
53.17
56.99
49.23
46.76 $
48.15
47.25
55.14
53.25
56.99
49.75
21.29 $
25.58
21.81
—
21.81
17.67 $
21.34
18.10
29.04
18.35
2.29 $
2.68
2.43
3.61
5.07
4.18
22.34 $
13.80
19.74
26.23
4.42
6.16
15.73
1.96 $
2.22
2.03
4.42
4.27
3.37
19.64 $
11.89
17.42
21.95
14.40
7.83
16.07
36.92
37.47
37.13
43.33
41.88
42.98
39.20
36.92
37.47
37.13
43.33
41.88
42.98
39.20
9.18
13.96
9.71
19.48
9.95
1.48
1.99
1.61
3.97
5.31
3.37
18.40
18.88
18.54
21.28
20.53
11.91
18.29
(a) Includes inter-company transfers valued at approximate market prices, primarily onshore U.S., which include certain processing and distribution fees.
(b) In 2017, we sold our assets in Norway. See Note 3, Dispositions in the Notes to Consolidated Financial Statements. The average selling prices in Norway
for 2016 were $43.32 per barrel for crude oil (including hedging), $43.32 per barrel for crude oil (excluding hedging), $19.48 per barrel for NGLs and
$5.22 per mcf for natural gas. The average production (lifting) costs in Norway were $24.70 per boe in 2016.
(c) 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.
(d) Includes Midstream tariff expense of $13.69 per boe in 2018 (2017: $11.10 per boe; 2016: $9.24 per boe).
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Gross and Net Undeveloped Acreage
At December 31, 2018, gross and net undeveloped acreage amounted to:
United States .......................................................................................................................................
South America ....................................................................................................................................
Europe ................................................................................................................................................
Africa ..................................................................................................................................................
Asia and other (b) ...............................................................................................................................
Total (c) ....................................................................................................................................... (cid:3)
Undeveloped
Acreage (a)
Gross
Net
(In thousands)
436
14,332
169
3,334
6,350
24,621
383
3,943
91
272
2,755
7,444
(a)(cid:3) Includes acreage held under production sharing contracts.
(b)(cid:3) Includes 5.1 million gross acres (2.1 million net acres) offshore Canada.
(c)(cid:3) At December 31, 2018, 26% of our net undeveloped acreage is scheduled to expire during the next three years pending results of exploration activities.
In addition, we relinquished 1.75 million gross acres (0.9 million net acres) offshore Nova Scotia, Canada in January 2019.
Gross and Net Developed Acreage, and Productive Wells
At December 31, 2018 gross and net developed acreage and productive wells amounted to:
Developed Acreage
Applicable to
Productive Wells
Net
Gross
(In thousands)
Productive Wells (a)
Gross
Oil
Net
Gross
Gas
Net
953
United States ................................................................................
Europe .........................................................................................
23
Africa ........................................................................................... 9,564
452
Asia and other ..............................................................................
29
554 2,693 1,281
12 —
19
782 1,032
9
84
118
226 — —
156
Total ...................................................................................... (cid:3) 10,992 1,576 3,744 1,377
14
21
—
1
60
82
(a) Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 105 gross wells and 61 net wells.
Exploratory and Development Wells
Net exploratory and net development wells completed during the years ended December 31 were:
Net Exploratory Wells
2017
2016
2018
Net Development Wells
2017
2016
2018
Productive wells
United States .................................................................................
Europe ..........................................................................................
Asia and other ...............................................................................
Dry holes
United States .................................................................................
Africa (a) ......................................................................................
Asia and other (b) .........................................................................
Total .......................................................................................
—
—
4
4
—
—
2
2
6
—
—
2
2
—
—
—
—
2
—
—
1
1
1
—
1
2
3
92
—
1
93
—
—
—
—
93
65
1
1
67
—
—
—
—
67
83
1
—
84
—
—
—
—
84
(a)(cid:3) In 2017, we expensed seven wells in our Deepwater Tano/Cape Three Points Block, offshore Ghana, which were drilled in prior years.
(b)(cid:3) In 2016, we expensed 18 wells relating to our Equus natural gas project, offshore Australia, which were drilled in prior years.
Number of Wells in the Process of Being Drilled
At December 31, 2018, the number of wells in the process of drilling amounted to:
United States ........................................................................................................................................
Asia and other ......................................................................................................................................
Total............................................................................................................................................... (cid:3)
Gross
Wells
Net
Wells
112
11
123
35
4
39
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Midstream
The Midstream operating segment provides fee-based services, including gathering, compressing and processing natural gas
and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane,
and water handling services primarily in the Bakken and Three Forks Shale plays in the Williston Basin area of North Dakota.
In July 2015, we sold a 50% interest in Hess Infrastructure Partners LP (HIP) to Global Infrastructure Partners (GIP) for net
cash consideration of approximately $2.6 billion. In April 2017, Hess Midstream Partners LP (the “Partnership”), sold
16,997,000 common units representing limited partner interests at a price of $23 per unit in an initial public offering (IPO) for
net proceeds of $365.5 million, of which $350 million was distributed equally to Hess Corporation and GIP.
At December 31, 2018, Hess Corporation and GIP each owned a direct 33.75% limited partner interest in the Partnership
and a 50% indirect ownership interest through HIP in the Partnership’s general partner, which has a 2% economic interest in
the Partnership plus incentive distribution rights. The public unit holders own a 30.5% limited partner interest in the
Partnership. In turn, the Partnership owns an approximate 20% controlling interest in the operating companies that comprise
our midstream joint venture, while HIP, the 50/50 joint venture between Hess Corporation and GIP, owns the remaining 80%.
The Partnership, HIP and its affiliates, and other minor water handling services wholly-owned by Hess comprise the
Midstream operating segment, which currently generates substantially all of its revenues under long-term, fee-based agreements
with our E&P operating segment but intends to pursue additional throughput volumes from third-parties in the Williston Basin
area. We operate the Midstream assets under various operational and administrative services agreements. In December 2018,
we entered into a Memorandum of Understanding with HIP to sell HIP our water handling business for $225 million in cash,
subject to customary adjustments. The parties expect to execute definitive agreements and close the transaction in the first
quarter of 2019, subject to receipt of regulatory approvals.
At December 31, 2018, Midstream assets included the following:
(cid:120)(cid:3) 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 and third-party pipeline facilities. This gathering system consists of approximately 1,200 miles
of high and low pressure natural gas and NGL gathering pipelines with a current capacity of up to approximately 370
mmcfd, including an aggregate compression capacity of approximately 190 mmcfd. The system also includes the
Hawkeye Gas Facility, which contributes approximately 50 mmcfd of the system’s current compression capacity.
(cid:120)(cid:3) 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 and the Johnson’s Corner Header System. The crude oil gathering system consists of approximately
400 miles of crude oil gathering pipelines with a current capacity of up to approximately 160,000 bopd. The system
also includes the Hawkeye Oil Facility, which contributes approximately 75,000 bopd of the system’s current capacity.
(cid:120)(cid:3) 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.
(cid:120)(cid:3) Little Missouri 4: A natural gas processing plant under construction in McKenzie County, North Dakota, with expected
processing capacity of approximately 200 mmcfd. The operator, Targa Resources Corp., estimates the plant will be
in service in the second quarter of 2019. The Partnership owns a 50% interest in Little Missouri 4 through a joint
venture with Targa Resources Corp. and will be entitled to half of the plant’s processing capacity when completed.
(cid:120)(cid:3) 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.
(cid:120)(cid:3) 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.
(cid:120)(cid:3) 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.
(cid:120)(cid:3) Crude Oil Rail Cars: A total of 550 crude oil rail cars, which we operate 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. In 2018, HIP
sold all its remaining older specification crude oil rail cars.
Johnson’s Corner Header System: A crude oil pipeline header system located in McKenzie County, North Dakota
that receives crude oil by pipeline from Hess and third-parties and delivers crude oil to third-party interstate pipeline
systems. The facility has a delivery capacity of approximately 100,000 bopd of crude oil.
(cid:120)(cid:3)
(cid:120)(cid:3) Water assets: A produced water gathering system located primarily in McKenzie, Williams and Mountrail Counties,
North Dakota, consisting of approximately 150 miles of water gathering pipelines.
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Competition and Market Conditions
See Item 1A. Risk Factors for a discussion of competition and market conditions.
Other Items
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, 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 Clean Gulf Associates (CGA), Marine Spill Response Corporation (MSRC),
Marine Well Containment Company (MWCC), Wild Well Control (WWC), Subsea Well Intervention Service (SWIS) and Oil
Spill Response Limited (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, 9 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 $1.11 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 $1.08 billion, 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.
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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.
Under a standard joint operating agreement (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.
Environmental
Compliance with various existing environmental and pollution control regulations imposed by federal, state, local and
foreign governments is not expected to have a material adverse effect on our financial condition or results of operations but
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. We spent approximately $15 million in 2018 for
environmental remediation. The level of other expenditures 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. For further discussion of environmental matters see Environment, Health and
Safety in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Number of Employees
At December 31, 2018, we had 1,708 employees.
Website Access to Our Reports
We make available free of charge through our website at 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, and Corporate Governance and Nominating 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.
Our business and operating results are highly dependent on the market prices of crude oil, NGLs 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, NGLs 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 or inability 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, NGLs and natural gas, political conditions and events (including instability,
changes in governments, armed conflict or economic sanctions) around the world and in particular in crude oil or natural gas
producing regions, the cost of exploring for, developing and producing crude oil, NGLs 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 may also influence the selling prices of crude oil, NGLs and natural gas. Average prices for 2018 were $64.90 per
barrel for WTI (2017: $50.85; 2016: $43.47) and $71.69 per barrel for Brent (2017: $54.74; 2016: $45.13). 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.
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. Reserve replacement can also be achieved through acquisition. Similar risks,
however, may be encountered in the production of oil and gas on properties acquired from others. In addition to the technical
risks to reserve replacement, replacing reserves and developing future production is 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 have the effect of
reducing capital available for exploration and development activity and may render certain development projects uneconomic
or delay their completion and may 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 2016, relative to
preceding years, resulting in reductions to our reported proved reserves. In contrast, crude oil prices improved somewhat in
2017 and 2018 resulting in increases to our reported proved reserves. If crude oil prices in 2019 average below prices used to
determine proved reserves at December 31, 2018, 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.
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,
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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.
We are subject to changing laws and regulations and other governmental actions that can significantly and adversely
affect our business. Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive
tax claims, disallowance of tax credits and deductions, 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, reduction of sulfur content in bunker fuel, the imposition of tariffs, limitations on access to
exploration and development opportunities, anti-bribery or anti-corruption laws, as well as other political developments may
affect our operations and financial results.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms,
if at all. The exploration, development and production of crude oil and natural gas involves 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, or at all. In addition, a ratings downgrade may require that we issue letters of credit or provide other forms
of collateral under certain contractual requirements. Any inability to access capital markets could adversely impact our
financial adaptability and our ability to execute our strategy and may also expose us to heightened exposure to credit risk.
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 the
operations of the oil and gas industry.
Our oil and gas operations are subject to environmental risks and environmental laws and regulations that can result
in significant costs and liabilities. Our oil and gas operations, like those of the industry, 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 laws and regulations. Non-compliance with these laws and regulations may subject us
to administrative, civil or criminal penalties, remedial clean-ups and natural resource damages or 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 and the oil and gas industry in general. 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 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 initiatives may result in significant operational changes and expenditures, reduced demand for our
products and adversely affect our business. We recognize that climate change is a global environmental concern. Continuing
political and social attention to the issue of climate change has resulted in both existing and pending international agreements
and national, regional or local legislation and regulatory measures to limit greenhouse gas 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 greenhouse gases from our
operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs.
In addition, our production is sold to third parties that produce petroleum fuels, which through normal end user consumption
result in the emission of greenhouse gases. Regulatory initiatives to reduce the use of these fuels may reduce demand for crude
oil and other hydrocarbons and have an adverse effect on our sales volumes, revenues and margins. The imposition and
enforcement of stringent greenhouse gas emissions reduction targets could severely and adversely impact the oil and gas
industry and significantly reduce the value of our business. Furthermore, increasing attention to climate change risks has
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resulted in governmental investigations, and public and private litigation, which could increase our costs or otherwise adversely
affect our business. For example, in 2017 certain municipalities and private associations in California, Rhode Island, and
Maryland separately filed lawsuits against over 30 fossil fuel producers, including us, for alleged damages purportedly caused
by climate change.
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.
Catastrophic events, whether naturally occurring or man-made, may materially affect our operations and financial
conditions. Our oil and gas operations are subject to unforeseen occurrences which have affected us from time to time and
which may damage or destroy assets, interrupt operations and have other significant adverse effects. Examples of catastrophic
events include hurricanes, fires, explosions, blowouts, pipeline interruptions and ruptures, severe weather, geological events,
labor disputes or cyber-attacks. We maintain insurance coverage against many, but not all, potential losses and liabilities in
amounts we deem 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 agencies, timely access to
necessary equipment, availability of necessary personnel, construction delays, unfavorable weather conditions and equipment
failures. This may lead to delays and differences between estimated and actual timing of critical events. These delays could
impact our future results of operations and cash flows.
Departures of key members from our senior management team, and/or 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 depends upon the continued service of key members of our senior management team, who play an important
role in developing and implementing our strategy. The departure of key members of senior management or an inability to
recruit and retain adequate numbers of experienced technical and professional personnel in the necessary locations may prevent
us from executing our strategy in full or, in part, which could negatively impact our business.
We are dependent on oilfield service companies for items including drilling rigs, equipment, supplies and skilled
labor. An inability or significant delay in securing these services, or a high cost thereof, may result in material negative
economic consequences. 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. These consequences may impact our ability to run our operations and to deliver projects on time
with the potential for material negative economic consequences.
We manage commodity price and other risks through our risk management function but such activities 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 additional 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 hedging agreement. In addition, we are exposed to risks related to changes in interest rates
and foreign currency values, and may engage in hedging activities to mitigate related volatility.
One of our subsidiaries is the general partner of a publicly traded master limited partnership, Hess Midstream
Partners LP. The responsibilities associated with being a general partner expose us to a broader range of legal liabilities.
Our control of Hess Midstream Partners LP bestows upon us additional fiduciary duties including, but not limited to, the
obligations associated with managing potential conflicts of interests, additional reporting requirements from the Securities and
Exchange Commission and the provision of tax information to unit holders of Hess Midstream Partners LP. These heightened
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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.
Disruption, failure or cyber security breaches affecting or targeting computer, telecommunications systems, and
infrastructure used by the Company may materially impact our business and operations. Computers and
telecommunication systems are used to conduct our exploration, development and production activities and have become an
integral part of our business. We use these systems to analyze and store financial and operating data and to communicate
within our company and with outside business partners. 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 and result in disruptions to our business operations or the access, disclosure or loss of our data and proprietary
information. In addition, computers control oil and gas production, processing equipment, and distribution systems 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, a disruption, failure or a cyber breach of these operating systems, or of the networks and infrastructure on which
they rely 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.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
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 methyl tertiary butyl ether (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 Environmental
Protection Agency (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 also agreed with 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
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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 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. The remedy
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. EPA has estimated that this remedy
will cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of
the remedy remain uncertain. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and
connected ship-building and repair facility adjacent to the Canal. We indicated to EPA that we would comply with the
Administrative Order and are currently contributing funding for the Remedial Design based on an interim allocation of costs
among the parties. At the same time, we are participating in an allocation process whereby a neutral expert selected by the
parties will determine the final shares of the Remedial Design costs to be paid by each of the participants.
On September 28, 2017, we received a general notice letter and offer to settle from the U.S. Environmental Protection
Agency relating to Superfund claims for the Ector Drum, Inc. Superfund Site in Odessa, Texas. The EPA and Texas
Commission on Environmental Quality (TCEQ) took clean-up and response action at the site commencing in 2014 and
concluded in December 2015. The site was determined to have improperly stored industrial waste, including drums with oily
liquids. The total clean-up cost incurred by the EPA was approximately $3.5 million. We were invited to negotiate a voluntary
settlement for our purported share of the clean-up costs. Our share, if any, is undetermined.
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 certain sites, such as those discussed above, the EPA’s claims or assertions of liability against us relating
to these sites have not been fully developed. With respect to the remaining sites, the EPA’s claims have been settled, or a
proposed settlement is under consideration, in all cases for amounts that are not material. The ultimate impact of these
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, but is not
expected to be material.
From time to time, we are involved in other judicial and administrative proceedings, including proceedings relating to other
environmental matters. 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
the aforementioned proceedings is not expected to have a material adverse effect on our financial condition, results of operations
or cash flows.
Item 4. Mine Safety Disclosures
None.
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Item 5. Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity
PART II
Securities
Stock Market Information
Our common stock is traded principally on the New York Stock Exchange (ticker symbol: HES).
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 13 oil and gas peer companies, including us as disclosed in our 2018 Proxy Statement.
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
Holders
At January 31, 2019, there were 3,100 stockholders (based on the number of holders of record) who owned a total of
303,034,262 shares of common stock.
Dividends
In 2018, 2017 and 2016, cash dividends on common stock totaled $1.00 per share per year ($0.25 per quarter).
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Share Repurchase Activities
Our share repurchases activities for the year ended December 31, 2018, were as follows:
2018
Total Number of(cid:3)
Shares Purchased
(a) (b)
Average
Price Paid
per Share (a)
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs (d)
Maximum Approximate
Dollar Value of
Shares that May
Yet be Purchased
Under the Plans
or Programs (e)
(In millions)
January .............................................................................
February ...........................................................................
March...............................................................................
April (c) ...........................................................................
May ..................................................................................
June ..................................................................................
July (c) .............................................................................
August .............................................................................
September ........................................................................
October ............................................................................
November ........................................................................
December .........................................................................
Total for 2018 ...........................................................
607,771 $
3,670,578
3,748,598
8,039,878
—
508,742
2,412,545
729,203
699,004
505,740
2,130,582
2,145,786
25,198,427 $
52.30
45.76
48.57
58.49
—
58.49
63.98
63.97
70.10
63.27
56.79
45.21
54.84
607,771 $
3,670,578
3,708,888
8,039,878
—
508,742
2,412,545
729,203
699,004
505,740
2,130,582
2,145,786
25,158,717
998
830
1,650
1,150
1,150
1,150
950
949
900
868
747
650
(a) Repurchased in open-market transactions. The average price paid per share was inclusive of transaction fees.
(b) Includes 39,710 common shares repurchased in March, all of which were subsequently granted to Directors in accordance with the Non-Employee Directors’
Stock Award Plan.
(c) In April 2018, we entered into an accelerated share repurchase program (ASR) with a financial institution to repurchase $500 million of our common stock,
in which we received an initial delivery of approximately 8 million shares and upon completion of this transaction in June, we received an additional delivery
of approximately 0.5 million shares of our common stock. In July 2018, we entered into an ASR with a financial institution to repurchase $200 million of our
common stock, in which we received an initial delivery of approximately 2.4 million shares and upon completion of this transaction in August, we received an
additional delivery of approximately 0.7 million shares of our common stock. The transaction price for each ASR was determined by the volume-weighted
average price of the shares during the term less a negotiated discount.
(d) Since initiation of the buyback program in August 2013, total shares repurchased through December 31, 2018 amounted to 91.9 million at a total cost of $6.85
billion including transaction fees.
(e) 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, 2018.
Plan Category
Equity compensation plans approved by security holders ......................
Equity compensation plans not approved by security holders (c) ...........
5,170,079 (a) $
—
61.91
—
Number of Securities(cid:3)
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*)
19,036,450 (b)
—
(a) This amount includes 5,170,079 shares of common stock issuable upon exercise of outstanding stock options. This amount excludes 1,063,118 performance
share units (PSU) 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. In addition, this amount also excludes 2,881,204 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, performance share units 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 11, 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:
Income Statement Selected Financial Data
Sales and other operating revenues
2018
2017
2016
(In millions, except per share amounts)
2015
2014
Crude oil (a) ......................................................................................... $ 4,960 $ 4,239 $ 3,639 $ 5,259 $ 9,058
397
Natural gas liquids (a) ..........................................................................
1,247
Natural gas (a) .....................................................................................
35
Other operating revenues (b) ...............................................................
Total Sales and other operating revenues....................................... $ 6,323 $ 5,466 $ 4,762 $ 6,636 $ 10,737
244
1,052
81
533
965
(135 )
264
766
93
457
750
20
Income (loss) from continuing operations .............................................. $
Income (loss) from discontinued operations ...........................................
Net income (loss) .................................................................................... $
Less: Net income (loss) attributable to noncontrolling interests .............
Net income (loss) attributable to Hess Corporation ................................ $
—
—
(115 ) $ (3,941 ) $ (6,076 ) $ (2,959 ) $ 1,692
682
—
(115 ) $ (3,941 ) $ (6,076 ) $ (3,007 ) $ 2,374
57
56
167
(282 ) (d) $ (4,074 ) (e) $ (6,132 ) (f) $ (3,056 ) (g) $ 2,317 (h)
133
(48 )
49
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic:
Continuing operations .......................................................................... $
Discontinued operations ......................................................................
Net income (loss) per share .................................................................... $
(1.10 ) $ (13.12 ) $ (19.92 ) $ (10.61 ) $
—
—
—
(0.17 )
(1.10 ) $ (13.12 ) $ (19.92 ) $ (10.78 ) $
Diluted:
Continuing operations .......................................................................... $
Discontinued operations ......................................................................
Net income (loss) per share .................................................................... $
(1.10 ) $ (13.12 ) $ (19.92 ) $ (10.61 ) $
—
—
—
(0.17 )
(1.10 ) $ (13.12 ) $ (19.92 ) $ (10.78 ) $
5.57
2.06
7.63
5.50
2.03
7.53
Balance Sheet Selected Financial Data
Total assets ............................................................................................. $ 21,433 $ 23,112 $ 28,621 $ 34,157 $ 38,372
Total debt (c) .......................................................................................... $ 6,672 $ 6,977 $ 6,806 $ 6,592 $ 5,952
Total equity ............................................................................................. $ 10,888 $ 12,354 $ 15,591 $ 20,401 $ 22,320
Dividends Per Share
Dividends per share of common stock .................................................... $
1.00 $
1.00 $
1.00 $
1.00 $
1.00
(a)(cid:3) Represents sales of Hess net production and purchased third-party volumes.
(b)(cid:3) Commencing with the adoption of Accounting Standards Codification (ASC) 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 revenue. Prior to January
1, 2018, gains (losses) on commodity derivatives were included within Crude oil revenues. See Note 1, Nature of Operations, Basis of Presentation and
Summary of Accounting Policies in the Notes to Consolidated Financial Statements.
(c)(cid:3) At December 31, 2018 includes debt from our Midstream operating segment of $981 million that is non-recourse to Hess Corporation (2017: $980 million;
2016: $733 million; 2015: $704 million; 2014: $0).
(d)(cid:3) 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 $91 million income tax benefit primarily relating 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.
(e)(cid:3) Includes after-tax impairment charges of $2,250 million (Gulf of Mexico and Norway), an after-tax dry hole and lease impairment charge of $280 million
(Ghana), 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.
(f)(cid:3) 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.
(g)(cid:3) Includes total after-tax charges of $1,943 million, including noncash charges of $1,483 million to write-off all goodwill associated with our Exploration
and production operating segment.
(h)(cid:3) Includes after-tax income of $1,589 million relating to net gains on asset sales and income from the partial liquidation of last-in, first-out (LIFO)
inventories, partially offset by after-tax charges totaling $580 million for dry hole expenses, charges associated with termination of lease contracts,
severance and other exit costs, income tax restructuring charges and other charges.
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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, the information set forth in Risk Factors under Item 1A.
Index
Overview
Consolidated Results of Operations
Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Overview
Hess Corporation, incorporated in the State of Delaware in 1920, is a global Exploration and Production (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.), Denmark, the Malaysia/Thailand Joint
Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana, Suriname, Canada and
in the U.S. Gulf of Mexico. At the Stabroek Block (Hess 30%), offshore Guyana, we have participated in twelve significant
discoveries. The Liza Phase 1 development was sanctioned in 2017 and is expected to startup in early 2020 with production
reaching up to 120,000 gross bopd. The discovered resources to date on the Stabroek Block are expected to underpin the
potential for at least five FPSOs producing more than 750,000 gross bopd by 2025.
Our Midstream operating segment provides fee-based services, including gathering, compressing and processing natural gas
and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane,
and water handling services primarily in the Bakken and Three Forks Shale plays in the Williston Basin area of North Dakota.
In 2018, we completed the sale of our joint venture interests in the Utica shale play in eastern Ohio, onshore U.S., and during
2017 we sold our interests in Equatorial Guinea, Norway and our enhanced oil recovery assets in the Permian Basin, onshore
U.S. These sales, which generated total proceeds of approximately $3.5 billion, are consistent with our strategy to high grade
our portfolio by divesting lower return, mature assets to invest in higher return assets, primarily in Guyana and the Bakken,
and to provide returns to shareholders. During 2018, we repurchased $1.38 billion of common stock (2017: $120 million),
repaid debt of $633 million, and paid dividends of $345 million. At December 31, 2018, we had cash and cash equivalents of
$2.6 billion excluding Midstream.
Outlook
We project our E&P capital and exploratory expenditures will be approximately $2.9 billion in 2019. Capital investment
for our Midstream operations is expected to be approximately $330 million. Oil and gas production in 2019 is forecast to be
in the range of 270,000 boepd to 280,000 boepd excluding Libya, up from 248,000 boepd in 2018, excluding Libya and assets
sold. We have purchased crude oil put options for calendar year 2019 that establish a WTI monthly floor price of $60 per
barrel for 95,000 bopd.
Net cash provided by operating activities was $1,939 million in 2018, compared to $945 million in 2017, while capital
expenditures for 2018 and 2017 were $2,180 million and $1,973 million, respectively. Based on current forward strip crude
oil prices for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at December 31, 2018
will be sufficient to fund our capital investment program and dividends through the end of 2019.
Consolidated Results
Net loss attributable to Hess Corporation was $282 million in 2018 (2017: $4,074 million; 2016: $6,132 million). Excluding
items affecting comparability of earnings between periods summarized on page 26, the adjusted net loss was $176 million in
2018 (2017: $1,401 million; 2016: $1,489 million). Annual production averaged 277,000 boepd in 2018 (2017: 306,000 boepd;
2016: 322,000 boepd). Total proved reserves were 1,192 million boe at December 31, 2018 (2017: 1,154 million boe; 2016:
1,109 million boe).
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Significant 2018 Activities
The following is an update of significant E&P activities during 2018:
Producing E&P assets:
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
In North Dakota, net production from the Bakken oil shale play averaged 117,000 boepd (2017: 105,000 boepd).
During 2018, we operated an average of 4.8 rigs, drilled 121 wells, completed 118 wells, and brought on
production 104 wells. During 2018, we transitioned from utilizing sliding sleeve completion designs to plug and
perf completions. During 2019, we plan to operate six rigs, drill approximately 170 wells and bring approximately
160 wells on production. From 2019, all production wells will use plug and perf completions, which we expect
will allow us to increase peak net production to approximately 200,000 boepd by 2021. We forecast net
production for full year 2019 to be in the range of 135,000 boepd to 145,000 boepd.
In the Gulf of Mexico, net production averaged 57,000 boepd (2017: 54,000 boepd). The increase in production
was primarily due to the Stampede and Penn State Fields, partially offset by the impact of downtime from a
planned well workover at the Tubular Bells Field, the shutdown at the third-party operated Enchilada platform,
and natural field decline. We forecast Gulf of Mexico net production for full year 2019 to be in the range of
65,000 boepd to 70,000 boepd.
In the Gulf of Thailand, net production from Block A-18 of the JDA averaged 36,000 boepd for the year (2017:
37,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay
Basin averaged 27,000 boepd for the year (2017: 11,000 boepd). Production from the North Malay Basin full-
field development project commenced in July 2017. During 2018 we drilled three production wells at North
Malay Basin, and plan to continue the drilling program and development activities in 2019.
We forecast Gulf of Thailand net production for full year 2019 to be in the range of 60,000 boepd and 65,000
boepd.
(cid:120)(cid:3)
In Denmark, we announced that we decided to retain our interest in the Hess operated offshore South Arne Field
after offers received in a previously announced sale process did not meet our value expectations. During 2019,
we plan to drill an exploration well on License 06/16, located approximately 19 miles from South Arne.
Other E&P assets:
(cid:120)(cid:3) Offshore Guyana, at the Stabroek Block (Hess 30%), the operator, Esso Exploration and Production Guyana
Limited progressed the first phase of the Liza Field development, which was sanctioned in 2017. The Liza Phase
1 development, which is expected to begin producing oil by early 2020 will use the Liza Destiny FPSO to produce
up to 120,000 gross bopd. Drilling of development wells in the Liza Field is continuing, subsea equipment is
being prepared for installation, and the topside facilities modules have been installed on the Liza Destiny FPSO
in Singapore, which is expected to arrive offshore Guyana in the third quarter of 2019. Preparations are also
underway for the installation of subsea umbilicals, risers and flowlines at the Liza Field in the spring of 2019.
Phase 2 of the Liza Field development is expected to start production by mid-2022. Pending government and
regulatory approvals, project sanction for Phase 2 is expected by the operator in the first quarter of 2019 and will
include a second FPSO vessel designed to produce up to 220,000 gross bopd. Project sanction for a third phase
of development at the Payara Field is expected in 2019 with first production expected to start up as early as 2023.
In addition to the first three phases, development planning is underway for additional FPSOs. The ultimate sizing
and timing will be a function of further exploration and appraisal drilling.
The operator is currently utilizing three drillships on the block. The Stena Carron and the Noble Tom Madden,
which arrived in the third quarter of 2018, are involved in exploration and appraisal drilling. The Noble Bob
Douglas is drilling development wells for Liza Phase 1. In 2018, the following explorations wells were drilled
on the Stabroek Block (in chronological order):
Ranger-1: The well, located approximately 60 miles northwest of the Liza discovery, encountered
approximately 230 feet of high-quality, oil-bearing carbonate reservoir.
Pacora-1: The well encountered approximately 65 feet of high-quality, oil-bearing sandstone reservoir, and
is located approximately four miles west of the Payara-1 well, which was drilled in 2017. The operator plans
to integrate this discovery into the Payara Field development.
Liza-5: The well encountered 77 feet of high-quality, oil-bearing sandstone reservoir and is located
approximately six miles northwest of the Liza-1 well, which was drilled in 2016.
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Sorubim-1: The well did not encounter commercial quantities of hydrocarbons.
Longtail-1: The well encountered approximately 256 feet of high-quality, oil-bearing sandstone reservoir and
is located approximately five miles west of the Turbot-1 well, which was drilled in 2017.
Hammerhead-1: The well encountered approximately 197 feet of high-quality, oil-bearing sandstone
reservoir and is located approximately 13 miles to the southwest of the Liza-1 well.
Pluma-1: The well encountered approximately 121 feet of high-quality, hydrocarbon-bearing sandstone
reservoir and represents the tenth discovery on the Block. The well is located approximately 17 miles south
of the Turbot-1 well.
In February 2019, the operator announced the eleventh and twelfth discoveries on the Stabroek Block at the
Tilapia-1 and Haimara-1 wells. The Tilapia-1 well encountered approximately 305 feet of high-quality, oil-
bearing sandstone reservoir, and is located approximately three miles west of the Longtail-1 well. The Haimara-
1 well encountered approximately 207 feet of high-quality, gas condensate-bearing sandstone reservoir, and is
located approximately 19 miles east of the Pluma-1 well.
(cid:120)(cid:3) At Block 42 (Hess - 33%), offshore Suriname, the operator, Kosmos Energy Ltd., completed drilling operations
on the Pontoenoe-1 exploration well. Commercial quantities of hydrocarbons were not discovered and well
results will be integrated into the ongoing evaluation for future exploration on the block. Total well costs charged
to exploration expenses were $33 million.
(cid:120)(cid:3)
In Canada, offshore Nova Scotia (Hess - 50%), the operator, BP Canada, completed drilling of the Aspy
exploration well, which did not encounter commercial quantities of hydrocarbons. Total well costs charged to
exploration expenses were $120 million.
The following is an update of significant Midstream activities during 2018:
(cid:120)(cid:3)
In December 2018, we entered into a Memorandum of Understanding with HIP to sell HIP our water handling
business for $225 million in cash, subject to customary adjustments. The parties expect to execute definitive
agreements and close the transaction in the first quarter of 2019, subject to receipt of regulatory approvals.
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Liquidity and Capital and Exploratory Expenditures
In 2018, net cash provided by operating activities was $1,939 million (2017: $945 million; 2016: $795 million). At
December 31, 2018, consolidated cash and cash equivalents were $2,694 million (2017: $4,847 million), consolidated debt was
$6,672 million (2017: $6,977 million), and our consolidated debt to capitalization ratio was 38.0% (2017: 36.1%).
Capital and exploratory expenditures were as follows (in millions):
(cid:3)
E&P Capital and Exploratory Expenditures
United States
(cid:3)
2018
(cid:3)
2017
(cid:3)(cid:3)
2016
Bakken ........................................................................................................................ $
Other Onshore ............................................................................................................
Total Onshore .......................................................................................................
Offshore ......................................................................................................................
Total United States ...........................................................................................................
South America ..................................................................................................................
Europe ..............................................................................................................................
Asia and other ...................................................................................................................
E&P - Capital and Exploratory Expenditures ..................................................................... $
967 $
43
1,010
368
1,378
423
8
260
2,069 $
624 $
30
654
702
1,356
242
142
307
2,047 $
429
46
475
735
1,210
144
65
452
1,871
Exploration expenses charged to income included in E&P capital and exploratory expenditures above were:
United States ..................................................................................................................... $
International ......................................................................................................................
54
Total Exploration Expenses Charged to Income included above ................................... $
160 $
2018
(cid:3)
106 $
2017
(cid:3)(cid:3)
90 $
2016
93
140
233
105
195 $
Midstream Capital Expenditures
Midstream - Capital Expenditures (a) ............................................................................... $
271 $
121 $
283
2018
(cid:3)
2017
(cid:3)(cid:3)
2016
(a)(cid:3) Excludes equity investments of $67 million in 2018.
In 2019, we project our E&P capital and exploratory expenditures will be approximately $2.9 billion.
25
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Consolidated Results of Operations
Results by Segment:
The after-tax income (loss) by major operating activity is summarized below:
2018
2016
2017
(In millions, except per share amounts)
(cid:3)(cid:3)
Net Income (Loss) Attributable to Hess Corporation:
Exploration and Production ............................................................................................... $
Midstream ..........................................................................................................................
Corporate, Interest and Other .............................................................................................
Total ............................................................................................................................... $
51 $
120
(453 )
(282 ) $
Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted (a) . $
(1.10 ) $
(cid:3)(cid:3)
(3,653 ) (cid:3)(cid:3) $
42 (cid:3)(cid:3)
(463 ) (cid:3)(cid:3)
(4,074 ) (cid:3)(cid:3) $
(cid:3)(cid:3)
(13.12 ) (cid:3)(cid:3) $
(4,964 )
42
(1,210 )
(6,132 )
(19.92 )
(a)(cid:3) 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.
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 31 through 35.
Items Affecting Comparability of Earnings Between Periods, After Income Taxes:
Exploration and Production ..............................................................................................
Midstream .........................................................................................................................
Corporate, Interest and Other ............................................................................................
$
Total .............................................................................................................................. $
2018
2017
(In millions)
(cid:3) (cid:3)
(cid:3)
(86 ) $
—
(20 )
(106 ) $
(2,609 )
(34 )
(30 )
(2,673 ) $
(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)
$
2016
(cid:3)(cid:3)
(3,699 )
(21 )
(923 )
(4,643 )
The following table reconciles reported net income (loss) attributable to Hess Corporation and adjusted net income (loss):
2018
2017
(In millions)
2016
Net income (loss) attributable to Hess Corporation ..........................................................
Less: Total items affecting comparability of earnings between periods ...........................
$
Adjusted Net Income (Loss) Attributable to Hess Corporation............................... $
(282 ) $
(106 )
(176 ) $
(4,074 ) $
(2,673 )
(1,401 ) $
(6,132 )
(4,643 )
(1,489 )
Adjusted net income (loss) attributable to Hess Corporation presented in this report 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. 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. This measure is not, and should not be viewed as, a substitute for U.S. GAAP net income (loss).
26
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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 48. The items in the table below are explained on pages 31
through 35.
(cid:3)
2018
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax:
Sales and other operating revenues ................................................................................... $
Gains (losses) on asset sales, net.......................................................................................
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 .............................................................................................................................. $
Comparison of Results
Exploration and Production
Following is a summarized statement of income for our E&P operations:
Before Income Taxes
2017
(In millions)
(cid:3)(cid:3)
(cid:3)(cid:3) (cid:3)
— $
24
(19 )
(3 )
(130 )
(53 )
(16 )
—
(197 ) $
(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)
(22 ) $
(98 )
—
(280 )
(11 )
—
(19 )
(4,203 )
(4,633 ) $
2016
(cid:3)(cid:3)
(cid:3)(cid:3)
—
27
(164 )
(1,029 )
(1 )
(148 )
—
(67 )
(1,382 )
2018
2017
(In millions)
2016
Revenues and Non-Operating Income
Sales and other operating revenues ................................................................................... $
Gains (losses) on asset sales, net.......................................................................................
Other, net ..........................................................................................................................
Total revenues and non-operating income ..................................................................
6,323 $
27
53
6,403
5,460 $
(39 )
(1 )
5,420
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 .................................................................................
Net Income (Loss) Attributable to Hess Corporation ........................................................ $
1,833
941
171
648
362
258
1,748
—
5,961
442
391
51 $
1,335
1,248
119
543
507
224
2,736
4,203
10,915
(5,495 )
(1,842 )
(3,653 ) $
4,755
27
16
4,798
1,128
1,658
101
497
1,442
236
3,113
—
8,175
(3,377 )
1,587
(4,964 )
Excluding the E&P items affecting comparability of earnings between periods in the table on page 31, 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, depreciation, depletion and amortization, exploration expenses and income taxes, as discussed below.
27
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Selling Prices: Average worldwide realized crude oil selling prices, including hedging, were 23% higher in 2018 compared
to the prior year, primarily due to the increase in Brent and WTI crude oil prices. In addition, realized worldwide selling prices
for NGLs increased in 2018 by 19% and worldwide natural gas prices increased in 2018 by 24%, compared to the prior year. In
total, higher realized selling prices improved 2018 financial results by approximately $700 million after income taxes,
compared with 2017. Our average selling prices were as follows:
2018
2017
2016
Crude Oil - Per Barrel (Including Hedging)
United States
Onshore ...................................................................................................................... $
Offshore ......................................................................................................................
Total United States ...........................................................................................................
Europe ..............................................................................................................................
Africa ................................................................................................................................
Asia ...................................................................................................................................
Worldwide ..................................................................................................................
56.90 $
62.02
58.69
70.08
69.64
70.42
60.77
46.04 $
47.34
46.50
55.03
53.17
56.99
49.23
Crude Oil - Per Barrel (Excluding Hedging)
United States
Onshore ...................................................................................................................... $
Offshore ......................................................................................................................
Total United States ...........................................................................................................
Europe ..............................................................................................................................
Africa ................................................................................................................................
Asia ...................................................................................................................................
Worldwide ..................................................................................................................
60.64 $
65.73
62.41
70.08
69.64
70.42
63.80
46.76 $
48.15
47.25
55.14
53.25
56.99
49.75
Natural Gas Liquids - Per Barrel
United States
Onshore ...................................................................................................................... $
Offshore ......................................................................................................................
Total United States ...........................................................................................................
Europe ..............................................................................................................................
Worldwide ..................................................................................................................
21.29 $
25.58
21.81
—
21.81
17.67 $
21.34
18.10
29.04
18.35
Natural Gas - Per Mcf
United States
Onshore ...................................................................................................................... $
Offshore ......................................................................................................................
Total United States ...........................................................................................................
Europe ..............................................................................................................................
Asia and other ...................................................................................................................
Worldwide ..................................................................................................................
2.29 $
2.68
2.43
3.61
5.07
4.18
1.96 $
2.22
2.03
4.42
4.27
3.37
36.92
37.47
37.13
43.33
41.88
42.98
39.20
36.92
37.47
37.13
43.33
41.88
42.98
39.20
9.18
13.96
9.71
19.48
9.95
1.48
1.99
1.61
3.97
5.31
3.37
(a)(cid:3) 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 2018 would be $63.77 per barrel for crude oil (including hedging), $66.80 per barrel for crude oil (excluding hedging),
$22.00 per barrel for NGLs and $4.25 per mcf for natural gas.
Net realized losses from crude oil hedging contracts reduced Sales and other operating revenues by $183 million ($183
million after income taxes) in 2018, and $59 million ($59 million after income taxes) in 2017. There were no crude oil hedge
contracts in 2016. We have purchased crude oil put options for calendar year 2019 that establish a WTI monthly floor price of
$60 per barrel on 95,000 bopd for $116 million, which will be amortized on a straight-line basis during 2019.
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Production Volumes: Our daily worldwide net production was as follows:
2018
2017
2016
(In thousands)
Crude Oil - Barrels
United States
Bakken ........................................................................................................................
Other Onshore ............................................................................................................
Total Onshore .......................................................................................................
Offshore ......................................................................................................................
Total United States ...........................................................................................................
Europe ..............................................................................................................................
Africa ................................................................................................................................
Asia ...................................................................................................................................
Worldwide ............................................................................................................
Natural Gas Liquids – Barrels
United States
Bakken ........................................................................................................................
Other Onshore ............................................................................................................
Total Onshore .......................................................................................................
Offshore ......................................................................................................................
Total United States ...........................................................................................................
Europe ..............................................................................................................................
Worldwide ............................................................................................................
Natural Gas – Mcf
United States
Bakken ........................................................................................................................
Other Onshore ............................................................................................................
Total Onshore .......................................................................................................
Offshore ......................................................................................................................
Total United States ...........................................................................................................
Europe ..............................................................................................................................
Asia and other ...................................................................................................................
Worldwide ............................................................................................................
76
1
77
41
118
6
18
4
146
29
5
34
5
39
—
39
70
44
114
67
181
8
364
553
Barrels of Oil Equivalent .....................................................................................................
277
67
6
73
39
112
28
35
2
177
28
8
36
5
41
1
42
62
92
154
57
211
33
276
520
306
68
9
77
45
122
33
34
2
191
27
11
38
5
43
1
44
61
133
194
64
258
43
222
523
322
Crude oil and natural gas liquids as a share of total production ..............................................
67 %
72 %
73 %
In 2019, we expect net production, excluding Libya, to average between 270,000 boepd and 280,000 boepd, compared to
full year pro forma 2018 net production, excluding Libya and assets sold, of 248,000 boepd.
Production variances related to 2018, 2017 and 2016 are summarized as follows:
United States: Bakken net production was higher in 2018, compared to 2017, primarily due to increased drilling activity
and improved well performance in the current year. The year-on-year decline in U.S. other onshore production in 2018 and
2017 reflects the sale of our interests in the Utica shale play in August 2018 and the sale of our Permian assets in August
2017. Total U.S. offshore oil production was higher in 2018, compared to 2017, primarily due to the Stampede and Penn State
Fields, partially offset by the impact of downtime from a planned well workover at the Tubular Bells Field, the shutdown at
the third-party operated Enchilada platform, and natural field decline. Total offshore production was lower in 2017, compared
to 2016, due to shut-in production from the fire at the third-party operated Enchilada platform and natural field decline, partially
offset by higher production from the Tubular Bells Field. Production from Utica averaged 9,000 boepd for calendar year 2018
(2017: 19,000 boepd; 2016: 29,000 boepd). Production from the Permian averaged net 4,000 boepd for calendar year 2017
(2016: 7,000 boepd).
Europe: Total net production was lower in 2018 compared to 2017, primarily due to the sale of our interests in Norway in
December 2017. Crude oil and natural gas production was lower in 2017 compared to 2016, primarily due to natural field
decline. Production in Norway averaged 24,000 boepd in 2017 (2016: 28,000 boepd).
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Africa: Crude oil production was lower in 2018 compared to 2017, primarily reflecting the sale of Equatorial Guinea in
November 2017, partially offset by higher production in Libya. Crude oil production in 2017 was comparable to 2016, as
lower volumes from Equatorial Guinea were offset by higher production in Libya. Production in Equatorial Guinea averaged
25,000 boepd in 2017 (2016: 33,000 boepd). Production in Libya was 20,000 boepd in 2018 (2017: 10,000 boepd; 2016: 1,000
boepd).
Asia: Natural gas production was higher in 2018, compared to 2017, and in 2017, compared to 2016, primarily due to first
production at the North Malay Basin full-field development in July 2017.
Sales Volumes: The impact of lower sales volumes, primarily due to asset sales, decreased after-tax results by approximately
$150 million in 2018, compared to 2017. Worldwide sales volumes from Hess net production, excluding sales volumes of
crude oil, NGLs and natural gas purchased from third-parties, were as follows:
Crude oil – barrels ..................................................................................................................
Natural gas liquids – barrels ...................................................................................................
Natural gas – mcf ....................................................................................................................
Barrels of Oil Equivalent ...............................................................................................
2018
2017
(In thousands)
2016
52,742
14,019
202,041
100,435
63,367
15,152
190,089
110,201
72,462
16,055
191,482
120,431
Crude oil - barrels per day ......................................................................................................
Natural gas liquids - barrels per day .......................................................................................
Natural gas - mcf per day ........................................................................................................
Barrels of Oil Equivalent Per Day .................................................................................
144
39
553
275
173
42
520
302
198
44
523
329
Marketing, including purchased oil and gas: Marketing expense is mainly comprised of costs to purchase crude oil, NGLs
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. The increases in 2018, compared to 2017, and in 2017, compared to 2016,
primarily reflect the impact of higher benchmark crude oil prices on the cost of purchased volumes.
Cash Operating Costs: Cash operating costs, consisting of operating costs and expenses, production and severance taxes
and E&P general and administrative expenses, decreased by $221 million in 2018, compared to the prior year (2017: $404
million decrease versus 2016). The decrease in 2018, compared to 2017, is primarily due to asset sales and cost savings
initiatives, partially offset by higher production taxes in the Bakken. The decrease in 2017, compared to 2016, is due to lower
workover expenses, lease operating and employee costs, partially offset by higher production taxes in the Bakken. Operating
costs in 2016 include higher workover costs to replace failed subsurface valves in the Gulf of Mexico.
Midstream Tariffs Expense: Tariffs expense in 2018 increased, compared to 2017, primarily due to higher throughput
volumes and water disposal activity in 2018, partially offset by lower costs from our former business in the Permian. Tariffs
expense in 2017 increased, compared to 2016, primarily due to higher shortfall fees in 2017. For 2019, we estimate Midstream
tariffs expense to be in the range of $750 million to $775 million.
Depreciation, Depletion and Amortization: Depreciation, depletion and amortization (DD&A) costs decreased by $988
million in 2018, compared to 2017, primarily due to the sale of assets which had higher DD&A rates than the portfolio average,
a lower DD&A rate at the Bakken due to year-end 2017 proved reserve additions, and the impact of prior year asset impairments.
DD&A costs decreased by $377 million in 2017, compared to 2016, primarily due to lower production and an improved portfolio
average DD&A rate due to the production mix.
Unit costs: Unit cost per boe information is based on total E&P production volumes and excludes items affecting
comparability of earnings as disclosed below. Actual and forecast unit costs are as follows:
2018
Actual
2017
2016
Cash operating costs (b) ....................................... $
DD&A (c) ............................................................
Total Production Unit Costs .......................... $
12.66 $
17.14
29.80 $
14.27 $
24.53
38.80 $
15.56
26.40
41.96
Forecast range (a)
2019
$13.00 — $14.00
18.00 — 19.00
$31.00 — $33.00
(a)(cid:3) Forecast information excludes any contribution from Libya and items affecting comparability of earnings.
(b)(cid:3) Excluding items affecting comparability of earnings and Libya, cash operating costs per boe for 2018 were $13.32 (2017: $14.56; 2016: $15.45).
(c)(cid:3) Excluding items affecting comparability of earnings and Libya, DD&A per boe for 2018 were $18.29 (2017: $25.29; 2016: $26.48).
30
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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 .................................................................................
Geological and geophysical expense and exploration overhead .............................................
(cid:3)(cid:3)
(cid:3) $
2018
(cid:3)
2017
(cid:3)(cid:3)
2016
(In millions)
165 $
37
160
362 $
268 $
44
195
507 $
1,064
145
233
1,442
(a)(cid:3) In 2018, we recorded dry hole costs associated with the Aspy well, offshore Nova Scotia, Canada, the Pontoenoe-1 well, offshore Suriname, and the
Sorubim-1 well on the Stabroek Block, offshore Guyana. In 2017, we recorded dry hole costs associated with our former interests in Ghana. In 2016, we
recorded dry hole costs associated with our former interests in Australia and three exploration wells in the Gulf of Mexico.
Exploration expenses were lower in 2018, compared to 2017, primarily due to lower dry hole expense and lower geologic
and seismic costs. Exploration expenses were lower in 2017, compared to 2016, primarily due to lower dry hole expense,
leasehold impairment expense, geologic and seismic costs, and employee expenses. See items affecting comparability of
earnings between periods described below. For 2019, we estimate exploration expenses, excluding dry hole expense, to be in
the range of $200 million to $220 million.
Income Taxes: The E&P income tax provision was an expense of $391 million in 2018 (2017: $1,842 million benefit; 2016:
$1,587 million expense). Excluding items affecting comparability between periods, the E&P income tax provision was an
expense of $391 million in 2018 (2017: $95 million expense; 2016: $948 million benefit). The provision in 2018 compared to
2017, and 2017 compared to 2016, reflects higher production from Libya and lower deferred tax benefits on losses.
Commencing in 2017, we are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S.,
Denmark (hydrocarbon tax only), Malaysia and Guyana, while we maintain valuation allowances against net deferred tax assets
in these jurisdictions in accordance with the requirements of U.S. accounting standards. See E&P items affecting comparability
of earnings below and Critical Accounting Policies and Estimates – Income Taxes beginning on page 39.
Actual and forecast effective tax rates are as follows:
Effective income tax benefit (expense) rate ............................................................
Adjusted effective income tax benefit (expense) rate (a) ........................................
(88 )
60
34
7
(47 )
42
(a)(cid:3) Excludes any contribution from Libya and items affecting comparability of earnings.
2018
%
Actual
2017
%
2016
%
Forecast range
2019
%
N/A
0 to (4)
Items Affecting Comparability of Earnings Between Periods: Reported E&P earnings include the following items affecting
comparability of income (expense) before and after income taxes:
Before Income Taxes
2018
2017
2016
(cid:3)
(cid:3) 2018
After Income Taxes
2017
2016
17
(41 ) $
Gains (losses) on asset sales, net........................................................ $
(17 )
(110 ) —
Exit costs and other ............................................................................
Impairment ........................................................................................ — (4,203 )
—
(280 ) (1,021 ) (cid:3) —
(745 )
Dry hole, lease impairment and other exploration expenses .............. —
— (cid:3) —
Noncash charges on de-designated crude oil collars .......................... —
—
(22 )
— (cid:3) — — (2,869 )
Income tax adjustments ..................................................................... — —
(66 )
Offshore rig cost ................................................................................ — —
Inventory write-off ............................................................................ — —
(19 )
(86 ) $ (2,609 ) $ (3,699 )
(105 ) (cid:3) — —
(39 ) (cid:3) — —
(In millions)
27 (cid:3)$
(57 ) $
(26 ) (cid:3)
(110 ) —
— (cid:3) — (2,250 )
(280 )
(22 )
(86 ) $ (4,546 ) $ (1,164 ) (cid:3)$
24 $
24 $
$
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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:
(cid:3)
Sales and other operating revenues ......................................................................................... $
Gains (losses) on asset sales, net.............................................................................................
Operating costs and expenses .................................................................................................
Exploration expenses, including dry holes and lease impairment ...........................................
General and administrative expenses ......................................................................................
Depreciation, depletion and amortization ...............................................................................
Impairment .............................................................................................................................
$
2018
Before Income Taxes
2017
(In millions)
2016
— $
24
(19 )
(3 )
(72 )
(16 )
—
(86 ) $
(22 ) $
(41 )
—
(280 )
—
—
(4,203 )
(4,546 ) $
—
27
(162 )
(1,029 )
—
—
—
(1,164 )
2018:
(cid:120)(cid:3) Gains (losses) on asset sales, net: We recorded a pre-tax gain of $14 million ($14 million after income taxes)
associated with the sale of our 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.
(cid:120)(cid:3) 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 severance charge of $37 million ($37 million
after income taxes), related to a cost reduction program undertaken to reflect the reduced scale of our business
following significant asset sales in 2017.
2017:
(cid:120)(cid:3) Gains (losses) on asset sales, net: We recognized a pre-tax gain of $486 million ($486 million after income taxes)
related to the sale of our assets in Equatorial Guinea, and a pre-tax gain of $330 million ($314 million after income
taxes) related to the sale of our enhanced oil recovery assets in the Permian Basin. We also incurred a pre-tax loss of
$857 million ($857 million after income taxes) on the sale of our interests in Norway. The loss included the
recognition of $900 million in earnings for cumulative translation adjustments previously reflected within
accumulated other comprehensive income. See Note 3, Dispositions in the Notes to Consolidated Financial Statements.
(cid:120)(cid:3)
Impairment: We recorded a noncash impairment charge related to our interests in Norway totaling $2,503 million pre-tax
($550 million after income taxes) in the third quarter prior to the sale of our interests in the fourth quarter. In addition, we
recognized pre-tax impairment charges to reduce the carrying value of our interests in the Stampede Field by $1,095
million ($1,095 million after income taxes), and the Tubular Bells Field by $605 million ($605 million after income
taxes) primarily because of a lower long-term crude oil price outlook. The Stampede Field had significant capitalized
exploration and appraisal costs that were incurred on a 100% working interest basis on the Pony discovery prior to
unitizing into the Stampede project. See Note 13, Impairment in the Notes to Consolidated Financial Statements.
(cid:120)(cid:3) Dry hole, lease impairment and other exploration expenses: We recorded a pre-tax charge of $280 million ($280
million after income taxes) to fully impair the carrying value of our interest at the Hess operated offshore Deepwater
Tano/Cape Three Points license, offshore Ghana (Hess 50% license interest) as a result of management’s decision in
the fourth quarter of 2017 to not develop the previously discovered fields. These costs were incurred in periods prior
to 2017.
(cid:120)(cid:3) Noncash charges on de-designated crude oil collars: We recorded a pre-tax charge of $22 million ($22 million after
income taxes) related to certain crude oil collars not designated as cash flow hedges. The de-designation was a result
of production downtime caused by a fire at the third-party operated Enchilada platform in the Gulf of Mexico during
the fourth quarter.
2016:
(cid:120)(cid:3) Dry hole, lease impairment and other exploration expenses: We recorded a pre-tax charge of $938 million ($693
million after income taxes) to write-off all previously capitalized wells and other project related costs for our Equus
natural gas project, offshore the North West Shelf of Australia, following the decision to defer further development
of the project. In addition, we recorded a pre-tax charge of $83 million ($52 million after income taxes) to write-off
the previously capitalized Sicily-1 exploration well based on our decision not to pursue the project. These costs were
incurred in periods prior to 2016.
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(cid:120)(cid:3) Gains on asset sale, net: We recognized a pre-tax gain of $27 million ($17 million after income taxes) related to the
sale of undeveloped onshore acreage in the U.S.
(cid:120)(cid:3)
Income taxes: We recorded a non-cash charge of $2,920 million to establish valuation allowances against net deferred tax
assets at December 31, 2016, as required under application of the accounting standards following a three-year cumulative
loss. This deferred tax charge had no impact on the Corporation’s cash flows or its underlying tax positions. In addition,
we recorded a tax benefit of $51 million related to the resolution of certain international tax matters.
(cid:120)(cid:3) Offshore rig cost: We recognized a pre-tax charge of $105 million ($66 million after income taxes) related to an
offshore drilling rig.
(cid:120)(cid:3)
Inventory write-off: We incurred a pre-tax charge of $39 million ($19 million after income taxes) to write off surplus
materials and supplies inventory.
(cid:120)(cid:3) Exit costs and other: We recorded exit and other costs of $26 million ($17 million after income taxes), which primarily
relates to employee severance as part of a cost reduction program.
Midstream
Following is a summarized statement of income for our Midstream operations, which include results for a gas plant and
associated CO2 assets in the Permian Basin (through August 2017) and water handling services in North Dakota that are wholly-
owned by Hess:
2018
2017
(In millions)
2016
Revenues and Non-Operating Income
Sales and other operating revenues ...................................................................................
Losses on asset sales, net ..................................................................................................
Other, net ..........................................................................................................................
Total revenues and non-operating income ..................................................................
$
713 $
—
6
719
Costs and Expenses
Operating costs and expenses ...........................................................................................
General and administrative expenses ................................................................................
Depreciation, depletion and amortization .........................................................................
Impairment .......................................................................................................................
Interest expense ................................................................................................................
Total costs and expenses .............................................................................................
193
14
127
—
60
394
(cid:3)(cid:3) (cid:3)(cid:3) (cid:3)
617 (cid:3)(cid:3) $
(51 ) (cid:3)(cid:3)
— (cid:3)(cid:3)
566 (cid:3)(cid:3)
(cid:3)(cid:3)
195 (cid:3)(cid:3)
16 (cid:3)(cid:3)
123 (cid:3)(cid:3)
—
26 (cid:3)(cid:3)
360 (cid:3)(cid:3)
(cid:3)(cid:3)
569
—
—
569
218
20
121
67
19
445
124
Results of Operations Before Income Taxes .......................................................................
26
Provision (benefit) for income taxes (a) ...........................................................................
98
Net income (loss) ....................................................................................................................
56
Less: Net income (loss) attributable to noncontrolling interests (b) .................................
Net Income (Loss) Attributable to Hess Corporation ........................................................ $
42
(a)(cid:3) The provision for income taxes in the Midstream segment in 2018 and 2017 is presented before consolidating its operations with other U.S. activities of
325
38
287
167
120 $
206 (cid:3)(cid:3)
31 (cid:3)(cid:3)
175
133
42 $
the Company and prior to evaluating realizability of net U.S. deferred taxes. An offsetting impact is presented in the E&P segment.
(b)(cid:3) The partnership is not subject to tax and, therefore, the noncontrolling interest’s share of net income is a pre-tax amount.
Sales and other operating revenues in 2018 increased, compared to 2017, primarily due to higher throughput volumes and
water disposal activity in 2018, partially offset by prior year activity associated with our former Permian assets that were sold
in August 2017. Sales and other operating revenues in 2017 increased, compared to 2016, primarily due to higher shortfall
fees earned, and higher tariff rates and throughput volumes, partially offset by lower rail export revenue associated with third-
party rail charges and the sale of our Permian assets in August 2017.
Operating costs and expenses in 2018 reflect increased activity related to produced water disposal services and lower costs
from our former Permian assets versus the prior year. Operating costs and expenses were lower in 2017 compared to 2016,
primarily due to lower third-party rail charges and the sale of our Permian assets in August 2017. DD&A expenses were higher
in 2018 compared to 2017, primarily due to pipeline assets that were brought into service in the current year.
The increase in interest expense in 2018, compared to 2017, and 2017, compared to 2016, reflects higher borrowings by
Hess Infrastructure Partners LP.
For 2019, we estimate net income attributable to Hess Corporation from the Midstream segment to be in the range of $170
million to $180 million.
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Items Affecting Comparability of Earnings Between Periods: We recognized a pre-tax loss of $57 million ($34 million after
income taxes and noncontrolling interest) in 2017 related to the sale of our Midstream assets in the Permian Basin. Midstream
results in 2016 included a pre-tax charge of $67 million ($21 million after income taxes and noncontrolling interest) to impair
older specification rail cars.
Corporate, Interest and Other
The following table summarizes Corporate, Interest and Other expenses:
2018
2017
(In millions)
2016
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 ................................ $
97 $
359
(20 )
339
436
(3 )
433
20
453 $
160 $
385
(86 )
299
459
(26 )
433
30
463 $
131
380
(61 )
319
450
(163 )
287
923
1,210
Corporate and other expenses, excluding items affecting comparability, were lower in 2018, compared to 2017, primarily
due to lower employee related costs, non-service pension costs and legal fees. Corporate and other expenses, excluding items
affecting comparability, were higher in 2017, compared to 2016, primarily due to higher legal costs, increased pension
settlement charges in 2017, and the recognition of a nonrecurring gain of $8 million in 2016. In 2019, after-tax Corporate and
other expenses, excluding items affecting comparability of earnings between periods, are estimated to be in the range of
$105 million to $115 million.
Interest expense was lower in 2018, compared to 2017, due to lower average borrowings. Capitalized interest was lower in
2018, compared to 2017, primarily due to the Stampede Field commencing production in January 2018. Interest expense was
higher in 2017, compared to 2016, primarily due to slightly higher average borrowings. Capitalized interest expense was higher
in 2017, compared to 2016, due to increased activity at the Hess operated Stampede development project and sanction of the
Liza Field Phase 1 development project during 2017. In 2019 after-tax interest expense, net is estimated to be in the range of
$315 million to $325 million.
Excluding items affecting comparability of earnings between periods, the benefit for income taxes is lower in 2018 and
2017, compared to 2016, due to us generally not recognizing deferred tax benefit or expense in the U.S. while we maintain
valuation allowances against net deferred tax assets in accordance with the requirements of U.S. accounting standards. This
accounting treatment commenced on December 31, 2016. See items affecting comparability of earnings below and Critical
Accounting Policies and Estimates – Income Taxes beginning on page 39.
Items Affecting Comparability of Earnings Between Periods: Corporate, Interest and Other results included the following
items affecting comparability of income (expense) before and after income taxes:
2018:
(cid:120)(cid:3) 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. See Note 8, Debt, in the Notes to Consolidated Financial Statements.
(cid:120)(cid:3) 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.
(cid:120)(cid:3)
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 hedging program, as required under accounting standards.
2017:
(cid:120)(cid:3) Exit costs and other: We recorded a pre-tax charge of $30 million ($30 million after income taxes) in connection with
vacated office space, of which $11 million is included in General and administrative expenses and $19 million is
included in Depreciation, depletion and amortization in the Statement of Consolidated Income.
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2016:
(cid:120)(cid:3)
Income tax: We recorded a non-cash charge of $829 million to establish valuation allowances against net deferred tax
assets at December 31, 2016, as required under application of the accounting standards following a three-year cumulative
loss. This deferred tax charge had no impact on the Corporation’s cash flows or its underlying tax positions.
(cid:120)(cid:3) Loss on debt extinguishment: We recorded a pre-tax charge of $148 million ($92 million after income taxes) related
to the repurchase and redemption of notes to complete a debt refinancing.
(cid:120)(cid:3) Exit costs and other: We recorded exit and other costs of $3 million ($2 million after income taxes), which primarily
relates to employee severance.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:
2018
2017
(In millions, except ratio)
Cash and cash equivalents (a) ................................................................................................................... $
Current maturities of long-term debt ........................................................................................................
Total debt (b) ............................................................................................................................................
Total equity ...............................................................................................................................................
Debt to capitalization ratio (c) ..................................................................................................................
(a)(cid:3) Includes $109 million of cash attributable to our Midstream Segment, at December 31, 2018 (2017: $356 million).
(b)(cid:3) Includes $981 million of debt outstanding from HIP at December 31, 2018 (2017: $980 million) that is non-recourse to Hess Corporation.
(c)(cid:3) Total debt as a percentage of the sum of total debt plus equity.
2,694
67
6,672
10,888
38.0 %
$
4,847
580
6,977
12,354
36.1 %
Cash Flows
The following table sets forth a summary of our cash flows:
2018
2017
(In millions)
2016
Net cash provided by (used in):
Operating activities .............................................................................................................. $
Investing activities ...............................................................................................................
Financing activities ..............................................................................................................
Net Increase (Decrease) in Cash and Cash Equivalents .............................................. $
1,939 $
(1,566 )
(2,526 )
(2,153 ) $
945 $
1,358
(188 )
2,115 $
795
(2,090 )
1,311
16
Operating Activities: In 2018, net cash provided by operating activities increased, compared to 2017, primarily due to
higher benchmark crude oil prices and lower operating costs, partially offset by lower production volumes largely due to asset
sales. In 2017, operating cash flows increased, compared to 2016, primarily due to higher benchmark crude oil prices and
lower operating costs, partially offset by lower production volumes.
Changes in working capital in 2018 reduced cash by $186 million (2017: $780 million reduction; 2016: $47 million
reduction), primarily from premiums on crude oil hedge contracts and abandonment expenditures. Changes in working capital
in 2017 included increased accounts receivable due to higher crude oil prices, abandonment expenditures, premiums on crude
oil hedge contracts, pension contributions, contract termination payments for an offshore drilling rig, and crude oil delivered
as line fill.
Investing Activities: Total addition to property, plant and equipment were $2,097 million in 2018 (2017: $1,937 million;
2016: $2,251 million). The increase in Additions to property, plant and equipment in 2018, compared to 2017, is primarily
related to increased expenditures in the Bakken, offshore Guyana, offshore Canada and in our Midstream segment, primarily
offset by the impact of prior year asset sales and reduced development expenditure in both the Gulf of Mexico and Malaysia.
In 2017, Additions to property, plant and equipment were lower, compared to 2016, primarily due to lower development
expenditures at North Malay Basin, partially offset by increased investments in Bakken and Guyana in 2017. In 2018,
Midstream equity investments in its 50/50 joint venture with Targa Resources were $67 million. Proceeds from the sale of
assets of $607 million in 2018 (2017: $3,296 million; 2016: $140 million) include the divestiture of our joint venture interests
in the Utica shale play in eastern Ohio, and our share of proceeds from the sale and lease-back transaction of the North Malay
Basin floating storage and offloading vessel.
Financing Activities: Repayments of debt were $633 million in 2018 (2017: $459 million; 2016: $1,455 million) while
borrowings of debt with maturities in excess of 90 days were $800 million in 2017 and $1,496 million in 2016. We settled
common stock purchases in the amount of $1,365 million in 2018 (2017: $110 million). Common and preferred stock dividends
paid were $345 million in 2018 (2017: $363 million; 2016: $350 million). In 2017, Hess Midstream Partners LP received
35
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proceeds of $365.5 million from the issuance of common units in an initial public offering, of which $350 million was
distributed equally to Hess Corporation and GIP. Net outflows to noncontrolling interests were $211 million in 2018 (2017:
$243 million net outflow; 2016: $23 million net outflow). In 2016, we issued 28,750,000 shares of common stock and
depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock for total net proceeds of
$1.64 billion.
Future Capital Requirements and Resources
At December 31, 2018, Hess Corporation, had $2.6 billion in cash and cash equivalents, excluding Midstream, and total
liquidity, including available committed credit facilities, of approximately $7.0 billion. The Corporation has no significant
near-term debt maturities. We have purchased crude oil put options for calendar year 2019 that establish a WTI monthly floor
price of $60 per barrel for 95,000 bopd.
Net production in 2019 is forecast to be in the range of 270,000 boepd to 280,000 boepd, excluding Libya, and we expect
our 2019 E&P capital and exploratory expenditures will be approximately $2.9 billion. Based on current forward strip crude
oil prices for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at December 31, 2018,
will be sufficient to fund our capital investment program and dividends through the end of 2019.
The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at
December 31, 2018:
Hess Corporation
Expiration
Date
Capacity Borrowings
Credit
Issued
(In millions)
Total
Used
Available
Capacity
Letters of
Revolving credit facility - Hess Corporation (a) .... January 2021(cid:3)
Committed lines ..................................................... Various (b)
Uncommitted lines ................................................. Various (b)
$ 4,000 $
445
255
Total - Hess Corporation ..................................
$ 4,700 $
— $
—
—
— $
— $
29
255
284 $
— $ 4,000
416
29
255
—
284 $ 4,416
Midstream
Revolving credit facility - HIP (c) ......................... November 2022 $
Revolving credit facility - Hess Midstream
Partners LP (d) ....................................................... March 2021
Total - Midstream ............................................
$
600 $
— $
— $
— $
600
300
900 $
—
— $
—
— $
—
— $
300
900
(a)(cid:3) In January 2020, the capacity reduces to $3.7 billion.
(b)(cid:3) Committed and uncommitted lines have expiration dates throughout 2019.
(c)(cid:3) This credit facility may only be utilized by HIP and is non-recourse to Hess Corporation.
(d)(cid:3) This credit facility may only be utilized by Hess Midstream Partners LP and is non-recourse to Hess Corporation.
The Corporation’s $4.0 billion syndicated revolving credit facility expires in January 2021, with commitments of $3.7 billion
available for the final year. Borrowings on the facility will generally bear interest at 1.30% above the London Interbank Offered
Rate (LIBOR). The interest rate will be higher if our credit rating is lowered. The facility contains a financial covenant that
limits the amount of the total borrowings on the last day of each fiscal quarter to 60% of the Corporation’s total capitalization,
defined as total debt plus stockholders’ equity. At December 31, 2018, Hess Corporation had no outstanding borrowings or
letters of credit under this facility and was in compliance with this financial covenant.
We had $284 million in letters of credit outstanding at December 31, 2018 (2017: $246 million), which primarily relate to
our international operations. See also Note 21, Financial Risk Management Activities in the Notes to Consolidated Financial
Statements.
We also have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred
stock.
At December 31, 2018, HIP has $800 million of senior secured syndicated credit facilities maturing November 2022,
consisting of a $600 million 5-year revolving credit facility and a drawn $200 million 5-year Term Loan A facility. The
revolving credit facility can be used for borrowings and letters of credit to fund the joint venture’s operating activities and
capital expenditures. 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%. The interest rate is subject to adjustment based on HIP’s leverage ratio, which is calculated as
total debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). If HIP obtains an investment grade
credit rating, as defined in the amended credit agreement, pricing levels will be based on the credit ratings in effect from time
36
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to time. The credit facilities contain financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0 for
the prior four fiscal quarters and an interest coverage ratio, which is calculated as EBITDA to cash interest expense, of no less
than 2.25 to 1.0 for the prior four fiscal quarters. The amended credit agreement includes a secured leverage ratio test not to
exceed 3.75 to 1.00 for so long as the facilities remain secured. HIP is in compliance with these financial covenants at
December 31, 2018. Outstanding borrowings under this credit facility are non-recourse to Hess Corporation. At December 31,
2018, HIP’s revolving credit facility was undrawn and borrowings under the Term Loan A facility amounted to $197.5 million,
excluding deferred issuance costs. The credit facilities are secured by first-priority perfected liens on substantially all of HIP’s
and certain of its wholly-owned subsidiaries’ directly owned assets, including its equity interests in certain subsidiaries, subject
to customary exclusions.
Hess Midstream Partners LP (the “Partnership”) has a $300 million 4-year senior secured syndicated revolving credit facility
that became available for utilization at completion of its initial public offering in April 2017. The credit facility can be used
for borrowings and letters of credit to fund operating activities and capital expenditures of the Partnership and expires March
2021. Borrowings on the credit facility will generally bear interest at LIBOR plus an applicable margin of 1.275%. The interest
rate is subject to adjustment based on the Partnership’s leverage ratio, which is calculated as total debt to EBITDA. If the
Partnership obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time. The Partnership
is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio
of no more than 4.5 to 1.0 for the prior four fiscal quarters. The credit facility is secured by first priority perfected liens on
substantially all directly owned assets of the Partnership and its wholly-owned subsidiaries, including equity interests in
subsidiaries, subject to certain customary exclusions. Outstanding borrowings under this credit facility are non-recourse to
Hess Corporation. At December 31, 2018, this facility was undrawn.
Credit Ratings
Two of the three major credit rating agencies that rate the Corporation’s debt have assigned an investment grade rating. At
December 31, 2018, we have investment grade credit ratings from Standard and Poor’s Ratings Services (BBB-) and Fitch
Ratings (BBB-). Moody’s Investors Service has rated our debt at Ba1. The consequence of lower credit ratings is an increase
in interest rates and facility fees on our credit facilities and the potential for additional required collateral under operating
agreements, which are not material.
At December 31, 2018, HIP’s senior unsecured debt is rated BB+ by Standard and Poor’s Ratings Services, Ba3 by Moody’s
Investors Service, and BB by Fitch Ratings.
Contractual Obligations and Contingencies
The following table shows aggregate information about certain contractual obligations at December 31, 2018:
Payments Due by Period
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3) 2020 and
2022 and (cid:3)(cid:3) (cid:3)
Total
2019
2021
(In millions)
2023
(cid:3)(cid:3)
Thereafter
Total Debt (excludes interest) (a) ....................................... $
Operating Leases (b) (c) .....................................................
Purchase Obligations:
6,672 $
902
67 $
355
66 $
221
192 $
128
6,347
198
Capital expenditures (c) .....................................................
Operating expenses (c) ......................................................
Transportation and related contracts (c) .............................
Asset retirement obligations ..............................................
Other liabilities ..................................................................
1,069
433
1,050
857
518
443
219
212
116
121
551
99
401
75
93
75
61
336
36
84
—
54
101
630
220
(a)(cid:3) We anticipate cash payments for interest of $401 million for 2019, $775 million for 2020-2021, $752 million for 2022-2023, and $3,912 million thereafter
for a total of $5,840 million. These interest payments reflect our contractual obligations at December 31, 2018.
(b)(cid:3) On January 1, 2019, we will adopt ASC 842, Leases, which will result in operating lease commitments greater than one year being reflected on our
Consolidated Balance Sheet. See Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies, in the Notes to Consolidated
Financial Statements for further details.
(c)(cid:3) Comprises obligations where we, as operator, have contracted directly with suppliers.
Capital expenditures represent amounts that we were contractually committed at December 31, 2018, including the portion
of our planned capital expenditure program for 2019. 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, 2018, including pension plan liabilities and estimates for
uncertain income tax positions. The Corporation and certain of its subsidiaries lease drilling rigs, support vessels, office space
and other assets for varying periods under leases accounted for as operating leases.
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Off-Balance Sheet Arrangements
At December 31, 2018, we had $284 million in letters of credit. See also Note 19, Guarantees, Contingencies and
Commitments in the Notes to Consolidated Financial Statements.
Foreign Operations
We conduct E&P activities outside the U.S., principally in the Joint Development Area of Malaysia/Thailand and Malaysia,
Denmark, Libya, Guyana, 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.
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 updates 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 2019 are at levels below that used
in determining 2018 proved reserves, we may recognize negative revisions to our December 31, 2019 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 2019 above those used in determining 2018 proved
reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2019. It is
difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2019,
due to numerous currently unknown factors, including 2019 crude oil prices, any revisions based on 2019 reservoir
performance, and the levels to which industry costs will change in response to movements in commodity prices. A 10% change
in proved developed and proved undeveloped reserves at December 31, 2018 would result in an approximate $200 million pre-
tax change in depreciation, depletion, and amortization expense for 2019 based on projected production volumes. See the
Supplementary Oil and Gas Data on pages 82 through 92 in the accompanying financial statements for additional information
on our oil and gas reserves.
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Midstream Joint Venture: We consolidate the activities of our 50/50 joint venture HIP, 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 our 50% ownership to direct those activities
that most significantly impact the economic performance of HIP, and are obligated to absorb losses or have the right to receive
benefits that could potentially be significant to HIP. This conclusion was based on a qualitative analysis that considered HIP’s
governance structure, the commercial agreements between HIP and us, and the voting rights established between the members,
which provide us the ability to control the operations of HIP.
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 determined 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. While crude oil prices in 2018 were higher than the last few years, we
could experience an asset impairment in the future if the projected production volumes from oil and gas fields decrease, crude oil
and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase
significantly.
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. We conduct the goodwill test at a reporting unit
level, which is defined in accounting standards as an operating segment or one level below an operating segment. The reporting
unit or units used in an evaluation and measurement of goodwill for impairment testing are determined from several factors,
including the manner in which the business is managed. At December 31, 2018, our Midstream operating segment had goodwill
of $360 million that resulted from an allocation from our E&P segment upon the formation of the Midstream segment in 2015.
Our E&P segment has no goodwill at December 31, 2018.
To determine whether an indicator of impairment exists, 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.
Fair value for the Midstream operating segment is based on a market approach, whereby the market capitalization of Hess
Midstream Partners, LP’s (the Partnership), which represents an approximate 20% economic interest in the operating
companies that comprise the Midstream segment, is adjusted to an amount equal to a 100% economic interest in the operating
companies based on the Partnership’s stock price at the time of the impairment test. Other adjustments made to compute fair
value include estimating the fair value of other minor Midstream assets not owned by the Partnership and long-term debt held
directly by HIP.
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 only recognize the financial statement effect of a tax position
when management believes that it is more likely than not, that based on the technical merits, 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.
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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. 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 carryback or carryforward periods that are so brief that it would limit realization of tax benefits if a significant
deductible temporary difference is expected to reverse in a single year. Due to a sustained low commodity price environment,
we remained in a three-year cumulative consolidated loss position at December 31, 2018. 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 (hydrocarbon tax only), Malaysia, and Guyana, while we maintain
valuation allowances against net deferred tax assets in these jurisdictions.
At December 31, 2018, the Consolidated Balance Sheet reflects a $4,877 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 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 9, 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 rate used for measuring the present value of future plan obligations: The discount rate used to estimate our
projected benefit obligation 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, 2018, a 0.25% decrease in the discount rate
assumption would increase projected benefit obligations by approximately $100 million and forecasted 2019 annual benefit
expense by approximately $5 million. The increase in the projected benefit obligation 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 portfolio.
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 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. At December 31, 2018, a 0.25% decrease in the
expected long-term rates of returns on plan assets assumption would increase forecasted 2019 annual benefit expense by
approximately $5 million.
Other assumptions include the rate of future increases in compensation levels and participant mortality level.
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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 commitment 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 of fair value assigned for each physical derivative and financial asset or
liability 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 environment, health, safety and social responsibility (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.
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. We are committed to complying with all Greenhouse Gas (GHG) emissions
mandates and the responsible management of GHG emissions at our facilities.
We will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be
necessary include onshore E&P facilities, sites from discontinued operations where we retained liability and, although not
currently significant, “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. At December 31, 2018, our reserve for estimated remediation liabilities was approximately $80 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 2018 (2017: $15 million; 2016: $10 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.
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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, natural
gas liquids, 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:
(cid:121)(cid:3) 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.
(cid:121)(cid:3) Forward Foreign Exchange Contracts: We enter into forward contracts, primarily for the British Pound, which
commit us to buy or sell a fixed amount of British Pound at a predetermined exchange rate on a future date.
(cid:121)(cid:3) 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.
(cid:121)(cid:3) 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
At December 31, 2018, outstanding total debt, excluding capital leases, was substantially comprised of fixed rate debt
instruments with a carrying value of $6,403 million and a fair value of $6,225 million. A 15% increase or decrease in interest
rates would decrease or increase the fair value of our fixed rate debt by approximately $480 million or $550 million,
respectively. Any changes in interest rates do not impact 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, 2018, we have outstanding WTI crude oil put contracts for calendar year 2019 with a WTI monthly floor
price of $60 per barrel for 95,000 bopd. At December 31, 2018, an assumed 10% increase in the forward WTI crude oil prices
used in determining the fair value of our crude oil put contracts would reduce the fair value of these derivatives instruments by
approximately $120 million, while an assumed 10% decrease in the same WTI crude oil prices would increase the fair value
of these derivative instruments by approximately $140 million.
We have outstanding foreign exchange contracts with a total notional amount of $16 million at December 31, 2018 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% weakening of the U.S. Dollar exchange rate is estimated to be a loss of less than $5 million at
December 31, 2018.
See Note 21, 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
Management’s Report on Internal Control over Financial Reporting ....................................................................
Reports of Independent Registered Public Accounting Firm.................................................................................
Consolidated Balance Sheet at December 31, 2018, and 2017 ..............................................................................
Statement of Consolidated Income for each of the Three Years in the Period Ended December 31, 2018 ...........
Statement of Consolidated Comprehensive Income for each of the Three Years in the Period Ended
December 31, 2018 ...........................................................................................................................................
Statement of Consolidated Cash Flows for each of the Three Years in the Period Ended December 31, 2018 ....
Statement of Consolidated Equity for each of the Three Years in the Period Ended December 31, 2018 ............
Notes to Consolidated Financial Statements ..........................................................................................................
Note 1 - Nature of Operations, Basis of Presentation and Summary of Accounting Policies.......................
Note 2 – Revenue..........................................................................................................................................
Note 3 – Dispositions....................................................................................................................................
Note 4 – Inventories......................................................................................................................................
Note 5 - Property, Plant and Equipment .......................................................................................................
Note 6 - Hess Infrastructure Partners LP ......................................................................................................
Note 7 - Hess Midstream Partners LP – Initial Public Offering ...................................................................
Note 8 - Debt ................................................................................................................................................
Note 9 - Asset Retirement Obligations .........................................................................................................
Note 10 - Retirement Plans ...........................................................................................................................
Note 11 - Share-based Compensation ...........................................................................................................
Note 12 - Exit and Disposal Costs ................................................................................................................
Note 13 – Impairment ...................................................................................................................................
Note 14 - Income Taxes ................................................................................................................................
Note 15 - Basic and Diluted Earnings Per Common Share ..........................................................................
Note 16 - Common and Preferred Stock .......................................................................................................
Note 17 - Supplementary Cash Flow Information ........................................................................................
Note 18 - Leased Assets ...............................................................................................................................
Note 19 - Guarantees, Contingencies and Commitments .............................................................................
Note 20 - Segment Information ....................................................................................................................
Note 21 - Financial Risk Management Activities .........................................................................................
Note 22 - Subsequent Event..........................................................................................................................
Supplementary Oil and Gas Data ...........................................................................................................................
Quarterly Financial Data ........................................................................................................................................
Page
Number
44
45
47
48
49
50
51
52
52
57
59
59
60
61
62
62
64
65
69
70
70
71
73
74
75
75
76
78
79
81
82
93
* 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, 2018.
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, 2018, as stated in their report, which is included
herein.
February 21, 2019
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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, 2018, 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, 2018, 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, 2018 and 2017, the related statements of
consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December
31, 2018, and the related notes and our report dated February 21, 2019 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
February 21, 2019
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
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, 2018 and 2017, the related statements of consolidated income, comprehensive income, cash
flows and equity for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred
to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated
financial position of the Corporation at December 31, 2018 and 2017, and the consolidated results of its operations and its cash
flows for each of the three years in the period ended December 31, 2018, 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, 2018, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(2013 framework), and our report dated February 21, 2019 expressed an unqualified opinion thereon.
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 required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws
and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due
to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
We have served as the Corporation’s auditor since 1971
New York, New York
February 21, 2019
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(cid:3)
(cid:3)
(cid:3)
(cid:3)
2018
December 31,
(cid:3)(cid:3)
(In millions,
except share amounts)
2017
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 .....................................................................................
Goodwill ................................................................................................................................................
Deferred income taxes ...........................................................................................................................
Other assets ............................................................................................................................................
Total Assets .....................................................................................................................
Liabilities
Current Liabilities:
Accounts payable ................................................................................................................................
Accrued liabilities ...............................................................................................................................
Taxes payable .....................................................................................................................................
Current maturities of long-term debt ..................................................................................................
Total current liabilities ............................................................................................................
Long-term debt ......................................................................................................................................
Deferred income taxes ...........................................................................................................................
Asset retirement obligations ..................................................................................................................
Other liabilities and deferred credits ......................................................................................................
Total Liabilities ...............................................................................................................
Equity
Hess Corporation stockholders’ equity:
Preferred stock, par value $1.00; Authorized — 20,000,000 shares:
$
2,694
$
4,847
771
230
245
519
4,459
33,222
17,139
16,083
360
21
510
21,433
495
1,560
81
67
2,203
6,605
421
741
575
10,545
$
$
677
347
232
54
6,157
32,504
16,312
16,192
360
21
382
23,112
435
1,337
83
580
2,435
6,397
429
753
744
10,758
$
$
Series A 8% Cumulative Mandatory Convertible; $1,000 per share liquidation preference;
Issued — 574,997 shares (2017: 575,000) ................................................................................
1
1
Common stock, par value $1.00; Authorized — 600,000,000 shares:
Issued — 291,434,534 shares (2017: 315,053,615) ...................................................................
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 ...........................................................................................
$
291
5,386
4,257
(306 )
9,629
1,259
10,888
21,433
$
315
5,824
5,597
(686 )
11,051
1,303
12,354
23,112
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
(cid:3)
(cid:3)
(cid:3)
Years Ended December 31,
2018
2016
2017
(In millions, except per share amounts)
(cid:3)(cid:3)
(cid:3)(cid:3)
Revenues and Non-Operating Income
Sales and other operating revenues ...................................................................................
Gains (losses) on asset sales, net.......................................................................................
Other, net ..........................................................................................................................
Total revenues and non-operating income ..................................................................
$
$
6,323
32
111
6,466
$
5,466
(86 )
11
5,391
4,762
23
54
4,839
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 .................................................................................. (cid:3) $
$
$
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
$
$
$
$
1,267
1,443
119
507
422
325
—
2,883
4,203
11,169
(5,778 )
(1,837 )
(3,941 )
133
(4,074 )
46
(4,120 )
(13.12 )
(13.12 )
314.1
1.00
$
$
$
$
1,063
1,876
101
1,442
414
338
148
3,244
67
8,693
(3,854 )
2,222
(6,076 )
56
(6,132 )
41
(6,173 )
(19.92 )
(19.92 )
309.9
1.00
See accompanying Notes to Consolidated Financial Statements.
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
2018
Years Ended December 31,
2017
(In millions)
(cid:3)(cid:3)
2016
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Net Income (Loss) .................................................................................................................
$
(115 )
$
(3,941 )
$
(6,076 )
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 ...............................
Foreign currency translation adjustment
Foreign currency translation adjustment ...............................................................
Asset disposition ...................................................................................................
Change in foreign currency translation adjustment .................................................
Other Comprehensive Income (Loss) ............................................................................
Comprehensive Income (Loss) .............................................................................................
Less: Comprehensive income (loss) attributable to noncontrolling interests ....................
Comprehensive Income (Loss) Attributable to Hess Corporation ...................................
$
173
—
173
330
(86 )
244
417
29
(6 )
23
41
—
41
64
—
—
—
481
366
167
199
18
—
18
(156 )
—
(156 )
(138 )
35
—
35
77
—
77
112
144
900
1,044
1,018
—
—
—
—
—
—
—
(155 )
20
(135 )
60
(21 )
39
(96 )
56
—
56
(40 )
(2,923 )
133
(3,056 )
$
(6,116 )
56
(6,172 )
$
See accompanying Notes to Consolidated Financial Statements.
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(cid:3)
Cash Flows from Operating Activities
Net income (loss) ..................................................................................................................
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating
activities
(Gains) losses on asset sales, net.....................................................................................
Depreciation, depletion and amortization .......................................................................
Impairment .....................................................................................................................
Exploratory dry hole costs ..............................................................................................
Exploration lease and other impairment .........................................................................
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 ....................................................................................................................
Proceeds from issuance of Hess Midstream Partnership LP units ........................................
Proceeds from issuance of preferred stock............................................................................
Proceeds from issuance of common stock ............................................................................
Common stock acquired and retired .....................................................................................
Cash dividends paid ..............................................................................................................
Noncontrolling interests, net .................................................................................................
Other, net ..............................................................................................................................
Net cash provided by (used in) financing activities .........................................
2018
Year Ended December 31,
2017
(In millions)
2016
(cid:3)
(cid:3)(cid:3)
(cid:3)(cid:3)
(cid:3)(cid:3)
$
(115 )
$
(3,941 )
$
(6,076 )
(32 )
1,883
—
165
37
72
182
(120 )
53
(138 )
(12 )
88
(2 )
(122 )
1,939
(1,854 )
(243 )
(67 )
607
(9 )
(1,566 )
—
—
(633 )
—
—
—
(1,365 )
(345 )
(211 )
28
(2,526 )
86
2,883
4,203
268
44
86
97
(2,001 )
—
(340 )
(64 )
(44 )
(34 )
(298 )
945
(1,788 )
(149 )
—
3,296
(1 )
1,358
(153 )
800
(459 )
366
—
—
(110 )
(363 )
(243 )
(26 )
(188 )
(23 )
3,244
67
1,064
145
73
—
2,200
148
96
77
(87 )
9
(142 )
795
(1,974 )
(277 )
—
140
21
(2,090 )
43
1,496
(1,455 )
—
557
1,087
—
(350 )
(23 )
(44 )
1,311
16
2,716
2,732
Net Increase (Decrease) in Cash and Cash Equivalents .....................................................
Cash and Cash Equivalents at Beginning of Year ..............................................................
Cash and Cash Equivalents at End of Year.........................................................................
$
(2,153 )
4,847
2,694
$
2,115
2,732
4,847
$
See accompanying Notes to Consolidated Financial Statements.
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED EQUITY
Mandatory
Convertible
Preferred
Stock
Common
Stock
Capital
in
Excess
of Par
Value
Accumulated
Other
Comprehensive
Income (Loss)
Total Hess
Stockholders'
Equity
Retained
Earnings
Noncontrolling
Interests
Total
Equity
Balance at December 31, 2015 ....... $
Net income (loss) ...........................
Other comprehensive income
(loss) ..............................................
Stock issuance ...............................
Share-based compensation activity,
including income taxes ..................
Dividends on preferred stock .........
Dividends on common stock ..........
Noncontrolling interests, net ..........
Balance at December 31, 2016 ....... $
Cumulative effect of adoption of
new accounting standards ..............
Net income (loss) ...........................
Other comprehensive income
(loss) ..............................................
Share-based compensation activity
Dividends on preferred stock .........
Dividends on common stock ..........
Common stock acquired and
retired.............................................
Hess Midstream Partners LP units
issuance .........................................
Noncontrolling interests, net ..........
Balance at December 31, 2017 ....... $
Cumulative effect of adoption of
new accounting standards ..............
Net income (loss) ...........................
Other comprehensive income
(loss) ..............................................
Share-based compensation activity
Dividends on preferred stock .........
Dividends on common stock ..........
Common stock acquired and
retired.............................................
Noncontrolling interests, net ..........
Balance at December 31, 2018 ....... $
— $
—
286 $ 4,127 $ 16,637 $
— — (6,132 )
(1,664 ) $
—
19,386 $
(6,132 )
1,015 $ 20,401
56 (6,076 )
(In millions)
—
1
—
—
—
—
1 $
—
—
—
—
—
—
— — —
29 1,577 —
(40 )
—
(40 )
1,607
—
(40 )
— 1,607
69 —
2
(41 )
— —
— —
(317 )
— — —
317 $ 5,773 $ 10,147 $
—
—
—
—
(1,704 ) $
71
(41 )
(317 )
—
14,534 $
—
—
—
(14 )
71
(41 )
(317 )
(14 )
1,057 $ 15,591
—
(39 )
2
— — (4,074 )
—
—
(37 )
(4,074 )
—
(37 )
133 (3,941 )
— — —
92 —
1
(46 )
— —
(317 )
— —
1,018
—
—
—
1,018
93
(46 )
(317 )
— 1,018
93
—
(46 )
—
(317 )
—
—
(3 )
(43 )
(74 )
—
(120 )
—
(120 )
—
—
1 $
— — —
— — —
315 $ 5,824 $ 5,597 $
—
—
—
—
—
—
— —
— —
101
(282 )
— — —
103 —
1
(46 )
— —
(299 )
— —
—
—
(686 ) $
(101 )
—
481
—
—
—
—
—
11,051 $
356
356
(243 )
(243 )
1,303 $ 12,354
—
(282 )
481
104
(46 )
(299 )
— —
(115 )
167
—
—
—
—
481
104
(46 )
(299 )
—
—
1 $
(541 )
(814 )
(25 )
— — —
291 $ 5,386 $ 4,257 $
—
—
(306 ) $
(1,380 )
—
9,629 $
— (1,380 )
(211 )
(211 )
1,259 $ 10,888
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 Exploration and
Production (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.), Denmark, the
Malaysia/Thailand Joint Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana,
Suriname, Canada and in the U.S. Gulf of Mexico. At the Stabroek Block (Hess 30%), offshore Guyana, we have participated
in twelve significant discoveries and sanctioned in 2017 the first phase of development of the block.
Our Midstream operating segment provides fee-based services, including gathering, compressing and processing natural gas
and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane,
and water handling services primarily in the Bakken and Three Forks Shale plays 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. We also consolidate Hess Infrastructure Partners
LP (HIP), a variable interest entity, based on our conclusion that we have the power through our 50% ownership to direct those
activities that most significantly impact the economic performance of HIP, and are obligated to absorb losses or have 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.
In 2018, we adopted Accounting Standards Codification (ASC) Topic, ASC 606, Revenue from Contracts with Customers,
using the modified retrospective method. Accordingly, the required disclosures under ASC 606 were provided only for the
current period. The adoption of this standard did not affect the timing of revenue recognition for our uncompleted contracts at
January 1, 2018, and as a result, no cumulative effect adjustment to Retained earnings was recognized. Accounts receivables
from contracts with customers is presented separately in the Consolidated Balance Sheet with the prior year balance recast to
conform to the current period presentation. In addition, as the adoption of ASC 606 did not affect previous conclusions
regarding our involvement as a principal versus agent in contracts with customers, there were no changes in presentation to the
Statement of Consolidated Income.
In 2018, we adopted Accounting Standards Update (ASU) 2017-07, Compensation – Retirement Benefits (Topic 715):
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU contains a
provision that prohibits the capitalization of the non-service cost components of net periodic benefit cost when constructing or
producing an asset. This provision was applied prospectively effective January 1, 2018. The ASU contains another provision
requiring that non-service cost components of net periodic benefit cost be presented separately from the service cost component
in the Statement of Consolidated Income. We elected the practical expedient allowing the use of amounts previously disclosed
in the notes to our Consolidated Financial Statements as the basis for the required retrospective application of this provision,
as capitalization of non-service cost components of net periodic benefit cost was not material. For the years ended December
31, 2017 and 2016, the retrospective application resulted in the reclassification of net expense totaling $14 million and $5
million, respectively to Other, net from Operating costs and expenses and General and administrative expenses in our
Statement of Consolidated Income.
In 2018, we adopted ASU 2017-12, Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities.
This ASU makes certain targeted improvements to simplify the application of the existing hedge accounting guidance. The
adoption of this ASU resulted in an increase to Retained earnings and a decrease in Accumulated other comprehensive income
(loss) of $1 million in our Consolidated Balance Sheet in order to remove the cumulative effect of hedging ineffectiveness
previously recognized in earnings for contracts designated as hedging instruments that were outstanding at January 1, 2018.
In 2018,
the FASB
issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic
220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU allows the
reclassification of stranded income tax effects within Accumulated other comprehensive income (loss) to Retained earnings
that resulted from the enactment of U.S. Federal income tax reform, commonly referred to as the U.S. Tax Cuts and Jobs Act
(“Act”). Specifically, this ASU provides entities the option to reclassify the stranded income tax effects resulting from the
reduction to the corporate income tax rate from the Act upon adoption of this ASU, instead of upon liquidation of the individual
items (or of the underlying portfolio of items). This ASU is effective for us beginning in the first quarter of 2019, with early
adoption permitted. We elected to adopt this ASU effective October 1, 2018. The adoption resulted in an increase to Retained
earnings and a decrease to Accumulated other comprehensive income (loss) of $100 million in our Consolidated Balance Sheet.
In 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB
Emerging Issues Task Force). This ASU requires the total change in cash and cash equivalents and restricted cash be reflected
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on the statement of cash flows. A reconciliation to the balance sheet is also required when cash and cash equivalents and
restricted cash are not separately presented on the balance sheet or are presented in more than one financial statement line item
on the balance sheet. The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.
In 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and
Cash Payments (a consensus of the FASB Emerging Issues Task Force). This ASU is intended to reduce diversity in practice
in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific classification
issues for which current guidance is either unclear or is non-specific. The requirement that fees paid to third-parties and
premiums incurred relating to the repayment of debt be classified as financing cash outflows is among the classification issues
addressed by this ASU. The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.
In 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill
Impairment. This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of
goodwill exceeds its implied fair value to a condition that exists when the carrying amount of the reporting unit exceeds its fair
value. Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit
exceeds its fair value, limited by the amount of goodwill allocated to the reporting unit. This ASU is effective for us beginning
in the first quarter of 2020, with early adoption permitted. We elected to adopt this ASU effective October 1, 2018, and the
adoption had no impact on our Consolidated Financial Statements.
Estimates and Assumptions: In preparing financial statements in conformity with U.S. generally accepted accounting
principles (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 our 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: See Note 2, Revenue.
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 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 over the useful lives of the assets 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 determined 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
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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.
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 an indicator of impairment
exists, 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, 2018, 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: Unsold crude oil and NGLs are valued at the lower of cost or net realizable value. Cost is determined based
on the average cost of production. Materials and 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.
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 carryback or carryforward periods that are so brief that it would limit realization of tax
benefits if a significant deductible temporary difference is expected to reverse in a single year. 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, which represent Level 3 inputs in the fair value hierarchy
defined under Fair Value Measurements below. 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 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.
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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 commitment 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 of fair value assigned for each physical derivative and financial asset or liability
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 under the fair value method of accounting. The
fair value of all share-based compensation is recognized over the service period for the entire award, whether the award was
granted with ratable or cliff vesting, net of actual forfeitures. We estimate fair value at the date of grant using a Black-Scholes
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valuation model for employee stock options and a Monte Carlo simulation model for performance share units. 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. For our former operations in Norway that did not use the U.S. Dollar as the functional currency, adjustments resulting
from translating foreign currency assets and liabilities into U.S. Dollars were recorded in the Consolidated Balance Sheet in a
separate component of equity titled Accumulated other comprehensive income (loss) prior to the disposition. See Note 3,
Dispositions.
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 2018,
our reserve for estimated remediation liabilities was approximately $80 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 February 2016, the FASB issued ASU 2016-02, Leases, as a new ASC Topic, ASC
842. The new standard supersedes ASC 840 and will require the recognition of right-of-use assets and lease liabilities for all
leases with lease terms greater than one year, including leases currently treated as operating leases under ASC 840. ASC 842
is effective for us beginning in the first quarter of 2019. We have elected to adopt ASC 842 using the modified retrospective
method which allows application of the new standard prospectively from the date of adoption with a cumulative effect
adjustment, if any, recorded to Retained Earnings at the date of adoption. Accordingly, comparative financial statements for
periods prior to the adoption date of ASC 842 will not be affected. In addition, we have elected to apply a number of practical
expedients permitted by the ASU, including not needing to reassess: (i) whether existing contracts are (or contain) leases, (ii)
whether the lease classification for existing leases would differ under ASC 842, (iii) whether initial direct costs incurred for
existing leases are capitalizable under ASC 842, and (iv) land easements that were not previously accounted for as leases under
ASC 840. We have completed our implementation plan to adopt ASU 842, but we continue to monitor standard setting activity
and our internal controls to comply with the accounting and disclosure requirements. Upon adoption on January 1, 2019, we
expect to recognize operating and finance lease obligations totaling approximately $1.2 billion, of which approximately $390
million of liabilities at December 31, 2018, are included in the Consolidated Balance Sheet. We enter into various leases in
the normal course of business primarily for drilling rigs, a floating storage and offloading vessel, support vessels, and office
space.
In June 2016, the FASB issued 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 to the current "incurred loss" model. This ASU
is effective for us beginning in the first quarter of 2020, with early adoption permitted beginning in the first quarter of 2019.
We are currently assessing the impact of the ASU on our Consolidated Financial Statements.
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2. Revenue
Revenue from contracts with customers on a disaggregated basis in 2018 was as follows (in millions):
Exploration and Production
Midstream Eliminations Total
United
States Europe Africa
(cid:3)(cid:3)
(cid:3)(cid:3)(cid:3)(cid:3)
(cid:3)(cid:3)
Sales of our net production volumes:
(cid:3)(cid:3) (cid:3) (cid:3) (cid:3)
Crude oil revenue ............................................... $ 2,832 $
Natural gas liquids revenue ................................
Natural gas revenue ............................................
(cid:3) (cid:3)
(cid:3)
104 $ 3,523 $
308
859
11
14 1,768
Sales of purchased oil and gas ............................... 1,661 —
Intercompany revenue ........................................... — — — — —
769 6,458
Total revenues from contracts with customers ...... 4,977
(135 )
Other operating revenues (a) .................................
769 $ 6,323 $
308 — — —
651
176
Total sales and other operating revenues .... $ 4,842 $
Asia
(cid:3) (cid:3) (cid:3) (cid:3)
434 $
(135 ) — — —
(cid:3) (cid:3) (cid:3) (cid:3)
153 $
21
93
548 $
164 $
548
164
(cid:3) (cid:3) (cid:3) (cid:3)
E&P
Total
(cid:3)(cid:3)(cid:3) (cid:3)
(cid:3)
(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)
(cid:3)(cid:3)
— $
—
—
—
713
713
—
713 $
— $ 3,523
— 308
— 859
— 1,768
(713 ) —
(713 ) 6,458
— (135 )
(713 ) $ 6,323
(a)(cid:3) Includes gains (losses) on commodity derivatives.
Exploration and Production
The E&P segment recognizes revenue from the sale of crude oil, NGLs, 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 the minimum volume
commitment, 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, NGLs, 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, NGLs, or natural
gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other
operating revenues in the Statement of Consolidated Income.
Contract types
The following is a summary of contract types for our E&P segment:
Crude oil, NGLs, and natural gas – United States (U.S.): Contracts with customers for the sale of U.S. crude oil, NGLs,
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 NGLs that have remaining durations of less than ten years. Contracts
may specify a fixed volume for delivery subject to tolerance thresholds or may specify a percentage of production to be
delivered from a particular location. Pricing is determined with reference to a particular market or pricing index, plus or
minus adjustments reflecting quality or location differentials.
Crude oil – International: Contracts with customers for the sale of international crude oil involve the short-term sale of
volumes during a specified period. These contracts specify a fixed volume for delivery subject to tolerance thresholds.
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.
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Natural gas – 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. These contracts also specify a minimum
volume we are obligated to make available during specified periods within the contract term and may specify minimum
volumes the customer is obligated to purchase during specified periods within the contract term. If we do not deliver the
volume properly nominated by the customer, the customer is entitled to a price discount on future volumes equivalent to the
shortfall delivery. Under certain international natural gas sales agreements, if the customer purchases natural gas volumes
below the minimum volume commitment, the customer is required to pay us for the shortfall volumes and may receive make-
up volumes in subsequent periods at no additional cost.
Revenue from sale of third-party purchased volumes: Crude oil, NGLs, and natural gas 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. The types of contracts with customers for the sale of third-party purchased volumes are the same as those
described above.
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
or where we recognize a liability for price discounts owed against future deliveries as a result of not shipping minimum
volume commitments. At December 31, 2018 and 2017, there were no contract assets or contract liabilities, respectively.
Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil,
NGLs, or natural gas. In 2018, we did not recognize any impairment losses on receivables arising from contracts with
customers.
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 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 a marketing subsidiary 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 our
Midstream segment. 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 provides water handling
services to a subsidiary of Hess 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 to recognize revenue in the amount it is entitled to invoice. If the commercial agreements have take-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 take-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 quarter
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end of the quarterly commitment period. All revenues, receivables, and contract balances arising from the commercial
agreements between the Midstream segment and the Hess marketing subsidiary that is the counterparty to the commercial
agreements are eliminated upon consolidation.
3. Dispositions
2018: We completed the sale of our joint venture interests in the Utica shale play in eastern Ohio in August for proceeds of
$396 million, after normal closing adjustments, and recognized a pre-tax gain of $14 million ($14 million after income taxes).
In addition, we 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).
2017: We completed the sale of our enhanced oil recovery assets in the Permian Basin in August for proceeds of $597
million, after normal closing adjustments, and recognized a pre-tax gain of $273 million ($280 million attributable to Hess
Corporation after income taxes and noncontrolling interest). This sale transaction included both upstream and midstream assets
resulting in an after-tax gain of $314 million allocated to the E&P segment, and an after-tax loss of $34 million allocated to the
Midstream segment. In November, we completed the sale of our interests in Equatorial Guinea for proceeds of $449 million,
after normal closing adjustments, which resulted in a pre-tax gain of $486 million ($486 million after income taxes). In
December, we completed the sale of our interests in the Valhall and Hod assets, offshore Norway for proceeds of $2,056 million,
after normal closing adjustments, which resulted in a pre-tax loss of $857 million ($857 million after income taxes). This loss
includes a recognition in earnings of $900 million for cumulative translation adjustments that were previously reflected within
Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity. We also sold certain U.S. onshore assets for
proceeds totaling approximately $194 million and recognized net pre-tax gains totaling $12 million ($12 million after income
taxes).
Pre-tax income (loss) associated with our interests in Equatorial Guinea and Norway, excluding the financial statement
impacts resulting from the asset sales in 2017, were as follows for the three years ended December 31:
2018
2017
2016
(In millions)
Equatorial Guinea (a) .............................................................................................................. $
Norway (b)..............................................................................................................................
Income (Loss) from Continuing Operations Before Income Taxes ............................... $
— $
—
— $
69 $
(55 )
14 $
(95 )
(195 )
(290 )
(a)(cid:3) Pre-tax income for 2017 excludes the gain of $486 million related to sale of our assets in November 2017.
(b)(cid:3) Pre-tax loss for 2017 excludes the loss of $857 million related to sale of our assets in December 2017. In addition, the 2017 loss excludes a pre-tax
impairment charge of $2,503 million associated with the disposition.
2016: We sold miscellaneous non-core assets during the year for proceeds totaling approximately $100 million and
recognized net pre-tax gains totaling $23 million ($14 million after income taxes).
The asset sales in 2018 and 2017 high grade our portfolio by divesting of lower return, mature assets to invest in higher
return assets, primarily in Guyana and the Bakken, and to fund purchases of common stock and retirement of debt in 2018.
4. Inventories
Inventories at December 31 were as follows:
Crude oil and natural gas liquids ..............................................................................................................
Materials and supplies ..............................................................................................................................
Total Inventories ..................................................................................................................................
$
$
74
171
245
$
$
59
173
232
(cid:3)(cid:3)
(cid:3)(cid:3)
2018
(cid:3)(cid:3)
(In millions)
2017
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5. 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 ........................................................................................... $
2018
2017
(In millions)
394 $
3,124
26,173
29,691
3,492
39
33,222
17,139
16,083 $
520
3,162
25,550
29,232
3,219
53
32,504
16,312
16,192
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:
(cid:3)
(cid:3)(cid:3)
Balance at January 1 ............................................................................................................ $
(cid:3)
(cid:3)
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 .....................................................
Dispositions and other ......................................................................................................
Balance at December 31 ....................................................................................................... $
Number of Wells at December 31 ........................................................................................
2018
2017
2016
(In millions)
304 (cid:3) $
597 (cid:3)(cid:3) $
1,415
128 (cid:3)
116 (cid:3)(cid:3)
79
— (cid:3)
(14 ) (cid:3)
— (cid:3)
418 (cid:3) $
24
(165 ) (cid:3)(cid:3)
(268 ) (cid:3)(cid:3)
24 (cid:3)(cid:3)
304 (cid:3)(cid:3) $
12
—
(897 )
—
597
17
During the three years ended December 31, 2018, additions to capitalized exploratory well costs primarily related to drilling
at the Stabroek Block offshore Guyana. Other drilling activity included the Bunga prospect in Malaysia during 2018 and in
the Gulf of Mexico during 2016. Reclassifications to wells, facilities and equipment based on the determination of proved
reserves primarily related to the sanction of the first phase of Liza Field development, offshore Guyana in 2017.
Capitalized exploratory well costs charged to expense include the following:
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 of which $106 million were incurred and expensed in 2018.
2017: In Ghana, at the Hess operated offshore Deepwater Tano/Cape Three Points license (Hess 50% license interest),
management determined in the fourth quarter of 2017 that it would not develop the previously discovered fields. As a result,
we recorded a charge of $268 million to write-off previously capitalized exploration wells.
2016: At the Hess-operated Equus natural gas project, offshore the North West Shelf of Australia in the fourth quarter of
2016, we terminated a joint front-end engineering study with a third-party natural gas liquefaction joint venture and notified
the Australian government of our intent to defer the project. As a result, we expensed all well costs associated with the project,
including an exploration well completed in the second quarter of 2016, totaling $830 million. These properties were sold in
2017. In the second quarter of 2016, we expensed costs associated with two exploration wells at the non-operated Sicily project
in the Gulf of Mexico where hydrocarbons were encountered but we decided not to pursue the project due to the low commodity
price environment and the limited time remaining on the leases. We also expensed the cost of an unsuccessful exploration well
at the non-operated Melmar project in the Gulf of Mexico, where noncommercial quantities of hydrocarbons were encountered.
The preceding table excludes exploratory dry hole costs of $151 million in 2018 (2017: $0 million; 2016: $167 million),
which were incurred and subsequently expensed in the same year. In 2018, these costs are associated with the Aspy well,
offshore Nova Scotia, Canada, the Pontoenoe-1 well, offshore Suriname, the Sorubim-1 well on the Stabroek Block, offshore
Guyana, and the Bunga Teruntum-1 well in North Malay Basin.
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Exploratory well costs capitalized for greater than one year following completion of drilling were $267 million at December
31, 2018, separated by year of completion as follows (in millions):
2017 ................................................................................................................................................................................... $
2016 ...................................................................................................................................................................................
2015 ...................................................................................................................................................................................
2014 ...................................................................................................................................................................................
2013 ...................................................................................................................................................................................
$
97
—
166
—
4
267
Gulf of Mexico: Approximately 45% of the capitalized well costs in excess of one year relates to the appraisal of the northern
portion of the Shenzi Field (Hess 28% participating interest) in the Gulf of Mexico, where hydrocarbons were encountered in
the fourth quarter of 2015. Following exploration and appraisal drilling activities completed by the operator in prior years on
adjacent blocks to the north of our Shenzi blocks, the operator is planning to acquire 3D seismic in 2019 for use in development
planning of the northern portion of the Shenzi Field.
Guyana: Approximately 35% of the capitalized well costs in excess of one year relates to the Liza-4, Payara-1, Payara-2
and Snoek-1 wells on the Stabroek Block, offshore Guyana (Hess 30%), where hydrocarbons were encountered. The operator
plans to integrate the Liza-4 discovery into the second phase of development, which is expected to commence production by
mid-2022. The operator plans to integrate the Payara-1 and Payara-2 discoveries into the third phase of development, which
is expected to commence production as early as 2023. The Snoek discovery is expected to produce into the Liza Phase 1 FPSO
under a subsequent phase of development.
JDA: Approximately 15% of the capitalized well costs in excess of one year relates to the JDA in the Gulf of Thailand (Hess
50%) 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 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, offshore
Peninsular Malaysia (Hess 50%), where hydrocarbons were encountered in one successful exploration well drilled in the fourth
quarter of 2015. In 2018, we completed four exploration wells and are conducting subsurface evaluations for consideration in
future phases of field development.
6. Hess Infrastructure Partners LP
On July 1, 2015, we sold a 50% interest in Hess Infrastructure Partners LP (HIP) to Global Infrastructure Partners (GIP) for
net cash consideration of approximately $2.6 billion. HIP and its affiliates primarily comprise our Midstream operating
segment. The Midstream operating segment currently generates substantially all of its revenues under long-term, fee-based
agreements with our E&P operating segment and intends to pursue additional throughput volumes from third-parties in the
Williston Basin area. We operate the Midstream assets and operations, including routine and emergency maintenance and
repair services under various operational and administrative services agreements.
The tariff agreements between our E&P operating segment and the Midstream entities became effective on January 1, 2014
and are 10-year, fee-based commercial agreements, with HIP having the sole option to renew the agreements for an additional
10-year term. These agreements include minimum volume commitments based on dedicated production, inflation escalators
and fee recalculation mechanisms. The Midstream segment has minimal direct commodity price exposure, and the E&P
segment retains ownership of the crude oil, natural gas or NGLs processed, terminaled, stored or transported by the Midstream
segment.
We consolidate the activities of HIP, a 50/50 joint venture between Hess Corporation and GIP, which qualifies as a variable
interest entity (VIE) under U.S. GAAP. We have concluded that we are the primary beneficiary of the VIE, as defined in the
accounting standards, since we have the power, through our 50% ownership, to direct those activities that most significantly
impact the economic performance of HIP. This conclusion was based on a qualitative analysis that considered HIP’s
governance structure, the commercial agreements between HIP and us, and the voting rights established between the members,
which provide us the ability to control the operations of HIP.
At December 31, 2018, HIP liabilities totaling $1,105 million (2017: $1,065 million) are on a nonrecourse basis to Hess
Corporation, while HIP assets available to settle the obligations of HIP included Cash and cash equivalents totaling $109
million (2017: $356 million) and Property, plant and equipment, net totaling $2,664 million (2017: $2,520 million).
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7. Hess Midstream Partners LP – Initial Public Offering
In April 2017, Hess Midstream Partners LP (the “Partnership”), sold 16,997,000 common units representing limited partner
interests at a price of $23 per unit in an initial public offering (IPO) for net proceeds of $365.5 million, of which $350 million
was distributed equally to Hess Corporation and GIP.
The Partnership owns an approximate 20% controlling interest in the operating companies that comprise our midstream joint
venture, while HIP, the 50/50 joint venture between Hess Corporation and GIP, owns the remaining 80%. Hess Corporation
and GIP each own a direct 33.75% limited partner interest in the Partnership and a 50% indirect ownership interest through
HIP in the Partnership’s general partner, which has a 2% economic interest in the Partnership plus incentive distribution rights.
The public unit holders own a 30.5% limited partner interest in the Partnership.
8. Debt
Total debt at December 31 consisted of the following:
2018
2017
(In millions)
Debt - Hess Corporation:
Fixed-rate public notes:
8.1% due 2019 ....................................................................................................................... $
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 ........................................................................................................
Capital lease obligations ..............................................................................................................
Financing obligations associated with floating production system ..............................................
Fair value adjustments - interest rate hedging ..............................................................................
Total Debt - Hess Corporation............................................................................................ $
— $
298
992
463
627
537
740
1,234
493
5,384
269
40
(2 )
5,691 $
Debt - Midstream:
Fixed-rate notes: 5.6% due 2026 – HIP ...................................................................................... $
Term loan A facility – HIP ..........................................................................................................
Total Debt – Midstream ...................................................................................................... $
787 $
194
981 $
Total Debt:
Current maturities of long-term debt ........................................................................................... $
Long-term debt ............................................................................................................................
Total Debt ............................................................................................................................. $
67 $
6,605
6,672 $
At December 31, 2018, the maturity profile of total debt was as follows:
349
297
991
500
679
596
740
1,234
493
5,879
—
118
—
5,997
785
195
980
580
6,397
6,977
2019 ........................................................................................................................................ $
2020 ........................................................................................................................................
2021 ........................................................................................................................................
2022 ........................................................................................................................................
2023 ........................................................................................................................................
Thereafter ...............................................................................................................................
Total debt (excluding interest) .......................................................................................... $
67 $
32
34
171
21
6,347
6,672 $
56 $
17
18
19
21
5,560
5,691 $
11
15
16
152
—
787
981
Total
Hess
Corporation Midstream
(In millions)
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Debt (cid:177) Hess Corporation:
Fixed-rate public notes:
At December 31, 2018, Hess Corporation’s fixed-rate public notes had a gross principal amount of $5,438 million (2017:
$5,938 million) and a weighted average interest rate of 5.9% (2017: 6.0%). Our long-term debt agreements, including the
revolving credit facility, contain financial covenants that restrict the amount of total borrowings and secured debt. The most
restrictive of these covenants allow us to borrow up to an additional $3,098 million of secured debt at December 31, 2018.
Capitalized interest was $20 million in 2018 (2017: $86 million; 2016: $61 million).
In 2018, we paid $553 million to redeem $350 million principal amount of 8.125% notes due 2019 and to purchase other
notes with a carrying value of $150 million. As a result, we recorded total losses on debt extinguishment of $53 million in
2018 (2017: $0 million; 2016: $148 million). Concurrent with the redemption of the 2019 notes, we terminated interest rate
swaps with a notional amount of $350 million.
Capital lease:
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 (Hess operated – 50%). Pursuant to the sale
agreement, we received total proceeds of approximately $260 million, including our partner’s share of the proceeds which
is reported in Accounts Payable on our Consolidated Balance Sheet. No gain or loss was recognized from the sale
transaction. The lease agreement is for 16 years with four consecutive twelve-month renewal options that may be exercised
at our discretion. At December 31, 2018, the carrying value of the lease asset is $264 million and the carrying value of the
lease obligation is $269 million, which represents 100% of the present value of future minimum lease payments, of which
$15 million is included in Current maturities of long-term debt and $254 million is included in Long-term debt on our
Consolidated Balance Sheet. As the payments under the lease agreement become due, we will bill our partner their
proportionate share for reimbursement pursuant to the terms of our joint operating agreement.
Credit facility:
Hess Corporation’s $4 billion syndicated revolving credit facility expires in January 2021, with commitments of $3.7
billion available for the final year. Borrowings on the facility will generally bear interest at 1.30% above the London
Interbank Offered Rate (LIBOR). The interest rate will be higher if our credit rating is lowered. The facility contains a
financial covenant that limits the amount of the total borrowings on the last day of each fiscal quarter to 60% of the
Corporation’s total capitalization, defined as total debt plus stockholders’ equity. At December 31, 2018, Hess Corporation
had no outstanding borrowings or letters of credit under this facility and was in compliance with this financial covenant.
Other outstanding letters of credit at December 31 were as follows:
Committed lines (a) .................................................................................................................................. $
Uncommitted lines (a) ..............................................................................................................................
Total ...................................................................................................................................................... $
(a)(cid:3) At December 31, 2018, committed and uncommitted lines have expiration dates throughout 2019.
Debt - Midstream:
Our Midstream segment holds the following non-recourse debt:
Hess Infrastructure Partners (HIP):
2018
2017
(In millions)
29 $
255
284 $
29
217
246
In November 2017, HIP issued $800 million of 5.625% senior notes, due in February 2026 and concurrently amended its
senior unsecured credit facilities. HIP used a portion of the proceeds from the note issuance to repay borrowings under
HIP’s credit facilities and to fund a distribution to the partners. Under the amended credit facilities, the 5-year Term Loan
A facility was reduced to $200 million and the 5-year syndicated revolving credit facility increased to $600 million from
$400 million previously, with the maturity of both facilities extended to November 2022. The amended facilities are secured
by first-priority perfected liens on substantially all of HIP’s and certain of its wholly-owned subsidiaries’ directly owned
assets, including its equity interests in certain subsidiaries, subject to customary exclusions. The 5-year syndicated revolving
credit facility is expected to continue to fund the joint venture’s operating activities and capital expenditures. 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%.
The interest rate continues to be subject to adjustment based on the joint venture’s leverage ratio, which is calculated as total
debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). If HIP obtains an investment grade
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credit rating, as defined in the amended credit agreement, pricing levels will be based on the credit ratings in effect from
time to time. The joint venture is subject to customary covenants in the credit agreement that include financial covenants
that generally require a leverage ratio of no more than 5.0 to 1.0 for the prior four fiscal quarters and an interest coverage
ratio, which is calculated as EBITDA to cash interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters.
The amended credit agreement includes a secured leverage ratio test not to exceed 3.75 to 1.00 for so long as the facilities
remain secured. HIP is in compliance with all debt covenants at December 31, 2018, and its financial covenants do not
currently impact its ability to issue indebtedness to fund future capital expenditures. At December 31, 2018, HIP’s revolving
credit facility was undrawn and borrowings under the Term Loan A facility amounted to $197.5 million, excluding deferred
issuance costs.
Hess Midstream Partners (the Partnership):
The Partnership has a $300 million 4-year senior secured syndicated revolving credit facility through March 2021 that
can be used for borrowings and letters of credit to fund operating activities and capital expenditures of the
Partnership. Borrowings on the credit facility will generally bear interest at LIBOR plus an applicable margin of
1.275%. The interest rate is subject to adjustment based on the Partnership’s leverage ratio, which is calculated as total debt
to EBITDA. If the Partnership obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to
time. The Partnership is subject to customary covenants in the credit agreement, including financial covenants that generally
require a leverage ratio of no more than 4.5 to 1.0 for the prior four fiscal quarters. The credit facility is secured by first
priority perfected liens on substantially all directly owned assets of the Partnership and its wholly-owned subsidiaries,
including equity interests in subsidiaries, subject to certain customary exclusions. Outstanding borrowings under this credit
facility are non-recourse to Hess Corporation. At December 31, 2018, this facility was undrawn.
9. Asset Retirement Obligations
The following table describes changes to and maturity of our asset retirement obligations:
Balance at January 1 ............................................................................................................................... (cid:3) $
Liabilities incurred ............................................................................................................................ (cid:3)
Liabilities settled or disposed of ....................................................................................................... (cid:3)
Accretion expense ............................................................................................................................. (cid:3)
Revisions of estimated liabilities ...................................................................................................... (cid:3)
Foreign currency remeasurement ...................................................................................................... (cid:3)
Balance at December 31 .......................................................................................................................... (cid:3) $
Total Asset Retirement Obligations at December 31:
(cid:3) (cid:3)
Current portion of asset retirement obligations ................................................................................. (cid:3) $
Long-term asset retirement obligations ............................................................................................. (cid:3)
(cid:3)
Total at December 31 ................................................................................................................... (cid:3) $
2018
2017
(In millions)
801 $
68
(46 )
37
1
(4 )
$
857
(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)
116 $
741
857 $
2,128
62
(1,464 )
97
(54 )
32
801
(cid:3)(cid:3)
48
753
801
The liabilities incurred in 2018 include $25 million related to acquired participating interests. The liabilities settled or
disposed of in 2017 primarily relate to the sale of our interests in Norway and Equatorial Guinea. The fair value of 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, was $148 million at December 31, 2018 (2017: $118 million).
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10. 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. Additionally, we maintain an unfunded
postretirement medical plan that provides health benefits to certain 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
2018
2017
2018
2017
2018
2017
(In millions)
Change in Benefit Obligation
Balance at January 1, ...................................................................... $ 2,765
30
84
(237 )
(110 )
(10 )
4
(34 )
Balance at December 31, (c) ........................................................... 2,492
Service cost ..................................................................................
Interest cost ..................................................................................
Actuarial (gains) loss (a) ..............................................................
Benefit payments (b)....................................................................
Plan curtailments .........................................................................
Plan amendments .........................................................................
Foreign currency exchange rate changes .....................................
$ 2,560
36
93
138
(113 )
(3 )
—
54
2,765
$
249
12
7
(29 )
(19 )
(4 )
—
—
216
$
256
13
9
10
(39 )
—
—
—
249
$
87
2
3
(24 )
(7 )
(2 )
—
—
59
$
84
4
3
3
(7 )
—
—
—
87
Change in Fair Value of Plan Assets
Balance at January 1, ...................................................................... $ 2,732
(77 )
59
(110 )
(36 )
Balance at December 31, ................................................................ 2,568
Actual return on plan assets .........................................................
Employer contributions ...............................................................
Benefit payments (b)....................................................................
Foreign currency exchange rate changes .....................................
$ 2,284
351
158
(113 )
52
2,732
$ —
—
19
(19 )
—
—
$ —
—
39
(39 )
—
—
$ —
—
7
(7 )
—
—
$ —
—
7
(7 )
—
—
Funded Status (Plan assets greater (less) than benefit
obligations) at December 31, ........................................................... $
76
$
(33 )
$
(216 )
$
(249 )
$
(59 )
$
(87 )
Unrecognized Net Actuarial (Gains) Losses .................................. $
778
$
789
$
47
$
84
$
(32 )
$
(10 )
(a)(cid:3) The change in discount rate in 2018 resulted in total actuarial gains of approximately $235 million (2017: $170 million of actuarial losses).
(b)(cid:3) Benefit payments include lump-sum settlement payments of approximately $32 million in 2018 (2017: $57 million).
(c)(cid:3) At December 31, 2018, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $2,424 million and $171 million,
respectively (2017: $2,679 million and $190 million, respectively).
Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following:
Funded
Pension Plans
Unfunded
Pension Plan
2018
2017
2018
2017
Postretirement
Medical Plan
2018
2017
(In millions)
Noncurrent assets ............................................................................... $
76
Current liabilities ............................................................................... —
Noncurrent liabilities ......................................................................... —
76
Pension assets / (accrued benefit liability) ............................... $
$
22
—
(55 )
(33 )
$
$ —
(30 )
(186 )
(216 )
$
$ —
(18 )
(231 )
(249 )
$
$ —
(9 )
(50 )
(59 )
$
$ —
(11 )
(76 )
(87 )
$
Accumulated other comprehensive loss, pre-tax (a) .......................... $
778 $
789 $
47 $
84 $
(32 ) $
(10 )
(a)(cid:3) The after-tax deficit reflected in Accumulated other comprehensive income (loss) was $581 million at December 31, 2018 (2017: $548 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
2017
2016
2018
Postretirement Medical Plan
2016
2017
2018
49 $
Service cost ....................................................................................... $
102
Interest cost .......................................................................................
(168 )
Expected return on plan assets ..........................................................
58
Amortization of unrecognized net actuarial losses (gains)................
Settlement loss ..................................................................................
19
Curtailment gain ............................................................................... — —
Special termination benefit recognized ............................................. — —
60 $
Net Periodic Benefit Cost (a) .................................................... $
42 $
91
(194 )
39
4
(18 ) $
2 $
3
(In millions)
4 $
60 $
107
3
(166 ) — —
60
(2 ) —
— — —
—
(2 ) —
1 — —
7 $
1 $
62 $
4
3
—
—
—
—
—
7
(a)(cid:3) Net non-service pension costs are included in Other, net in the Statement of Consolidated Income. In 2018, net non-service pension costs amounted to
income of $61 million (2017: $14 million of expense; 2016: $5 million of expense).
In 2018, we recorded curtailment gains of $14 million to Accumulated other comprehensive Income (loss) and $2 million to
the Statement of Consolidated Income following workforce reductions. In connection with this curtailment, as required under
accounting standards, we remeasured our U.S. retirement plans and recorded a total decrease of $125 million in the
Corporation’s U.S. post retirement liabilities. This reduction was primarily driven by a change in weighted average discount
rates used to measure the liabilities. There was no change to the weighted average expected long-term rate of return on plan
assets.
For the full year 2019, we forecast pension service costs for our pension and postretirement medical plans to be
approximately $40 million and net non-service pension costs of approximately $40 million of income, which is comprised of
interest cost of approximately $95 million, amortization of unrecognized net actuarial losses of approximately $45 million, and
estimated expected return on plan assets of approximately $180 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........................................................................................
2018
2017
2016
3.9 %
3.8 %
3.9 %
3.3 %
7.2 %
4.5 %
3.3 %
4.5 %
3.7 %
3.7 %
7.3 %
4.6 %
3.7 %
4.6 %
4.1 %
4.1 %
7.4 %
4.5 %
The actuarial assumptions used to determine Benefit obligations at December 31 for the postretirement medical plan were
as follows:
(cid:3)
2018
(cid:3)
2017
2016
Discount rate .....................................................................................................................
Initial health care trend rate ..............................................................................................
Ultimate trend rate ............................................................................................................
Year in which ultimate trend rate is reached .....................................................................
3.9 %
6.9 %
4.5 %
2038
3.2 %
7.3 %
4.5 %
2038
3.5 %
7.7 %
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. Beginning in 2018, we have elected to use a split discount rate approach
for all of our retirement plans. This involves the continued use of a single weighted-average discount rate in the calculation of
the projected benefit obligation, and separate discount rates for each projected benefit payment in the calculation of service
cost and interest cost. In contrast, historically, a single weighted-average discount rate was used in both the calculation of the
projected benefit obligation, and service cost and interest cost.
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
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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 are highly liquid, providing ample liquidity for benefit payment requirements. The current target
allocations for plan assets are 50% equity securities, 30% 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, 2018 and
2017 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
(In millions)
Net Asset
Value (d)
Total
December 31, 2018
Cash and Short-Term Investment Funds ............................................. $
Equities:
3 $
47 $
— $
— $
50
U.S. equities (domestic) .........................................................................
International equities (non-U.S.)............................................................
Global equities (domestic and non-U.S.) ...............................................
654
92
2
Fixed Income:
Treasury and government issued (a) ......................................................
Government related (b) ..........................................................................
Mortgage-backed securities (c) ..............................................................
Corporate ...............................................................................................
—
—
—
—
—
29
203
240
37
159
272
Other:
Hedge funds ...........................................................................................
Private equity funds ...............................................................................
Real estate funds ....................................................................................
Diversified commodities funds ..............................................................
Total investments .................................................................................... $
—
—
49
—
—
—
—
19
800 $ 1,006 $
—
—
—
—
—
—
—
—
—
61
—
61 $
December 31, 2017
Cash and Short-Term Investment Funds ............................................. $
Equities:
32 $
69 $
— $
U.S. equities (domestic) .........................................................................
International equities (non-U.S.)............................................................
Global equities (domestic and non-U.S.) ...............................................
789
104
2
Fixed Income:
Treasury and government issued (a) ......................................................
Government related (b) ..........................................................................
Mortgage-backed securities (c) ..............................................................
Corporate ...............................................................................................
Other:
Hedge funds ...........................................................................................
Private equity funds ...............................................................................
Real estate funds ....................................................................................
Diversified commodities funds ..............................................................
Total investments .................................................................................... $
—
—
—
—
—
—
63
—
990 $
—
34
238
271
34
139
182
—
—
—
24
991 $
—
—
—
—
1
1
—
—
—
2
—
4 $
—
288
—
—
—
27
31
654
409
205
240
37
186
303
135
170
50
—
135
170
160
19
701 $ 2,568
(cid:3)(cid:3)
(cid:3)(cid:3)
(cid:3)
(cid:3)(cid:3)
(cid:3)(cid:3) (cid:3)
101
— $
—
296
—
—
—
26
6
789
434
240
271
35
166
188
187
140
92
—
187
140
157
24
747 $ 2,732
(a) Includes securities issued and guaranteed by U.S. and non-U.S. governments.
(b) Primarily consists of securities issued by governmental agencies and municipalities.
(c) Comprised of U.S. residential and commercial mortgage-backed securities.
(d) Includes certain investments that have been valued using the net asset value 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.
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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. Cash on hand is classified as Level 1 and short-term investment funds are
classified as Level 2.
Equities - Consists of individually held or commingled funds of U.S. and International equity securities. Equity
securities, which are individually held and are traded actively on exchanges, are classified as Level 1. Commingled
funds, consisting primarily of equity securities, are valued using the net asset value (NAV) per fund share derived
from quoted prices in active markets of the underlying securities. These funds are classified as Level 2 where they
have readily determinable fair values, otherwise they are classified under the NAV practical expedient.
Fixed income investments - Consists of 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 commingled investment funds that invest in fixed income securities. Individual
fixed income securities are generally priced based on evaluated prices from independent pricing services, which are
monitored and provided by the third-party custodial firm responsible for safekeeping plan assets. Individual fixed
income securities are classified as Level 2. Certain fixed income investments are commingled funds that are valued
at the NAV per fund share derived indirectly from observable inputs or from quoted prices in less liquid markets of
the underlying securities. These funds are classified as Level 2 where they have readily determinable fair values,
otherwise they are classified under the NAV practical expedient.
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 derived using information provided by fund managers which include various inputs such
as discounted future cash flows, market based comparable data and independent appraisals from third parties. These
funds are classified as Level 2 or 3 where they have readily determinable fair values, otherwise they are classified
under the NAV practical expedient.
The following tables provide changes in financial assets that are measured at fair value based on Level 3 inputs that are held
by institutional funds classified as:
Fixed
Income
Real Estate
Funds
(In millions)
Total
Balance at January 1, 2017 .................................................................................................. $
Actual return on plan assets .................................................................................................
Purchases, sales or other settlements ...................................................................................
Net transfers in (out) of Level 3 ...........................................................................................
Balance at December 31, 2017 .............................................................................................
Actual return on plan assets .................................................................................................
Purchases, sales or other settlements ...................................................................................
Net transfers in (out) of Level 3 ...........................................................................................
Balance at December 31, 2018 ............................................................................................. $
2 $
—
1
(1 )
2
—
(2 )
—
— $
8 $
—
(6 )
—
2
1
58
—
61 $
10
—
(5 )
(1 )
4
1
56
—
61
Contributions and estimated future benefit payments:
We expect to contribute approximately $40 million to our funded pension plans in 2019.
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):
2019 ................................................................................................................................................................................... $
2020 ...................................................................................................................................................................................
2021 ...................................................................................................................................................................................
2022 ...................................................................................................................................................................................
2023 ...................................................................................................................................................................................
Years 2024 to 2028 ............................................................................................................................................................
142
139
135
139
140
722
We also have several 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 $19 million in
2018 for contributions to these plans (2017: $22 million; 2016: $25 million).
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11. Share-based Compensation
We have established and maintain a Long-term Incentive Plan (LTIP), as amended, for the granting of restricted common shares
(Restricted stock), performance share units (PSUs) and stock options to our employees. At December 31, 2018, the total number
of authorized common stock under the LTIP, as amended, was 51.5 million shares, of which we have 19.0 million shares available
for issuance. Share-based compensation expense consisted of the following:
Restricted stock............................................................................................................ $
Stock options ...............................................................................................................
Performance share units ...............................................................................................
Share-based compensation expense before income taxes .................................... $
Income tax benefit on share-based compensation expense .................................. $
40 $
10
22
72 $
— $
56 $
9
21
86 $
1 $
45
7
21
73
28
Based on share-based compensation awards outstanding at December 31, 2018, unearned compensation expense, before
income taxes, will be recognized in future years as follows (in millions): 2019: $57, 2020: $30 and 2021: $6.
2018
2017
(In millions)
2016
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 are 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 2018:
Shares of Restricted
Common Stock
Weighted - Average Price
on Date of Grant
Outstanding at January 1, 2018 ............................................................
Granted .................................................................................................
Vested (a)..............................................................................................
Forfeited ...............................................................................................
Outstanding at December 31, 2018 .......................................................
(a) In 2018, restricted stock with fair values of $54 million were vested (2017: $37 million; 2016: $41 million).
(In thousands, except per share amounts)
3,202 $
1,258
(1,099 )
(480 )
2,881 $
54.04
50.78
65.80
50.63
48.70
PSUs:
PSUs generally vest three years from the date of grant and are valued based on the prevailing market price of our common
stock 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. 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 2018:
Performance Share Units
Weighted - Average Fair
Value on Date of Grant
(In thousands, except per share amounts)
Outstanding at January 1, 2018 ............................................................
Granted .................................................................................................
Vested (a)..............................................................................................
Forfeited ...............................................................................................
Outstanding at December 31, 2018 .......................................................
1,146 $
278
(313 )
(48 )
1,063 $
58.78
59.65
76.64
53.62
53.98
(a) In 2018, PSU’s with fair value of $9 million were vested (2017: $10 million; 2016: $15 million).
The following weighted average assumptions were utilized to estimate the fair value of PSU awards:
Risk free interest rate ............................................................................................
Stock price volatility .............................................................................................
Contractual term in years ......................................................................................
Grant date price of Hess common stock ............................................................... $
2.39 %
1.55 %
0.400
3.0
48.48
$
0.387
3.0
51.03
$
0.96 %
0.329
3.0
44.31
2018
2017
2016
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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 market price of
the common stock on the date of grant. The following is a summary of stock options activity in 2018:
Outstanding at January 1, 2018 .........................................................
Granted ..............................................................................................
Exercised ...........................................................................................
Forfeited ............................................................................................
Outstanding at December 31, 2018 ....................................................
6,482 $
683
(564 )
(1,431 )
5,170 $
66.84
48.48
55.84
80.23
61.91
Number of options
(In thousands)
Weighted Average
Exercise Price per
Share
Weighted Average
Remaining
Contractual Term
3.6 years
4.3 years
At December 31, 2018, there were 5.2 million outstanding stock options (3.9 million exercisable) with a weighted average
remaining contractual life of 4.3 years (2.9 years for exercisable options) and an aggregated intrinsic value of 0 (0 for
exercisable options).
The following weighted average assumptions were utilized to estimate the fair value of stock options:
(cid:3)
2018
2017
2016
Risk free interest rate ............................................................................................
Stock price volatility .............................................................................................
Dividend yield ......................................................................................................
Expected life in years............................................................................................
Weighted average fair value per option granted ................................................... $
2.74 %
0.322
2.06 %
6.0
13.69
$
2.17 %
0.333
1.96 %
6.0
14.51
(cid:3)(cid:3)$
1.47 %
0.326
2.26 %
6.0
11.33
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.
12. Exit and Disposal Costs
In 2018, we incurred severance expense of $38 million (2017: $18 million; 2016: $55 million) and paid accrued severance
costs of $40 million (2017: $48 million; 2016: $52 million). The severance expenses incurred during the three-year period
resulted from asset sales and cost savings initiatives in response to low crude oil prices. Severance charges were based on
amounts incurred under ongoing severance arrangements or other statutory requirements, plus amounts earned under enhanced
benefit arrangements. We recognized the expense associated with the enhanced benefits ratably over the estimated service
period required for the employee to earn the benefit upon termination. We also recorded charges for vacated office space of
$73 million in 2018 (2017: $14 million).
At December 31, 2018, we had accrued liabilities for severance costs of $4 million (2017: $6 million) and accrued liabilities
for exit cost provisions of $85 million (2017: $28 million). Accrued severance costs are expected to be paid in 2019, and
accrued exit costs will be paid over the next several years.
13. Impairment
2017: In the third quarter, we recognized a pre-tax charge of $2,503 million ($550 million after income taxes) to impair the
carrying value of our interests in Norway based on an anticipated sale of the asset, which closed in the fourth quarter of 2017.
See Note 3, Dispositions. In the fourth quarter, we recognized pre-tax impairment charges to reduce the carrying value of our
interests in the Stampede Field by $1,095 million ($1,095 million after income taxes), and the Tubular Bells Field by $605
million ($605 million after income taxes) primarily as a result of a lower long-term crude oil price outlook. The Stampede
Field had significant capitalized exploration and appraisal costs that were incurred on a 100% working interest basis on the
Pony discovery prior to unitizing into the Stampede project. The fourth quarter impairment charges were based on a total fair
value estimate of approximately $1.1 billion that was determined using internal projected discounted cash flows. The
determination of projected discounted cash flows depended on estimates of oil and gas reserves, future prices, operating costs,
capital expenditures, discount rate and timing of future net cash flows.
2016: We recorded a pre-tax impairment charge of $67 million ($21 million after income taxes and noncontrolling interest)
to impair older specification rail cars in our Midstream segment based on estimated salvage values, which approximated fair
value.
Each of the valuation methods used in the determination of the impairment charges above represent Level 3 fair value
measurements.
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14. Income Taxes
The provision (benefit) for income taxes consisted of:
United States
Federal
Current .............................................................................................................................. $
Deferred taxes and other accruals .....................................................................................
State .....................................................................................................................................
Foreign
Current (b) ........................................................................................................................
Deferred taxes and other accruals .....................................................................................
Total..................................................................................................................................
Adjustment of deferred taxes for foreign income tax law changes .........................................
Total Provision (Benefit) For Income Taxes ................................................................. $
(a)(cid:3) Includes charges of $3,749 million to establish valuation allowances on net deferred tax assets.
(b)(cid:3) Primarily comprised of Libya in 2018 and 2017.
Income (loss) before income taxes consisted of the following:
2018
2017
(In millions)
2016 (a)
1 $
(74 )
(45 )
(118 )
455
(2 )
453
335
—
335 $
(23 ) $
(6 )
—
(29 )
179
(1,987 )
(1,808 )
(1,837 )
—
(1,837 ) $
(27 )
1,948
23
1,944
36
235
271
2,215
7
2,222
2018
2017
(In millions)
2016
United States (a) ..................................................................................................................... $
Foreign ....................................................................................................................................
Total Income (Loss) Before Income Taxes.................................................................... $
(219 ) $
439
220 $
(2,784 ) $
(2,994 )
(5,778 ) $
(2,431 )
(1,423 )
(3,854 )
(a)(cid:3) Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities.
The difference between our effective income tax rate and the U.S. statutory rate is reconciled below:
2018
2017
2016
U.S. statutory rate .............................................................................................................
Effect of foreign operations (a) .........................................................................................
State income taxes, net of Federal income tax ..................................................................
Change in enacted tax laws (b) .........................................................................................
Valuation allowance adjustment with tax law change (b) .................................................
Rate differential on U.S. loss ............................................................................................
Gains on asset sales, net ....................................................................................................
Impairment .......................................................................................................................
Valuation allowance on current year operations ...............................................................
Valuation allowance against previously benefitted deferred tax assets.............................
Noncontrolling interest in partnership ..............................................................................
Intraperiod allocation ........................................................................................................
Equity compensation shortfall ..........................................................................................
Other .................................................................................................................................
Total ...........................................................................................................................
21.0 %
141.2
(18.9 )
—
—
—
—
—
55.2
—
(15.9 )
(37.3 )
6.3
0.8
152.4 %
35.0 %
17.4
—
(23.6 )
23.6
(4.1 )
(2.2 )
—
(14.9 )
0.1
0.8
—
(0.3 )
—
31.8 %
35.0 %
4.6
1.9
(0.2 )
—
—
—
(2.1 )
—
(97.3 )
0.5
—
—
(0.1 )
(57.7 ) %
(a)(cid:3) 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.
(b)(cid:3) The enactment of the U.S. Tax Cuts and Jobs Act provided for a decrease in the corporate tax rate to 21% from 35% and a change to a territorial tax
regime, resulting in a net $1,336 million reduction to our U.S. net deferred tax asset at December 31, 2017, with a corresponding reduction in the
previously established U.S. valuation allowance.
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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) ........................................................................................... $
2018
2017
(In millions)
(853 ) $
(77 )
(930 )
4,239
134
416
232
225
161
5,407
(4,877 )
530
(400 ) $
(629 )
(24 )
(653 )
4,029
138
746
283
212
36
5,444
(5,199 )
245
(408 )
(a) In 2018, the valuation allowance decreased by $322 million (2017: decrease of $251 million; 2016: increase of $3,872).
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) .............................................................................................. $
2018
2017
(In millions)
21 $
(421 )
(400 ) $
21
(429 )
(408 )
At December 31, 2018, we have recognized a gross deferred tax asset related to net operating loss carryforwards of
$4,239 million before application of valuation allowances. The deferred tax asset is comprised of $1,382 million attributable
to foreign net operating losses which begin to expire in 2025, $2,386 million attributable to U.S. Federal operating losses which
begin to expire in 2035, and $471 million attributable to losses in various U.S. states which begin to expire in 2019. The
deferred tax asset attributable to foreign net operating losses, net of valuation allowances, is $12 million. A full valuation
allowance is established against the deferred tax asset attributable to U.S. Federal and state net operating losses. At
December 31, 2018, we have U.S. Federal, state and foreign alternative minimum tax credit carryforwards of $49 million,
which can be carried forward indefinitely, and approximately $15 million of other business credit carryforwards. The deferred
tax asset attributable to these credits, net of valuation allowances, is $1 million. A full valuation allowance is established
against our foreign tax credit carryforwards of $70 million, which begin to expire in 2019.
At December 31, 2018, the Balance Sheet reflects a $4,877 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
allowance against its deferred tax assets in the U.S., Denmark (hydrocarbon tax only), Malaysia, and Guyana. 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 cumulative loss incurred over the three-year period ending December 31, 2018
constitutes significant objective negative 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.
The Company completed its review of previously recorded provisional income tax amounts related to the U.S. Tax Cuts and
Jobs Act (“Act”) and concluded that additional information, interpretation and guidance that became available during the
twelve-month measurement period did not alter the Company’s accounting as reported in its Consolidated Financial Statements
as of December 31, 2017. There were no adjustments deemed necessary in the period ended December 31, 2018.
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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 ......................................................................................................... $
2018
2017
2016
(In millions)
205 $
19
36
(78 )
(10 )
(4 )
168 $
424 $
14
4
(147 )
(85 )
(5 )
205 $
604
19
113
(274 )
(27 )
(11 )
424
The December 31, 2018 balance of unrecognized tax benefits includes $7 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 $2 million and $8 million due to settlements with taxing authorities or other resolutions, as well as
lapses in statutes of limitation. At December 31, 2018, our accrued interest and penalties related to unrecognized tax benefits
is $3 million (2017: $23 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 2005.
15. Basic and Diluted Earnings Per Common Share
The Net income (loss) and weighted average number of common shares used in basic and diluted earnings per share
computation were as follows:
Net Income (Loss) Attributable to Hess Corporation Common Stockholders:
2018
(cid:3)(cid:3)
2017
(In millions)
(cid:3)(cid:3)
2016
Net income (loss) ............................................................................................................................. $
Less: Net income (loss) attributable to noncontrolling interests ...................................................
Less: Preferred stock dividends ....................................................................................................
Net income (loss) attributable to Hess Corporation Common Stockholders .................................... $
(115 ) $ (3,941 ) $ (6,076 )
56
167
41
46
(328 ) $ (4,120 ) $ (6,173 )
133
46
(cid:3)(cid:3)
Weighted Average Number of Common Shares Outstanding:
(cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)
(cid:3)(cid:3)
Basic ................................................................................................................................................
Effect of dilutive securities
Restricted common stock ..............................................................................................................
Stock options ................................................................................................................................
Performance share units ................................................................................................................
Mandatory Convertible Preferred stock ........................................................................................
Diluted .............................................................................................................................................
298.2
314.1
309.9
—
—
—
—
298.2
—
—
—
—
314.1
—
—
—
—
309.9
Net Income (Loss) Attributable to Hess Corporation per Common Share:
Basic ................................................................................................................................................ $
Diluted ............................................................................................................................................. $
(1.10 ) $ (13.12 ) $ (19.92 )
(1.10 ) $ (13.12 ) $ (19.92 )
Antidilutive shares excluded from the computation of diluted shares:
Restricted common stock .................................................................................................................
Stock options ...................................................................................................................................
Performance share units ...................................................................................................................
Common shares from conversion of preferred stock .......................................................................
2.9
5.5
1.1
12.7
3.3
6.4
0.6
12.8
3.3
6.9
0.9
11.2
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16. Common and Preferred Stock
The following table provides the changes in our outstanding common shares:
(cid:3)
(cid:3)(cid:3)
Balance at January 1 ........................................................................................................................... (cid:3)
Shares issued ................................................................................................................................... (cid:3)
Activity related to restricted stock awards, net ................................................................................ (cid:3)
Stock options exercised ................................................................................................................... (cid:3)
PSU vested....................................................................................................................................... (cid:3)
Shares repurchased .......................................................................................................................... (cid:3)
Balance at December 31 ..................................................................................................................... (cid:3)
(cid:3)
(cid:3)
2018
(cid:3)(cid:3)
2017
2016
(In millions)
315.1
—
0.8
0.6
0.1
(25.2 )
291.4
316.5
—
0.8
0.2
0.2
(2.6 )
315.1
286.0
28.8
1.1
0.2
0.4
—
316.5
Common and Preferred Stock Issuance:
In February 2016, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of
8% Series A Mandatory Convertible Preferred Stock (Convertible Preferred Stock), par value $1 per share, with a liquidation
preference of $1,000 per share, for total net proceeds of approximately $1.6 billion after deducting underwriting discounts,
commissions, and offering expenses. The dividends on the Convertible Preferred Stock are payable on a cumulative basis.
Unless converted earlier, each share of Convertible Preferred Stock will automatically convert into between 21.822 shares
and 25.642 shares of our common stock based on the volume weighted average share price (“VWAP”) over a period of
twenty-consecutive trading days ending January 28, 2019, subject to anti-dilution adjustments. See Note 15, Basic and
Diluted Earnings Per Common Share and Note 22, Subsequent Event.
We also entered into capped call transactions on 12.55 million covered shares that were expected generally to reduce the
potential dilution to our common stock upon conversion of the Convertible Preferred Stock if the VWAP for any individual
day during the period of twenty consecutive trading days ending January 28, 2019 exceeded $45.83 per share, subject to
anti-dilution adjustments. On any day during the twenty consecutive trading days ending January 28, 2019, if the daily
VWAP is between $45.83 and $53.625, the value of the capped call transactions for that day will be the proportionate
covered shares multiplied by the difference between the VWAP for that day and $45.83. The number of common shares to
be delivered by the counterparties to us will be the sum of each daily calculation during the twenty-consecutive trading day
period. The premium paid for the capped call transactions was $37 million, which was recorded against Capital in excess
of par in the Statement of Consolidated Equity. See Note 22, Subsequent Event.
Common Stock Repurchase Plan:
In 2018, we repurchased 25.2 million shares of our common stock (2017: 2.6 million shares) for $1,380 million (2017: $120
million), at an average cost per share of $54.85 (2017: $45.67). There were no repurchases in 2016. At December 31, 2018,
we are authorized, but not required, to purchase additional common stock up to a value of $650 million.
Common stock dividends:
In 2018, 2017 and 2016, 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:
(cid:3)
(cid:3)(cid:3)
(cid:3)
(cid:3)
2018
2017
(cid:3)(cid:3)
2016
(In millions)
Cash Flows from Operating Activities
Interest paid ........................................................................................................................... $
Net income taxes (paid) refunded .......................................................................................... (cid:3)
(cid:3)
(394 ) $
(463 )
(cid:3)(cid:3)(cid:3)(cid:3)
(314 ) $
(210 ) (cid:3)(cid:3)
(cid:3)(cid:3)
(cid:3)(cid:3)
(338 )
132
Cash Flows from Investing Activities
Capital expenditures incurred - E&P ..................................................................................... $
Increase (decrease) in related liabilities .................................................................................
Additions to property, plant and equipment - E&P....................................................... $
(1,909 ) $
55
(1,854 ) $
(1,852 ) $
64 (cid:3)(cid:3)
(1,788 ) $
(1,638 )
(336 )
(1,974 )
Capital expenditures incurred – Midstream ........................................................................... $
Increase (decrease) in related liabilities .................................................................................
Additions to property, plant and equipment – Midstream ............................................ $
(271 ) $
28
(243 ) $
(121 ) $
(28 )
(149 ) $
(283 )
6
(277 )
18. Leased Assets
We and certain of our subsidiaries lease drilling rigs, support vessels, office space and other assets for varying periods under
contractual obligations accounted for as operating leases. Operating lease expenses for drilling rigs used to drill development
wells and successful exploration wells are capitalized. At December 31, 2018, future minimum rental payments applicable to
non-cancelable operating leases with remaining terms in excess of one year (other than oil and gas property leases) are as
follows (in millions):
2019 ................................................................................................................................................................................... $
2020 ...................................................................................................................................................................................
2021 ...................................................................................................................................................................................
2022 ...................................................................................................................................................................................
2023 ...................................................................................................................................................................................
Remaining years ................................................................................................................................................................
Total Minimum Lease Payments .................................................................................................................................
Less: Income from subleases ..........................................................................................................................................
Net Minimum Lease Payments .............................................................................................................................. $
355
156
65
64
64
198
902
114
788
Rental expense was as follows:
(cid:3)
(cid:3)
2018
Total rental expense ................................................................................................................ $
Less: Income from subleases ..................................................................................................
Net Rental Expense ...................................................................................................... $
154
8
146
2017
(In millions)
$
123
10
113
$
2016
$
$
106
5
101
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19. 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.
Numerous issues may need to be resolved, including through lengthy discovery, conciliation and/or arbitration proceedings, or
litigation before a loss or range of loss can be reasonably estimated. Subject to the foregoing, in management’s opinion, based
upon currently known facts and circumstances, the outcome of such lawsuits, claims and proceedings, including the matters
described below, is not expected to have a material adverse effect on our financial condition. 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.
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 methyl tertiary butyl ether (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 Environmental
Protection Agency (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 also agreed with 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 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. The remedy
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. EPA has estimated that this remedy
will cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of
the remedy remain uncertain. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and
connected ship-building and repair facility adjacent to the Canal. We indicated to EPA that we would comply with the
Administrative Order and are currently contributing funding for the Remedial Design based on an interim allocation of costs
76
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among the parties. At the same time, we are participating in an allocation process whereby a neutral expert selected by the
parties will determine the final shares of the Remedial Design costs to be paid by each of the participants.
On September 28, 2017, we received a general notice letter and offer to settle from the U.S. Environmental Protection
Agency relating to Superfund claims for the Ector Drum, Inc. Superfund Site in Odessa, Texas. The EPA and Texas
Commission on Environmental Quality (TCEQ) took clean-up and response action at the site commencing in 2014 and
concluded in December 2015. The site was determined to have improperly stored industrial waste, including drums with oily
liquids. The total clean-up cost incurred by the EPA was approximately $3.5 million. We were invited to negotiate a voluntary
settlement for our purported share of the clean-up costs. Our share, if any, is undetermined.
From time to time, we are involved in other judicial and administrative proceedings, including proceedings relating to other
environmental matters. 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
the aforementioned proceedings is not expected to have a material adverse effect on our financial condition, results of operations
or cash flows.
Unconditional Purchase Obligations and Commitments
The following table shows aggregate information for certain unconditional purchase obligations and commitments at
December 31, 2018, which are not included elsewhere within these Consolidated Financial Statements:
Payments Due by Period
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3) 2020 and
2022 and (cid:3)(cid:3) (cid:3)
Total
2019
2021
(In millions)
2023
(cid:3)(cid:3)
Thereafter
Capital expenditures ............................................................. $
Operating expenses ...............................................................
Transportation and related contracts .....................................
1,069 $
433
1,050
443 $
219
212
551 $
99
401
75 $
61
336
—
54
101
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20. Segment Information
We currently have two operating segments, Exploration and Production (E&P) and Midstream. The E&P operating segment
explores for, develops, produces, purchases and sells crude oil, NGLs and natural gas. Production operations over the three years
ended December 31, 2018 were primarily in the United States (U.S.), Denmark, the JDA and Malaysia, and from divested assets,
including Equatorial Guinea (until November 2017) and Norway (until December 2017). The Midstream operating segment
provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of NGLs,
transportation of crude oil by rail car, terminaling and loading crude oil and NGLs, 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):
(cid:3)
2018
Exploration
and
Corporate,
Interest
Production Midstream
and Other Eliminations Total
Sales and Other Operating Revenues - Third-parties .......................... $
Intersegment Revenues .......................................................................
Sales and Other Operating Revenues .................................................. $
6,323 $
—
6,323 $
— $
713
713 $
— $
—
— $
— $
(713 )
(713 ) $
6,323
—
6,323
(cid:3)(cid:3)
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 ...........................................................................
51 $
—
1,748
391
126
16,109
1,909
120 $
60
127
38
67
3,285
271
(453 ) $
339
8
(94 )
—
2,039
—
(cid:3)(cid:3)
2017
(cid:3) (cid:3)
(cid:3) (cid:3)(cid:3) (cid:3)
(cid:3) (cid:3) (cid:3)
(cid:3) (cid:3) (cid:3) (cid:3)
(282 )
— $
399
—
1,883
—
335
—
193
—
— 21,433
2,180
—
(cid:3)(cid:3)
(cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)
Sales and Other Operating Revenues - Third-parties .......................... $
Intersegment Revenues .......................................................................
Sales and Other Operating Revenues .................................................. $
5,460 $
—
5,460 $
6 $
611
617 $
— $
—
— $
— $
(611 )
(611 ) $
5,466
—
5,466
(cid:3)(cid:3)
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 ...........................................................................
(3,653 ) $
—
2,736
4,203
(1,842 )
134
15,613
1,852
42 $
26
123
—
31
—
3,329
121
(463 ) $
299
24
—
(26 )
—
4,170
—
(cid:3)(cid:3)
2016
(cid:3) (cid:3)
(cid:3) (cid:3)(cid:3) (cid:3)
(cid:3) (cid:3) (cid:3)
(cid:3) (cid:3) (cid:3) (cid:3)
(4,074 )
— $
325
—
2,883
—
4,203
—
(1,837 )
—
—
134
— 23,112
1,973
—
(cid:3)(cid:3)
(cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)
Sales and Other Operating Revenues - Third-parties .......................... $
Intersegment Revenues .......................................................................
Sales and Other Operating Revenues .................................................. $
4,755 $
—
4,755 $
(cid:3)(cid:3)
Net Income (Loss) Attributable to Hess Corporation .......................... $
Interest Expense ..................................................................................
Depreciation, Depletion and Amortization .........................................
Impairment ..........................................................................................
Provision (Benefit) for Income Taxes .................................................
Capital Expenditures ...........................................................................
(4,964 ) $
—
3,113
—
1,587
1,638
7 $
562
569 $
42 $
19
121
67
26
283
— $
—
— $
— $
(562 )
(562 ) $
4,762
—
4,762
(1,210 ) $
319
10
—
609
—
— $
—
—
—
—
—
(6,132 )
338
3,244
67
2,222
1,921
(a) The provision for income taxes in the Midstream segment in 2018 and 2017 is presented before consolidating its operations with other U.S. activities of
the Company and prior to evaluating realizability of net U.S. deferred taxes. An offsetting impact is presented in the E&P segment.
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The following table presents financial information by major geographic area:
United
States
Europe
Africa
Asia and
Other
Countries
Corporate,
Interest
and other
Total
2017
2018
(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)
Sales and Other Operating Revenues ............................. (cid:3)(cid:3) $
Net Income (Loss) Attributable to Hess Corporation ..... (cid:3)(cid:3)
Depreciation, Depletion and Amortization .................... (cid:3)(cid:3)
Provision (Benefit) for Income Taxes ............................ (cid:3)(cid:3)
Identifiable Assets ......................................................... (cid:3)(cid:3)
Property, Plant and Equipment (Net) ............................. (cid:3)(cid:3)
Capital Expenditures ...................................................... (cid:3)(cid:3)
(cid:3)(cid:3)
(cid:3)(cid:3)
Sales and Other Operating Revenues ............................. (cid:3)(cid:3) $
Net Income (Loss) Attributable to Hess Corporation ..... (cid:3)(cid:3)
Depreciation, Depletion and Amortization .................... (cid:3)(cid:3)
Impairment .................................................................... (cid:3)(cid:3)
Provision (Benefit) for Income Taxes ............................ (cid:3)(cid:3)
Identifiable Assets ......................................................... (cid:3)(cid:3)
Property, Plant and Equipment (Net) ............................. (cid:3)(cid:3)
Capital Expenditures ...................................................... (cid:3)(cid:3)
(cid:3)(cid:3)
(cid:3)(cid:3)
Sales and Other Operating Revenues ............................. (cid:3)(cid:3) $
Net Income (Loss) Attributable to Hess Corporation ..... (cid:3)(cid:3)
Depreciation, Depletion and Amortization .................... (cid:3)(cid:3)
Impairment .................................................................... (cid:3)(cid:3)
Provision (Benefit) for Income Taxes ............................ (cid:3)(cid:3)
Capital Expenditures ...................................................... (cid:3)(cid:3)
2016
(cid:3) (cid:3)
(cid:3) (cid:3)
4,842 (cid:3) $
131 (cid:3)
1,424 (cid:3)
(25 ) (cid:3)
13,250 (cid:3)
11,653 (cid:3)
1,543 (cid:3)
(cid:3)
(cid:3)
3,692 (cid:3) $
(2,433 ) (cid:3)
1,942 (cid:3)
1,700 (cid:3)
— (cid:3)
13,640 (cid:3)
11,894 (cid:3)
1,387 (cid:3)
(cid:3)
(cid:3)
3,085 (cid:3) $
(2,353 ) (cid:3)
2,133 (cid:3)
67 (cid:3)
411 (cid:3)
1,400
(cid:3) (cid:3)
(cid:3) (cid:3)
164 $
42
37
15
1,033
906
8
629 $
(1,383 )
381
2,503
(1,999 )
1,024
946
141
610 $
(439 )
502
—
243
59
(In millions)
(cid:3) (cid:3)
(cid:3) (cid:3)
548 (cid:3) $
36 (cid:3)
19 (cid:3)
430 (cid:3)
395 (cid:3)
355 (cid:3)
9 (cid:3)
(cid:3)
(cid:3)
675 (cid:3) $
259 (cid:3)
263 (cid:3)
— (cid:3)
197 (cid:3)
428 (cid:3)
365 (cid:3)
30 (cid:3)
(cid:3)
(cid:3)
601 (cid:3) $
(355 ) (cid:3)
375 (cid:3)
— (cid:3)
244 (cid:3)
10 (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
769 $
(38 )
395
9
4,716
3,154
620
470 $
(54 )
273
—
(9 )
3,850
2,964
415
466 $
(1,775 )
224
—
715
452
(cid:3)(cid:3) (cid:3) (cid:3)(cid:3)(cid:3)(cid:3)
— (cid:3) $
(453 ) (cid:3)
8 (cid:3)
(94 ) (cid:3)
2,039 (cid:3)
15 (cid:3)
— (cid:3)
(cid:3)
(cid:3)
— (cid:3) $
(463 ) (cid:3)
24 (cid:3)
— (cid:3)
(26 ) (cid:3)
4,170 (cid:3)
23 (cid:3)
— (cid:3)
(cid:3)
(cid:3)
— (cid:3) $
(1,210 ) (cid:3)
10 (cid:3)
— (cid:3)
609 (cid:3)
— (cid:3)
(cid:3)(cid:3)
6,323
(282 )
1,883
335
21,433
16,083
2,180
5,466
(4,074 )
2,883
4,203
(1,837 )
23,112
16,192
1,973
4,762
(6,132 )
3,244
67
2,222
1,921
21. 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. 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, 2018, these forward
contracts relate to the British Pound. Interest rate swaps may be used to convert interest payments on certain long-term debt
from fixed to floating rates.
Gross notional amounts of both long and short positions are presented in the volume tables beginning below. These amounts
include long and short positions that offset in closed positions and have not reached contractual maturity. Gross notional
amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash
settlements under the contracts.
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The gross notional amounts of outstanding financial risk management derivative contracts related to WTI instruments as of
the dates shown below were as follows:
Calendar year program .............................................................................................................................
Instrument type .........................................................................................................................................
Crude oil volumes (millions of barrels) ....................................................................................................
Ceiling price .............................................................................................................................................
Floor price ................................................................................................................................................
December 31,
2018
2019
Puts
34.7
N/A
60
$
December 31,
2017
2018
Collars
42.0
65
50
$
$
At December 31, 2017, we had WTI crude oil price collars for calendar year 2018 with a monthly floor price of $50 per
barrel and a monthly ceiling price of $65 per barrel for 115,000 bopd. In the first quarter of 2018, we bought back the WTI
$65 call options within the crude oil price collars for the period of May 1, 2018 through December 31, 2018. In 2018, we
purchased WTI put options for calendar year 2019 with a WTI monthly floor price of $60 per barrel for 95,000 bopd.
The gross notional amounts of outstanding financial risk management derivative contracts, excluding commodity contracts,
were as follows:
Foreign exchange ...................................................................................................................................... $
Interest rate swaps .................................................................................................................................... $
(In millions)
16 $
100 $
52
450
December 31,
2018
December 31,
2017
The table below reflects the gross and net fair values of risk management derivative instruments and their respective financial
statement caption in the Consolidated Balance Sheet:
December 31, 2018
Derivative Contracts Designated as Hedging Instruments
Commodity - Other current assets ................................................................................................... $
Interest rate - Other liabilities and deferred credits (noncurrent) .....................................................
Total derivative contracts designated as hedging instruments ............................................................
Gross fair value of derivative contracts ..............................................................................................
Master netting arrangements ...............................................................................................................
Net Fair Value of Derivative Contracts ....................................................................................... $
December 31, 2017
Derivative Contracts Designated as Hedging Instruments
Commodity - Accounts payable....................................................................................................... $
Interest rate - Other assets (noncurrent) and Accounts payable .......................................................
Total derivative contracts designated as hedging instruments ............................................................
Derivative Contracts Not Designated as Hedging Instruments
Commodity - Accounts payable.......................................................................................................
Foreign exchange - Accounts receivable: Joint venture and other ...................................................
Total derivative contracts not designated as hedging instruments ......................................................
Gross fair value of derivative contracts ..............................................................................................
Master netting arrangements ...............................................................................................................
Net Fair Value of Derivative Contracts ....................................................................................... $
All fair values above are based on Level 2 inputs.
Assets
Liabilities
(In millions)
484 $
—
484
484
—
484 $
— $
—
—
—
1
1
1
—
1 $
—
(2 )
(2 )
(2 )
—
(2 )
(7 )
(4 )
(11 )
(2 )
—
(2 )
(13 )
—
(13 )
Impact on statement of consolidated income from derivative contracts designated as hedging instruments:
Crude oil derivatives: In 2018, crude oil price hedging contracts decreased Sales and other operating revenues by $161
million (2017: decrease of $34 million; 2016: $0). At December 31, 2018, pre-tax deferred gains in Accumulated other
comprehensive income (loss) related to outstanding crude oil price hedging contracts were $365 million, of which all will be
reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.
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Interest rate swaps designated as fair value hedges: At December 31, 2018, we had interest rate swaps with gross notional
amounts of $100 million (2017: $450 million), which were designated as fair value hedges and relate to debt where we have
converted interest payments on certain long-term debt from fixed to floating rates. During 2018, we terminated interest rate
swaps with a gross notional amount of $350 million and paid $3 million (2017: $0; 2016: $5 million proceeds). See Note 8,
Debt. 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 2018, the change in fair value of interest rate swaps was an increase in the derivative
liability of $1 million (2017: $4 million increase in liability; 2016: $6 million increase in asset) with a corresponding adjustment
in the carrying value of the hedged fixed-rate debt.
Interest rate swaps designated as cash flow hedges: During 2017, HIP entered into interest rate swaps with gross notional
amounts totaling $553 million to convert interest payments on certain long-term debt from floating to fixed rates before settling
these instruments for a payment of $3 million as part of the refinancing that occurred later in the year. See Note 8, Debt.
Impact on statement of consolidated income from derivative contracts not designated as hedging instruments:
Crude oil collars: In 2018, noncash adjustments to de-designated crude oil price hedging contracts decreased Sales and other
operating revenues by $22 million (2017: decrease of $25 million).
Foreign exchange: Total foreign exchange gains and losses were a loss of $5 million in 2018 (2017: gain of $15 million;
2016: gain of $26 million) and are reported in Other, net in Revenues and non-operating income in the Statement of
Consolidated Income. A 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 loss of $2 million in 2018 (2017: gain of $3 million; 2016: gain of $62
million).
After-tax foreign currency translation adjustments included in the Statement of Consolidated Comprehensive Income
amounted to gains of $144 million in 2017 and $56 million in 2016. In 2017, $900 million of cumulative currency translation
losses were recognized in earnings as a result of the sale of our assets in Norway. See Note 3, Dispositions.
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, 2018, our Accounts receivable were concentrated with the following counterparty industry segments: Financial
Institutions — 34%, Integrated companies — 24%, Independent E&P companies — 22%, National oil companies — 7%
Refining and marketing companies — 5%, Storage and transportation companies — 3%, and Others — 5%. 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, 2018, we had outstanding letters of credit totaling $284 million (2017: $246 million).
Fair Value Measurement: At December 31, 2018, outstanding total debt, excluding capital leases, was substantially
comprised of fixed rate debt instruments with a carrying value of $6,403 million and a fair value of $6,225 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,
2018 and December 31, 2017.
22. Subsequent Event
On January 31, 2019, the 8.00% Series A Mandatory Convertible Preferred Stock (Preferred Stock) automatically converted
into shares of common stock at a rate of 21.822 shares of common stock per share of Preferred Stock. In total, the Preferred
Stock was converted into approximately 12.5 million shares of common stock. In connection with the Preferred Stock offering
in 2016, the Company entered into capped call transactions to reduce the potential dilution to the Company’s common stock
upon conversion of the Preferred Stock, subject to a cap. The Company received approximately 0.9 million shares of common
stock upon settlement of the capped call transactions. As a result, the net number of common shares issued by the Company
upon conversion of the Preferred Stock was approximately 11.6 million shares.
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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, 2018, we produced crude oil, NGLs and natural gas principally in the
United States (U.S.), Europe (Norway until December 2017 and Denmark), Africa (Equatorial Guinea until November 2017
and Libya) and Asia and Other (the Malaysia/Thailand Joint Development Area (JDA), and Malaysia). Exploration activities
were also conducted, or are planned, in certain of these areas as well as additional countries. See Note 3, Dispositions in the
Notes to Consolidated Financial Statements.
Costs Incurred in Oil and Gas Producing Activities
For the Years Ended December 31
2018
Property acquisitions
Total
United
States
Europe
(b)
(In millions)
Africa
Asia and
Other
Unproved ............................................................................ $
Proved .................................................................................
Exploration ............................................................................
Production and development capital expenditures (a) ...........
51 $
43
442
1,577
43 $
43
111
1,239
2017
Property acquisitions
Unproved ............................................................................ $
Proved .................................................................................
Exploration ............................................................................
Production and development capital expenditures (a) ...........
46 $
—
322
1,687
46 $
—
94
1,160
2016
Property acquisitions
Unproved ............................................................................ $
Proved .................................................................................
Exploration ............................................................................
Production and development capital expenditures (a) ...........
11 $
—
491
1,181
11 $
—
211
999
— $
—
—
(7 )
— $
—
1
146
— $
—
6
(64 )
— $
—
—
9
— $
—
—
40
— $
—
(2 )
(58 )
8
—
331
336
—
—
227
341
—
—
276
304
(a) Includes an increase of $44 million for asset retirement obligations related to net accruals and revisions in 2018 (2017: $8 million increase; 2016:
$188 million decrease).
(b) Costs incurred in oil and gas producing activities in Norway, including net accruals and revisions for asset retirement obligations, amounted to a net
credit of $19 million for the year ended December 31, 2016.
Capitalized Costs Relating to Oil and Gas Producing Activities
Unproved properties .................................................................................................................. $
Proved properties .......................................................................................................................
Wells, equipment and related facilities ......................................................................................
Total costs ...............................................................................................................................
Less: Reserve for depreciation, depletion, amortization and lease impairment ......................
Net Capitalized Costs ........................................................................................................ $
At December 31,
2018
2017
(In millions)
394 $
3,124
26,173
29,691
16,361
13,330 $
520
3,162
25,550
29,232
15,654
13,578
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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, NGLs and natural gas, 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 20, Segment Information in the Notes to Consolidated
Financial Statements.
For the Years Ended December 31
2018
Total
United
States
Europe
(b)
(In millions)
Africa
Asia and
Other
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 $
164 $
455 $
755
941
171
648
362
258
1,748
4,128
387
337
50 $
697
165
648
119
230
1,297
3,156
(15 )
(63 )
48 $
71
—
—
—
22
37
130
34
14
20 $
32
—
—
1
—
19
52
403
376
27 $
141
6
—
242
6
395
790
(35 )
10
(45 )
2017
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 ....................................................... $
4,128 $
2,335 $
628 $
700 $
465
1,250
119
543
507
225
2,736
4,203
9,583
(5,455 )
(1,873 )
(3,582 ) $
652
116
543
275
—
—
106
208
1,819
1,700
5,144
(2,809 )
(47 )
(2,762 ) $
1
10
381
2,503
3,170
(2,542 )
(2,014 )
(528 ) $
186
1
—
280
4
263
—
734
(34 )
197
(231 ) $
137
2
—
120
3
273
—
535
(70 )
(9 )
(61 )
2016
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 (a) .......................
Results of Operations ....................................................... $
3,628 $
2,056 $
597 $
519 $
456
1,662
101
497
1,442
232
3,113
7,047
(3,419 )
1,549
(4,968 ) $
920
94
497
342
215
2,012
4,080
(2,024 )
379
(2,403 ) $
321
1
—
6
1
502
831
(234 )
208
(442 ) $
249
—
—
—
7
375
631
(112 )
244
(356 ) $
172
6
—
1,094
9
224
1,505
(1,049 )
718
(1,767 )
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(a)(cid:3) Includes charges to establish valuation allowances against net deferred tax assets amounting to $2,920 million. The charge is attributed to the geographic
region in which the operations occurred that gave rise to the net deferred tax asset (United States - $1,144 million, Europe - $486 million, Africa - $249
million and Asia & Other - $1,041 million).
(b)(cid:3) Results of operations for oil and gas producing activities in Norway for the year ended December 31, 2016 (in millions) were as follows:
Sales and Other Operating Revenues ......................................................................................................................................... $
Costs and Expenses
Operating costs and expenses ................................................................................................................................................
Production and severance taxes ............................................................................................................................................
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 .................................................................................................................................................................. $
419
252
—
6
362
620
(201 )
(157 )
(44 )
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 February 19, 2007).” 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. 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 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 85
through 90). 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 2018 was
Mr. Kenneth Kosco, Senior Manager, Global Reserves. Mr. Kosco is a member of the Society of Petroleum Engineers and has
30 years of experience in the oil and gas industry with a BS 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.
Mr. Kosco is responsible for the Corporation’s Global Reserves group, which is the internal organization responsible for
establishing 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 80% of 2018 year-end reported reserve quantities on a barrel of oil equivalent
basis (2017: 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 letter report, dated February 6, 2019, 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, 2018 oil
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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% (2017: 4%) 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, 2018 were $65.55 per barrel for WTI (2017: $51.19; 2016: $42.68) and $72.08 per barrel for
Brent (2017: $54.87; 2016: $44.45). New York Mercantile Exchange (NYMEX) natural gas prices used were $3.01 per mcf
in 2018 (2017: $3.03; 2016: $2.54).
At December 31, 2018, spot prices for WTI oil closed at $45.41 per barrel. If crude oil prices during 2019 average below
those used in determining 2018 proved reserves, we may recognize negative revisions to our proved reserves at December 31,
2019, which can vary significantly by asset due to differing cost structures. Conversely, if crude oil prices in 2019 remain
above those used in determining 2018 proved reserves, we could recognize positive revisions to our proved reserves at
December 31, 2019. It is difficult to estimate the magnitude of any potential negative or positive change in proved reserves at
December 31, 2019, due to a number of factors that are currently unknown, including 2019 crude oil prices, any revisions based
on 2019 reservoir performance, and the levels to which industry costs will change in response to movements in commodity
prices.
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Following are the Corporation’s proved reserves:
Crude Oil & Condensate
(cid:3)(cid:3)
Net Proved Reserves
United
States
Europe
(b)
Africa
(Millions of bbls)
Asia &
Other Total
Natural Gas Liquids
Asia &
Other Total
Europe
(b)
United
States
(Millions of bbls)
(45 )
(12 )
—
42
12
(12 )
At December 31, 2016 ...................................... 355 210 162
Revisions of previous estimates (a) ................
Extensions, discoveries and other additions....
Sales of minerals in place ............................... —
Production.......................................................
5 726
At January 1, 2016 ........................................... 346 203 172
31
(14 )
1
2
45
33 — —
Revisions of previous estimates (a) ................
13
Extensions, discoveries and other additions.... 127
Sales of minerals in place ...............................
Production.......................................................
(70 )
(1 )
5 732
12
45 174
(15 ) — (194 )
(21 ) (158 )
(1 )
(10 )
(15 ) —
(65 )
(13 )
(41 )
49 659 171 —
49 128
At December 31, 2017 ...................................... 433
(2 )
(2 )
(10 )
Revisions of previous estimates (a) ................
(17 )
(3 )
2 125
Extensions, discoveries and other additions.... 114
7
2
3
Purchase of minerals in place .........................
(3 )
Sales of minerals in place ...............................
(53 )
Production.......................................................
74
23
5 —
— — — — —
(16 ) —
86
8
56 —
50 —
(6 )
— 101
27
4
(19 ) —
—
5
— —
— (16 )
— 94
— 56
— 50
(14 )
— (15 )
— 171
(14 ) — — (14 )
39 — — 39
1
(8 )
(1 )
(14 ) — — (14 )
48 714 175 — — 175
(43 )
At December 31, 2018 ...................................... 501
3 — — —
—
(3 ) —
1 — —
(8 ) —
(2 )
(7 )
39 126
5
2 —
(6 ) —
(8 ) —
—
—
Net Proved Developed Reserves
At January 1, 2016 ............................................. 253 114 148
At December 31, 2016 ....................................... 245 116 138
45 112
At December 31, 2017 ....................................... 239
38 111
At December 31, 2018 ...................................... 266
5 520
5 504
5 401
4 419
12
51
59
3
87 —
—
85
— 63
— 62
— 87
— 85
Net Proved Undeveloped Reserves
At January 1, 2016 .............................................
93
At December 31, 2016 ....................................... 110
At December 31, 2017 ....................................... 194
At December 31, 2018 ...................................... 235
89
94
4
1
24 — 206
24 — 228
44 258
16
44 295
15
15
23
5
27
84 —
—
90
— 38
— 32
— 84
— 90
(a)(cid:3) Revisions resulting from the impact of price changes in production sharing contracts reduced proved crude oil and condensate reserves in 2018 by 3
million, primarily in Guyana. (2017: 0 million barrels; 2016: 1 million barrels increase).
(b)(cid:3) Our Norwegian operations were sold in 2017. Crude oil and condensate and NGLs proved reserves in Norway for 2016 were as follows:
At January 1, 2016 ..............................................................................................................................
Revisions of previous estimates......................................................................................................
Extensions, discoveries and other additions ..................................................................................
Sales of minerals in place ..............................................................................................................
Production .....................................................................................................................................
At December 31,2016 ...........................................................................................................................
Net Proved Developed Reserves at December 31, 2016 ....................................................................
Net Proved Undeveloped Reserves at December 31, 2016 ................................................................
171
(2 )
4
—
(8 )
165
75
90
27
(19 )
—
—
—
8
3
5
Crude Oil &
Condensate
(Millions of bbls)
Natural Gas
Liquids
(Millions of bbls)
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Natural Gas
Total
United
States
Europe
(c)
Asia &
Other Total
United
States
Europe
(c)
Asia &
Other Total
Africa
(Millions of mcf)
Africa
(Millions of boe)
(cid:3)(cid:3)
Net Proved Reserves
At January 1, 2016 ........................... 505 234 148 667 1,554 504 269 197 116 1,086
74
Revisions of previous estimates (a) 116
Extensions, discoveries and other
additions .........................................
69
Sales of minerals in place ............... — — — — — — — — — —
(15 ) (120 )
Production (b) ................................. (104 )
At December 31, 2016 ...................... 590 220 143 744 1,697 539 255 186 129 1,109
5 106
41 — — 114
(3 ) 160 235
40 — —
(83 ) (206 )
28 228
(39 )
(12 )
(15 )
(78 )
(38 )
(17 )
28
97
84
29
10
31
73
(2 )
(2 )
(6 )
1
Revisions of previous estimates (a) 171
Extensions, discoveries and other
additions ......................................... 219
Sales of minerals in place ...............
Production (b) .................................
74 291
7 — 176 402 214
(18 ) — (239 )
(29 ) (192 )
(15 ) — (186 )
(18 ) (153 )
(12 )
(18 ) (113 )
(13 )
(70 )
(2 ) (103 ) (200 )
(13 )
(82 )
64 149 190 1,154
92 124 845 1,941 751
At December 31, 2017 ...................... 880
(41 )
(12 )
(21 )
(21 )
(14 )
(24 )
3 —
(58 )
(5 )
(3 )
Revisions of previous estimates (a)
Extensions, discoveries and other
additions ......................................... 177
Purchase of minerals in place ......... — — — — —
Sales of minerals in place ............... (145 ) — — — (145 )
Production (b) .................................
1
3
8 104 292 183
4 — — —
(35 ) — — —
(3 )
(70 )
(5 ) (132 ) (215 )
78 128 796 1,815 812
19 213
4
(35 )
(3 )
(23 ) (103 )
52 147 181 1,192
(7 )
8
3
(75 )
At December 31, 2018 ...................... 813
Net Proved Developed Reserves
At January 1, 2016 ............................. 368 123 137 643 1,271 365 147 171 112 795
At December 31, 2016 ....................... 404 125 132 739 1,400 371 140 160 128 799
58 132 121 725
At December 31, 2017 ....................... 526
51 130 102 706
At December 31, 2018 ...................... 432
80 117 696 1,419 414
77 115 585 1,209 423
Net Proved Undeveloped Reserves
At January 1, 2016 ............................. 137 111
95
At December 31, 2016 ....................... 186
12
At December 31, 2017 ....................... 354
1
At December 31, 2018 ...................... 381
11
11
7 149 522 337
13 211 606 389
24 283 139 122
5 297 168 115
6
1
26
26
17
17
4 291
1 310
69 429
79 486
(a)(cid:3) Revisions resulting from the impact of price changes in production sharing contracts reduced proved natural gas reserves in 2018 by 22 million mcf
(2017: 22 million mcf decrease; 2016: 12 million mcf increase).
(b)(cid:3) Natural gas production in 2018 includes 13 million mcf used for fuel (2017: 11 million mcf; 2016: 15 million mcf).
(c)(cid:3) Natural gas and Total proved reserves in Norway for 2016 were as follows:
At January 1, 2016 .............................................................................................................................
Revisions of previous estimates.....................................................................................................
Extensions, discoveries and other additions .................................................................................
Sales of minerals in place .............................................................................................................
Production ....................................................................................................................................
At December 31, 2016 .........................................................................................................................
Natural Gas
(Millions of mcf)
191
(26 )
4
—
(9 )
160
Total
(Millions of boe)
230
(25 )
5
—
(10 )
200
Net Proved Developed Reserves at December 31, 2016 ...................................................................
Net Proved Undeveloped Reserves at December 31, 2016 ...............................................................
72
88
90
110
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Extensions, discoveries and other additions (‘Additions’)
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 NGLs and 274 million mcf of natural gas) and are discussed
in further detail on page 89.
2017: Total Additions were 291 million boe, of which 11 million boe (4 million barrels of crude oil, 1 million barrels
of NGLs and 37 million mcf of natural gas) related to proved developed reserves. Additions to proved developed
reserves were primarily from drilling activity in the Bakken and North Malay Basin. Additions to proved undeveloped
reserves were 280 million boe (170 million barrels of crude oil, 49 million barrels of NGLs and 365 million mcf of
natural gas) and are discussed in further detail on page 89.
2016: Total Additions were 69 million boe, of which 45 million boe (34 million barrels of crude oil, 2 million barrels
of NGLs and 55 million mcf of natural gas) related to proved developed reserves. Additions to proved developed
reserves were primarily from drilling activity in the Bakken and from a 20-year extension to the license for the South
Arne Field, offshore Denmark, which extends expiry to 2047. Additions to proved undeveloped reserves were 24
million boe (11 million barrels of crude oil, 3 million barrels of NGLs and 59 million mcf of natural gas) and are
discussed in further detail on page 89.
Revisions of previous estimates
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 (crude oil - 4 million barrels increase, NGLs - 4 million
barrels decrease and natural gas - 20 million mcf increase). Revisions to proved developed reserves primarily relate
to the Bakken. Revisions associated with proved undeveloped reserves are discussed in further detail on page 89.
2017: Total revisions of previous estimates amounted to a net increase of 106 million boe, of which revisions of
proved developed reserves amounted to a net increase of 126 million boe (41 million barrels of crude oil, 44 million
barrels of NGLs and 243 million mcf of natural gas). Revisions to proved developed reserves from the Bakken
amounted to 85 million boe with approximately 55% resulting from improved reservoir performance, and the
remaining 45% resulting from higher prices and an improved cost structure. The Gulf of Mexico and Utica had
positive revisions to proved developed reserves totaling 16 million boe due to improved reservoir performance, while
higher crude oil prices resulted in revisions to proved developed reserves of 15 million boe in Denmark and
Utica. Revisions associated with proved undeveloped reserves are discussed in further detail on page 89.
2016: Total revisions of previous estimates amounted to a net increase of 74 million boe, of which net
positive revisions increased proved reserves by 103 million boe (54 million barrels of crude oil, 5 million barrels of
NGLs and 265 million mcf of natural gas) and negative revisions associated with lower crude oil prices reduced proved
reserves by 29 million boe (23 million barrels of crude oil, 1 million barrels of NGLs and 30 million mcf of natural
gas). Total revisions of proved developed reserves amounted to a net increase of 41 million boe (5 million barrels
decrease of crude oil, 7 million barrels increase of NGLs and 235 million mcf increase of natural gas) reflecting
improved expected recoveries in the Bakken, completion of incremental development activities at the North Malay
Basin, partially offset by negative revisions at the Valhall Field offshore Norway due to changes in estimated
recoveries of NGLs and natural gas, and negative price revisions mostly related to crude oil reserves. Revisions
associated with proved undeveloped reserves are discussed in further detail on page 89.
Sales of minerals in place (‘Asset sales’)
2018: Assets sales primarily include our former interests in the Utica Basin of Ohio.
2017: Assets sales primarily include our former interests in Norway, Equatorial Guinea, and our enhanced oil recovery
assets in the Permian Basin.
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Proved Undeveloped Reserves
Following are the Corporation’s proved undeveloped reserves:
Net Proved Undeveloped Reserves
At January 1, 2016 ..............................................................
Revisions of previous estimates .........................................
Extensions, discoveries and other additions.......................
Transfers to proved developed reserves .............................
Sales of minerals in place ..................................................
At December 31, 2016 .........................................................
Revisions of previous estimates .........................................
Extensions, discoveries and other additions.......................
Transfers to proved developed reserves .............................
Sales of minerals in place ..................................................
At December 31, 2017 .........................................................
Revisions of previous estimates .........................................
Extensions, discoveries and other additions.......................
Transfers to proved developed reserves .............................
Sales of minerals in place ..................................................
At December 31, 2018 .........................................................
Extensions, discoveries and other additions (‘Additions’)
United
States
Europe
Africa
(Millions of boe)
Asia
& Other
Total
139
50
13
(34 )
—
168
(8 )
209
(32 )
—
337
(22 )
178
(97 )
(7 )
389
122
(14 )
11
(4 )
—
115
(3 )
3
—
(109 )
6
(7 )
2
—
—
1
26
—
—
—
—
26
(9 )
—
—
—
17
(6 )
8
(2 )
—
17
4
(3 )
—
—
—
1
—
68
—
—
69
(9 )
19
—
—
79
291
33
24
(38 )
—
310
(20 )
280
(32 )
(109 )
429
(44 )
207
(99 )
(7 )
486
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 Asia 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.
2017: In the United States, additions from the Bakken were 180 million boe, of which approximately 70% resulted
from higher crude oil prices that increased the percentage of proved undeveloped wells in our planned five-year
drilling program compared to the prior year. The remaining 30% of Bakken additions reflect the expected improved
recovery in future wells from changes in well completion design and reservoir performance. Additions from the
Stampede Field in the Gulf of Mexico were 21 million boe, due to completion of further development activities. At
the Stabroek Block, offshore Guyana, additions of 45 million boe were recognized for project sanction of the first
phase of the Liza Field development. Other international additions were primarily at North Malay Basin due to higher
prices.
2016: In the United States, additions were at the Utica shale play in Ohio as result of changes in well design that
improved both well economics and recoverability, and at the Bakken due to drilling plans. In Europe, additions were
primarily from a 20-year extension to the license for the South Arne Field, offshore Denmark, which extends expiry to
2047.
Revisions of previous estimates
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 PSC in Guyana.
2017: Total negative reserve revisions of 20 million boe, primarily relate to changes in drilling plans in Libya and
lower reserves at certain fields in the Gulf of Mexico and Denmark.
2016: Total positive reserve revisions were 33 million boe. Technical revisions increased reserves by 44 million boe
and were primarily from an improved well design at the Bakken, which was partially offset by negative revisions at
the Valhall Field offshore Norway due to changes in expected recoveries of NGLs and natural gas. Negative revisions
resulting from lower commodity prices totaled 11 million boe and were primarily in the Bakken.
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Transfers to proved developed reserves (‘Transfers’)
2018: Transfers from proved undeveloped reserves included 75 million boe in the Bakken shale play associated with
drilling activity, and 22 million boe at the Stampede Field in the Gulf of Mexico where first production was achieved
in 2018.
2017: Transfers from proved undeveloped reserves included 24 million boe in the Bakken and 8 million boe at the
Penn State Field in the Gulf of Mexico associated with drilling activity.
2016: Transfers from proved undeveloped reserves included 21 million boe in the Bakken and 13 million boe at the
Tubular Bells and Conger Fields in the Gulf of Mexico associated with drilling activity.
In 2018, capital expenditures of $1,070 million were incurred to convert proved undeveloped reserves to proved developed
reserves (2017: $527 million; 2016: $589 million).
Projects that have proved reserves, which have been classified as undeveloped for a period in excess of five years, total
6 million boe, or 1% of total proved reserves at December 31, 2018. Most of the proved undeveloped reserves in excess of
five years relate to Libya.
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.
Proved reserves from these production sharing contracts for each of the three years ended December 31, 2018 are presented
separately below, as well as volumes produced and received during 2018, 2017 and 2016 from these production sharing
contracts.
Crude Oil
Natural Gas
United
States Europe Africa
Asia &
Other
(a)
Total
United
States
Europe Africa
Asia &
Other
(a)
Total
(Millions of bbls)
(Millions of mcf)
Production Sharing Contracts
Proved Reserves
At December 31, 2016 ......... — —
24
At December 31, 2017 ......... — — —
At December 31, 2018 ........ — — —
Production
12
2016 ..................................... — —
2017 ..................................... — —
9
2018 ..................................... — — —
5
49
48
1
1
1
29 — —
15
49 — — —
48 — — —
744
845
796
2
13 — —
10 — —
2
1 — — —
83
103
132
759
845
796
85
105
132
(a) Asia and Other includes Guyana proved undeveloped reserves of 40 million barrels of oil and 11 million mcf of natural gas at December 31, 2018 and 43
million barrels of oil and 11 million mcf of natural gas at December 31, 2017.
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 2018 were $65.55 per barrel for WTI (2017: $51.19; 2016:
$42.68) and $72.08 per barrel for Brent (2017: $54.87; 2016: $44.45) and do not include the effects of commodity hedges.
New York Mercantile Exchange (NYMEX) natural gas prices used were $3.01 per mcf in 2018 (2017: $3.03; 2016: $2.54).
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
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in the standardized measure computations. The future net cash flow estimates could be materially different if other assumptions
were used.
At December 31
2018
Total
United
States
Europe (a)
(In millions)
Africa
Asia &
Other
Future revenues.................................................................... $ 50,948 $ 31,460 $
Less:
3,036 $
9,183 $
7,269
Future production costs ..................................................
Future development costs ..............................................
Future income tax expenses ...........................................
Future net cash flows ...........................................................
Less: Discount at 10% annual rate .......................................
13,636
8,427
10,950
33,013
17,935
7,285
9,718
6,132
2,641
18,491
12,969
5,437
1,311
449
246
2,006
1,030
444
678
301
7,496
8,475
708
359
1,929
1,545
567
4,041
3,228
1,045
Standardized Measure of Discounted Future Net Cash
Flows ...................................................................................... $ 10,650 $
7,532 $
586 $
349 $
2,183
2017
Future revenues.................................................................... $ 36,746 $ 20,834 $
Less:
2,958 $
7,154 $
5,800
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 ...................................................................................... $
13,042
6,748
6,379
26,169
10,577
4,221
8,802
4,601
444
13,847
6,987
2,904
1,501
553
137
2,191
767
272
782
330
5,485
6,597
557
307
1,957
1,264
313
3,534
2,266
738
6,356 $
4,083 $
495 $
250 $
1,528
2016
Future revenues.................................................................... $ 32,814 $ 13,035 $ 10,283 $
Less:
6,907 $
2,589
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 ...................................................................................... $
14,054
8,635
2,450
25,139
7,675
3,650
6,639
2,910
—
9,549
3,486
1,288
5,091
4,348
(2,064 ) (b)
7,375
2,908
2,072
1,440
992
4,406
6,838
69
40
884
385
108
1,377
1,212
250
4,025 $
2,198 $
836 $
29 $
962
(a)(cid:3) The standardized measure of discounted future net cash flows relating to proved reserves in Norway for 2016 (in millions) were as follows:
Future revenues ..................................................................................................................................................................................... $
Less:
Future production costs ...................................................................................................................................................................
Future development costs ................................................................................................................................................................
Future income tax expenses (b) .......................................................................................................................................................
Future net cash flows .............................................................................................................................................................................
Less: Discount at 10% annual rate ........................................................................................................................................................
Standardized Measure of Discounted Future Net Cash Flows ............................................................................................................ $
8,188
4,004
3,931
(2,112 )
5,823
2,365
1,969
396
(b)(cid:3) The Petroleum Tax Act provides for compensation by the Norwegian government to a company upon cessation of its E&P activities on the Norwegian
Continental Shelf in an amount equal to the tax values of unutilized tax losses and certain other tax attributes, including dismantlement expenditures
incurred after production has ceased that would qualify for compensation at an effective tax rate of 78%. Due to the low crude oil price used in the 2016
computation, future income taxes reflect cash inflows for Norway of $2.1 billion on an undiscounted basis. The corresponding present value reflected in
the Standardized Measure of Discounted Future Net Cash Flows at December 31, 2016 is $70 million.
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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
2018
2017
(In millions)
2016
Standardized Measure of Discounted Future Net Cash Flows at January 1 ...... $
6,356 $
4,025 $
7,190
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 applicable to future production ........
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 . $
(2,755 )
1,533
7,076
(1,119 )
2,129
(630 )
(83 )
929
(2,662 )
(124 )
4,294
10,650 $
(2,216 )
1,679
2,330
(568 )
1,282
644
116
603
(709 )
(830 )
2,331
6,356 $
(1,368 )
1,369
(4,284 )
(76 )
338
376
—
779
1,331
(1,630 )
(3,165 )
4,025
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Following are selected quarterly results of operations (unaudited):
2018
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(In millions, except per share amounts)
Sales and other operating revenues ..................................................................
Gross profit (loss) (a) .......................................................................................
$
$
1,346
244
$
$
1,534
310
$
$
1,793
500
1,650
310
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 ...... $
(65 )
41
(106 )
11
(117 ) (b) $
(87 )
43
(130 )
12
(142 ) (c)
3
45
(42 )
11
(53 ) (d)
34
38
(4 )
12
(16 ) (e)
Net income (loss) attributable to Hess Corporation per common share:
Basic ...........................................................................................................
Diluted ........................................................................................................
$
$
(0.38 ) $
(0.38 ) $
(0.48 )
(0.48 )
(0.18 )
(0.18 )
(0.05 )
(0.05 )
2017
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(In millions, except per share amounts)
Sales and other operating revenues ..................................................................
Gross profit (loss) (a) .......................................................................................
$
$
1,258
$
(68 ) $
1,197
(201 )
$
$
1,348
(2,632 )
$ 1,663
$ (1,548 )
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 ...... $
(296 )
28
(324 )
12
(336 ) $
(417 )
32
(449 )
11
(460 )
(593 )
31
(624 )
11
(2,635 )
42
(2,677 )
12
$
(635 ) (f) $ (2,689 ) (g)
Net income (loss) attributable to Hess Corporation per common share:
Basic ...........................................................................................................
Diluted ........................................................................................................
$
$
(1.07 ) $
(1.07 ) $
(1.46 )
(1.46 )
$
$
(2.02 )
(2.02 )
$ (8.57 )
$ (8.57 )
(a)(cid:3) Gross profit represents Sales and other operating revenues, less Marketing expenses, Operating costs and expenses, Production and severance taxes,
Depreciation, depletion and amortization and Impairment.
(b)(cid:3) Includes a net after-tax severance charge of $37 million ($37 million pre-tax), an after-tax charge of $27 million ($27 million pre-tax) relating to the
premium paid for the retirement of debt, and a noncash income tax benefit of $30 million to offset a noncash income tax expense recognized in other
comprehensive income, resulting from a reduction in our pension liabilities.
(c)(cid:3) Includes an after-tax gain of $10 million ($10 million pre-tax) associated with the sale of our interests in Ghana, an after-tax charge of $26 million ($26
million pre-tax) relating to the premium paid for the retirement of debt, and an after-tax charge of $58 million ($58 million pre-tax) resulting from the
settlement of legal claims related to former downstream interests.
(d)(cid:3) Includes an after-tax gain of $14 million ($14 million pre-tax) associated with the sale of our interests in the Utica shale play in eastern Ohio, noncash
after-tax charges of $73 million ($73 million pre-tax) in connection with vacated office space, and an allocation of noncash income tax expense of $12
million to offset the recognition of a noncash income tax benefit recorded in other comprehensive income resulting from changes in fair value of our 2019
crude oil hedging program.
(e)(cid:3) Includes a noncash income tax benefit of $73 million to offset the recognition of a noncash income tax expense recorded in other comprehensive income
primarily resulting from changes in fair value of our 2019 crude oil hedging program.
(f)(cid:3) Includes an after-tax impairment charge of $550 million ($2,503 million pre-tax) associated with the expected sale of our interests in Norway and an
after-tax gain of $280 million ($280 million pre-tax) related to the sale of our Permian assets.
(g)(cid:3) Includes an after-tax impairment charge of $1,700 million ($1,700 million pre-tax) associated with certain Gulf of Mexico assets, an after-tax charge of
$280 million to fully impair the carrying value of our interests in Ghana ($280 million pre-tax), and a net $371 million after-tax loss related to sales of
our interests in Norway and Equatorial Guinea ($371 million pre-tax).
The results of operations for the periods reported herein should not be considered as indicative of future operating results.
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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, 2018, 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, 2018.
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, 2018 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.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information relating to Directors is incorporated herein by reference to “Election of Directors” from the Corporation’s
definitive proxy statement for the 2019 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.
Information relating to the audit committee is incorporated herein by reference to “Election of Directors” from the
Corporation’s definitive proxy statement for the 2019 annual meeting of stockholders.
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Executive Officers of the Corporation
The following table presents information as of February 21, 2019 regarding executive officers of the Corporation:
Name
John B. Hess
Age
Office Held* and Business Experience
64 Chief Executive Officer and Director
Gregory P. Hill
57
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.
Chief Operating Officer, Executive Vice President and President,
Exploration and Production
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.
Year
Individual
Became an
Executive
Officer
1983
2009
Timothy B. Goodell
61 Senior Vice President, General Counsel and Corporate Secretary
2009
Mr. Goodell has been the Senior Vice President and General Counsel of
the Corporation since 2009 and Corporate Secretary since 2016. Prior to
joining the Corporation in 2009, he was a partner at the law firm of White
& Case, LLP where he spent 25 years.
John P. Rielly
56 Senior Vice President and Chief Financial Officer
2002
Mr. Rielly has been the Senior Vice President and Chief Financial
Officer of the Corporation since 2004. 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 16 years.
Andrew Slentz
57 Senior Vice President, Human Resources
2016
Mr. Slentz has been Senior Vice President, Human Resources of the
Corporation since April 2016. Prior to joining the Corporation, 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.
Richard Lynch
60 Senior Vice President, Technology and Services
2018
Mr. Lynch has been Senior Vice President, Technology and Services of
the Corporation since 2018. Mr. Lynch previously was Senior Vice
President Global Developments, Drilling and Completions. Prior to
joining Hess 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.
Michael R. Turner
59 Senior Vice President, Global Production
Mr. Turner has been Senior Vice President, Global Production of the
Corporation since 2017. He previously served as Senior Vice President,
Onshore. Prior to joining the Corporation in 2009, Mr. Turner spent 28
years with Royal Dutch Shell and its affiliates in a variety of production
leadership positions around the world.
Barbara Lowery-Yilmaz
62 Senior Vice President, Exploration
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.
2014
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 5, 2018.
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Except for Mr. Lynch, Ms. Lowery-Yilmaz and 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.
Lynch served in senior positions at BP plc, most recently as Vice President Global Wells Organizations, overseeing all upstream
activities associated with drilling and completion, intervention and well integrity. Ms. Lowery-Yilmaz served in senior
executive positions in Exploration and Production at BP plc. Mr. Slentz served in senior executive positions in human resources
at Peabody Energy and its affiliates.
Item 11. Executive Compensation
Information relating to executive compensation is incorporated herein by reference to “Election of Directors—Executive
Compensation and Other Information,” from the Corporation’s definitive proxy statement for the 2019 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 “Election of Directors—Ownership of Voting Securities by Certain Beneficial Owners” and “Election of
Directors—Ownership of Equity Securities by Management” from the Corporation’s definitive proxy statement for the
2019 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 “Election of Directors” from the Corporation’s
definitive proxy statement for the 2019 annual meeting of stockholders.
Item 14. Principal Accounting Fees and Services
Information relating to this item is incorporated herein by reference to “Ratification of Selection of Independent Auditors”
from the Corporation’s definitive proxy statement for the 2019 annual meeting of stockholders.
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Item 15. Exhibits, Financial Statement Schedules
(a) 1. and 2. Financial statements and financial statement schedules
PART IV
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.
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
Supplementary Data.
3. Exhibits
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 Index is incorporated herein by reference.
3(1)
3(2)
3(3)
3(4)
4(1)
4(2)
4(3)
4(4)
4(5)
4(6)
4(7)
4(8)
4(9)
Restated Certificate of Incorporation of Registrant, including amendment thereto dated May 3, 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, 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 13, 2014.
By-laws of Registrant incorporated by reference to Exhibit 3(2) of Form 8-K of Registrant filed on November 9,
2015.
Five-Year Credit Agreement, dated as of January 21, 2015, as amended and restated as of December 1, 2017,
among Hess Corporation, the subsidiaries party thereto, 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 Registrant filed on December
7, 2017.
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 September 30,
1999.
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 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
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 of 1933, as
amended, on August 9, 2001.
Prospectus Supplement, dated February 28, 2002, to Prospectus dated July 27, 2001 relating to Registrant’s
7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant 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 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
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
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 June
25, 2014.
97
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4(10)
4(11)
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.
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.
10(1)*
Annual Cash Incentive Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on
March 6, 2018.
10(2)*
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.
10(3)*
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.
10(4)*
Hess Corporation Pension Restoration Plan, dated January 19, 1990, incorporated by reference to Exhibit 10(9) of
Form 10-K of Registrant for the fiscal year ended December 31, 1989. (P)
10(5)*
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.
10(6)*
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.
10(7)*
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.
10(8)*
Forms of Awards under Registrant’s 2008 Long-term Incentive Plan, incorporated by reference to Exhibit 10(14)
of Form 10-K of Registrant for the fiscal year ended December 31, 2009.
10(9)*
Form of Performance Award Agreement under Registrant’s 2008 Long-term Incentive Plan incorporated by
reference to Exhibit 10(2) of Form 8-K of Registrant filed on March 13, 2012.
10(10)*
10(11)*
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.
Form of Performance Award Agreement for the three-year period ending December 31, 2017 under Registrant’s
Amended and Restated 2008 Long-term Incentive Plan, incorporated by reference to Exhibit 10(3) of Form 10-Q
of Registrant for the three months ended March 31, 2015.
10(12)*
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.
10(13)*
10(14)*
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).
98
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10(15)
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.
10(16)*
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.
10(17)*
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.
10(18)*
Deferred Compensation Plan of Registrant, dated December 1, 1999, incorporated by reference to Exhibit 10(16)
of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
10(19)*
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.
10(20)*
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, 2018.
10(21)*
Form of Stock Option 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, 2018.
10(22)*
Form of 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, 2018.
21
Subsidiaries of Registrant.
23(1)
Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 21, 2019.
23(2)
Consent of DeGolyer and MacNaughton dated February 21, 2019.
31(1)
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
31(2)
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
32(1)
32(2)
99(1)
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 6, 2019, on proved reserves audit as of December 31, 2018 of certain properties attributable to Registrant.
101(INS)
XBRL Instance Document
101(SCH)
XBRL Schema Document
101(CAL)
XBRL Calculation Linkbase Document
101(LAB)
XBRL Labels Linkbase Document
101(PRE)
XBRL Presentation Linkbase Document
101(DEF)
XBRL Definition Linkbase Document
* These exhibits relate to executive compensation plans and arrangements.
99
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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 21st day of
February 2019.
SIGNATURES
HESS CORPORATION
(Registrant)
100
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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 true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution,
for him and in his 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 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 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/ RODNEY F. CHASE
Rodney F. Chase
/s/ TERRENCE J. CHECKI
Terrence J. Checki
/s/ LEONARD S. COLEMAN JR.
Leonard S. Coleman Jr.
/s/ EDITH E. HOLIDAY
Edith E. Holiday
/s/ DR. RISA LAVIZZO-MOUREY
Dr. Risa Lavizzo-Mourey
/s/ MARC S. LIPSCHULTZ
Marc S. Lipschultz
/s/ DAVID MCMANUS
David McManus
/s/ DR. KEVIN O. MEYERS
Dr. Kevin O. Meyers
/s/ FREDRIC G. REYNOLDS
Fredric G. Reynolds
/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
Director
Senior Vice President and Chief
Financial Officer
(Principal Financial and Accounting Officer)
Date
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
February 21, 2019
Director
February 21, 2019
101
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUBSIDIARIES OF THE REGISTRANT
Exhibit 21
Name of Company
Hess Asia Holdings Inc
Hess Bakken Investments II L.L.C.
Hess Bakken Investments III L.L.C.
Hess Bakken Investments IV L.L.C.
Hess Bakken Processing L.L.C.
Hess Canada Oil and Gas ULC
Hess Capital Corporation S.a.r.l.
Hess Capital Limited
Hess Capital Services Corporation
Hess Canada (Aspy) Exploration Limited
Hess Canada Exploration Limited
Hess Capital Services L.L.C.
Hess Denmark Aps
Hess Equatorial Guinea Investments Limited
Hess Exploration and Production Malaysia B.V.
Hess Energy Exploration Limited
Hess Exploration & Production Holdings Limited
Hess Finance
Hess GOM Deepwater L.L.C.
Hess GOM Exploration L.L.C.
Hess Gulf of Mexico Ventures L.L.C.
Hess Guyana Exploration (Liza) Limited
Hess Guyana Exploration Limited
Hess Holdings EG Limited
Hess Holdings West Africa Limited
Hess Hungary Finance KFT
Hess (Indonesia-VIII) Holdings Limited
Hess Infrastructure Partners LP
Hess International Holdings Corporation
Hess International Holdings Limited
Hess International Receivables Limited
Hess Libya Exploration Limited
Hess Libya (Waha) Limited
Hess Limited
Hess Llano L.L.C
Hess Middle East New Ventures Limited
Hess Midstream Partners LP
Hess Midstream Partners GP LP
Hess (Netherlands) Oil & Gas Holdings C.V.
Hess New Ventures Exploration Limited
Hess North Dakota Export Logistics L.L.C.
Hess North Dakota Export Logistics Holdings L.L.C.
Hess North Dakota Export Logistics Operations LP
Hess North Dakota Pipelines L.L.C.
Hess North Dakota Pipelines Holdings L.L.C.
Registrant
ownership %
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
50
100
100
100
100
100
100
100
100
35
50
100
100
47
47
47
47
47
Jurisdiction
Cayman Islands
Delaware
Delaware
Delaware
Delaware
Canada
Luxembourg
Cayman Islands
Delaware
Cayman Islands
Cayman Islands
Delaware
Denmark
Cayman Islands
The Netherlands
Delaware
Delaware
England & Wales
Delaware
Delaware
Delaware
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Hungary
Cayman Islands
Delaware
Delaware
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
England & Wales
Delaware
Cayman Islands
Delaware
Delaware
The Netherlands
Cayman Islands
Delaware
Delaware
Delaware
Delaware
Delaware
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Name of Company
Hess North Dakota Pipelines Operations LP
Hess NWE Holdings Limited
Hess Ohio Developments, L.L.C.
Hess Ohio Holdings Corporation
Hess Ohio Sub-Holdings L.L.C.
Hess Oil and Gas Holdings Inc.
Hess Oil Company of Thailand (JDA) Limited
Hess Services UK Limited
Hess Shenzi L.L.C.
Hess Stampede L.L.C.
Hess Tank Cars L.L.C.
Hess Tank Cars II L.L.C.
Hess Tank Cars Holdings II L.L.C.
Hess TGP Finance Company L.L.C.
Hess TGP Holdings L.L.C.
Hess TGP Operations LP
Hess Tioga Gas Plant L.L.C.
Hess Trading Corporation
Hess Tubular Bells L.L.C.
Hess West Africa Holdings Limited
HIH C.V.
Registrant
ownership %
47
100
100
100
100
100
100
100
100
100
50
50
50
100
47
47
47
100
100
100
100
Jurisdiction
Delaware
England & Wales
Delaware
Delaware
Delaware
Cayman Islands
Cayman Islands
England & Wales
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Cayman Islands
The Netherlands
Each of the foregoing subsidiaries conducts business under the name listed. The above list does not include 47 subsidiary
holding companies (20 domestic and 27 non-U.S.) that would otherwise be reported except that they are ultimately 100%
owned by the Registrant and, as their line of business, fulfill similar roles to those holding companies separately identified in
the above list. In addition, we have excluded subsidiaries associated with divested assets, discontinued activities and those that
when considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary.
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Exhibit 23(1)
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the following Registration Statements:
(1)(cid:3) Registration Statement (Form S-8 No. 333-43569) pertaining to the Hess Corporation Employees’ Savings Plan,
(2)(cid:3) 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,
(3)(cid:3) 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,
(4)(cid:3) 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,
(5)(cid:3) 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,
(6)(cid:3) Registration Statement (Form S-8 No. 333-219113) pertaining to the Hess Corporation 2017 Long-Term
Incentive Plan, and
(7)(cid:3) Registration Statement (Form S-3 No. 333-223279) of Hess Corporation;
of our reports dated February 21, 2019, 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, 2018.
New York, New York
February 21, 2019
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DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244
Exhibit 23(2)
February 21, 2019
Hess Corporation
1185 Avenue of the Americas
New York, New York 10036
Ladies and Gentlemen:
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 third-party letter report dated February 6, 2019,
containing our opinion on the estimated proved reserves, as of December 31, 2018 attributable to certain properties that Hess
Corporation has represented that it owns (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, 2018. 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. 333-223-279) 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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Exhibit 31(1)
I, John B. Hess, certify that:
1. I have reviewed this annual report on Form 10-K of Hess Corporation;
2. Based on my knowledge, this annual 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.
Date: February 21, 2019
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Exhibit 31(2)
I, John P. Rielly, certify that:
1. I have reviewed this annual report on Form 10-K of Hess Corporation;
2. Based on my knowledge, this annual 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.
Date: February 21, 2019
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CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32(1)
In connection with the Annual Report of Hess Corporation (the Corporation) on Form 10-K for the period ended
December 31, 2018 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.
Date: February 21, 2019
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CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32(2)
In connection with the Annual Report of Hess Corporation (the Corporation) on Form 10-K for the period ended December 31, 2018
as filed with the Securities and Exchange Commission on the date hereof (the Report), I, John P. Rielly, Senior 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.
Date: February 21, 2019
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DeGolyer and MacNaughton
(cid:3)
Board of Directors
Hess Corporation
1185 Avenue of the Americas
New York, New York 10036
Ladies and Gentlemen:
Exhibit 99.1
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 6, 2019
Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2018, of
the net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain selected 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 6, 2019. Hess has represented to us that these properties account for approximately 80.3 percent
on a net equivalent barrel basis of Hess’ net proved reserves, as of December 31, 2018, 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. We have reviewed information provided to us by Hess that it represents
to be Hess’ estimates of the net reserves, as of December 31, 2018, 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, 2018. 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 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 of the properties was not considered necessary for the purposes of this report.
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Definition of Reserves
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.
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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.
(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 Rule 4-
10(a)(2) of Regulation S-X, or by other evidence using reliable technology establishing reasonable certainty.
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
(Revision as of February 19, 2007)” 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.
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.
A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized
for the evaluation of all reserves categories. 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. Analysis was
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 impact of dynamic reservoir and fracture
parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. The methodology
used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of
basic data, production history, and the appropriate reserves definitions.
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.
(cid:3)
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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 non-producing and undeveloped reserves, type-well analysis was performed using well data from
analogous reservoirs for which more complete historical performance data were available.
Data provided by Hess from wells drilled through December 31, 2018 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 2018. Estimated cumulative production, as of December 31, 2018, 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 C5+ and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions. NGL reserves
are the result of low-temperature plant processing. Oil, condensate, and NGL reserves reported herein are expressed in
thousands of barrels (103bbl) 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 the gas
consumed in operation and is included in marketable gas and estimated herein as reserves. Gas reserves estimated herein are
reported as marketable gas. Gas reserves estimated herein 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 reserves presented in this report are expressed in
millions of cubic feet (106ft3).
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. This conversion factor was provided by Hess.
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 12-month average price (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.$65.55 per barrel for West Texas Intermediate and U.S.$72.08
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 oil and condensate price for the fields evaluated was
U.S.$63.87 per barrel.
NGL Prices
Hess has represented that the NGL prices were based on a 12 month average 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. These prices were held constant
over the lives of the properties. The volume-weighted average NGL price for the fields evaluated was U.S.$8.10
per barrel.
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
(cid:3)
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NYMEX was U.S.$3.01 per thousand cubic feet and the UK International Petroleum Exchange reference price was
U.S.$7.79 per million British thermal units. 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 gas price for the fields evaluated was U.S.$2.39 per thousand cubic feet.
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 2018 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 the 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.
In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, 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 Financial Accounting Standards Board and Rules 4–10(a) (1)–(32)
of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange
Commission; 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. The Hess net proved reserves attributable to these properties, as of
December 31, 2018, and which represent approximately 80.3 percent of total Hess net reserves on a net equivalent barrel 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, 2018
Oil and
Condensate
(106bbl)
NGL
(106bbl)
Marketable
Gas
(109ft3)
Oil Equivalent
(106boe)
United States
Europe
Asia and Other
Total
477
39
8
524
169
0
0
169
724
78
785
1,587
766
52
139
957
Notes:
1. 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.
2. Totals may vary due to rounding.
3. Net proved fuel gas reserves included as a portion of marketable gas reserves were
estimated to be 162 109ft3.
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, 2018, 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.
(cid:3)
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Hess’ oil and gas reserves have been 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, neither we nor Hess are aware of any such governmental actions which restrict the
recovery of the December 31, 2018, 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 letter 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.
Submitted,
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
[SEAL]
Thomas C. Pence, P.E.
Senior Vice President
DeGolyer and MacNaughton
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(cid:39)(cid:72)(cid:42)(cid:82)(cid:79)(cid:92)(cid:72)(cid:85)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:48)(cid:68)(cid:70)(cid:49)(cid:68)(cid:88)(cid:74)(cid:75)(cid:87)(cid:82)(cid:81)(cid:3)
(cid:3)
(cid:26)(cid:3)
CERTIFICATE of QUALIFICATION
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.(cid:3)
That I am a Senior Vice President of DeGolyer and MacNaughton, which firm did prepare the report of third
party dated February 6, 2019, on the proved reserves evaluation of certain properties attributable to Hess Corporation,
and that I, as Senior Vice President, was responsible for the preparation of this report of third party.
2.(cid:3)
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 36 years of experience in oil and gas reservoir studies and
reserves evaluations.
[SEAL]
Thomas C. Pence, P.E.
Senior Vice President
DeGolyer and MacNaughton
(cid:3)
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COMMON STOCK
Listed New York Stock Exchange (ticker symbol: HES)
Transfer Agent and Registrar
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
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 2018 Form 10-K.
DIVIDEND REINVESTMENT PLAN
Information concerning the Dividend Reinvestment
Plan available to holders of Hess Corporation common
stock may be obtained by writing to Computershare,
Dividend Reinvestment Department, P.O. Box 505000,
Louisville, KY 40233-5000, or by calling 1-866-203-6215.
Shareholder online inquiries:
https://www-us.computershare.com/investor/contact
Hess website:
www.hess.com
DOCUMENTS AVAILABLE
Copies of the corporation’s 2018 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 Securities and Exchange Commission (SEC), as
well as the 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 Hess Annual Report cover and editorial sections are printed on recycled paper made from fiber
sourced from well-managed forests and other controlled wood sources and independently certified
to Forest Stewardship Council® (FSC®) standards.
© 2019 Hess Corporation
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www.hess.com
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