2017
T
L
R
A
U
O
N
P
E
N
R
A
Financial
Highlights
(Millions of dollars and shares, except per share data)
20171
20161
20151
Revenue
Operating Income (Loss)
$ 20,620
$ 1,362
$ 15,887
$ (6,778)
$ 23,633
$
(165)
Revenue
in billions
Dividends to
Shareholders
in millions
Amounts Attributable to Company Shareholders:
Loss from Continuing Operations
Net Loss
$
$
(444)
(463)
$ (5,761)
$ (5,763)
$
$
(666)
(671)
6
.
0
2
$
9
.
5
1
$
6
.
3
2
$
6
2
6
$
0
2
6
$
4
1
6
$
Diluted Income per Share Attributable
to Company Shareholders:
Loss from Continuing Operations
Net Loss
Cash Dividends per Share
Diluted Common Shares Outstanding
Working Capital2
Capital Expenditures
Total Debt
$
$
$
(0.51)
(0.53)
0.72
870
$ 5,915
$ 1,373
$ 10,942
$
$
$
(6.69)
(6.69)
0.72
861
$ 7,654
$
798
$ 12,384
$
$
(0.78)
(0.79)
$ 0.72
853
$ 14,733
$ 2,184
$ 15,355
Debt to Total Capitalization3
57%
57%
50%
Depreciation, Depletion and Amortization
Total Capitalization4
$ 1,556
$ 19,291
$ 1,503
$ 21,832
$ 1,835
$ 30,850
1 Reported results during these periods include impairments and other charges of $647 million for the year ended
December 31, 2017, merger-related costs and termination fee of $4.1 billion and impairments and other charges
of $3.4 billion for the year ended December 31, 2016, and impairments and other charges of $2.2 billion for the
year ended December 31, 2015.
2 Working Capital is defined as total current assets less total current liabilities.
3 Debt to Total Capitalization is defined as total debt divided by the sum of total debt plus total shareholders’ equity.
4 Total Capitalization is defined as total debt plus total shareholders’ equity.
17
16
15
17
16
15
Capital
Expenditures
in billions
4
1.
$
8
.
0
$
2
.
2
$
17
16
15
HALLIBURTON 2017 ANNUAL REPORT
1
To Our
Shareholders
2017 was a tale of two cycles for the oil and gas industry. North
America began to recover from one of the steepest industry downturns
on record while activity in the international market appeared to reach
bottom. Our strong execution culture, clear strategy and customer
alignment are enabling us to win the recovery in North America and
to outperform our peers internationally – delivering revenue growth,
improved margins and leading returns.
We are pleased with all that Halliburton accomplished in 2017. We
effectively executed our strategy to collaborate and engineer solutions
to maximize asset value for our customers. Thanks to the exceptional
performance and commitment of approximately 55,000 Halliburton
employees, we outperformed our peers with industry-leading returns and
generated strong cash flow. At the same time, we reduced our debt by
$1.4 billion, strengthening our balance sheet and enhancing our financial
flexibility. We continued to exercise capital discipline while also advancing
our differentiating technologies and digital capabilities.
In North America, we quickly responded to the recovering market,
reactivating equipment and hiring personnel to meet customer
demand for efficiency and increased production. Halliburton was the
first service company to return to profitability in North America, a direct
reflection of our leadership position, scale and technology strength.
As the international market worked through its own downturn, we
gained market share in key regions by focusing on the most active
markets while maintaining a presence in other areas that will serve
us well going forward.
We look ahead to 2018 with great optimism and enthusiasm as the
macro environment for oil continues to improve. Our North America
customers are back to work driving what we expect to be strong growth
in unconventional activity. Internationally, we believe the market has
reached bottom and we are seeing the beginning of a recovery in
mature fields, while deepwater remains challenged.
Our collaborative approach and differentiating technologies enable
us to deliver the most efficient wells for our customers no matter the
geography. These, along with our comprehensive service offerings
and stringent cost control efforts, position us well for the continuing
recovery in North America and the future recovery of the international
market. An added benefit going forward is tax reform. With a lower
effective tax rate, Halliburton will be on a more level playing field with
our foreign competitors.
“ We are more
convinced than
ever that Halliburton
is in the right
businesses and is
capturing its full
potential through
a strategy that
maximizes asset
value for our
customers.”
2
We are more convinced than ever that Halliburton is in the right
businesses and is capturing its full potential through a strategy that
maximizes asset value for our customers. We are committed to
remaining the leading oilfield service company delivering the best value
to our customers and the best returns to our investors. And we remain
focused on integrity, efficiency, safety and service quality.
On June 1, 2017, following our vigorous management succession plan,
Jeff Miller was unanimously selected by our Board of Directors to
succeed Dave Lesar as chief executive officer. Mr. Lesar, having led the
Company for nearly 17 years, continues to serve as executive chairman
of the Board. We are grateful for his outstanding leadership and look
forward to his continued contributions to the success of Halliburton.
In closing, we want to thank our employees, our Board of Directors and
shareholders for the vital role they play in the success of Halliburton. As
we continue to serve our customers in this evolving market environment,
we know we have the right leadership, employees and strategy in place to
guide Halliburton forward into its 100th year in business. Halliburton is the
execution company, and we will continue to deliver superior performance
for our customers, shareholders and employees.
Jeffrey A. Miller
President and
Chief Executive Officer
David J. Lesar
Executive Chairman of the Board
Christopher T. Weber
Executive Vice President and
Chief Financial Officer
Lawrence J. Pope
Executive Vice President
of Administration and
Chief Human Resources Officer
Robb L. Voyles
Executive Vice President,
Secretary and General Counsel
Eric J. Carre
Executive Vice President,
Global Business Lines
James S. Brown
President, Western Hemisphere
Joe D. Rainey
President, Eastern Hemisphere
Jeffrey A. Miller
President and Chief Executive Officer
2017 HIGHLIGHTS
• Halliburton outperformed our peers
in every region around the globe,
total Company revenue grew 30%
to $20.6 billion and we generated
$1.4 billion in operating income.
• Halliburton led its peers in
shareholder returns.
• Halliburton generated approximately
$2.5 billion in operating cash flow
and retired $1.4 billion in debt.
• Halliburton has significantly improved
its health and safety performance over
the last 5 years, achieving a reduction
of 35 percent to our total recordable
incident rate. Halliburton achieved a
historic low in 2017.
• Halliburton collaborated with
customers on over 100 research and
development projects to engineer
solutions to maximize the value of
their assets.
Mission
To achieve superior growth and
returns for our shareholders by
delivering technology and services
that improve efficiency, increase
recovery, and maximize production
for our customers.
Value Proposition
We collaborate and engineer
solutions to maximize asset value
for our customers.
HALLIBURTON 2017 ANNUAL REPORT
3
Halliburton added to its technology offering in
its Drilling and Evaluation division through the
acquisition of Ingrain and OPT.
Ingrain specializes in the analysis of complex
rock types and has developed and brought
to market unique capabilities in rock physics,
using digital scanning and analysis to derive
petrophysical insights for operators to use
in commercial decision-making. Ingrain’s
capabilities combined with Halliburton
technologies in formation evaluation, coring
and surface data logging will strengthen
workflows and help develop solutions to
maximize our customers’ asset value.
OPT’s expertise covers all major aspects of
field management and production analytics
leading to better results as determined through
a comprehensive study of oil and gas fields
from the reservoir and wellbore to the surface.
The acquisition of OPT fills an important gap
in our portfolio and enhances our Voice of the
Oilfield™ solution by combining OPT’s best of
breed petroleum and production engineering
capabilities with DecisionSpace® Production.
Product innovations during the year
included Baroid’s award-winning Bara
ECD®. This high-performance drilling fluid
provides a solution for narrow margin drilling
applications, which require precise control
of equivalent circulating density (ECD).
Ideal for deepwater wells and wells with
depleted zones and histories of fluid losses,
Bara ECD reduces non-productive time,
lowers costs and improves safety by helping
to prevent a number of issues that can
occur with higher ECDs.
Drilling & Evaluation Division
Product Lines
• Baroid
• Consulting & Project Management
• Drill Bits & Services
• Landmark
• Sperry Drilling
• Testing & Subsea
• Wireline & Perforating
Drilling &
Evaluation
Drilling &
Evaluation
2017 DRILLING & EVALUATION HIGHLIGHTS
• Revenue grew to $7.5 billion from $7.0 billion in 2016.
• In North America, revenue grew in line with the average U.S. land rig count growth of 43 percent.
• Delivered a strong second-half performance, including growing sequential revenue in all regions
during the fourth quarter.
• Quarterly sequential operating income growth of 62 percent in the fourth quarter providing
approximately 50-percent incrementals.
4
While soft conditions for Drilling and
Evaluation (D&E) services persisted
into 2017, we saw growth resume during
the second half of the year. Revenue
grew 8 percent during the year, driven
by increased drilling activity in North
America as a result of improved pricing,
utilization and rig count.
ADDING VALUE TO CUSTOMER ASSETS
Halliburton has built its success on helping
customers lower the cost per barrel of oil
equivalent (BOE) and maximize the ultimate
recovery from each well. Our innovative
technologies provide practical solutions
through better tools, improved products
and superior information.
Among the efficient new tools introduced
in 2017 are the Geometrix™ 4D Shaped
Cutters. With four distinct geometric profiles,
they reduce drilling costs through improved
cutting efficiency and increased control.
Halliburton now offers the largest portfolio of
shaped cutters in the oil and gas industry.
INFORMATION DRIVES RESULTS
In today’s complex drilling environments,
including deepwater and mature fields,
superior information drives improved
results. By providing consistent, high-data
rate transmission of drilling and formation
evaluation measurements, Sperry Drilling’s
JetPulse™ high-speed telemetry service
enables operators to make better decisions
faster. It helps optimize well placement,
improve well control, cure mud losses
and increase drilling efficiency. By combining
this new telemetry technology with
measurement/logging-while-drilling services,
the system reduces flat time in the drilling
curve, maximizes the rate of penetration
and optimizes reservoir contact.
PARTNERING FOR SUCCESS
Working closely with customers and
providing expert project management
services is central to Halliburton’s strategy
for creating superior solutions. Through
project management, we add value to
customer projects by building efficiencies
into the planning stage, drawing on our
innovative technologies and comprehensive,
life-of-field capabilities, and ensuring
exceptional execution.
In the Middle East, increased demand for
these services has allowed Halliburton
to build on our leading position in project
management to grow our market share
and enhance our reputation for better,
lower-cost wells.
Several awards during 2017 helped
consolidate our market leadership in the
Middle East, including an award for the
delivery of more than 300 wells in Oman,
and a contract in Iraq to continue to provide
drilling services for a six-year sustained
production project. These awards are a
testimony to the safe, high-quality services
we have provided, and it solidifies our
position as a leading service company in
this region.
As the recovery gains momentum, we expect
increased activity levels to drive continued
growth in our project management business.
Our broad range of capabilities and continued
focus on technology complement our project
management leadership to provide an
unmatched value proposition.
New Technology Development
In 2017, Halliburton launched over 35 new
products across all 14 product lines to
improve our service for our customers and
increase efficiency. Halliburton achieved
industry-leading patent efficiency; with
1.4 patents granted for every $1 million
of research and development spend.
Halliburton is a leader in the digital
transformation of the oilfield, using data
analytics for predictive maintenance,
automation and digital workflow. Well
Construction 4.0™ is an open and integrated
environment that digitally transforms the
well design, planning and execution lifecycle.
It enables operators to reduce well program
preparation time and costs, as well as
increasing final wellbore quality and reliability.
Utilizing leading-edge digital technologies
to integrate and analyze both historical
and real-time data from multiple sources,
Well Construction 4.0 bridges the gap
between field planning in the office and
well site execution at the rig site.
HALLIBURTON 2017 ANNUAL REPORT
5
Completion &
Production
2017 COMPLETION & PRODUCTION HIGHLIGHTS
• Revenue grew by 47 percent in 2017 to $13.1 billion.
• Generated operating income of $1.6 billion, up from $107 million in 2016.
• In the first half of 2017, we successfully reactivated our hydraulic fracturing fleet, moving swiftly to
capture market share, helping to improve North America operating margins by 1,000 basis points.
• Acquired Summit ESP, elevating Halliburton to the second-largest ESP provider in
North America and advancing our strategy to grow the production part of our portfolio.
Completion & Production Division
Product Lines
• Artificial Lift
• Cementing
• Completion Tools
• Multi-Chem
• Pipeline & Process Services
• Production Enhancement
• Production Solutions
6
Halliburton added to its product portfolio
with the acquisition of Summit ESP, a leading
provider of electric submersible pump (ESP)
technology and services. The addition of
Summit’s artificial lift offerings and industry-
leading customer service strengthens
the Halliburton artificial lift portfolio for its
global customers.
Halliburton was honored with two spotlight
on new technology awards by the Offshore
Technology Conference. These awards
recognize the latest and most advanced
technologies that are leading the industry
into the future.
The HCS AdvantageOne™ offshore
cementing system was honored for addressing
the complexities of deepwater by enabling
remote operations, using an integrated liquid
additive system for precise slurry blending
and allowing predictive maintenance with
shore-based monitoring.
The Ecostar™ electric tubing-retrievable
safety valve was also honored. It is the
world’s first fully electronic safety valve.
Halliburton’s Completion and Production
(C&P) division benefited from a strong
rebound in the North American market as
the average U.S. land rig count increased
76 percent from 2016 to 2017. While still
depressed, our international business
began to show signs of recovery in the
latter half of the year driven primarily by
improved performance in the Middle East,
the North Sea and Latin America.
WINNING THE RECOVERY IN
NORTH AMERICA
Halliburton recognized the changing market
early and moved quickly to capitalize on this
opportunity. We completed the reactivation of
our hydraulic fracturing fleet in July, enabling
us to capture key customers early in the
recovery, increasing our market share.
But being first is not enough. We also
want to be the best. We do that through
execution excellence and innovative
technologies that maximize value for our
customers. We listen to our customers and
create solutions that improve operational
efficiency and/or maximize production.
Our ExpressKinect™ Wellhead Connection
Unit allows us to deliver superior efficiency
and safety for multi-well fracturing operations
by providing a solution to the complex
and labor-intensive rig-up requirements
for multiple wells.
By providing a single-line rig-up to the
wellhead, ExpressKinect drastically reduces
rig-up time and complexity. Wellhead
exchanges are executed in five minutes
or less, and up to 85 percent of the
high-pressure iron between the manifold
trailer and the wellhead is eliminated.
The result is improved equipment utilization
and a significant decrease in safety risk
exposure for employees onsite.
GAINING GROUND GLOBALLY
Our international business has proven
resilient through a severe and extended
downturn. Late in 2017, we began to see the
first signs of recovery with modest growth
in activity but continued pricing pressure.
The Middle East has been our most stable
region, producing consistent work for
Halliburton. Two other markets boosted
our international results: the North
Sea, where we are performing electric
completions and Brazil, where the focus
is on intelligent completions.
As the world’s leading provider of intelligent
completion technology to the upstream oil
industry, Halliburton helps optimize production
without costly well intervention. Our reliable
and fit-for-purpose SmartWell® systems enable
operators to collect, transmit and analyze
downhole data, remotely control selected
reservoir zones and maximize reservoir
efficiency. The results include increased
production, higher ultimate recovery and
lower capital and operating costs.
THE FUTURE: CONTINUED GROWTH
IN NORTH AMERICA
Looking ahead, we see substantial market
strength in North America with increased
commodity prices, a surge in unconventional
activity and a continuation of the C&P pricing
recovery that began during 2017. We expect
to continue to grow margins in 2018 by using
three levers: additional pricing increases,
improved equipment utilization and technology
solutions which reduce cost and increase
efficiency and production.
We also will continue to focus on growing
our production portfolio in the areas of
artificial lift and production chemicals.
Our acquisition of Summit ESP in 2017 was
an important strategic step for artificial lift.
As a leading provider of electric submersible
pump technology, Summit elevates Halliburton
to the second-largest ESP provider in North
America. This strengthens our leading position
in North American oilfield services and
expands our artificial lift portfolio for our
global customers.
Hart’s MEA Award Winners
Halliburton was honored to receive three
Meritorious Awards for Engineering Innovation
(MEA) from Hart Energy.
EXPRESSKINECT
ExpressKinect™ Wellhead Connection Unit
(WCU) drastically reduces rig-up time and
complexity, resulting in a more efficient, safer
rig-up operation. The WCU eliminates up to
85 percent of the high-pressure iron between
the manifold trailer and the wellhead.
EQUISEAL
EquiSeal™ Conformance service helps
operators achieve the lowest cost per BOE
through custom chemistry. Specifically
designed for horizontal and highly deviated
wellbores, EquiSeal and EquiSeal NWB use
a crosslinked polymer system to provide
unprecedented sealant capability for
controlling unwanted fluid production.
ENDURANCE HYDRAULIC SCREEN
Endurance Hydraulic Screen® is a compliant
screen that delivers a new level of sand
control completion, providing reservoir
compliance through positive wellbore
support. The system removes the annular
gap between the screen and open hole
upon hydraulic activation.
HALLIBURTON 2017 ANNUAL REPORT
7
Leadership
8
BOARD OF DIRECTORS
David J. Lesar
Executive Chairman of the Board,
Halliburton Company
(2000)
Abdulaziz F. Al Khayyal
Retired Senior Vice President of Industrial Relations,
Saudi Aramco
(2014) (C) (D)
William E. Albrecht
Non-Executive Chairman of the Board,
California Resources Corporation
(2016) (B) (C)
Alan M. Bennett
Retired President and Chief Executive Officer,
H&R Block, Inc.
(2006) (A) (D)
James R. Boyd
Retired Chairman of the Board,
Arch Coal, Inc.
(2006) (A) (B)
Milton Carroll
Executive Chairman of the Board,
CenterPoint Energy, Inc.
(2006) (B) (D)
Nance K. Dicciani
Non-Executive Chair of the Board,
AgroFresh Solutions, Inc.
(2009) (A) (C)
Murry S. Gerber
Retired Executive Chairman of the Board,
EQT Corporation
(2012) (A) (B)
CORPORATE OFFICERS
David J. Lesar
Executive Chairman of the Board
Jeffrey A. Miller
President and Chief Executive Officer
Christopher T. Weber
Executive Vice President and
Chief Financial Officer
Lawrence J. Pope
Executive Vice President of Administration and
Chief Human Resources Officer
Robb L. Voyles
Executive Vice President, Secretary and
General Counsel
Eric J. Carre
Executive Vice President,
Global Business Lines
James S. Brown
President, Western Hemisphere
José C. Grubisich
Managing Partner of
Olimpia Investimentos e Participações
(2013) (A) (C)
Robert A. Malone
Executive Chairman, President and
Chief Executive Officer,
First Sonora Bancshares, Inc.
(2009) (B) (C)
J. Landis Martin
Chairman of Platte River Equity
(1998) (C) (D)
Jeffrey A. Miller
President and Chief Executive Officer,
Halliburton Company
(2014)
Debra L. Reed
Chairman and Chief Executive Officer,
Sempra Energy
(2001) (B) (D)
(A) Member of the Audit Committee
(B) Member of the Compensation Committee
(C) Member of the Health, Safety and
Environment Committee
(D) Member of the Nominating and
Corporate Governance Committee
Joe D. Rainey
President, Eastern Hemisphere
Anne L. Beaty
Senior Vice President, Finance
Myrtle L. Jones
Senior Vice President, Tax
Charles E. Geer, Jr.
Vice President and Corporate Controller
Timothy M. McKeon
Vice President and Treasurer
Jeffery S. Spalding
Vice President and
Chief Ethics & Compliance Officer
Bruce A. Metzinger
Vice President,
Public Law and Assistant Secretary
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2017
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 001-03492
HALLIBURTON COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
75-2677995
(I.R.S. Employer
Identification No.)
3000 North Sam Houston Parkway East
Houston, Texas 77032
(Address of principal executive offices)
Telephone Number – Area code (281) 871-2699
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock par value $2.50 per share
Name of each exchange on
which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
No
[X]
]
[
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes
No
[X]
]
[
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes
No
[X]
]
[
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files).
Yes
No
[X]
[
]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,”
and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
Smaller reporting company
[X]
]
[
]
[
Accelerated filer
(Do not check if a smaller reporting company)
Emerging growth company
[
[
]
]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [
] No [X]
The aggregate market value of Halliburton Company Common Stock held by nonaffiliates on June 30, 2017, determined using the per share
closing price on the New York Stock Exchange Composite tape of $42.71 on that date, was approximately $37.1 billion.
As of February 2, 2018, there were 874,909,834 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.
Portions of the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) are incorporated by
reference into Part III of this report.
HALLIBURTON COMPANY
Index to Form 10-K
For the Year Ended December 31, 2017
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
PART I
Item 1.
Item 1(a).
Item 1(b).
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Item 7(a).
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Item 9(a).
Item 9(b).
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
MD&A AND FINANCIAL STATEMENTS
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Shareholders’ Equity
Notes to Consolidated Financial Statements
Selected Financial Data (Unaudited)
Quarterly Data and Market Price Information (Unaudited)
PART III
Item 10.
Item 11.
Item 12(a).
Item 12(b).
Item 12(c).
Item 12(d).
Item 13.
Item 14.
PART IV
Item 15.
Item 16.
SIGNATURES
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners
Security Ownership of Management
Changes in Control
Securities Authorized for Issuance Under Equity Compensation Plans
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits
Form 10-K Summary
i
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PART I
Item 1. Business.
General description of business
Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware
in 1924. With approximately 55,000 employees, representing 140 nationalities in approximately 70 countries, we help our
customers maximize value throughout the lifecycle of the reservoir - from locating hydrocarbons and managing geological data,
to drilling and formation evaluation, well construction and completion and optimizing production throughout the life of the
asset. We serve major, national and independent oil and natural gas companies throughout the world and operate under two
divisions, which form the basis for the two operating segments we report, the Completion and Production segment and the
Drilling and Evaluation segment.
Completion and Production delivers cementing, stimulation, intervention, pressure control, specialty chemicals,
artificial lift and completion products and services. The segment consists of the following product service lines:
- Production Enhancement: includes stimulation services and sand control services. Stimulation services optimize oil
and natural gas reservoir production through a variety of pressure pumping services, nitrogen services and chemical
processes, commonly known as hydraulic fracturing and acidizing. Sand control services include fluid and chemical
systems and pumping services for the prevention of formation sand production.
- Cementing: involves bonding the well and well casing while isolating fluid zones and maximizing wellbore stability.
Our cementing product service line also provides casing equipment.
- Completion Tools: provides downhole solutions and services to our customers to complete their wells, including
well completion products and services, intelligent well completions, liner hanger systems, sand control systems and
service tools.
- Production Solutions: provides customized well intervention solutions to increase well performance, which includes
coiled tubing, hydraulic workover units and downhole tools.
- Pipeline & Process Services: provides a complete range of pre-commissioning, commissioning, maintenance and
decommissioning services to the onshore and offshore pipeline and process plant construction, commissioning and
maintenance industries.
- Multi-Chem: provides customized specialty oilfield production and completion chemicals and services to maximize
production, ensure integrity of well and pipeline assets and address production, processing and transportation
challenges.
- Artificial Lift: provides services to maximize reservoir and wellbore recovery by applying lifting technology,
intelligent field management solutions and related services throughout the life of the well, including electrical
submersible pumps and progressive cavity pumps.
Drilling and Evaluation provides field and reservoir modeling, drilling, evaluation and precise wellbore placement
solutions that enable customers to model, measure, drill and optimize their well construction activities. The segment consists of
the following product service lines:
- Baroid: provides drilling fluid systems, performance additives, completion fluids, solids control, specialized testing
equipment and waste management services for oil and natural gas drilling, completion and workover operations.
- Sperry Drilling: provides drilling systems and services that offer directional control for precise wellbore placement
while providing important measurements about the characteristics of the drill string and geological formations while
drilling wells. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-
drilling, surface data logging, multilateral systems, underbalanced applications and rig site information systems.
- Wireline and Perforating: provides open-hole logging services that supply information on formation evaluation and
reservoir fluid analysis, including formation lithology, rock properties and reservoir fluid properties. Also offered
are cased-hole and slickline services, including perforating, pipe recovery services, through-casing formation
evaluation and reservoir monitoring, casing and cement integrity measurements and well intervention services.
- Drill Bits and Services: provides roller cone rock bits, fixed cutter bits, hole enlargement and related downhole tools
and services used in drilling oil and natural gas wells. In addition, coring equipment and services are provided to
acquire cores of the formation drilled for evaluation.
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- Landmark Software and Services: supplies integrated exploration, drilling and production software and related
professional and data management services for the upstream oil and natural gas industry.
- Testing and Subsea: provides acquisition and analysis of dynamic reservoir information and reservoir optimization
solutions to the oil and natural gas industry through a broad portfolio of test tools, data acquisition services, fluid
sampling, surface well testing and subsea safety systems.
- Consulting and Project Management: provides integrated solutions to our customers by leveraging the full line of
our oilfield services, products and technologies to solve customer challenges throughout the oilfield lifecycle. It
includes project management, consulting, integrated asset management and well control and prevention services.
See Note 2 to the consolidated financial statements for further financial information related to each of our business
segments. We have manufacturing operations in various locations, the most significant of which are located in the United
States, Canada, Malaysia, Singapore and the United Kingdom.
Business strategy
Our value proposition is to collaborate and engineer solutions to maximize asset value for our customers. We strive to
achieve superior growth and returns for our shareholders by delivering technology and services that improve efficiency,
increase recovery and maximize production for our customers. Our objectives are to:
- create a balanced portfolio of services and products supported by global infrastructure and anchored by
technological innovation to further differentiate our company;
- reach a distinguished level of operational excellence that reduces costs and creates real value;
- preserve a dynamic workforce by being a preferred employer to attract, develop and retain the best global talent; and
- uphold our strong ethical and business standards, and maintain the highest standards of health, safety and
environmental performance.
For further discussion on our business strategies, see "Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Executive Overview."
Markets and competition
We are one of the world’s largest diversified energy services companies. Our services and products are sold in highly
competitive markets throughout the world. Competitive factors impacting sales of our services and products include: price;
service delivery; health, safety and environmental standards and practices; service quality; global talent retention;
understanding the geological characteristics of the hydrocarbon reservoir; product quality; warranty; and technical proficiency.
We conduct business worldwide in approximately 70 countries. The business operations of our divisions are organized
around four primary geographic regions: North America, Latin America, Europe/Africa/CIS and Middle East/Asia. In 2017,
2016 and 2015, based on the location of services provided and products sold, 53%, 41% and 44% of our consolidated revenue
was from the United States. No other country accounted for more than 10% of our consolidated revenue during these periods.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information
about our geographic operations. Because the markets for our services and products are vast and cross numerous geographic
lines, it is not practicable to provide a meaningful estimate of the total number of our competitors. The industries we serve are
highly competitive, and we have many substantial competitors. Most of our services and products are marketed through our
service and sales organizations.
Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil
unrest, war or other armed conflict, sanctions, expropriation or other governmental actions, inflation, changes in foreign
currency exchange rates, foreign currency exchange restrictions and highly inflationary currencies, and other geopolitical
factors. We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one
country, other than the United States, would be materially adverse to our business, consolidated results of operations or
consolidated financial condition.
Information regarding our exposure to foreign currency fluctuations, risk concentration and financial instruments used
to minimize risk is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Financial Instrument Market Risk” and in Note 12 to the consolidated financial statements.
Customers
Our revenue from continuing operations during the past three years was derived from the sale of services and products
to the energy industry. No customer represented more than 10% of our consolidated revenue in any period presented.
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Raw materials
Raw materials essential to our business are normally readily available. Market conditions can trigger constraints in the
supply of certain raw materials, such as proppants (primarily sand), hydrochloric acid and gels, including guar gum (a blending
additive used in hydraulic fracturing). We are always seeking ways to ensure the availability of resources, as well as manage
costs of raw materials. Our procurement department uses our size and buying power to enhance our access to key materials at
competitive prices.
Research and development costs
We maintain an active research and development program. The program improves products, processes and engineering
standards and practices that serve the changing needs of our customers, such as those related to high pressure and high
temperature environments, and also develops new products and processes. Our expenditures for research and development
activities were $360 million in 2017, $329 million in 2016 and $487 million in 2015.
Patents
We own a large number of patents and have pending a substantial number of patent applications covering various
products and processes. We are also licensed to utilize technology covered by patents owned by others, and we license others to
utilize technology covered by our patents. We do not consider any particular patent to be material to our business operations.
Seasonality
Weather and natural phenomena can temporarily affect the performance of our services, but the widespread
geographical locations of our operations mitigate those effects. Examples of how weather can impact our business include:
- the severity and duration of the winter in North America can have a significant impact on natural gas storage levels
and drilling activity;
- the timing and duration of the spring thaw in Canada directly affects activity levels due to road restrictions;
- typhoons and hurricanes can disrupt coastal and offshore operations; and
- severe weather during the winter normally results in reduced activity levels in the North Sea and Russia.
Additionally, customer spending patterns for software, completion tools and various other oilfield services and
products typically result in higher activity in the fourth quarter of the year.
Employees
At December 31, 2017, we employed approximately 55,000 people worldwide compared to approximately 50,000 at
December 31, 2016. At December 31, 2017, approximately 13% of our employees were subject to collective bargaining
agreements. Based upon the geographic diversification of these employees, we do not believe any risk of loss from employee
strikes or other collective actions would be material to the conduct of our operations taken as a whole.
Environmental regulation
We are subject to numerous environmental, legal and regulatory requirements related to our operations worldwide. For
further information related to environmental matters and regulation, see Note 7 to the consolidated financial statements and
Item 1(a), “Risk Factors.”
Hydraulic fracturing
Hydraulic fracturing is a process that creates fractures extending from the well bore into the rock formation to enable
natural gas or oil to move more easily from the rock pores to a production conduit. A significant portion of our Completion and
Production segment provides hydraulic fracturing services to customers developing shale natural gas and shale oil. From time
to time, questions arise about the scope of our operations in the shale natural gas and shale oil sectors, and the extent to which
these operations may affect human health and the environment.
At the direction of our customer, we design and generally implement a hydraulic fracturing operation to 'stimulate' the
well's production, once the well has been drilled, cased and cemented. Our customer is generally responsible for providing the
base fluid (usually water) used in the hydraulic fracturing of a well. We generally supply the proppant (primarily sand) and at
least a portion of the additives used in the overall fracturing fluid mixture. In addition, we mix the additives and proppant with
the base fluid and pump the mixture down the wellbore to create the desired fractures in the target formation. The customer is
responsible for disposing and/or recycling for further use any materials that are subsequently produced or pumped out of the
well, including flowback fluids and produced water.
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As part of the process of constructing the well, the customer will take a number of steps designed to protect drinking
water resources. In particular, the casing and cementing of the well are designed to provide 'zonal isolation' so that the fluids
pumped down the wellbore and the oil and natural gas and other materials that are subsequently pumped out of the well will not
come into contact with shallow aquifers or other shallow formations through which those materials could potentially migrate to
freshwater aquifers or the surface.
The potential environmental impacts of hydraulic fracturing have been studied by numerous government entities and
others. In 2004, the United States Environmental Protection Agency (EPA) conducted an extensive study of hydraulic fracturing
practices, focusing on coalbed methane wells, and their potential effect on underground sources of drinking water. The EPA’s
study concluded that hydraulic fracturing of coalbed methane wells poses little or no threat to underground sources of drinking
water. In December 2016, the EPA released a final report, “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic
Fracturing Water Cycle on Drinking Water Resources in the United States” representing the culmination of a six-year study
requested by Congress. While the EPA report noted a potential for some impact to drinking water sources caused by hydraulic
fracturing, the agency confirmed the overall incidence of impacts is low. Moreover, a number of the areas of potential impact
identified in the report involve activities for which we are not generally responsible, such as potential impacts associated with
withdrawals of surface water for use as a base fluid and management of wastewater.
We have made detailed information regarding our fracturing fluid composition and breakdown available on our
internet web site at www.halliburton.com. We also have proactively developed processes to provide our customers with the
chemical constituents of our hydraulic fracturing fluids to enable our customers to comply with state laws as well as voluntary
standards established by the Chemical Disclosure Registry, www.fracfocus.org.
We have also invested considerable resources in developing hydraulic fracturing technologies, in both the equipment
and chemistry portions of our business, which offer our customers a variety of environment-friendly alternatives related to the
use of hydraulic fracturing fluid additives and other aspects of our hydraulic fracturing operations. We created a hydraulic
fracturing fluid system comprised of materials sourced entirely from the food industry. In addition, we have engineered a
process that uses ultraviolet light to control the growth of bacteria in hydraulic fracturing fluids, allowing customers to
minimize the use of chemical biocides. We are committed to the continued development of innovative chemical and mechanical
technologies that allow for more economical and environmentally friendly development of the world’s oil and natural gas
reserves, and that reduce noise while complying with Tier 4 lower emission legislation.
In evaluating any environmental risks that may be associated with our hydraulic fracturing services, it is helpful to
understand the role that we play in the development of shale natural gas and shale oil. Our principal task generally is to manage
the process of injecting fracturing fluids into the borehole to 'stimulate' the well. Thus, based on the provisions in our contracts
and applicable law, the primary environmental risks we face are potential pre-injection spills or releases of stored fracturing
fluids and potential spills or releases of fuel or other fluids associated with pumps, blenders, conveyors, or other above-ground
equipment used in the hydraulic fracturing process.
Although possible concerns have been raised about hydraulic fracturing, the circumstances described above have
helped to mitigate those concerns. To date, we have not been obligated to compensate any indemnified party for any
environmental liability arising directly from hydraulic fracturing, although there can be no assurance that such obligations or
liabilities will not arise in the future. For further information on risks related to hydraulic fracturing, see Item 1(a), “Risk
Factors.”
Working capital
We fund our business operations through a combination of available cash and equivalents, short-term investments and
cash flow generated from operations. In addition, our revolving credit facility is available for additional working capital needs.
Web site access
Our annual reports 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 of 1934 are made available free of
charge on our internet web site (www.halliburton.com) as soon as reasonably practicable after we have electronically filed the
material with, or furnished it to, the Securities and Exchange Commission (SEC). The public may read and copy any materials
we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on
the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an
internet site (www.sec.gov) that contains our reports, proxy and information statements and our other SEC filings. We have
posted on our web site our Code of Business Conduct, which applies to all of our employees and Directors and serves as a code
of ethics for our principal executive officer, principal financial officer, principal accounting officer and other persons
performing similar functions. Any amendments to our Code of Business Conduct or any waivers from provisions of our Code
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of Business Conduct granted to the specified officers above are disclosed on our web site within four business days after the
date of any amendment or waiver pertaining to these officers. There have been no waivers from provisions of our Code of
Business Conduct for the years 2017, 2016, or 2015. Except to the extent expressly stated otherwise, information contained on
or accessible from our web site or any other web site is not incorporated by reference into this annual report on Form 10-K and
should not be considered part of this report.
Executive Officers of the Registrant
The following table indicates the names and ages of the executive officers of Halliburton Company as of February 9,
2018, including all offices and positions held by each in the past five years:
Name and Age
Offices Held and Term of Office
Anne L. Beaty
(Age 61)
Senior Vice President, Finance of Halliburton Company, since March 2017
Senior Vice President, Internal Assurance Services of Halliburton Company, November
2013 to March 2017
Vice President, Internal Audit and Controls of Halliburton Company, January 2007 to
November 2013
President, Western Hemisphere of Halliburton Company, since January 2008
Executive Vice President, Global Business Lines of Halliburton Company, since May 2016
Senior Vice President, Drilling and Evaluation Division of Halliburton Company, June 2011
to April 2016
James S. Brown
(Age 63)
Eric J. Carre
(Age 51)
Charles E. Geer, Jr.
(Age 47)
Vice President and Corporate Controller of Halliburton Company, since January 2015
Vice President, Finance of Halliburton Company, December 2013 to December 2014
Vice President and Chief Accounting Officer of Select Energy Services, April 2011 to
November 2013
Myrtle L. Jones
(Age 58)
David J. Lesar
(Age 64)
Senior Vice President, Tax of Halliburton Company, since March 2013
Senior Managing Director of Tax and Internal Audit, Service Corporation International,
February 2008 to February 2013
Executive Chairman of the Board of Directors of Halliburton Company, since August 2000
Chief Executive Officer of Halliburton Company, August 2014 to May 2017
President and Chief Executive Officer of Halliburton Company, August 2000 to July 2014
Timothy M. McKeon
(Age 45)
Jeffrey A. Miller
(Age 54)
Vice President and Treasurer of Halliburton Company, since January 2014
Assistant Treasurer of Halliburton Company, September 2011 to December 2013
President and Chief Executive Officer of Halliburton Company, since June 2017
President of Halliburton Company, August 2014 to May 2017
Member of the Board of Directors of Halliburton Company, since August 2014
Executive Vice President and Chief Operating Officer of Halliburton Company, September
2012 to July 2014
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Lawrence J. Pope
(Age 49)
Executive Vice President of Administration and Chief Human Resources Officer of
Halliburton Company, since January 2008
Joe D. Rainey
(Age 61)
Robb L. Voyles
(Age 60)
President, Eastern Hemisphere of Halliburton Company, since January 2011
Executive Vice President, Secretary and General Counsel of Halliburton Company, since
May 2015
Interim Chief Financial Officer of Halliburton Company, March 2017 to June 2017
Executive Vice President and General Counsel of Halliburton Company, January 2014 to
April 2015
Senior Vice President, Law of Halliburton Company, September 2013 to December 2013
Partner, Baker Botts L.L.P., January 1989 to August 2013
Christopher T. Weber
(Age 45)
Executive Vice President and Chief Financial Officer of Halliburton Company, since June
2017
Senior Vice President and Chief Financial Officer of Parker Drilling Company, May 2013 to
May 2017
Vice President and Treasurer of Ensco plc, from 2011 to May 2013
There are no family relationships between the executive officers of the registrant or between any director and any executive
officer of the registrant.
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Item 1(a). Risk Factors.
The statements in this section describe the known material risks to our business and should be considered carefully.
Trends in oil and natural gas prices affect the level of exploration, development and production activity of our
customers and the demand for our services and products, which could have a material adverse effect on our business,
consolidated results of operations and consolidated financial condition.
Demand for our services and products is particularly sensitive to the level of exploration, development and production
activity of, and the corresponding capital spending by, oil and natural gas companies. The level of exploration, development and
production activity is directly affected by trends in oil and natural gas prices, which historically have been volatile and are likely
to continue to be volatile.
Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of
and demand for oil and natural gas, market uncertainty and a variety of other economic factors that are beyond our control.
Crude oil prices have fluctuated significantly since 2014, with West Texas Intermediate (WTI) oil spot prices declining from a
high of $108 per barrel in June 2014 to a low of $26 per barrel in February 2016, and subsequently increasing to reach a high of
$60 per barrel in December 2017. For more information, see “Management’s Discussion and Analysis of Financial Condition and
Results of Operations - Business Environment and Results of Operations.”
The reduction in oil and natural gas prices in 2015 through 2016 depressed levels of exploration, development and
production activity and negatively impacted our operating results during those periods. Although commodity prices improved in
2017, average prices remained well below 2014 levels. Any prolonged reductions of commodity prices could once again have a
material adverse effect on our business, consolidated results of operations and consolidated financial condition, including
potential asset impairments and severance costs. Given the long-term nature of many large-scale development projects, even the
perception of longer-term lower oil and natural gas prices by oil and natural gas companies can similarly cause them to reduce or
defer major expenditures. We also have a small number of integrated projects that have remuneration tied to hydrocarbon
production. Reduction in oil and gas prices can affect the overall returns for these projects, either lengthening the time until the
expected returns are realized or by impairing the value of the asset.
Factors affecting the prices of oil and natural gas include:
- the level of supply and demand for oil and natural gas;
- governmental regulations, including the policies of governments regarding the exploration for and production and
development of their oil and natural gas reserves;
- weather conditions and natural disasters;
- worldwide political, military and economic conditions;
- the ability or willingness of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain oil
production levels;
- the level of oil production by non-OPEC countries;
- oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
- the cost of producing and delivering oil and natural gas; and
- increased demand for alternative fuels and electric vehicles, including government initiatives to promote the use of
renewable energy sources and public sentiment around alternatives to oil and gas.
Our business is dependent on capital spending by our customers, and reductions in capital spending could have a
material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Our business is directly affected by changes in capital expenditures by our customers, and reductions in their capital
spending could reduce demand for our services and products and have a material adverse effect on our business, consolidated
results of operations, and consolidated financial condition. Some of the items that may impact our customer's capital spending
include:
- oil and natural gas prices, including volatility of oil and natural gas prices and expectations regarding future prices;
- the inability of our customers to access capital on economically advantageous terms;
- the consolidation of our customers;
- customer personnel changes; and
- adverse developments in the business or operations of our customers, including write-downs of reserves and
borrowing base reductions under customer credit facilities.
Many of our customers reduced capital spending in 2015 and 2016 as a result of decreases in commodity prices. While
customer budgets generally increased in 2017 in response to improved market conditions, any significant reduction in
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commodity prices or a change in our customers’ expectations of future oil and natural gas prices, economic growth or the
demand for oil and natural gas may result in capital budget reductions in the future.
Our operations are subject to political and economic instability and risk of government actions that could have a
material adverse effect on our business, consolidated results of operations and consolidated financial condition.
We are exposed to risks inherent in doing business in each of the countries in which we operate. Our operations are
subject to various risks unique to each country that could have a material adverse effect on our business, consolidated results of
operations and consolidated financial condition. With respect to any particular country, these risks may include:
- political and economic instability, including:
• civil unrest, acts of terrorism, war and other armed conflict;
• inflation; and
• currency fluctuations, devaluations and conversion restrictions; and
- governmental actions that may:
• result in expropriation and nationalization of our assets in that country;
• result in confiscatory taxation or other adverse tax policies;
• limit or disrupt markets or our operations, restrict payments, or limit the movement of funds;
• impose sanctions on our ability to conduct business with certain customers or persons;
• result in the deprivation of contract rights; and
• result in the inability to obtain or retain licenses required for operation.
For example, due to the unsettled political conditions in many oil-producing countries, our operations, revenue and
profits are subject to the adverse consequences of war, terrorism, civil unrest, strikes, currency controls and governmental
actions. These and other risks described above could result in the loss of our personnel or assets, cause us to evacuate our
personnel from certain countries, cause us to increase spending on security worldwide, cause us to cease operating in certain
countries, disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate
greater political and economic instability in some of the geographic areas in which we operate. Areas where we operate that have
significant risk include, but are not limited to: the Middle East, North Africa, Angola, Azerbaijan, Colombia, Indonesia,
Kazakhstan, Mexico, Nigeria, Russia and Venezuela. In addition, any possible reprisals as a consequence of military or other
action, such as acts of terrorism in the United States or elsewhere, could have a material adverse effect on our business,
consolidated results of operations and consolidated financial condition.
Our operations are subject to cyber-attacks that could have a material adverse effect on our business, consolidated
results of operations and consolidated financial condition.
Our operations are increasingly dependent on digital technologies and services. We use these technologies for internal
purposes, including data storage, processing and transmissions, as well as in our interactions with customers and suppliers.
Digital technologies are subject to the risk of cyber-attacks. If our systems for protecting against cybersecurity risks prove not to
be sufficient, we could be adversely affected by, among other things: loss of or damage to intellectual property, proprietary or
confidential information, or customer, supplier, or employee data; interruption of our business operations; and increased costs
required to prevent, respond to, or mitigate cybersecurity attacks. These risks could harm our reputation and our relationships
with customers, suppliers, employees and other third parties, and may result in claims against us. These risks could have a
material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Our operations outside the United States require us to comply with a number of United States and international
regulations, violations of which could have a material adverse effect on our business, consolidated results of operations and
consolidated financial condition.
Our operations outside the United States require us to comply with a number of United States and international
regulations. For example, our operations in countries outside the United States are subject to the United States Foreign Corrupt
Practices Act (FCPA), which prohibits United States companies and their agents and employees from providing anything of
value to a foreign official for the purposes of influencing any act or decision of these individuals in their official capacity to help
obtain or retain business, direct business to any person or corporate entity, or obtain any unfair advantage. Our activities create
the risk of unauthorized payments or offers of payments by our employees, agents, or joint venture partners that could be in
violation of anti-corruption laws, even though some of these parties are not subject to our control. We have internal control
policies and procedures and have implemented training and compliance programs for our employees and agents with respect to
the FCPA. However, we cannot assure that our policies, procedures and programs always will protect us from reckless or
criminal acts committed by our employees or agents. We are also subject to the risks that our employees, joint venture partners
and agents outside of the United States may fail to comply with other applicable laws. Allegations of violations of applicable
anti-corruption laws have resulted and may in the future result in internal, independent, or government investigations. Violations
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of anti-corruption laws may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could
have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
In addition, the shipment of goods, services and technology across international borders subjects us to extensive trade
laws and regulations. Our import activities are governed by the unique customs laws and regulations in each of the countries
where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods,
services and technology and impose related export recordkeeping and reporting obligations. Governments may also impose
economic sanctions against certain countries, persons and entities that may restrict or prohibit transactions involving such
countries, persons and entities, which may limit or prevent our conduct of business in certain jurisdictions. During 2014, the
United States and European Union imposed sectoral sanctions directed at Russia’s oil and gas industry. Among other things,
these sanctions restrict the provision of U.S. and EU goods, services and technology in support of exploration or production for
deep water, Arctic offshore, or shale projects that have the potential to produce oil in Russia. These sanctions resulted in our
winding down and ending work on two projects in Russia in 2014, and have prevented us from pursuing certain other projects in
Russia. In 2017, the U.S. Government imposed additional sanctions against Russia’s oil and gas industry and certain Russian
companies. Our ability to engage in certain future projects in Russia or involving certain Russian customers is dependent upon
whether or not our involvement in such projects is restricted under U.S. or EU sanctions laws and the extent to which any of our
current or prospective operations in Russia or with certain Russian customers may be subject to those laws. Those laws may
change from time to time, and any expansion of sanctions against Russia’s oil and gas industry could further hinder our ability to
do business in Russia or with certain Russian customers, which could have a material adverse effect on our consolidated results
of operations.
During 2017, the U.S. Government imposed economic sanctions in Venezuela around certain financing transactions as
further discussed below.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic
sanctions are complex and constantly changing. These laws and regulations can cause delays in shipments and unscheduled
operational downtime. Moreover, any failure to comply with applicable legal and regulatory trading obligations could result in
criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from governmental contracts, seizure of
shipments and loss of import and export privileges. In addition, investigations by governmental authorities and legal, social,
economic and political issues in these countries could have a material adverse effect on our business, consolidated results of
operations and consolidated financial condition.
Our business in Venezuela subjects us to actions by the Venezuelan government, sanctions imposed or other actions
by the U.S. and foreign governments, the risk of delayed payments and currency risks, all of which could have a material
adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
There are risks associated with our operations in Venezuela, which continues to experience significant political and
economic turmoil. The political and economic conditions deteriorated in 2017, leading to uncertainty in the future business
climate, the state of security and governance of the country. This environment increases the risk of civil unrest, armed conflicts,
adverse actions by the government of Venezuela, including the possibility that the Venezuelan government could assume control
over our operations and assets, and imposition of additional sanctions or other actions by the U.S. and foreign governments that
may restrict our ability to continue operations or realize the value of our assets. In 2017, the U.S. Government announced
sanctions directed at certain Venezuelan individuals and imposed additional economic sanctions around certain financing
transactions in Venezuela. These sanctions prohibit dealings by our U.S. employees and entities in certain new debt issued by our
primary customer in Venezuela or the Venezuelan government as well as dealings in existing Venezuelan government bonds.
There can be no assurance that other sanctions affecting our business in Venezuela will not be imposed in the future that may
have a material adverse effect on our ability to operate in Venezuela.
We have continued to experience delays in collecting payments on our receivables from our primary customer in
Venezuela, including recent delays in scheduled payments on our existing promissory note. In November 2017, several credit
rating agencies downgraded this customer’s credit rating, some as low as a default level. As a result of this credit downgrade,
delayed payments on our promissory note and accounts receivable, and deteriorating market conditions in Venezuela, we
recognized an aggregate charge of $647 million during 2017, representing a fair market value adjustment on our promissory note
and a full reserve against our other accounts receivable with this customer.
On January 29, 2018, the Venezuelan government announced that it has changed the existing dual-rate foreign exchange
system by eliminating the DIPRO foreign exchange rate. All future currency transactions will now be carried out at the DICOM
floating rate. We are currently evaluating the impact that this change in foreign exchange system will have on our business,
consolidated results of operations and consolidated financial condition. This includes potential further write-downs of our net
investment in Venezuela, which was approximately $202 million as of December 31, 2017.
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The future results of our Venezuelan operations will be affected by many factors, including the foreign currency
exchange rate, actions of the Venezuelan government, general economic conditions such as continued inflation, existing or future
sanctions, future customer spending and the ability of our primary customer to pay its debts. For further information, see Note 3
to the consolidated financial statements and "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Business Environment and Results of Operations - International operations - Venezuela."
Changes in, compliance with, or our failure to comply with laws in the countries in which we conduct business may
negatively impact our ability to provide services in, make sales of equipment to and transfer personnel or equipment among
some of those countries and could have a material adverse effect on our business and consolidated results of operations.
In the countries in which we conduct business, we are subject to multiple and, at times, inconsistent regulatory regimes,
including those that govern our use of radioactive materials, explosives and chemicals in the course of our operations. Various
national and international regulatory regimes govern the shipment of these items. Many countries, but not all, impose special
controls upon the export and import of radioactive materials, explosives and chemicals. Our ability to do business is subject to
maintaining required licenses and complying with these multiple regulatory requirements applicable to these special products. In
addition, the various laws governing import and export of both products and technology apply to a wide range of services and
products we offer. In turn, this can affect our employment practices of hiring people of different nationalities because these laws
may prohibit or limit access to some products or technology by employees of various nationalities. Changes in, compliance with,
or our failure to comply with these laws may negatively impact our ability to provide services in, make sales of equipment to and
transfer personnel or equipment among some of the countries in which we operate and could have a material adverse effect on
our business and consolidated results of operations.
The adoption of any future federal, state, or local laws or implementing regulations imposing reporting obligations
on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells
and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial
condition.
Various federal and state legislative and regulatory initiatives have been or could be undertaken which could result in
additional requirements or restrictions being imposed on hydraulic fracturing operations. For example, the EPA released the final
results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water
resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under
some circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of the EPA’s study
could spur action towards federal or state legislation and regulation of hydraulic fracturing or similar production operations.
At the same time, legislation and/or regulations have been adopted in many states that require additional disclosure
regarding chemicals used in the hydraulic fracturing process but that generally include protections for proprietary information.
Legislation and/or regulations are being considered at the state and local level that could impose further chemical disclosure or
other regulatory requirements (such as restrictions on the use of certain types of chemicals or prohibitions on hydraulic fracturing
operations in certain areas) that could affect our operations. Three states (New York, Maryland and Vermont) have banned the
use of high volume hydraulic fracturing. Moreover, in light of concerns about seismic activity being triggered by the injection of
produced waters into underground wells and hydraulic fracturing, certain regulators are also considering additional requirements
related to seismic safety for hydraulic fracturing activities. Local jurisdictions in some states have adopted ordinances that
restrict or in certain cases prohibit the use of hydraulic fracturing. In addition, governmental authorities in various foreign
countries where we have provided or may provide hydraulic fracturing services have imposed or are considering imposing
various restrictions or conditions that may affect hydraulic fracturing operations.
The adoption of any future federal, state, local, or foreign laws or regulations imposing reporting obligations on, or
limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could
have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.
Liabilities arising out of catastrophic well incidents, such as the Deepwater Horizon blowout in April 2010, could
have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
Catastrophic events can occur at well sites where we conduct our operations, including blow outs resulting in
explosions, fires, personal injuries, property damage, pollution and regulatory responsibility. Generally, we rely on contractual
indemnities, releases and limitations on liability with our customers, and liability insurance coverage, to protect us from potential
liability related to such occurrences. However, we do not have these contractual provisions in all contracts, and even where we
do, it is possible that the respective customer or insurer could seek to avoid or be financially unable to meet its obligations or a
court may decline to enforce such provisions. Damages that are not indemnified or released could greatly exceed available
insurance coverage and could have a material adverse effect on our liquidity, consolidated results of operations and consolidated
financial condition.
10
Liability for cleanup costs, natural resource damages and other damages arising as a result of environmental laws
could be substantial and could have a material adverse effect on our liquidity, consolidated results of operations and
consolidated financial condition.
We are exposed to claims under environmental requirements and, from time to time, such claims have been made
against us. In the United States, environmental requirements and regulations typically impose strict liability. Strict liability means
that in some situations we could be exposed to liability for cleanup costs, natural resource damages and other damages as a result
of our conduct that was lawful at the time it occurred or the conduct of prior operators or other third parties. Liability for
damages arising as a result of environmental laws could be substantial and could have a material adverse effect on our liquidity,
consolidated results of operations and consolidated financial condition.
We are periodically notified of potential liabilities at federal and state superfund sites. These potential liabilities may
arise from both historical Halliburton operations and the historical operations of companies that we have acquired. Our exposure
at these sites may be materially impacted by unforeseen adverse developments both in the final remediation costs and with
respect to the final allocation among the various parties involved at the sites. The relevant regulatory agency may bring suit
against us for amounts in excess of what we have accrued and what we believe is our proportionate share of remediation costs at
any superfund site. We also could be subject to third-party claims, including punitive damages, with respect to environmental
matters for which we have been named as a potentially responsible party.
Failure on our part to comply with, and the costs of compliance with, applicable health, safety and environmental
requirements could have a material adverse effect on our liquidity, consolidated results of operations and consolidated
financial condition.
Our business is subject to a variety of health, safety and environmental laws, rules and regulations in the United States
and other countries, including those covering hazardous materials and requiring emission performance standards for facilities.
For example, our well service operations routinely involve the handling of significant amounts of waste materials, some of which
are classified as hazardous substances. We also store, transport and use radioactive and explosive materials in certain of our
operations. Applicable regulatory requirements include those concerning:
- the containment and disposal of hazardous substances, oilfield waste and other waste materials;
- the importation and use of radioactive materials;
- the use of underground storage tanks;
- the use of underground injection wells; and
- the protection of worker safety both onshore and offshore.
These and other requirements generally are becoming increasingly strict. The failure to comply with the requirements,
many of which may be applied retroactively, may result in:
- administrative, civil and criminal penalties;
- revocation of permits to conduct business; and
- corrective action orders, including orders to investigate and/or clean up contamination.
Failure on our part to comply with applicable environmental requirements or costs arising from regulatory compliance,
including compliance with changes in or expansion of applicable regulatory requirements, could have a material adverse effect
on our liquidity, consolidated results of operations and consolidated financial condition.
Existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate
change could have a negative impact on our business and may result in additional compliance obligations with respect to the
release, capture and use of carbon dioxide that could have a material adverse effect on our liquidity, consolidated results of
operations and consolidated financial condition.
Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand
for our services. For example, oil and natural gas exploration and production may decline as a result of environmental
requirements, including land use policies responsive to environmental concerns. State, national and international governments
and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of
greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and
natural gas industry, existing or future laws, regulations, treaties, or international agreements related to greenhouse gases and
climate change, including incentives to conserve energy or use alternative energy sources, may reduce demand for oil and natural
gas and could have a negative impact on our business. Likewise, such restrictions may result in additional compliance
obligations with respect to the release, capture, sequestration and use of carbon dioxide that could have a material adverse effect
on our liquidity, consolidated results of operations and consolidated financial condition.
11
Our business could be materially and adversely affected by severe or unseasonable weather where we have
operations.
Our business could be materially and adversely affected by severe weather, particularly in Canada, the Gulf of Mexico,
Russia and the North Sea. Some experts believe global climate change could increase the frequency and severity of extreme
weather conditions. Repercussions of severe or unseasonable weather conditions may include:
- evacuation of personnel and curtailment of services;
- weather-related damage to offshore drilling rigs resulting in suspension of operations;
- weather-related damage to our facilities and project work sites;
- inability to deliver materials to jobsites in accordance with contract schedules;
- decreases in demand for oil and natural gas during unseasonably warm winters; and
- loss of productivity.
Changes in or interpretation of tax law and currency/repatriation control could impact the determination of our
income tax liabilities for a tax year.
We have operations in approximately 70 countries. Consequently, we are subject to the jurisdiction of a significant
number of taxing authorities. The income earned in these various jurisdictions is taxed on differing bases, including net income
actually earned, net income deemed earned and revenue-based tax withholding. The final determination of our income tax
liabilities involves the interpretation of local tax laws, tax treaties and related authorities in each jurisdiction, as well as the
significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and
nature of income earned and expenditures incurred. Changes in the operating environment, including changes in or interpretation
of tax law and currency/repatriation controls, could impact the determination of our income tax liabilities for the year.
Additionally, we are currently evaluating provisions of United States tax reform enacted in December 2017, which
among other things, lowered the corporate income tax rate from 35% to 21% and moved the country towards a territorial tax
system with a one-time mandatory tax on previously deferred foreign earnings of foreign subsidiaries. In the fourth quarter of
2017, we recorded a total provision to income taxes of $770 million related to our preliminary assessment of the net effects of
tax reform. As we do not have all the necessary information to analyze all income tax effects of tax reform, this is a provisional
amount which we believe represents a reasonable estimate of the accounting implications of this tax reform. We will continue to
evaluate tax reform and adjust the provisional amounts as additional information is obtained. The ultimate impact of tax reform
may differ from our provisional amounts due to changes in our interpretations and assumptions, as well as additional regulatory
guidance that may be issued. We expect to complete our detailed analysis no later than the fourth quarter of 2018. For further
information, see Note 8 to the consolidated financial statements.
We are subject to foreign exchange risks and limitations on our ability to reinvest earnings from operations in one
country to fund the capital needs of our operations in other countries or to repatriate assets from some countries.
A sizable portion of our consolidated revenue and consolidated operating expenses is in foreign currencies. As a result,
we are subject to significant risks, including:
- foreign currency exchange risks resulting from changes in foreign currency exchange rates and the implementation of
exchange controls; and
- limitations on our ability to reinvest earnings from operations in one country to fund the capital needs of our
operations in other countries.
As an example, we conduct business in countries that have restricted or limited trading markets for their local currencies
and restrict or limit cash repatriation. We may accumulate cash in those geographies, but we may be limited in our ability to
convert our profits into United States dollars or to repatriate the profits from those countries. For further information, see
"Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results
of Operations" and Note 8 to the consolidated financial statements.
Our failure to protect our proprietary information and any successful intellectual property challenges or
infringement proceedings against us could materially and adversely affect our competitive position.
We rely on a variety of intellectual property rights that we use in our services and products. We may not be able to
successfully preserve these intellectual property rights in the future, and these rights could be invalidated, circumvented or
challenged. In addition, the laws of some foreign countries in which our services and products may be sold do not protect
intellectual property rights to the same extent as the laws of the United States. Our failure to protect our proprietary information
and any successful intellectual property challenges or infringement proceedings against us could materially and adversely affect
our competitive position.
12
If we are not able to design, develop and produce commercially competitive products and to implement commercially
competitive services in a timely manner in response to changes in the market, customer requirements, competitive pressures
and technology trends, our business and consolidated results of operations could be materially and adversely affected, and the
value of our intellectual property may be reduced.
The market for our services and products is characterized by continual technological developments to provide better and
more reliable performance and services. If we are not able to design, develop and produce commercially competitive products
and to implement commercially competitive services in a timely manner in response to changes in the market, customer
requirements, competitive pressures and technology trends, our business and consolidated results of operations could be
materially and adversely affected, and the value of our intellectual property may be reduced. Likewise, if our proprietary
technologies, equipment, facilities, or work processes become obsolete, we may no longer be competitive, and our business and
consolidated results of operations could be materially and adversely affected.
If we lose one or more of our significant customers or if our customers delay paying or fail to pay a significant
amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of
operations and consolidated financial condition.
We depend on a limited number of significant customers. While none of these customers represented more than 10% of
consolidated revenue in any period presented, the loss of one or more significant customers could have a material adverse effect
on our business and our consolidated results of operations.
In most cases, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or
failing to pay our invoices. In weak economic or commodity price environments, we may experience increased delays and
failures due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit
markets. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a
material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We sometimes provide integrated project management services in the form of long-term, fixed price contracts that
may require us to assume additional risks associated with cost over-runs, operating cost inflation, labor availability and
productivity, supplier and contractor pricing and performance, and potential claims for liquidated damages.
We sometimes provide integrated project management services outside our normal discrete business in the form of long-
term, fixed price contracts. Some of these contracts are required by our customers, primarily national oil companies (NOCs).
These services include acting as project managers as well as service providers and may require us to assume additional risks
associated with cost over-runs. These customers may provide us with inaccurate information in relation to their reserves, which
is a subjective process that involves location and volume estimation, that may result in cost over-runs, delays and project losses.
In addition, NOCs often operate in countries with unsettled political conditions, war, civil unrest, or other types of community
issues. These issues may also result in cost over-runs, delays and project losses.
Providing services on an integrated basis may also require us to assume additional risks associated with operating cost
inflation, labor availability and productivity, supplier pricing and performance, and potential claims for liquidated damages. We
rely on third-party subcontractors and equipment providers to assist us with the completion of these types of contracts. To the
extent that we cannot engage subcontractors or acquire equipment or materials in a timely manner and on reasonable terms, our
ability to complete a project in accordance with stated deadlines or at a profit may be impaired. If the amount we are required to
pay for these goods and services exceeds the amount we have estimated in bidding for fixed-price work, we could experience
losses in the performance of these contracts. These delays and additional costs may be substantial, and we may be required to
compensate our customers for these delays. This may reduce the profit to be realized or result in a loss on a project.
Constraints in the supply of, prices for and availability of transportation of raw materials can have a material
adverse effect on our business and consolidated results of operations.
Raw materials essential to our business, such as proppants (primarily sand), hydrochloric acid, and gels, including guar
gum, are normally readily available. Shortage of raw materials as a result of high levels of demand or loss of suppliers during
market challenges can trigger constraints in the supply chain of those raw materials, particularly where we have a relationship
with a single supplier for a particular resource. Many of the raw materials essential to our business require the use of rail, storage
and trucking services to transport the materials to our jobsites. These services, particularly during times of high demand, may
cause delays in the arrival of or otherwise constrain our supply of raw materials. These constraints could have a material adverse
effect on our business and consolidated results of operations. In addition, price increases imposed by our vendors for raw
materials used in our business and the inability to pass these increases through to our customers could have a material adverse
effect on our business and consolidated results of operations.
13
Our acquisitions, dispositions and investments may not result in anticipated benefits and may present risks not
originally contemplated, which may have a material adverse effect on our liquidity, consolidated results of operations and
consolidated financial condition.
We continually seek opportunities to maximize efficiency and value through various transactions, including purchases
or sales of assets, businesses, investments, or joint venture interests. These transactions are intended to (but may not) result in the
realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or income, or
the reduction of risk. Acquisition transactions may use cash on hand or be financed by additional borrowings or by the issuance
of our common stock. These transactions may also affect our liquidity, consolidated results of operations and consolidated
financial condition.
These transactions also involve risks, and we cannot ensure that:
- any acquisitions we attempt will be completed on the terms announced, or at all;
- any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated
benefits;
- any acquisitions would be successfully integrated into our operations and internal controls;
- the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal
exposure, including under the FCPA, or that we will appropriately quantify the exposure from known risks;
- any disposition would not result in decreased earnings, revenue, or cash flow;
- use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other uses; or
- any dispositions, investments, or acquisitions, including integration efforts, would not divert management resources.
Actions of and disputes with our joint venture partners could have a material adverse effect on the business and
results of operations of our joint ventures and, in turn, our business and consolidated results of operations.
We conduct some operations through joint ventures in which unaffiliated third parties may control the operations of the
joint venture or we may share control. As with any joint venture arrangement, differences in views among the joint venture
participants may result in delayed decisions, the joint venture operating in a manner that is contrary to our preference or in
failures to agree on major issues. We also cannot control the actions of our joint venture partners, including any nonperformance,
default, or bankruptcy of our joint venture partners. These factors could have a material adverse effect on the business and results
of operations of our joint ventures and, in turn, our business and consolidated results of operations.
Our ability to operate and our growth potential could be materially and adversely affected if we cannot attract,
employ and retain technical personnel at a competitive cost.
Many of the services that we provide and the products that we sell are complex and highly engineered and often must
perform or be performed in harsh conditions. We believe that our success depends upon our ability to attract, employ and retain
technical personnel with the ability to design, utilize and enhance these services and products. A significant increase in the wages
paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay,
or both. If either of these events were to occur, our cost structure could increase, our margins could decrease and any growth
potential could be impaired.
The loss or unavailability of any of our executive officers or other key employees could have a material adverse
effect on our business.
We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss
or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
14
Item 1(b). Unresolved Staff Comments.
None.
Item 2. Properties.
We own or lease numerous properties in domestic and foreign locations. Our principal properties include
manufacturing facilities, research and development laboratories, technology centers and corporate offices. We also have
numerous small facilities that include sales, project and support offices and bulk storage facilities throughout the world. All of
our owned properties are unencumbered. We believe all properties that we currently occupy are suitable for their intended use.
The following locations represent our major facilities by segment:
– Completion and Production: Arbroath, United Kingdom; Johor Bahru, Malaysia; and Lafayette, Louisiana
– Drilling and Evaluation: Alvarado, Texas; Nisku, Canada; and The Woodlands, Texas
– Shared/corporate facilities: Carrollton, Texas; Denver, Colorado; Dhahran, Saudi Arabia; Dubai, United Arab
Emirates (corporate executive offices); Duncan, Oklahoma; Houston, Texas (corporate executive offices); Kuala
Lumpur, Malaysia; London, England; Moscow, Russia; Panama City, Panama; Pune, India; Rio de Janeiro, Brazil;
Singapore; and Tananger, Norway
Item 3. Legal Proceedings.
Information related to Item 3. Legal Proceedings is included in Note 7 to the consolidated financial statements.
Item 4. Mine Safety Disclosures.
Our barite and bentonite mining operations, in support of our fluid services business, are subject to regulation by the
federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning
mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and
Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this annual report.
15
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities.
Halliburton Company’s common stock is traded on the New York Stock Exchange. Information related to the high and
low market prices of our common stock and quarterly dividend payments is included under the caption “Quarterly Data and
Market Price Information” on page 68 of this annual report. Quarterly cash dividends on our common stock, which were paid in
March, June, September and December of each year, were $0.18 per share for all four quarters of 2016 and 2017. The
declaration and payment of future dividends will be at the discretion of the Board of Directors and will depend on, among other
things, future earnings, general financial condition and liquidity, success in business activities, capital requirements and general
business conditions. Subject to Board of Directors approval, our intention is to continue paying dividends at our current rate
during 2018.
The following graph and table compare total shareholder return on our common stock for the five-year period ended
December 31, 2017, with the Philadelphia Oil Service Index (OSX) and the Standard & Poor’s 500 ® Index over the same
period. This comparison assumes the investment of $100 on December 31, 2012 and the reinvestment of all dividends. The
shareholder return set forth is not necessarily indicative of future performance.
2012
2013
2014
2015
2016
2017
December 31
Halliburton
Philadelphia Oil Service Index (OSX)
Standard & Poor’s 500 ® Index
$
100.00 $
100.00
100.00
148.00 $
121.15
156.82
116.03 $
95.32
178.28
102.26 $
71.30
180.75
165.22 $
83.08
202.37
151.61
67.60
246.55
16
At February 2, 2018, we had 12,374 shareholders of record. In calculating the number of shareholders, we consider
clearing agencies and security position listings as one shareholder for each agency or listing.
The following table is a summary of repurchases of our common stock during the three-month period ended
December 31, 2017.
Period
October 1 - 31
November 1 - 30
December 1 - 31
Total
Total Number
of Shares
Purchased (a)
Average
Price Paid
per Share
25,254
17,384
193,421
236,059
$43.06
$42.88
$43.98
$43.80
Total Number
of Shares
Purchased as
Part of Publicly
Announced Plans
or Programs (b)
—
—
—
—
Maximum
Number (or
Approximate
Dollar Value) of
Shares that may yet
be Purchased Under
the Program (b)
$5,700,004,373
$5,700,004,373
$5,700,004,373
(a) All of the 236,059 shares purchased during the three-month period ended December 31, 2017 were acquired from
employees in connection with the settlement of income tax and related benefit withholding obligations arising from
vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common
stock.
(b) Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the fourth
quarter of 2017, we did not repurchase shares of our common stock pursuant to that plan. We have authorization
remaining to repurchase up to a total of approximately $5.7 billion of our common stock.
Item 6. Selected Financial Data.
Information related to selected financial data is included on page 67 of this annual report.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Information related to Management’s Discussion and Analysis of Financial Condition and Results of Operations is
included on pages 19 through 36 of this annual report.
Item 7(a). Quantitative and Qualitative Disclosures About Market Risk.
Information related to market risk is included in “Management’s Discussion and Analysis of Financial Condition and
Results of Operations – Financial Instrument Market Risk” and Note 12 to the consolidated financial statements.
17
Item 8. Financial Statements and Supplementary Data.
Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015
Consolidated Balance Sheets at December 31, 2017 and 2016
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2017, 2016 and 2015
Notes to Consolidated Financial Statements
Selected Financial Data (Unaudited)
Quarterly Data and Market Price Information (Unaudited)
Page No.
37
38
41
42
43
44
45
46
67
68
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9(a). Controls and Procedures.
In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under
the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of
the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that
evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were
effective as of December 31, 2017 to provide reasonable assurance that information required to be disclosed in our reports filed
or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and
procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is
accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as
appropriate, to allow timely decisions regarding required disclosure.
There has been no change in our internal control over financial reporting that occurred during the three months ended
December 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial
reporting.
See page 37 for Management’s Report on Internal Control Over Financial Reporting and page 39 for Report of
Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
Item 9(b). Other Information.
None.
18
HALLIBURTON COMPANY
Management’s Discussion and Analysis of Financial Condition and Results of Operations
EXECUTIVE OVERVIEW
Financial results
Our business continued to strengthen during 2017, which was a dynamic year for the oil and gas sector that marked
another step on the road to recovery for our industry. We successfully executed our strategy by growing our global market
share, moving quickly to reactivate equipment and build new equipment in North America to meet customer demand,
continuing to focus on cost efficiencies, and aligning our business with customers in the fastest growing market segments to
collaborate and engineer solutions to maximize their asset value. In the beginning of 2017, we made the decision to bring back
cold-stacked pressure pumping equipment more rapidly than originally planned because of customer demand and to maintain
market share while capturing leading edge pricing. We have successfully executed this plan with the reactivated and new-build
equipment enhancing our overall margins during 2017.
Our North American business continued to improve during 2017, with revenue growth of 71% outperforming the
growth in average North American rig count of 69%, compared to 2016. We also experienced a significant margin improvement
in 2017 and profitability growth in six consecutive quarters as a result of activity and pricing increases. We are diligently
working towards optimizing margins and reaching targets we have set for our organization, which we believe are achievable
through higher pricing, improved equipment utilization and technology solutions. While the international markets have been
slower to recover and continue to face pricing pressure as customers defer new projects and focus on lowering costs, these
regions showed signs of recovery in the latter half of 2017, driven primarily by improved performance in the Middle East, the
North Sea and Latin America. We are committed to making these markets sustainable and have focused on the use of
technology and lowering customer costs during the down cycle. Our product service lines continue to deliver technology driven
value propositions to help our customers increase production and lower costs.
We generated total company revenue of $20.6 billion during 2017, a 30% increase from the $15.9 billion of revenue
generated in 2016, with our Completion and Production segment improving 47% and our Drilling and Evaluation segment
improving 8%. We also reported total company operating income of approximately $1.4 billion in 2017. These results were
primarily driven by improved activity, utilization and pricing in the United States land market associated with stimulation, well
completion and drilling services. Our operating results also benefited from the structural global cost savings initiatives
implemented over the past few years to address challenging market conditions.
Business outlook
While the past few years have been challenging as we navigated through this industry cycle, we believe our financial
results in 2017 reflect our successful execution in a dynamic environment and that our strategy has positioned us to take
advantage of opportunities ahead. We are benefiting from our improved market share, delivery platform and cost containment
strategies, and we are optimistic about the prospects for 2018.
In North America, improved commodity prices and rig counts from 2016 lows have resulted in a rapidly recovering
market throughout 2017, particularly in United States unconventionals. At the current North American rig count, we are drilling
approximately the same footage as the peak of 2014, but with less equipment in the field as we experience significantly
increased completions intensity. As rig count stabilizes, our customers focus on efficiencies, optimization and production. We
are continuing to collaborate and engineer solutions to maximize asset value for our customers and will continue to focus on
increasing equipment utilization, managing costs and expanding our surface efficiency model.
Additionally, we gained significant North America market share through the downturn by demonstrating to our
customers the benefits of our service quality and technology. We have been utilizing this increased market share to drive margin
improvement. The historically high level of market share we built in the downturn gives us the ability to focus our work with
the most efficient customers, and we continued to execute our strategy of high grading the profitability of our portfolio with
customers that value our services.
While the international markets had been more resilient than North America through most of the downturn, we
experienced activity reductions and pricing pressure in these markets in 2017 when compared to 2016, particularly in the
Eastern Hemisphere. This was driven by stressed customer budgets and economics across deepwater and mature fields.
However, the international sector began to show signs of recovery in the latter half of 2017. Heading into 2018, we are
encouraged by these markets, with enhanced tender activity and constructive conversations with our international customers.
While we expect international activity to gradually improve throughout 2018, we are cognizant that pricing pressure and
19
concessions that have been given throughout the cycle need to be unwound. We will continue to collaborate with our customers
to create solutions through technology and improved operating efficiency that will overcome challenging project economics.
During 2017, we had approximately $1.4 billion of capital expenditures, an increase of 72% from 2016, which was
predominantly made in our Production Enhancement, Sperry Drilling, Production Solutions, Wireline and Perforating, and
Baroid product service lines. We successfully executed our deployment strategy to reactivate our cold-stacked pressure
pumping equipment to respond to customer demand and converting our hydraulic fracturing fleet to Q10 pumps to support our
surface efficiency model. We remain committed to generating industry-leading returns and continue to be focused on achieving
leading edge pricing, driving better utilization and continuous cost control.
During 2017, we acquired Summit ESP, Ingrain Inc. and Optimization Petroleum Technology. The additions of these
three businesses strengthen our Artificial Lift, Wireline and Perforating, and Landmark portfolios for our customers.
We intend to continue to strengthen our product service lines through a combination of organic growth, investment and
selective acquisitions. We plan to continue executing the following strategies in 2018:
- directing capital and resources into strategic growth markets, including unconventional plays and mature fields;
- leveraging our broad technology offerings to provide value to our customers and enable them to more efficiently
drill and complete their wells;
- exploring additional opportunities for acquisitions that will enhance or augment our current portfolio of services and
products, including those with unique technologies or distribution networks in areas where we do not already have
significant operations;
- investing in technology that will help our customers reduce reservoir uncertainty and increase operational efficiency;
- improving working capital and managing our balance sheet to maximize our financial flexibility;
- continuing to seek ways to be one of the most cost-efficient service providers in the industry by maintaining capital
discipline and leveraging our scale and breadth of operations;
- collaborating and engineering solutions to maximize asset value for our customers; and
- striving to achieve superior growth and returns for our shareholders.
Our operating performance and business outlook are described in more detail in “Business Environment and Results of
Operations.”
Financial markets, liquidity and capital resources
We believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any
near-term negative impact on our operations from adverse market conditions. We had $2.3 billion of cash and equivalents as of
December 31, 2017. We also have $3.0 billion available under our revolving credit facility which, combined with our cash
balance, we believe provides us with sufficient liquidity to address the challenges and opportunities of the current market.
Given our optimism about the business outlook and projected impact of U.S. tax reform, we are actively evaluating our options
and opportunities around uses of cash, which could include debt retirements, funding acquisitions and organic growth projects
and return of capital to shareholders. For additional information on market conditions, see “Liquidity and Capital Resources”
and “Business Environment and Results of Operations.”
20
LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2017, we had $2.3 billion of cash and equivalents, compared to $4.0 billion at December 31,
2016. Additionally, we held $106 million of investments in fixed income securities at December 31, 2017, compared to $92
million at December 31, 2016. These securities are reflected in "Other current assets" and "Other assets" in our consolidated
balance sheets. Approximately $1.9 billion of our total cash position as of December 31, 2017 was held by our foreign
subsidiaries, a substantial portion of which is available to be repatriated into the United States to fund our U.S. operations or for
general corporate purposes, with a portion subject to certain country-specific restrictions. See Note 8 for further discussion
regarding U.S. tax reform and its corresponding impact on foreign cash repatriation.
Significant sources and uses of cash
Sources of cash:
– Cash flows from operating activities were $2.5 billion in 2017. This includes a United States tax refund of
approximately $478 million that we received in the third quarter of 2017, primarily related to the carryback of our
net operating losses recognized in 2016.
Uses of cash:
– We paid an aggregate $1.6 billion on long-term borrowings in 2017. This includes an early redemption of $1.4
billion of senior notes during the first quarter of 2017, which resulted in a payment of approximately $1.5 billion,
inclusive of the redemption premium. We also repaid $45 million of notes that matured during the second quarter of
2017. See Note 6 for further information.
– Capital expenditures were $1.4 billion in 2017 and were predominantly made in our Production Enhancement,
Sperry Drilling, Production Solutions, Wireline and Perforating and Baroid product service lines.
– We paid approximately $630 million in the third quarter of 2017 to acquire Summit ESP, Ingrain Inc. and
Optimization Petroleum Technology. The additions of these three businesses strengthen our artificial lift, wireline
and Landmark portfolios for our global customers.
– We paid $626 million of dividends to our shareholders in 2017.
– Our primary components of net working capital (receivables, inventories and accounts payable) increased during the
year by a net $626 million, primarily due to increased business activity.
– We made the final installment settlement payment of $335 million related to the Macondo well incident, as well as
our third and final legal fees payment of $33 million.
Future sources and uses of cash
We manufacture most of our own equipment, which allows us flexibility to increase or decrease our capital
expenditures based on market conditions. Capital spending for 2018 is currently expected to be approximately $1.7 billion, an
increase of over 25% from 2017. We expect capital spending to be in-line with our expected depreciation and amortization
expense. The capital expenditures plan for 2018 is primarily directed towards our industry-leading pressure pumping fleet, the
deployment of new Sperry drilling tools and the continued investment in our Artificial Lift and Multi-Chem product service
lines.
Currently, our quarterly dividend rate is $0.18 per share, or approximately $156 million per quarter. Subject to Board
of Directors approval, our intention is to continue paying dividends at our current rate during 2018. We also have $400 million
senior notes that mature in August 2018, which we intend to repay with cash on hand.
Our Board of Directors has authorized a program to repurchase our common stock from time to time. Approximately
$5.7 billion remains authorized for repurchases as of December 31, 2017, and may be used for open market and other share
purchases. There were no repurchases made under the program during the year ended December 31, 2017.
We had $333 million of gross unrecognized tax benefits at December 31, 2017, of which we estimate $319 million
may require a cash payment by us. We estimate that $296 million of the cash payment will not be settled within the next 12
months. We are not able to reasonably estimate in which future periods this amount will ultimately be settled and paid.
Additionally, given our current U.S. tax attributes, we currently do not expect to pay any cash tax on our deemed repatriation
tax obligations as a result of the recently enacted U.S. tax reform.
Given our optimism about the business outlook and projected impact of U.S. tax reform, we are actively evaluating
our options and opportunities around uses of cash, which could include debt retirements, funding acquisitions and organic
growth projects and return of capital to shareholders.
21
Contractual obligations
The following table summarizes our significant contractual obligations and other long-term liabilities as of
December 31, 2017:
Millions of dollars
Long-term debt (a)
Interest on debt (b)
Operating leases
Purchase obligations (c)
Other long-term liabilities (d)
Total
Payments Due
2018
2019
2020
2021
2022
Thereafter
Total
$
440 $
30 $
26 $
709 $
14 $
9,749 $
10,968
564
166
485
32
553
135
76
—
551
100
71
—
540
513
71
26
—
54
19
—
8,438
194
38
—
11,159
720
715
32
$ 1,687 $
794 $
748 $ 1,346 $
600 $
18,419 $
23,594
(a) Represents principal amounts of long-term debt, including capital lease obligations and current maturities of debt,
which excludes any unamortized debt issuance costs and discounts. See Note 6 to the consolidated financial
statements.
(b) Interest on debt includes 79 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.
(c) Amount in 2018 primarily represents certain purchase orders for goods and services utilized in the ordinary course of
our business.
(d) Represents pension funding obligations associated with international plans for 2018 only as we are currently not able
to reasonably estimate our contributions for years after 2018.
Other factors affecting liquidity
Financial position in current market. As of December 31, 2017, we had $2.3 billion of cash and equivalents, $106
million in fixed income investments and $3.0 billion of available committed bank credit under our revolving credit facility.
Furthermore, we have no financial covenants or material adverse change provisions in our bank agreements, and our debt
maturities extend over a long period of time. We believe our cash on hand, cash flows generated from operations and our
available credit facility will provide sufficient liquidity to address our global cash needs in 2018, including debt retirement,
capital expenditures, working capital investments, dividends, if any, and contingent liabilities.
Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which
approximately $1.8 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2017.
Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.
Credit ratings. Our credit ratings with Standard & Poor’s (S&P) remain BBB+ for our long-term debt and A-2 for our
short-term debt, with a stable outlook. Our credit ratings with Moody’s Investors Service (Moody's) remain Baa1 for our long-
term debt and P-2 for our short-term debt, with a stable outlook.
Customer receivables. In line with industry practice, we bill our customers for our services in arrears and are,
therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience
increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers’ cash flow from
operations and their access to the credit markets as well as unsettled political conditions. If our customers delay paying or fail
to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity,
consolidated results of operations and consolidated financial condition. See Part I, Item 1(a), “Risk Factors,” “Business
Environment and Results of Operations,” and Note 3 to the consolidated financial statements for further discussion related to
receivables from our primary customer in Venezuela.
22
BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS
We operate in approximately 70 countries throughout the world to provide a comprehensive range of services and
products to the energy industry. A significant amount of our consolidated revenue is derived from the sale of services and
products to major, national and independent oil and natural gas companies worldwide. The industry we serve is highly
competitive with many competitors in each segment of our business. In 2017, 2016 and 2015, based on the location of services
provided and products sold, 53%, 41% and 44%, respectively, of our consolidated revenue was from the United States. No
other country accounted for more than 10% of our revenue during these periods.
Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil
unrest, force majeure, war or other armed conflict, sanctions, expropriation or other governmental actions, inflation, changes in
foreign currency exchange rates, foreign currency exchange restrictions and highly inflationary currencies, as well as other
geopolitical factors. We believe the geographic diversification of our business activities reduces the risk that loss of operations
in any one country, other than the United States, would be materially adverse to our consolidated results of operations.
Activity within our business segments is significantly impacted by spending on upstream exploration, development
and production programs by our customers. Also impacting our activity is the status of the global economy, which impacts oil
and natural gas consumption.
Some of the more significant determinants of current and future spending levels of our customers are oil and natural
gas prices, global oil supply, completions intensity, the world economy, the availability of credit, government regulation and
global stability, which together drive worldwide drilling and completions activity. Lower oil and natural gas prices usually
translate into lower exploration and production budgets and lower rig count. Our financial performance is therefore
significantly affected by oil and natural gas prices and worldwide rig activity, which are summarized in the tables below.
The following table shows the average oil and natural gas prices for West Texas Intermediate (WTI), United Kingdom
Brent crude oil and Henry Hub natural gas:
Oil price - WTI (1)
Oil price - Brent (1)
Natural gas price - Henry Hub (2)
2017
2016
2015
$
50.93 $
43.14 $
54.30
3.04
43.55
2.52
48.69
52.36
2.63
(1) Oil price measured in dollars per barrel
(2) Natural gas price measured in dollars per million British thermal units (Btu), or MMBtu
23
The historical average rig counts based on the weekly Baker Hughes rig count information were as follows:
Land vs. Offshore
United States:
Land
Offshore (incl. Gulf of Mexico)
Total
Canada:
Land
Offshore
Total
International (excluding Canada):
Land
Offshore
Total
Worldwide total
Land total
Offshore total
2017
2016
2015
856
20
876
205
1
206
751
198
949
2,031
1,812
219
486
23
509
128
2
130
734
221
955
1,594
1,348
246
943
35
978
189
2
191
884
283
1,167
2,336
2,016
320
Oil vs. Natural Gas
United States (incl. Gulf of Mexico):
2017
2016
2015
Oil
Natural gas
Total
Canada:
Oil
Natural gas
Total
International (excluding Canada):
Oil
Natural gas
Total
Worldwide total
Oil total
Natural gas total
Drilling Type
United States (incl. Gulf of Mexico):
Horizontal
Vertical
Directional
Total
704
172
876
109
97
206
732
217
949
2,031
1,545
486
409
100
509
63
67
130
726
229
955
1,594
1,198
396
751
227
978
84
107
191
916
251
1,167
2,336
1,751
585
2017
2016
2015
736
70
70
876
400
60
49
509
744
139
95
978
Crude oil prices have been extremely volatile during the past few years. WTI oil spot prices declined significantly
beginning in 2014 from a peak price of $108 per barrel in June 2014 to a low of $26 per barrel in February 2016, a level which
had not been experienced since 2003. Brent crude oil spot prices declined from a high of $115 per barrel in June 2014 to $26
per barrel in January 2016. Since the low point experienced in early 2016, oil prices have increased substantially. WTI oil spot
prices ranged from a low of $42 per barrel in June 2017 to a high of $60 per barrel in December 2017. Brent crude oil spot
prices ranged from a low of $44 in June 2017 to a high of $67 in December 2017. The average full year 2017 WTI and Brent
crude oil spot prices of $51 per barrel and $54 per barrel increased 17% and 24% from 2016.
24
WTI and Brent crude oil spot prices had a monthly average in December 2017 of $58 per barrel and $64 per barrel,
respectively. Prices have increased steadily through the second half of the year, with year-end prices higher than the annual
average. Most of the price movement reflects continuing draws on global oil inventory levels, geopolitical tensions, and the
announcement from the Organization of the Petroleum Exporting Countries (OPEC) of an extension through the end of 2018 of
its crude oil supply reduction agreement. Crude oil production in the United States is projected to average 10.3 million barrels
per day in 2018, which will mark the highest annual average production in U.S. history.
In the United States Energy Information Administration (EIA) January 2018 "Short Term Energy Outlook," the EIA
projects Brent prices to average $60 per barrel in 2018 and $61 per barrel in 2019, while WTI prices are projected to average
about $4 less per barrel in both 2018 and 2019. The International Energy Agency's (IEA) January 2018 "Oil Market Report"
forecasts the 2018 global demand to average approximately 99.1 million barrels per day, an increase of 1% from 2017, driven
by increases in the Asia Pacific region, while all other regions remain approximately the same.
The Henry Hub natural gas spot price in the United States averaged $2.99 per MMBtu in 2017, an increase of $0.47
per MMBtu, or 19%, from 2016. The EIA January 2018 “Short Term Energy Outlook” projects Henry Hub natural gas prices to
average $2.88 per MMBtu in 2018 and $2.92 per MMBtu in 2019, a slight decline over 2017 levels primarily due to strong
expected production growth, which is forecast to meet growing domestic consumption and exports.
North America operations
The average North America oil-directed rig count increased 341 rigs, or 72%, for the full year 2017 as compared to
2016, while the average North America natural gas-directed rig count increased 102 rigs, or 61%, during the same period. In
the United States land market during 2017, there was a 76% improvement in the average rig count compared to 2016 and
completions activity continued to strengthen in this market for drilled but uncompleted wells. As a result of the recent uptick in
activity and the structural changes to our delivery platform we made over the past few years, after recording operating losses in
North America in 2016, we returned to operating profitability with continued improvements throughout 2017. Rig count has
stabilized during the second half of 2017, with customers searching for improved production with an increased focus on
efficiency and optimization of wells.
In the Gulf of Mexico, the average offshore rig count for 2017 was down 13% compared to 2016. Low commodity
prices have stressed budgets and have impacted economics across the deepwater market, negatively impacting activity and
pricing. These headwinds persist today, and we believe there will continue to be challenges in 2018 to deepwater project
economics. Activity in the Gulf of Mexico is dependent on governmental approvals for permits, our customers' actions and the
entry and exit of deepwater rigs in the market.
International operations
While the average international rig count for 2017 decreased by 1% compared to 2016, the international markets began
to show signs of improvement in the second half of the year. This improvement was driven primarily by the Middle East, North
Sea and Latin America. Lower sustained crude oil prices have caused many of our customers to reduce their budgets and defer
several new projects; however, we have continued to work with our customers to improve project economics through
technology and improved operating efficiency. For the Eastern Hemisphere, we believe the first quarter of 2017 represented the
bottom of the international rig count. The Middle East remains our most active international market, with the largest part of the
work focused on maximizing production in mature fields with the use of technology and expanded reservoir knowledge. While
we expect the international markets will continue to gradually improve throughout 2018, there are still headwinds that must be
overcome to obtain a full recovery. This includes an over capitalized market, pricing pressure and price concessions that we
have taken throughout the down cycle which we need to recapture. We will continue to remain focused on efficiencies in our
execution.
Venezuela. Venezuela continues to experience significant political and economic turmoil. At December 31, 2017, the
Venezuelan government had a dual-rate foreign exchange system: (i) the DIPRO, which represented a protected rate of 10.0
Bolívares per United States dollar made available for vital imports such as food, medicine and raw materials for production;
and (ii) the DICOM, which is intended to be a free floating system that will fluctuate according to market supply and demand.
The DICOM foreign exchange rate continues to significantly devalue and had a market rate of 3,345 Bolívares per United
States dollar at December 31, 2017, as compared to a market rate of 276 Bolívares per United States dollar in early 2016 when
the DICOM was created. On January 29, 2018, the Venezuelan government announced that it has eliminated the DIPRO foreign
exchange rate and all future currency transactions will be carried out at the DICOM rate. We are currently evaluating the impact
that this change in foreign exchange system will have on our business, consolidated results of operations and consolidated
financial condition. This includes potential further write-downs of our net investment in Venezuela, which was approximately
$202 million as of December 31, 2017.
25
We have continued to experience delays in collecting payments on our receivables from our primary customer in
Venezuela. In November 2017, several credit rating agencies downgraded this customer’s credit rating, some as low as a default
level. As a result of this credit downgrade, delayed payments on our promissory note and accounts receivable, and deteriorating
market conditions in Venezuela, we recognized an aggregate charge of $647 million during 2017, representing a fair market
value adjustment on our promissory note and a full reserve against our other accounts receivable with this customer. See Note 3
and Note 12 to the consolidated financial statements for additional information about outstanding receivables from our primary
customer in Venezuela and Part I, Item 1(a), “Risk Factors” for additional information on risks associated with our operations in
Venezuela, including recent sanctions imposed in Venezuela.
26
RESULTS OF OPERATIONS IN 2017 COMPARED TO 2016
REVENUE:
Millions of dollars
Completion and Production
Drilling and Evaluation
Total revenue
By geographic region:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
OPERATING INCOME:
Millions of dollars
Completion and Production
Drilling and Evaluation
Total
Corporate and other
Impairments and other charges
Total operating income (loss)
$
$
$
$
$
2017
2016
(Unfavorable)
Change
Favorable
Percentage
13,077 $
7,543
8,882 $
7,005
20,620 $
15,887 $
11,564 $
6,770 $
2,116
2,781
4,159
1,860
2,993
4,264
20,620 $
15,887 $
4,195
538
4,733
4,794
256
(212)
(105)
4,733
47%
8
30%
71%
14
(7)
(2)
30%
2017
2016
(Unfavorable)
Change
Favorable
Percentage
1,621 $
718
2,339
(330)
(647)
107 $
794
901
(4,322)
(3,357)
$
1,362 $
(6,778)$
1,514
(76)
1,438
3,992
2,710
8,140
1,415%
(10)
160
92
81
—
Consolidated revenue in 2017 increased 30% compared to 2016, associated with improved utilization, pricing and
activity, primarily attributable to higher stimulation activity, and well completion and drilling services in North America.
Revenue from North America was 56% of consolidated revenue in 2017 and 43% of consolidated revenue in 2016.
We reported consolidated operating income of $1.4 billion in 2017, as compared to an operating loss of $6.8 billion in
2016. Higher consolidated operating results were primarily due to increases in stimulation activity and well completion services
in North America. Operating results were also impacted by $647 million and $3.4 billion of impairments and other charges
recorded during 2017 and 2016, respectively. Additionally, we incurred $4.1 billion of merger related costs during 2016,
primarily due to a $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale
accounting.
OPERATING SEGMENTS
Completion and Production
Completion and Production revenue was $13.1 billion in 2017, an increase of $4.2 billion, or 47%, compared to 2016.
Completion and Production operating income was $1.6 billion in 2017 compared to $107 million in 2016. Operating results
significantly improved due to increased activity and pricing across the majority of our product service lines, primarily pressure
pumping services in North America. International operating results improved slightly as increased pressure pumping services in
the Middle East and Latin America were partially offset by reduced completion tool sales in the Eastern Hemisphere.
Drilling and Evaluation
Drilling and Evaluation revenue was $7.5 billion in 2017, an increase of $538 million, or 8%, from 2016. Drilling and
Evaluation operating income was $718 million in 2017, a decrease of $76 million, or 10%, compared to 2016. Operating results
improved for drilling services in North America as a result of improved pricing, utilization and rig count. These increases were
offset by pricing pressure and activity reductions across the majority of our product service lines in the Eastern Hemisphere,
particularly drilling and logging services, as well as activity reductions in Venezuela, primarily software sales and testing
activity.
27
GEOGRAPHIC REGIONS
North America
North America revenue was $11.6 billion in 2017, a 71% improvement compared to 2016. These results were driven
by improved customer demand in our United States land sector with increases in both pricing and activity, primarily related to
pressure pumping services, drilling activity and completion tool sales.
Latin America
Latin America revenue was $2.1 billion in 2017, a 14% increase compared to 2016, primarily related to higher drilling
activity in Brazil and Colombia, as well as increased project management activity in Mexico. These increases were partially
offset by reduced activity in the majority of our product service lines in Venezuela and lower completion tool sales in Brazil.
Europe/Africa/CIS
Europe/Africa/CIS revenue was $2.8 billion in 2017, a 7% decline compared to 2016. The decreases were driven by
activity reductions and pricing pressure across the region, particularly in Angola and the North Sea, along with reduced
completion tools sales and logging services throughout the region.
Middle East/Asia
Middle East/Asia revenue was $4.2 billion in 2017, a 2% decrease compared to 2016, driven by reduced activity and
pricing pressure, particularly for drilling and logging services in Thailand, reductions across all of our product service lines in
Indonesia and drilling services and completion tool sales across the region. These decreases were partially offset by improved
stimulation and well intervention activity in the Middle East, increased project management activity in Iraq and improved
activity across the majority of our product service lines in Australia.
OTHER OPERATING ITEMS
Corporate and other expenses were $330 million in 2017, as compared to $4.3 billion in 2016. The decrease was
primarily driven by merger-related costs during 2016 of a $3.5 billion termination fee and $464 million of charges resulting
from our reversal of assets held for sale accounting.
Impairments and other charges were $647 million in 2017 representing a fair market value adjustment on a
promissory note from our primary customer in Venezuela and a full reserve against our other accounts receivable with this
customer. See Note 3 to the consolidated financial statements for further information. This compares to $3.4 billion of
impairments and other charges recorded in 2016, primarily as a result of the downturn in the energy market, which consisted of
fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, country and
facility closures, a loss on exchange for our Venezuela promissory note and other charges.
NONOPERATING ITEMS
Interest expense, net was $593 million in 2017, which includes $104 million in costs related to the early
extinguishment of $1.4 billion of senior notes during the first quarter of 2017, offset by additional interest income recognized
during the year related to interest receipts and accretion on the promissory note from our primary customer in Venezuela. See
Note 3 to the consolidated financial statements for further information on our promissory note in Venezuela, including our
decision to discontinue the note accretion beginning in 2018. We recognized $639 million of net interest expense in 2016,
which includes $41 million of debt redemption fees and associated expenses related to the $2.5 billion of senior notes
mandatorily redeemed in the second quarter of 2016, with the corresponding interest savings from these debt payments
reflected in 2017.
Other, net was an $87 million loss in 2017, as compared to a $208 million loss in 2016, driven by foreign currency
exchange losses in various countries primarily due to the strengthening U.S. dollar. During 2017, foreign exchange losses were
primarily incurred in Brazil and Nigeria. During 2016, foreign exchange losses were primarily incurred in Egypt, Argentina and
Brazil, including a $53 million loss for the devaluation of the Egyptian pound.
28
Effective tax rate. During 2017, we recorded a total income tax provision of $1.1 billion on pre-tax income of $682
million, resulting in an effective tax rate of 165.8%. This includes $770 million of tax expenses associated with our preliminary
estimate of the net impact of the United States tax reform enacted in 2017. During 2016, we recorded a total income tax benefit
$1.9 billion on pre-tax losses of $7.6 billion, resulting in an effective tax rate of 24.4%. See Note 8 to the consolidated financial
statements for significant drivers of these effective tax rates.
29
RESULTS OF OPERATIONS IN 2016 COMPARED TO 2015
REVENUE:
Millions of dollars
Completion and Production
Drilling and Evaluation
Total revenue
By geographic region:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
OPERATING INCOME:
Millions of dollars
Completion and Production
Drilling and Evaluation
Total
Corporate and other
Impairments and other charges
Total operating loss
$
$
$
$
$
2016
2015
(Unfavorable)
Change
Favorable
Percentage
8,882 $
7,005
13,682 $
9,951
15,887 $
23,633 $
6,770 $
10,856 $
1,860
2,993
4,264
3,149
4,175
5,453
15,887 $
23,633 $
(4,800)
(2,946)
(7,746)
(4,086)
(1,289)
(1,182)
(1,189)
(7,746)
(35)%
(30)
(33)%
(38)%
(41)
(28)
(22)
(33)%
2016
2015
(Unfavorable)
Change
Favorable
Percentage
107 $
1,069 $
794
901
(4,322)
(3,357)
1,519
2,588
(576)
(2,177)
$
(6,778)$
(165)$
(962)
(725)
(1,687)
(3,746)
(1,180)
(6,613)
(90)%
(48)
(65)
650
54
4,008 %
Consolidated revenue in 2016 decreased 33% compared to 2015, associated with widespread pricing pressure and
activity reductions on a global basis, primarily attributable to stimulation activity, well completion services and pricing declines
in North America. Revenue outside of North America was 57% of consolidated revenue in 2016 and 54% of consolidated
revenue in 2015.
We reported a consolidated operating loss of $6.8 billion in 2016, as compared to an operating loss of $165 million in
2015. Operating results were negatively impacted by $3.4 billion and $2.2 billion of impairments and other charges recorded
during 2016 and 2015, respectively. Additionally, we incurred $4.1 billion of merger related costs during 2016, primarily due to
the $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting,
compared to $308 million of merger related costs during 2015. Also impacting consolidated operating results was the impact of
the global downturn in the energy market, primarily pricing pressure and activity reductions in North America pressure
pumping services and reduced well completion services globally.
OPERATING SEGMENTS
Completion and Production
Completion and Production revenue was $8.9 billion in 2016, a decrease of $4.8 billion, or 35%, compared to 2015,
due to a decline in activity and pricing in the majority of our product service lines, particularly North America pressure
pumping services which drove the majority of the revenue decline. International revenue declined as a result of reductions in
well completion services and stimulation activity in all regions.
Completion and Production operating income was $107 million in 2016, compared to $1.1 billion of operating income
in 2015, with decreased profitability across all regions as a result of global activity and pricing reductions, primarily in North
America stimulation activity and completion of well services across all regions.
30
Drilling and Evaluation
Drilling and Evaluation revenue was $7.0 billion in 2016, a decrease of $2.9 billion, or 30%, from 2015. Reductions
were seen across all product service lines due to the low rig count, lower pricing and customer budget constraints worldwide.
Drilling and Evaluation operating income was $794 million in 2016, a decrease of $725 million, or 48%, compared to
2015, driven by a decline in activity and pricing across all regions, particularly drilling and logging activity in Middle East/Asia
region and reduced fluid services in Latin America.
GEOGRAPHIC REGIONS
North America
North America revenue was $6.8 billion in 2016, a 38% decline compared to 2015, relative to a 45% decline in
average North America rig count. The decline was driven by reduced activity and pricing pressure throughout the United States
land market, specifically relating to stimulation and drilling activity.
Latin America
Latin America revenue was $1.9 billion in 2016, a 41% reduction compared to 2015. The reduction was primarily
related to our decision to curtail activity in Venezuela and currency weakness in the country, reduced activity across all product
service lines in Mexico and lower drilling activity in Brazil and Colombia.
Europe/Africa/CIS
Europe/Africa/CIS revenue was $3.0 billion in 2016, a decline of 28% compared to 2015. The decrease was driven by
a reduction of activity in the North Sea, Angola, Nigeria and Congo, along with lower drilling activity, completion tools sales
and pressure pumping services throughout the region.
Middle East/Asia
Middle East/Asia revenue was $4.3 billion in 2016, a reduction of 22% compared to 2015. This was the result of
pricing concessions across the region, along with reduced activity for pressure pumping services in the Middle East, Indonesia
and Australia, and a decline in drilling and logging activity in Indonesia, Malaysia and the Middle East.
OTHER OPERATING ITEMS
Corporate and other expenses increased to $4.3 billion in 2016, as compared to $576 million in 2015, primarily driven
by merger related costs. During 2016, we incurred a $3.5 billion termination fee and $464 million of charges resulting from our
reversal of assets held for sale accounting, as compared to $308 million of merger related costs during 2015.
Impairments and other charges. Primarily as a result of the downturn in the energy market and its corresponding
impact on the company's business outlook, we recorded a total of approximately $3.4 billion in company-wide charges during
2016, which consisted of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets,
severance costs, country and facility closures, a loss on exchange for a promissory note from our primary customer in
Venezuela and other charges. This compares to $2.2 billion of impairments and other charges recorded in 2015 which consisted
of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, country
and facility closures and other charges.
NONOPERATING ITEMS
Interest expense, net increased $192 million in 2016, compared to 2015. This was primarily due to additional interest
resulting from the $7.5 billion of senior notes issued in November 2015, coupled with the $41 million of redemption fees and
associated costs, which were recorded through interest expense, related to the $2.5 billion of senior notes mandatorily redeemed
during the second quarter of 2016. Additionally, we recognized interest income in 2016 related to interest receipts and
accretion on the promissory note from our primary customer in Venezuela.
Other, net was a $208 million loss in 2016, as compared to a $324 million loss in 2015, driven by foreign currency
exchange losses in various countries primarily due to the strengthening U.S. dollar. These losses included a $53 million loss in
2016 for the devaluation of the Egyptian pound and a $199 million loss in 2015 as a result of utilizing the new currency
exchange mechanism in Venezuela. Also impacting both periods were foreign currency exchange losses in Brazil and
Argentina. See "Business Environment and Results of Operations" for further information about Venezuela.
31
Effective tax rate. During 2016, we recorded a total income tax benefit of $1.9 billion on pre-tax losses of $7.6 billion,
resulting in an effective tax rate of 24.4%. During 2015, we recorded a total income tax benefit of $274 million on pre-tax
losses of $936 million, resulting in an effective tax rate of 29.3%. See Note 8 to the consolidated financial statements for
significant drivers of these effective tax rates.
32
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies
are described below to provide a better understanding of how we develop our assumptions and judgments about future events
and related estimations and how they can impact our financial statements. A critical accounting estimate is one that requires our
most difficult, subjective or complex judgments and assessments and is fundamental to our results of operations. We identified
our most critical accounting estimates to be:
- forecasting our effective income tax rate, including our future ability to utilize foreign tax credits and the
realizability of deferred tax assets, and providing for uncertain tax positions;
- legal, environmental and investigation matters;
- valuations of long-lived assets, including intangible assets and goodwill;
- purchase price allocation for acquired businesses; and
- allowance for bad debts, primarily related to receivables in Venezuela.
We base our estimates on historical experience and on various other assumptions we believe to be reasonable
according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical
accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and
judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our
consolidated financial statements and related notes included in this report.
Income tax accounting
We recognize the amount of taxes payable or refundable for the current year and use an asset and liability approach in
recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been recognized
in our financial statements or tax returns. We apply the following basic principles in accounting for our income taxes:
- a current tax liability or asset is recognized for the estimated taxes payable or refundable on tax returns for the
current year;
- a deferred tax liability or asset is recognized for the estimated future tax effects attributable to temporary differences
and carryforwards;
- the measurement of current and deferred tax liabilities and assets is based on provisions of the enacted tax law, and
the effects of potential future changes in tax laws or rates are not considered; and
- the value of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available
evidence, are not expected to be realized.
We determine deferred taxes separately for each tax-paying component (an entity or a group of entities that is
consolidated for tax purposes) in each tax jurisdiction. That determination includes the following procedures:
- identifying the types and amounts of existing temporary differences;
- measuring the total deferred tax liability for taxable temporary differences using the applicable tax rate;
- measuring the total deferred tax asset for deductible temporary differences and operating loss carryforwards using
the applicable tax rate;
- measuring the deferred tax assets for each type of tax credit carryforward; and
- reducing the deferred tax assets by a valuation allowance if, based on available evidence, it is more likely than not
that some portion or all of the deferred tax assets will not be realized.
Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and
estimates. Additionally, we use forecasts of certain tax elements, such as taxable income and foreign tax credit utilization, as
well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of
such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly
impact these variables, and changes to these variables could have a material impact on our income tax accounts related to both
continuing and discontinued operations.
We have operations in approximately 70 countries. Consequently, we are subject to the jurisdiction of a significant
number of taxing authorities. The income earned in these various jurisdictions is taxed on differing bases, including income
actually earned, income deemed earned and revenue-based tax withholding. The final determination of our income tax
liabilities involves the interpretation of local tax laws, tax treaties and related authorities in each jurisdiction. Changes in the
operating environment, including changes in tax law and currency/repatriation controls, could impact the determination of our
income tax liabilities for a tax year.
33
Tax filings of our subsidiaries, unconsolidated affiliates and related entities are routinely examined in the normal
course of business by tax authorities. These examinations may result in assessments of additional taxes, which we work to
resolve with the tax authorities and through the judicial process. Predicting the outcome of disputed assessments involves some
uncertainty. Factors such as the availability of settlement procedures, willingness of tax authorities to negotiate and the
operation and impartiality of judicial systems vary across the different tax jurisdictions and may significantly influence the
ultimate outcome. We review the facts for each assessment, and then utilize assumptions and estimates to determine the most
likely outcome and provide taxes, interest and penalties as needed based on this outcome. We provide for uncertain tax
positions pursuant to current accounting standards, which prescribe a minimum recognition threshold and measurement
methodology that a tax position taken or expected to be taken in a tax return is required to meet before being recognized in the
financial statements. The standards also provide guidance for derecognition classification, interest and penalties, accounting in
interim periods, disclosure and transition.
We are currently evaluating provisions of United States tax reform enacted in December 2017. In the fourth quarter of
2017, we recorded a provision to income taxes for our preliminary assessment of the impact of tax reform. As we do not have
all the necessary information to analyze all income tax effects of tax reform, this is a provisional amount which we believe
represents a reasonable estimate of the accounting implications of this tax reform. We will continue to evaluate tax reform and
adjust the provisional amounts as additional information is obtained. The ultimate impact of tax reform may differ from our
provisional amounts due to changes in our interpretations and assumptions, as well as additional regulatory guidance that may
be issued. We expect to complete our detailed analysis no later than the fourth quarter of 2018. For further information, see
Note 8 to the consolidated financial statements.
Legal, environmental and investigation matters
As discussed in Note 7 of our consolidated financial statements, as of December 31, 2017, we have accrued an
estimate of the probable and estimable costs for the resolution of some of our legal, environmental and investigation matters.
For other matters for which the liability is not probable and reasonably estimable, we have not accrued any amounts. Attorneys
in our legal department monitor and manage all claims filed against us and review all pending investigations. Generally, the
estimate of probable costs related to these matters is developed in consultation with internal and outside legal counsel
representing us. Our estimates are based upon an analysis of potential results, assuming a combination of litigation and
settlement strategies. The accuracy of these estimates is impacted by, among other things, the complexity of the issues and the
amount of due diligence we have been able to perform. We attempt to resolve these matters through settlements, mediation and
arbitration proceedings when possible. If the actual settlement costs, final judgments or fines, after appeals, differ from our
estimates, there may be a material adverse effect on our future financial results. We have in the past recorded significant
adjustments to our initial estimates of these types of contingencies.
Value of long-lived assets, including intangible assets and goodwill
We carry a variety of long-lived assets on our balance sheet including property, plant and equipment, goodwill and
other intangibles. Impairment is the condition that exists when the carrying amount of a long-lived asset exceeds its fair value,
and any impairment charge that we record reduces our earnings. Goodwill is the excess of the cost of an acquired entity over
the net of the amounts assigned to assets acquired and liabilities assumed. We conduct impairment tests on goodwill annually,
during the third quarter, or more frequently whenever events or changes in circumstances indicate an impairment may exist. We
conduct impairment tests on long-lived assets, other than goodwill, whenever events or changes in circumstances indicate that
the carrying value may not be recoverable.
When conducting an impairment test on long-lived assets, other than goodwill, we first compare estimated future
undiscounted cash flows associated with the asset to the asset’s carrying amount. If the undiscounted cash flows are less than
the asset’s carrying amount, we then determine the asset's fair value by using a discounted cash flow analysis. These analyses
are based on estimates such as management’s short-term and long-term forecast of operating performance, including revenue
growth rates and expected profitability margins, estimates of the remaining useful life and service potential of the asset, and a
discount rate based on our weighted average cost of capital.
We perform our goodwill impairment assessment for each reporting unit, which is the same as our reportable
segments, the Completion and Production division and the Drilling and Evaluation division, comparing the estimated fair value
of each reporting unit to the reporting unit’s carrying value, including goodwill. We estimate the fair value for each reporting
unit using a discounted cash flow analysis based on management’s short-term and long-term forecast of operating performance.
This analysis includes significant assumptions regarding discount rates, revenue growth rates, expected profitability margins,
forecasted capital expenditures and the timing of expected future cash flows based on market conditions. If the estimated fair
value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying
amount of a reporting unit exceeds its estimated fair value, an impairment loss is measured and recorded.
34
The impairment assessments discussed above incorporate inherent uncertainties, including projected commodity
pricing, supply and demand for our services and future market conditions, which are difficult to predict in volatile economic
environments and could result in impairment charges in future periods if actual results materially differ from the estimated
assumptions utilized in our forecasts. If crude oil prices decline significantly and remain at low levels for a sustained period of
time, we could be required to record an impairment of the carrying value of our long-lived assets in the future which could have
a material adverse impact on our operating results. See Note 1 to the consolidated financial statements for our accounting
policies related to long-lived assets as well as the results of our annual goodwill impairment assessment.
Acquisitions-purchase price allocation
We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair
values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill.
We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets
and widely accepted valuation techniques such as discounted cash flows. We engage third-party appraisal firms when
appropriate to assist in fair value determination of inventories, identifiable intangible assets and any other significant assets or
liabilities. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities
assumed, as well as asset lives, can materially impact our results of operations. Our acquisitions may also include contingent
consideration, or earn-out provisions, which provide for additional consideration to be paid to the seller if certain future
conditions are met. These earn-out provisions are estimated and recognized at fair value at the acquisition date based on
projected earnings or other financial metrics over specified periods after the acquisition date. These estimates are reviewed
during the specified period and adjusted based on actual results.
Allowance for bad debts, primarily related to receivables in Venezuela
We evaluate our global accounts receivable through a continuous process of assessing our portfolio on an individual
customer and overall basis. This process consists of a thorough review of historical collection experience, current aging status
of the customer accounts, financial condition of our customers and whether the receivables involve retainages. We also consider
the economic environment of our customers, both from a marketplace and geographic perspective, in evaluating the need for an
allowance. Based on our review of these factors, we establish or adjust allowances for specific customers and the accounts
receivable portfolio as a whole. This process involves a high degree of judgment and estimation, and frequently involves
significant dollar amounts. Accordingly, our results of operations can be affected by adjustments to the allowance due to actual
write-offs that differ from estimated amounts. Our estimates of allowances for bad debts have historically been accurate. Over
the last five years, our estimates of allowances for bad debts, as a percentage of notes and accounts receivable before the
allowance, have ranged from 1.8% to 12.8%. During 2017, we significantly increased our allowance for bad debts related to
accounts receivable with our primary customer in Venezuela as a result of delayed payments, deteriorating market conditions in
Venezuela and a recent credit downgrade. At December 31, 2017, allowance for bad debts totaled $725 million, or 12.8% of
notes and accounts receivable before the allowance. At December 31, 2016, allowance for bad debts totaled $175 million, or
4.3% of notes and accounts receivable before the allowance. A hypothetical 100 basis point change in our estimate of the
collectability of our notes and accounts receivable balance as of December 31, 2017 would have resulted in a $57 million
adjustment to 2017 total operating costs and expenses. See Note 3 to the consolidated financial statements for further
information.
OFF BALANCE SHEET ARRANGEMENTS
At December 31, 2017, we had no material off balance sheet arrangements, except for operating leases. In the normal
course of business, we have agreements with financial institutions under which approximately $1.8 billion of letters of credit,
bank guarantees or surety bonds were outstanding as of December 31, 2017. Some of the outstanding letters of credit have
triggering events that would entitle a bank to require cash collateralization. None of these off balance sheet arrangements either
has, or is likely to have, a material effect on our consolidated financial statements. For information on our contractual
obligations related to operating leases, see Note 7 to the consolidated financial statements and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Contractual obligations.”
FINANCIAL INSTRUMENT MARKET RISK
We are exposed to market risk from changes in foreign currency exchange rates and interest rates. We selectively
manage these exposures through the use of derivative instruments, including forward foreign exchange contracts, foreign
exchange options and interest rate swaps. The objective of our risk management strategy is to minimize the volatility from
fluctuations in foreign currency and interest rates. We do not use derivative instruments for trading purposes. The counterparties
to our forward contracts, options and interest rate swaps are global commercial and investment banks.
35
We use a sensitivity analysis model to measure the impact of potential adverse movements in foreign currency
exchange rates and interest rates. With respect to foreign exchange sensitivity, after consideration of the impact from our
foreign exchange hedges, a hypothetical 10% adverse change in the value of all our foreign currency positions relative to the
United States dollar as of December 31, 2017 would result in a $55 million, pre-tax, loss for our net monetary assets
denominated in currencies other than United States dollars. With respect to interest rates sensitivity, after consideration of the
impact from our interest rate swap, a hypothetical 100 basis point increase in the LIBOR rate would result in approximately an
additional $1 million of interest charges for the year ended December 31, 2017.
There are certain limitations inherent in the sensitivity analyses presented, primarily due to the assumption that
exchange rates and interest rates change instantaneously in an equally adverse fashion. In addition, the analyses are unable to
reflect the complex market reactions that normally would arise from the market shifts modeled. While this is our best estimate
of the impact of the various scenarios, these estimates should not be viewed as forecasts.
For further information regarding foreign currency exchange risk, interest rate risk and credit risk, see Note 12 to the
consolidated financial statements.
ENVIRONMENTAL MATTERS
We are subject to numerous environmental, legal and regulatory requirements related to our operations worldwide. For
information related to environmental matters, see Note 7 to the consolidated financial statements and Part I, Item 1(a), “Risk
Factors.”
FORWARD-LOOKING INFORMATION
The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information.
Forward-looking information is based on projections and estimates, not historical information. Some statements in this Form
10-K are forward-looking and use words like “may,” “may not,” “believe,” “do not believe,” “plan,” “estimate,” “intend,”
“expect,” “do not expect,” “anticipate,” “do not anticipate,” “should,” "would," "could," “likely” and other expressions. We
may also provide oral or written forward-looking information in other materials we release to the public. Forward-looking
information involves risk and uncertainties and reflects our best judgment based on current information. Our results of
operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition,
other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be
guaranteed. Actual events and the results of our operations may vary materially.
We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether
factors change as a result of new information, future events or for any other reason. You should review any additional
disclosures we make in our press releases and Forms 10-K, 10-Q and 8-K filed with or furnished to the SEC. We also suggest
that you listen to our quarterly earnings release conference calls with financial analysts.
36
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Halliburton Company is responsible for establishing and maintaining adequate internal control
over financial reporting as defined in the Securities Exchange Act Rule 13a-15(f).
Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those
systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and
presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary
over time.
In July 2017, we acquired Summit ESP. For purposes of determining the effectiveness of our internal control over
financial reporting, management has excluded Summit ESP from its evaluation. The acquired business represented
approximately 2% of our consolidated total assets at December 31, 2017 and less than 1% of our consolidated revenues for the
year ended December 31, 2017.
Under the supervision and with the participation of our management, including our chief executive officer and chief
financial officer, we conducted an evaluation to assess the effectiveness of our internal control over financial reporting as of
December 31, 2017 based upon criteria set forth in the Internal Control - Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of
December 31, 2017, our internal control over financial reporting is effective.
The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2017 has been audited
by KPMG LLP, an independent registered public accounting firm, as stated in their report that is included herein.
HALLIBURTON COMPANY
by
/s/ Jeffrey A. Miller
Jeffrey A. Miller
President and
Chief Executive Officer
/s/ Christopher T. Weber
Christopher T. Weber
Executive Vice President and
Chief Financial Officer
37
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Halliburton Company:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Halliburton Company and subsidiaries (the “Company”) as
of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income, shareholders’
equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes
(collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in
all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its
operations and its cash flows for each of the years in the three-year period ended December 31, 2017, 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 Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 9, 2018 expressed an unqualified opinion on the effectiveness of the Company’s
internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 14 to the consolidated financial statements, the Company changed its method of accounting for deferred
income taxes related to intra-entity transfers other than inventory effective January 1, 2017 due to the adoption of FASB ASU
2016-16, Intra-Entity Transfers of Assets Other Than Inventory.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express
an opinion on these consolidated 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 Company in accordance with the U.S. federal securities laws
and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the consolidated 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
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 9, 2018
38
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Halliburton Company:
Opinion on Internal Control Over Financial Reporting
We have audited Halliburton Company’s (the “Company”) internal control over financial reporting as of December 31, 2017,
based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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 Company as of December 31, 2017 and 2016, and the related consolidated
statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the years in the three-year
period ended December 31, 2017, and related notes (collectively, the “consolidated financial statements”), and our report dated
February 9, 2018 expressed an unqualified opinion on those consolidated financial statements.
As described in Management’s Report on Internal Control Over Financial Reporting, management excluded from its assessment
the internal control over financial reporting of Summit ESP (“Summit”), which was acquired during 2017 and whose total
assets constituted 2% of consolidated total assets and total revenues constituted less than 1% of consolidated total revenue as of
and for the year ended December 31, 2017. Our audit of internal control over financial reporting of the Company also excluded
an evaluation of the internal control over financial reporting of Summit.
Basis for Opinion
The Company’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 Company’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 Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our 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 of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included 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.
39
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.
/s/ KPMG LLP
Houston, Texas
February 9, 2018
40
HALLIBURTON COMPANY
Consolidated Statements of Operations
Millions of dollars and shares except per share data
Year Ended December 31
2017
2016
2015
Revenue:
Services
Product sales
Total revenue
Operating costs and expenses:
Cost of services
Cost of sales
Merger-related costs and termination fee
Impairments and other charges
General and administrative
Total operating costs and expenses
Operating income (loss)
Interest expense, net of interest income of $112, $59 and $16
Other, net
Income (loss) from continuing operations before income taxes
Income tax benefit (provision)
Loss from continuing operations
Loss from discontinued operations, net
Net loss
Net (income) loss attributable to noncontrolling interest
Net loss attributable to company
Amounts attributable to company shareholders:
Loss from continuing operations
Loss from discontinued operations, net
Net loss attributable to company
Basic and diluted loss per share attributable to company shareholders:
Loss from continuing operations
Loss from discontinued operations, net
Net loss per share
$
$
$
$
$
$
$
15,408 $
11,140 $
5,212
20,620
14,213
4,142
—
647
256
19,258
1,362
(593)
(87)
682
(1,131)
(449)
(19)
(468)$
5
(463)$
(444)$
(19)
(463)$
(0.51)$
(0.02)
(0.53)$
4,747
15,887
11,253
3,770
4,057
3,357
228
22,665
(6,778)
(639)
(208)
(7,625)
1,858
(5,767)
(2)
(5,769)$
6
(5,763)$
(5,761)$
(2)
(5,763)$
(6.69)$
—
(6.69)$
16,981
6,652
23,633
16,014
5,099
308
2,177
200
23,798
(165)
(447)
(324)
(936)
274
(662)
(5)
(667)
(4)
(671)
(666)
(5)
(671)
(0.78)
(0.01)
(0.79)
Basic and diluted weighted average common shares outstanding
870
861
853
See notes to consolidated financial statements.
41
HALLIBURTON COMPANY
Consolidated Statements of Comprehensive Income
Millions of dollars
Net loss
Other comprehensive income (loss), net of income taxes:
Defined benefit and other post retirement plans adjustment
Unrealized loss on cash flow hedges
Other
Other comprehensive income (loss), net of income taxes
Comprehensive loss
Comprehensive (income) loss attributable to noncontrolling interest
Comprehensive loss attributable to company shareholders
See notes to consolidated financial statements.
Year Ended December 31
2017
2016
2015
$
(468)$
(5,769)$
(667)
(22)
—
7
(15)
(483)$
5
(478)$
(92)
—
1
(91)
(5,860)$
6
(5,854)$
105
(67)
(2)
36
(631)
(4)
(635)
$
$
42
HALLIBURTON COMPANY
Consolidated Balance Sheets
Millions of dollars and shares except per share data
Assets
Current assets:
Cash and equivalents
Receivables (net of allowances for bad debts of $725 and $175)
Inventories
Prepaid income taxes
Other current assets
Total current assets
Property, plant and equipment (net of accumulated depreciation of $12,249 and $11,198)
Goodwill
Deferred income taxes
Other assets
Total assets
Current liabilities:
Accounts payable
Liabilities and Shareholders’ Equity
Accrued employee compensation and benefits
Short-term borrowings and current maturities of long-term debt
Deferred revenue
Taxes other than income
Liabilities for Macondo well incident
Other current liabilities
Total current liabilities
Long-term debt
Employee compensation and benefits
Other liabilities
Total liabilities
Shareholders’ equity:
Common shares, par value $2.50 per share (authorized 2,000 shares,
issued 1,069 and 1,070 shares)
Paid-in capital in excess of par value
Accumulated other comprehensive loss
Retained earnings
Treasury stock, at cost (196 and 204 shares)
Company shareholders’ equity
Noncontrolling interest in consolidated subsidiaries
Total shareholders’ equity
Total liabilities and shareholders’ equity
See notes to consolidated financial statements.
43
December 31
2017
2016
$
2,337 $
5,036
2,396
133
875
4,009
3,922
2,275
585
886
10,777
11,677
8,521
2,693
1,230
1,864
8,532
2,414
1,960
2,417
25,085 $
27,000
2,554 $
1,764
$
$
746
512
257
231
—
562
4,862
10,430
609
835
544
170
261
218
369
697
4,023
12,214
574
741
16,736
17,552
2,673
207
(469)
12,668
(6,757)
8,322
27
8,349
$
25,085 $
2,674
201
(454)
14,141
(7,153)
9,409
39
9,448
27,000
HALLIBURTON COMPANY
Consolidated Statements of Cash Flows
Millions of dollars
Cash flows from operating activities:
Net loss
Adjustments to reconcile net loss to cash flows from operating activities:
Depreciation, depletion and amortization
Deferred income tax provision (benefit), continuing operations
Impairments and other charges
U.S. tax refund
Payment related to the Macondo well incident
Cash impact of impairments and other charges – severance payments
Changes in assets and liabilities:
Receivables
Accounts payable
Inventories
Other
Year Ended December 31
2017
2016
2015
$
(468)$
(5,769)$
(667)
1,556
734
647
478
(368)
—
(1,350)
753
(29)
515
1,503
(1,501)
3,357
430
(33)
(273)
899
(219)
552
(649)
1,835
(224)
2,177
—
(333)
(304)
1,468
(603)
153
(596)
Total cash flows provided by (used in) operating activities
2,468
(1,703)
2,906
Cash flows from investing activities:
Capital expenditures
Payments to acquire businesses, net of cash acquired
Proceeds from sales of property, plant and equipment
Other investing activities
Total cash flows used in investing activities
Cash flows from financing activities:
Payments on long-term borrowings
Dividends to shareholders
Proceeds from issuance of common stock
Proceeds from issuance of long-term debt, net
Other financing activities
Total cash flows used in financing activities
Effect of exchange rate changes on cash
Increase (decrease) in cash and equivalents
Cash and equivalents at beginning of year
Cash and equivalents at end of year
Supplemental disclosure of cash flow information:
Cash payments (receipts) during the period for:
Interest
Income taxes
See notes to consolidated financial statements.
44
(1,373)
(628)
158
(84)
(1,927)
(798)
(31)
222
(103)
(710)
(1,641)
(3,171)
(626)
158
10
(62)
(620)
186
74
(9)
(2,184)
(39)
168
(137)
(2,192)
(8)
(614)
167
7,440
96
(2,161)
(3,540)
7,081
(52)
(115)
(1,672)
(6,068)
4,009
10,077
(9)
7,786
2,291
2,337 $
4,009 $
10,077
594 $
(178)$
659 $
(20)$
380
370
$
$
$
HALLIBURTON COMPANY
Consolidated Statements of Shareholders' Equity
Company Shareholders’ Equity
Millions of dollars
Balance at December 31, 2014
Comprehensive income (loss):
Net income (loss)
Other comprehensive income
Stock plans
Cash dividends ($0.72 per share)
Other
Balance at December 31, 2015
Comprehensive income (loss):
Net loss
Other comprehensive loss
Stock plans
Cash dividends ($0.72 per share)
Other
Balance at December 31, 2016
Comprehensive income (loss):
Net loss
Retained earnings adjustment for new accounting standard
Other comprehensive loss
Stock plans
Cash dividends ($0.72 per share)
Other
Paid-in
Capital in
Excess of
Par Value
Common
Shares
Treasury
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
interest in
Consolidated
Subsidiaries
Total
$
2,679 $
309 $
(8,131)$
21,809 $
(399)$
31 $ 16,298
—
—
(2)
—
—
—
—
(39)
—
4
—
—
481
—
—
(671)
—
—
(614)
—
—
36
—
—
—
4
—
—
—
(2)
(667)
36
440
(614)
2
$
2,677 $
274 $
(7,650)$
20,524 $
(363)$
33 $ 15,495
—
—
(3)
—
—
—
—
(69)
—
(4)
—
—
497
—
—
(5,763)
—
—
(620)
—
—
(91)
—
—
—
(6)
(5,769)
—
—
—
12
(91)
425
(620)
8
$
2,674 $
201 $
(7,153)$
14,141 $
(454)$
39 $
9,448
—
—
—
(1)
—
—
—
—
—
6
—
—
—
—
—
396
—
—
(463)
(384)
—
—
(626)
—
—
—
(15)
—
—
—
(5)
—
—
—
—
(7)
(468)
(384)
(15)
401
(626)
(7)
Balance at December 31, 2017
$
2,673 $
207 $
(6,757)$
12,668 $
(469)$
27 $
8,349
See notes to consolidated financial statements.
45
HALLIBURTON COMPANY
Notes to Consolidated Financial Statements
Note 1. Description of Company and Significant Accounting Policies
Description of Company
Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware
in 1924. We help our customers maximize value throughout the lifecycle of the reservoir - from locating hydrocarbons and
managing geological data, to drilling and formation evaluation, well construction and completion and optimizing production
throughout the life of the asset. We serve major, national and independent oil and natural gas companies throughout the world
and operate under two divisions, which form the basis for the two operating segments we report, the Completion and
Production segment and the Drilling and Evaluation segment.
Use of estimates
Our financial statements are prepared in conformity with United States generally accepted accounting principles,
requiring us to make estimates and assumptions that affect:
-
-
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements; and
the reported amounts of revenue and expenses during the reporting period.
We believe the most significant estimates and assumptions are associated with the forecasting of our effective income
tax rate and the valuation of deferred taxes, legal and environmental reserves, long-lived asset valuations, purchase price
allocations and allowance for bad debts. Ultimate results could differ from our estimates.
Basis of presentation
The consolidated financial statements include the accounts of our company and all of our subsidiaries that we control
or variable interest entities for which we have determined that we are the primary beneficiary. All material intercompany
accounts and transactions are eliminated. Investments in companies in which we do not have a controlling interest, but over
which we do exercise significant influence, are accounted for using the equity method of accounting. If we do not have
significant influence, we use the cost method of accounting. In addition, certain reclassifications of prior period balances have
been made to conform to the current period presentation.
Revenue recognition
Our services and products are generally sold based upon purchase orders or contracts with our customers that include
fixed or determinable prices but do not include right of return provisions or other significant post-delivery obligations. Our
products are produced in a standard manufacturing operation, even if produced to our customer’s specifications. We recognize
revenue from product sales when title passes to the customer, the customer assumes risks and rewards of ownership,
collectability is reasonably assured and delivery occurs as directed by our customer. Service revenue, including training and
consulting services, is recognized when the services are rendered and collectability is reasonably assured. Rates for services are
typically priced on a per day, per meter, per man-hour or similar basis. We will adopt a new revenue recognition standard
effective January 1, 2018 that will supersede existing revenue recognition guidance. See Note 14 for additional information.
Research and development
Research and development costs are expensed as incurred. Research and development costs were $360 million in
2017, $329 million in 2016 and $487 million in 2015.
Cash equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Inventories
Inventories are stated at the lower of cost and net realizable value. Cost represents invoice or production cost for new
items and original cost less allowance for condition for used material returned to stock. Production cost includes material, labor
and manufacturing overhead. Some domestic manufacturing and field service finished products and parts inventories for drill
bits, completion products and bulk materials are recorded using the last-in, first-out method. The remaining inventory is
recorded on the average cost method. We regularly review inventory quantities on hand and record provisions for excess or
obsolete inventory based primarily on historical usage, estimated product demand and technological developments.
46
Allowance for bad debts
We establish an allowance for bad debts through a review of several factors, including historical collection experience,
current aging status of the customer accounts and financial condition of our customers. Our policy is to write off bad debts
when the customer accounts are determined to be uncollectible.
Property, plant and equipment
Other than those assets that have been written down to their fair values due to impairment, property, plant and
equipment are reported at cost less accumulated depreciation, which is generally provided on the straight-line method over the
estimated useful lives of the assets. Accelerated depreciation methods are used for tax purposes, wherever permitted. Upon sale
or retirement of an asset, the related costs and accumulated depreciation are removed from the accounts and any gain or loss is
recognized. Planned major maintenance costs are generally expensed as incurred. Expenditures for additions, modifications and
conversions are capitalized when they increase the value or extend the useful life of the asset.
Goodwill and other intangible assets
We record as goodwill the excess purchase price over the fair value of the tangible and identifiable intangible assets
acquired in a business acquisition. Changes in the carrying amount of goodwill are detailed below by reportable segment.
Millions of dollars
Balance at December 31, 2015:
Completion
and Production
$
1,634 $
Drilling and
Evaluation
Total
751 $
2,385
Current year acquisitions
Purchase price adjustments for previous acquisitions
Other
Balance at December 31, 2016:
Current year acquisitions
Purchase price adjustments for previous acquisitions
Balance at December 31, 2017:
$
$
31
(2)
16
1,679 $
249
(6)
1,922 $
—
—
(16)
735 $
36
—
771 $
31
(2)
—
2,414
285
(6)
2,693
During 2017, we acquired three businesses, Summit ESP, Ingrain Inc. and Optimization Petroleum Technology, which
resulted in approximately $285 million of additional goodwill based on our preliminary purchase price allocations. The reported
amounts of goodwill for each reporting unit are reviewed for impairment on an annual basis, during the third quarter, and more
frequently when circumstances indicate an impairment may exist. As a result of our goodwill impairment assessments
performed in the years ended December 31, 2017, 2016 and 2015, we determined that the fair value of each reporting unit
exceeded its net book value and, therefore, no goodwill impairments were deemed necessary. For further information on our
goodwill impairment assessments, see “Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Critical Accounting Estimates.”
We amortize other identifiable intangible assets with a finite life on a straight-line basis over the period which the asset
is expected to contribute to our future cash flows, ranging from one to fifteen years. The components of these other intangible
assets generally consist of patents, license agreements, non-compete agreements, trademarks and customer lists and contracts.
Evaluating impairment of long-lived assets
When events or changes in circumstances indicate that long-lived assets other than goodwill may be impaired, an
evaluation is performed. For an asset classified as held for use, the estimated future undiscounted cash flows associated with the
asset are compared to the asset’s carrying amount to determine if a write-down to fair value is required. When an asset is
classified as held for sale, the asset’s book value is evaluated and adjusted to the lower of its carrying amount or fair value less
cost to sell. In addition, depreciation and amortization is ceased while it is classified as held for sale.
Income taxes
We recognize the amount of taxes payable or refundable for the year. In addition, deferred tax assets and liabilities are
recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax
returns. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be
realized.
47
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the
generation of future taxable income during the periods in which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in
making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the
periods in which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the
benefits of these deductible differences, net of the existing valuation allowances.
We recognize interest and penalties related to unrecognized tax benefits within the provision for income taxes on
continuing operations in our consolidated statements of operations.
During 2017, the President of the United States signed into law what is informally called the Tax Cuts and Jobs Act of
2017, a comprehensive U.S. tax reform package that, effective January 1, 2018, among other things, lowered the corporate
income tax rate from 35% to 21% and moved the country towards a territorial tax system with a one-time mandatory tax on
previously deferred foreign earnings of foreign subsidiaries. See Note 8 for further information.
Derivative instruments
At times, we enter into derivative financial transactions to hedge existing or projected exposures to changing foreign
currency exchange rates and interest rates. We do not enter into derivative transactions for speculative or trading purposes. We
recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges are adjusted to fair value and
reflected through the results of operations. If the derivative is designated as a hedge, depending on the nature of the hedge,
changes in the fair value of derivatives are either offset against:
-
-
the change in fair value of the hedged assets, liabilities or firm commitments through earnings; or
recognized in other comprehensive income until the hedged item is recognized in earnings.
The ineffective portion of a derivative’s change in fair value is recognized in earnings. Recognized gains or losses on
derivatives entered into to manage foreign currency exchange risk are included in “Other, net” on the consolidated statements
of operations. Gains or losses on interest rate derivatives are included in “Interest expense, net.”
Foreign currency translation
Foreign entities whose functional currency is the United States dollar translate monetary assets and liabilities at year-
end exchange rates, and nonmonetary items are translated at historical rates. Revenue and expense transactions are translated at
the average rates in effect during the year, except for those expenses associated with nonmonetary balance sheet accounts,
which are translated at historical rates. Gains or losses from remeasurement of monetary assets and liabilities due to changes in
exchange rates are recognized in our consolidated statements of operations in “Other, net” in the year of occurrence.
Stock-based compensation
Stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award and is
recognized as expense over the employee’s service period, which is generally the vesting period of the equity grant.
Additionally, compensation cost is recognized based on awards ultimately expected to vest, therefore, we have reduced the cost
for estimated forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant and revised in
subsequent periods to reflect actual forfeitures. See Note 10 and Note 14 for additional information related to stock-based
compensation.
Note 2. Business Segment and Geographic Information
We operate under two divisions, which form the basis for the two operating segments we report: the Completion and
Production segment and the Drilling and Evaluation segment. For more information about the product service lines included in
each segment, see Part I, Item 1, "Business.” Corporate and other includes certain expenses not attributable to a particular
business segment such as costs related to support functions and corporate executives. Other items include amortization expense
associated with intangible assets recorded as a result of our acquisitions in 2017 and merger-related costs in 2016 and 2015. The
balance sheet for Corporate is primarily composed of cash and equivalents, deferred tax assets and investment securities.
Intersegment revenue and revenue between geographic areas are immaterial. Our equity in earnings and losses of
unconsolidated affiliates that are accounted for using the equity method of accounting are included within cost of services and
cost of sales on our statements of operations, which is part of operating income of the applicable segment.
48
The following tables present financial information on our business segments.
Operations by business segment
Millions of dollars
Revenue:
Completion and Production
Drilling and Evaluation
Total revenue
Operating income (loss):
Completion and Production
Drilling and Evaluation
Total operations
Corporate and other (a)
Impairments and other charges (b)
Total operating income (loss)
Interest expense, net of interest income
Other, net
Year Ended December 31
2016
2017
2015
$
$
13,077 $
8,882 $
13,682
7,543
7,005
9,951
20,620 $
15,887 $
23,633
$
1,621 $
107 $
718
2,339
(330)
(647)
794
901
(4,322)
(3,357)
$
$
1,362 $
(6,778)$
(593)$
(87)
(639)$
(208)
1,069
1,519
2,588
(576)
(2,177)
(165)
(447)
(324)
(936)
Income (loss) from continuing operations before income taxes $
682 $
(7,625)$
Capital expenditures:
Completion and Production
Drilling and Evaluation
Corporate and other
Total
Depreciation, depletion and amortization:
Completion and Production
Drilling and Evaluation
Corporate and other
Total
$
$
$
$
1,111 $
500 $
1,526
261
1
297
1
650
8
1,373 $
798 $
2,184
953 $
900 $
1,160
563
40
569
34
638
37
1,556 $
1,503 $
1,835
(a) Includes merger-related costs for the periods presented, including a $3.5 billion termination fee and an aggregate $464 million of charges for
the reversal of assets held for sale accounting during the year ended December 31, 2016.
(b) Impairments and other charges are as follows:
-For the year ended December 31, 2017, the aggregate charge of $647 million represents a fair market value adjustment on our existing
promissory note with our primary customer in Venezuela and a full reserve against our other accounts receivable with this customer.
-For the year ended December 31, 2016, includes $2.1 billion attributable to Completion and Production, $1.2 billion attributable to
Drilling and Evaluation and $10 million attributable to Corporate and other.
-For the year ended December 31, 2015, includes $1.1 billion attributable to Completion and Production, $1.0 billion attributable to
Drilling and Evaluation and $88 million attributable to Corporate and other.
Millions of dollars
Total assets:
Completion and Production
Drilling and Evaluation
Shared assets
Corporate and other
Total
December 31
2017
2016
$
$
12,276 $
7,837
2,913
2,059
25,085 $
10,349
8,473
3,371
4,807
27,000
49
Not all assets are associated with specific segments. Those assets specific to segments include receivables, inventories,
certain identified property, plant and equipment (including field service equipment), equity in and advances to related
companies and goodwill. The remaining assets, such as cash and equivalents, are considered to be shared among the segments.
The following tables present information by geographic area. In 2017, 2016 and 2015, based on the location of
services provided and products sold, 53%, 41% and 44% of our consolidated revenue was from the United States. As of
December 31, 2017 and December 31, 2016, 56% and 50% of our property, plant and equipment was located in the United
States. No other country accounted for more than 10% of our revenue or property, plant and equipment during the periods
presented.
Operations by geographic region
Millions of dollars
Revenue:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Millions of dollars
Net property, plant and equipment:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Year Ended December 31
2016
2017
2015
$
$
11,564 $
2,116
2,781
4,159
20,620 $
6,770 $
1,860
2,993
4,264
15,887 $
10,856
3,149
4,175
5,453
23,633
December 31
2017
2016
$
$
4,922 $
945
1,098
1,556
8,521 $
4,431
1,068
1,253
1,780
8,532
Note 3. Receivables
As of December 31, 2017, 42% of our net trade receivables were from customers in the United States. As of
December 31, 2016, 27% of our net trade receivables were from customers in the United States and 15% were from customers
in Venezuela. Other than the United States and Venezuela, no other country or single customer accounted for more than 10% of
our trade receivables at these dates.
We routinely monitor the financial stability of our customers, and employ an extensive process to evaluate the
collectability of outstanding receivables. This process, which involves a high degree of judgment utilizing significant
assumptions, includes analysis of our customers’ historical time to pay, financial condition and various financial metrics, debt
structure, credit agency ratings and production profile, as well as political and economic factors in countries of operations and
other customer-specific factors.
Venezuela. We continue to experience delays in collecting payments on our receivables from our primary customer in
Venezuela. These outstanding receivables are not disputed, and we have not historically had material write-offs relating to this
customer. We are actively managing our strategic relationship with this customer, with ongoing dialogue between key
executives of both companies, including discussions regarding this customer's intention to pay outstanding receivables. We will
continue to vigorously pursue collection as we do business going forward in accordance with applicable U.S. sanctions.
During 2016, we exchanged $200 million of accounts receivables with our primary customer in Venezuela for an
interest-bearing promissory note with a par value of the same amount. We recognized a pre-tax loss on the exchange of $148
million at that time and had been accreting the carrying amount of the note to its par value from the third quarter of 2016
through the fourth quarter of 2017. We received our first principal payment in November 2017 and received five scheduled
interest payments since the note’s inception, but have not received the principal and interest payments scheduled in December
2017. In November 2017, several credit rating agencies downgraded this customer’s credit rating, some as low as a default
level.
50
As a result of this credit downgrade, delayed payments, and deteriorating market conditions in Venezuela, we changed
our accounting for our promissory note from held-to-maturity to available-for-sale, will no longer accrete the value of the note
going forward, and will mark the note to its fair market value on a quarterly basis with any unrealized gains and losses included
as a component of accumulated other comprehensive loss. Accordingly, we recognized an aggregate charge of $385 million
during the fourth quarter of 2017, consisting of $77 million for a fair market value adjustment of the note and $308 million for a
full reserve against our other accounts receivable with this customer. During the second quarter of 2017, we recognized a
charge of $262 million in anticipation of completing an additional note exchange with this customer. However, based on recent
executive management changes at, and recent conversations with, this customer, we no longer expect this transaction to take
place. The aggregate charges of $647 million during 2017 relating to Venezuela are included within "Impairments and other
charges" in our consolidated statements of operations.
As of December 31, 2017, we had $117 million in total outstanding net trade receivables in Venezuela, compared to
$610 million as of December 31, 2016. The majority of these receivables are United States dollar-denominated. Additionally,
the carrying amount of our existing promissory note was $32 million as of December 31, 2017 and classified as “Other assets”
on our consolidated balance sheets, compared to its par value of $175 million. We still intend to hold this promissory note to
maturity and will continue to vigorously pursue collection on this note and other accounts receivable with this customer.
On January 29, 2018, the Venezuelan government announced that it has changed the existing dual-rate foreign
exchange system by eliminating the DIPRO foreign exchange rate. All future currency transactions will now be carried out at
the DICOM floating rate. We are currently evaluating the impact that this change in foreign exchange system will have on our
business, consolidated results of operations and consolidated financial condition. This includes potential further write-downs of
our net investment in Venezuela, which was approximately $202 million as of December 31, 2017. See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations”
for additional information about the foreign currency exchange system in Venezuela, Note 12 for additional information about
the promissory note and Part I, Item 1(a), “Risk Factors” for additional information on risks associated with our operations in
Venezuela, including recent sanctions imposed in the country.
The following table presents a rollforward of our global allowance for bad debts for 2015, 2016 and 2017.
Millions of dollars
Year ended December 31, 2015
Year ended December 31, 2016
Year ended December 31, 2017
Note 4. Inventories
Balance at
Beginning of
Period
Charged to
Costs and
Expenses
Write-Offs
Balance at
End of
Period
$
137 $
145
175
44 $
50
568
(36)$
(20)
(18)
145
175
725
Inventories are stated at the lower of cost and net realizable value. In the United States, we manufacture certain
finished products and parts inventories for drill bits, completion products, bulk materials and other tools that are recorded using
the last-in, first-out method, which totaled $177 million at December 31, 2017 and $133 million at December 31, 2016. If the
average cost method had been used, total inventories would have been $31 million higher than reported as of December 31,
2017 and $16 million higher as of December 31, 2016. The cost of the remaining inventory was recorded using the average cost
method. Inventories consisted of the following:
Millions of dollars
Finished products and parts
Raw materials and supplies
Work in process
Total
December 31
2017
2016
$
$
1,547 $
703
146
2,396 $
1,388
778
109
2,275
All amounts in the table above are reported net of obsolescence reserves of $276 million at December 31, 2017 and
$263 million at December 31, 2016.
51
Note 5. Property, Plant and Equipment
Property, plant and equipment were composed of the following:
Millions of dollars
Land
Buildings and property improvements
Machinery, equipment and other
Total
Less accumulated depreciation
Net property, plant and equipment
Classes of assets are depreciated over the following useful lives:
December 31
2017
2016
$
$
248 $
3,460
17,062
20,770
12,249
8,521 $
228
3,399
16,103
19,730
11,198
8,532
Buildings and Property
Improvements
2017
11%
42%
22%
25%
2016
11%
42%
22%
25%
Machinery, Equipment
and Other
2017
35%
56%
9%
2016
34%
57%
9%
1
11
21
31
- 10 years
- 20 years
- 30 years
- 40 years
1
6
11
- 5 years
- 10 years
- 20 years
52
Note 6. Debt
Our total debt, including short-term borrowings and current maturities of long-term debt, consisted of the following:
Millions of dollars
5.0% senior notes due November 2045
3.8% senior notes due November 2025
3.5% senior notes due August 2023
4.85% senior notes due November 2035
7.45% senior notes due September 2039
4.75% senior notes due August 2043
6.7% senior notes due September 2038
3.25% senior notes due November 2021
4.5% senior notes due November 2041
2.0% senior notes due August 2018
7.6% senior notes due August 2096
8.75% senior debentures due February 2021
6.75% notes due February 2027
6.15% senior notes due September 2019
5.9% senior notes due September 2018
7.53% notes due May 2017
Other
Unamortized debt issuance costs and discounts
Total
Short-term borrowings and current maturities of long-term debt
Total long-term debt
December 31
2017
2016
$
$
2,000 $
2,000
1,100
1,000
1,000
900
800
500
500
400
300
185
104
—
—
—
251
(98)
10,942
(512)
10,430 $
2,000
2,000
1,100
1,000
1,000
900
800
500
500
400
300
185
104
1,000
400
45
260
(110)
12,384
(170)
12,214
Senior debt
All of our senior notes and debentures rank equally with our existing and future senior unsecured indebtedness, have
semiannual interest payments and have no sinking fund requirements. We may redeem all of our senior notes from time to time
or all of the notes of each series at any time at the applicable redemption prices, plus accrued and unpaid interest. Our 7.60%
and 8.75% senior debentures may not be redeemed prior to maturity.
In March 2017, we used cash on hand to redeem an aggregate principal amount of $1.4 billion of senior notes, which
consisted of $400 million of 5.9% senior notes due September 2018 and $1.0 billion of 6.15% senior notes due September
2019. In conjunction with this redemption, we terminated a series of interest rate swaps associated with these senior notes. As a
result, we recorded $104 million in costs related to the early extinguishment of debt, which included the redemption premium
and a write-off of the remaining original debt issuance costs and debt discount, partially offset by a gain from the termination of
the related interest rate swap agreements. These debt extinguishment costs are included in interest expense on our consolidated
statement of operations for the year ended December 31, 2017. We also repaid $45 million of notes that matured in May 2017.
Our $400 million of 2.0% senior notes will mature in August 2018, which we intend to repay with cash on hand.
Revolving credit facilities
We have a revolving credit facility with a capacity of $3.0 billion which expires in July 2020. The facility is for
working capital or general corporate purposes. The full amount of the revolving credit facility was available as of December 31,
2017.
Debt maturities
Our long-term debt matures as follows: $440 million in 2018, $30 million in 2019, $26 million in 2020, $709 million
in 2021, $14 million in 2022 and the remainder in 2023 and thereafter.
53
Note 7. Commitments and Contingencies
Securities and related litigation
In June 2002, a class action lawsuit was commenced against us in federal court alleging violations of the federal
securities laws in connection with our change in accounting for revenue on long-term construction projects and related
disclosures. In the weeks that followed, approximately twenty similar class actions were filed against us. The class action cases
were later consolidated, and the amended consolidated class action complaint was filed and served upon us in April 2003. In
June 2003, the plaintiffs filed a second amended consolidated complaint that included claims arising out of our 1998 acquisition
of Dresser Industries, Inc. and our disclosures and reserves relating to our asbestos liability exposure.
In December 2016, we reached an agreement in principle to settle this lawsuit, without any admission of liability and
subject to approval by the district court. During the second quarter of 2017, we paid approximately $54 million of the $100
million settlement fund, and our insurer paid the balance. On July 31, 2017, the district court issued final approval of the
settlement.
The settlement resolves all pending cases other than Magruder v. Halliburton Co., et. al. (the Magruder case). The
allegations arise out of the same general events described above, but for a later class period, December 8, 2001 to May 28,
2002. There has been limited activity in the Magruder case. In March 2009, our motion to dismiss was granted, with leave to re-
plead. In March 2012, plaintiffs filed an amended complaint and in May 2012, we filed another motion to dismiss, which
remains pending. We cannot predict the outcome or consequences of this case, which we intend to vigorously defend.
Environmental
We are subject to numerous environmental, legal and regulatory requirements related to our operations worldwide. In
the United States, these laws and regulations include, among others:
- the Comprehensive Environmental Response, Compensation and Liability Act;
- the Resource Conservation and Recovery Act;
- the Clean Air Act;
- the Federal Water Pollution Control Act;
- the Toxic Substances Control Act; and
- the Oil Pollution Act.
In addition to the federal laws and regulations, states and other countries where we do business often have numerous
environmental, legal and regulatory requirements by which we must abide. We evaluate and address the environmental impact
of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with
environmental, legal and regulatory requirements. Our Health, Safety and Environment group has several programs in place to
maintain environmental leadership and to help prevent the occurrence of environmental contamination. On occasion we are
involved in environmental litigation and claims, including the remediation of properties we own or have operated, as well as
efforts to meet or correct compliance-related matters. We do not expect costs related to those claims and remediation
requirements to have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial
position. Our accrued liabilities for environmental matters were $48 million as of December 31, 2017 and $50 million as of
December 31, 2016. Because our estimated liability is typically within a range and our accrued liability may be the amount on
the low end of that range, our actual liability could eventually be well in excess of the amount accrued. Our total liability
related to environmental matters covers numerous properties.
Additionally, we have subsidiaries that have been named as potentially responsible parties along with other third
parties for eight federal and state Superfund sites for which we have established reserves. As of December 31, 2017, those eight
sites accounted for approximately $5 million of our $48 million total environmental reserve. Despite attempts to resolve these
Superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount
accrued. With respect to some Superfund sites, we have been named a potentially responsible party by a regulatory agency;
however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims
with respect to environmental matters for which we have been named as a potentially responsible party.
Guarantee arrangements
In the normal course of business, we have agreements with financial institutions under which approximately $1.8
billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2017. Some of the outstanding
letters of credit have triggering events that would entitle a bank to require cash collateralization. None of these off balance sheet
arrangements either has, or is likely to have, a material effect on our consolidated financial statements.
54
Leases
We are party to numerous operating leases, primarily related to real estate, transportation and equipment. Total rentals
on our operating leases, net of sublease rentals, were $574 million in 2017, $587 million in 2016 and $875 million in 2015.
Future total rentals on our noncancellable operating leases are $720 million in the aggregate, which includes the
following: $166 million in 2018; $135 million in 2019; $100 million in 2020; $71 million in 2021; $54 million in 2022; and
$194 million thereafter.
Note 8. Income Taxes
The components of the benefit (provision) for income taxes on continuing operations were:
Millions of dollars
Current income taxes:
Federal
Foreign
State
Total current
Deferred income taxes:
Federal
Foreign
State
Total deferred
Income tax benefit (provision)
Year Ended December 31
2016
2017
2015
$
40 $
(423)
(14)
(397)
(678)
(31)
(25)
(734)
(1,131)$
$
737 $
(415)
35
357
1,343
77
81
1,501
1,858 $
635
(636)
51
50
(18)
262
(20)
224
274
The United States and foreign components of income (loss) from continuing operations before income taxes were as
follows:
Millions of dollars
United States
Foreign
Total
Year Ended December 31
2017
2016
2015
$
$
694 $
(6,636)$
(1,560)
(12)
(989)
682 $
(7,625)$
624
(936)
Reconciliations between the actual provision for income taxes on continuing operations and that computed by applying
the United States statutory rate to income (loss) from continuing operations before income taxes were as follows:
United States statutory rate
Impact of U.S. tax reform
Venezuela receivables adjustments
Impact of foreign income taxed at different rates
Valuation allowance against tax assets
Undistributed foreign earnings
Adjustments of prior year taxes
State income taxes
Domestic manufacturing deduction
Non-deductible acquisition costs
Other items, net
Year Ended December 31
2017
2016
2015
35.0%
35.0%
35.0%
113.0
36.6
(18.3)
(6.2)
3.8
(2.3)
1.7
—
—
2.5
—
—
(3.2)
(2.1)
(5.1)
0.2
1.0
(1.3)
0.6
(0.7)
—
(7.5)
17.0
(8.3)
—
1.3
2.0
—
(4.5)
(5.7)
Total effective tax rate on continuing operations
165.8%
24.4%
29.3%
55
Our effective tax rate on continuing operations was 165.8% for 2017, 24.4% for 2016 and 29.3% for 2015. For the
year ended December 31, 2017, we had the following significant items impacting our effective tax rate:
– we recorded an aggregate charge of $647 million on Venezuela receivables for which we are not recognizing a
corresponding tax benefit. See Note 3 to the consolidated financial statements for further information;
– we recorded $770 million of tax expenses associated with United States tax reform, as described below; and
– we recognized income in our foreign operations in which the corresponding tax expenses are applied at lower
statutory rates in certain jurisdictions.
On December 22, 2017, the President of the United States signed into law what is informally called the Tax Cuts and Jobs
Act of 2017 (the “Act”), a comprehensive U.S. tax reform package that, effective January 1, 2018, among other things, lowered the
corporate income tax rate from 35% to 21% and moved the country towards a territorial tax system with a one-time mandatory tax
on previously deferred foreign earnings of foreign subsidiaries. Under the accounting rules, companies are required to recognize the
effects of changes in tax laws and tax rates on deferred tax assets and liabilities in the period in which the new legislation is enacted.
The effects of the Act on Halliburton include three major categories: (i) recognition of liabilities for taxes on mandatory deemed
repatriation, (ii) remeasurement of deferred taxes and (iii) reassessment of the realizability of deferred tax assets. As described
further below, we recorded a total provision to income taxes of $770 million in the year ended December 31, 2017. As we do not
have all the necessary information to analyze all income tax effects of the Act, this is a provisional amount which we believe
represents a reasonable estimate of the accounting implications of this tax reform. We will continue to evaluate the Act and adjust the
provisional amounts as additional information is obtained. The ultimate impact of tax reform may differ from our provisional
amounts due to changes in our interpretations and assumptions, as well as additional regulatory guidance that may be issued.
We expect to complete our detailed analysis no later than the fourth quarter of 2018. Below is a brief description of each of
the three categories of effects from U.S. tax reform and its impact on us:
(i)
(ii)
(iii)
Liability for taxes due on mandatory deemed repatriation - under the Act, a company’s foreign earnings accumulated
under the legacy tax laws are deemed to be repatriated into the United States. We recorded a provisional estimate of
federal and state tax related to deemed repatriation in the amount of approximately $305 million. However, we had an
existing United States tax liability associated with foreign earnings that were not permanently reinvested outside the
United States in the amount of $435 million. It is now expected that these foreign earnings can be repatriated to the
United States without any additional United States tax above the amount accrued related to the mandatory deemed
repatriation. Accordingly, we released the entire $435 million liability. This $435 million release combined with the
provisional amount accrued related to the mandatory deemed repatriation of $305 million resulted in us recognizing a
net benefit of approximately $130 million for this item. We are currently analyzing the potential tax liabilities
attributable to any additional repatriation, but we have yet to determine whether we plan to change our prior assertion
and repatriate any additional earnings. Accordingly, we have not recorded any deferred taxes attributable to other
investments in our foreign subsidiaries. We will record the tax effects of any change in our prior assertion in the period
that we complete our analysis and are able to make a reasonable estimate, and disclose any unrecognized deferred tax
liability for temporary differences related to our foreign investments, if practicable.
Remeasurement of deferred taxes - under the Act, the U.S. corporate income tax rate was reduced from 35% to 21%.
Accordingly, we remeasured our U.S. deferred tax assets as of December 31, 2017 to a 21% rate, resulting in a tax
expense of $283 million.
Reassessment of the realizability of deferred tax assets - under the Act, many of the foreign tax credit utilization rules
were changed that required us to reassess the realizability of our foreign tax credit deferred tax asset. After review, it
was determined that under the new U.S. foreign tax credit rules we would not ultimately realize the full benefit
associated with our foreign tax credits at December 31, 2017. Accordingly, we recognized a provisional estimate of a
valuation allowance related to our foreign tax credits in the amount of $575 million. In addition, we had recorded
foreign tax credit benefits associated with a liability related to uncertain tax benefits recorded on foreign branches of
our U.S. subsidiaries. We determined that these foreign tax credits would also ultimately become unrealizable.
Accordingly, a provision of approximately $40 million was recognized.
56
The primary components of our deferred tax assets and liabilities were as follows:
Millions of dollars
Gross deferred tax assets:
Net operating loss carryforwards
Foreign tax credit carryforwards
Employee compensation and benefits
Accrued liabilities
Other
Total gross deferred tax assets
Gross deferred tax liabilities:
Depreciation and amortization
Undistributed foreign earnings
Other
Total gross deferred tax liabilities
Valuation allowances
Net deferred income tax asset
December 31
2017
2016
1,370 $
828
263
97
416
2,974
315
242
56
613
1,173
1,188 $
1,647
648
352
325
536
3,508
585
406
145
1,136
453
1,919
$
$
At December 31, 2017, we had $1.4 billion of domestic and foreign tax-effected net operating loss carryforwards. The
ultimate realization of these deferred tax assets depends on the ability to generate sufficient taxable income in the appropriate
taxing jurisdiction. $161 million of the net operating loss carryforwards will expire after taxable years ended from 2018 through
2022, $160 million will expire after taxable years ended from 2023 through 2027, and $693 million will expire after taxable
years ended from 2028 through 2037. The remaining balance will not expire. Additionally, we had $911 million of foreign tax
credit carryforwards that will expire from 2023 through 2027, which are offset by foreign branch deferred activity reflected in
the above table, along with $102 million of research and development tax credit carryforwards that will expire from 2028
through 2037.
The following table presents a rollforward of our unrecognized tax benefits and associated interest and penalties.
Millions of dollars
Unrecognized
Tax Benefits
Interest
and Penalties
$
$
$
Balance at January 1, 2015
Change in prior year tax positions
Change in current year tax positions
Cash settlements with taxing authorities
Lapse of statute of limitations
Balance at December 31, 2015
Change in prior year tax positions
Change in current year tax positions
Cash settlements with taxing authorities
Lapse of statute of limitations
Balance at December 31, 2016
Change in prior year tax positions
Change in current year tax positions
Cash settlements with taxing authorities
Lapse of statute of limitations
Balance at December 31, 2017
56
7
1
(15)
(2)
47
20
3
(8)
(1)
61
—
2
—
(3)
60
Includes $9 million as of December 31, 2017 and $84 million as of December 31, 2016 in foreign unrecognized tax
benefits that would give rise to a United States tax credit. As of December 31, 2017 and December 31, 2016,
approximately $319 million and $257 million, respectively, of unrecognized tax benefits would positively impact the
effective tax rate and be recognized as additional tax benefits in our statement of operations if resolved in our favor.
314
(33)
62
(16)
(5)
322
44
129
(62)
(6)
427 (a)
(108)
24
(6)
(4)
333 (a)(b) $
(a)
$
$
$
$
(b) Includes $23 million that could be resolved within the next 12 months.
We file income tax returns in the United States federal jurisdiction and in various states and foreign jurisdictions. In
most cases, we are no longer subject to state, local, or non-United States income tax examination by tax authorities for years
57
before 2009. Tax filings of our subsidiaries, unconsolidated affiliates and related entities are routinely examined in the normal
course of business by tax authorities. Currently, our United States federal tax filings for the tax years 2012 through 2015 are
under review by the Internal Revenue Service, and the appeal process is closed for the tax years 2010 through 2011.
Note 9. Shareholders’ Equity
Shares of common stock
The following table summarizes total shares of common stock outstanding:
Millions of shares
Issued
In treasury
Total shares of common stock outstanding
December 31
2017
2016
1,069
(196)
873
1,070
(204)
866
Our Board of Directors has authorized a program to repurchase our common stock from time to time. The program
does not require a specific number of shares to be purchased and the program may be effected through solicited or unsolicited
transactions in the market or in privately negotiated transactions. The program may be terminated or suspended at any time.
There were no repurchases made under the program during the years ended December 31, 2017 and 2016. Approximately $5.7
billion remains authorized for repurchases as of December 31, 2017. From the inception of this program in February 2006
through December 31, 2017, we repurchased approximately 201 million shares of our common stock for a total cost of
approximately $8.4 billion.
Preferred stock
Our preferred stock consists of five million total authorized shares at December 31, 2017, of which none are issued.
Accumulated other comprehensive loss
Accumulated other comprehensive loss consisted of the following:
Millions of dollars
Defined benefit and other postretirement liability adjustments (a)
Cumulative translation adjustment
Other
Total accumulated other comprehensive loss
December 31
2017
2016
$
$
(334)$
(313)
(80)
(55)
(80)
(61)
(469)$
(454)
(a) Included net actuarial losses for our international pension plans of $295 million at December 31, 2017 and
$290 million at December 31, 2016.
Note 10. Stock-based Compensation
The following table summarizes stock-based compensation costs for the years ended December 31, 2017, 2016 and
2015.
Millions of dollars
Stock-based compensation cost
Tax benefit
Stock-based compensation cost, net of tax
Year Ended December 31
2017
2016
2015
$
$
290 $
(64)
226 $
262 $
(77)
185 $
294
(99)
195
58
Our Stock and Incentive Plan, as amended (Stock Plan), provides for the grant of any or all of the following types of
stock-based awards:
- stock options, including incentive stock options and nonqualified stock options;
- restricted stock awards;
- restricted stock unit awards;
- stock appreciation rights; and
- stock value equivalent awards.
There are currently no stock appreciation rights, stock value equivalent awards, or incentive stock options outstanding.
Under the terms of the Stock Plan, approximately 206 million shares of common stock have been reserved for issuance to
employees and non-employee directors. At December 31, 2017, approximately 19 million shares were available for future
grants under the Stock Plan. The stock to be offered pursuant to the grant of an award under the Stock Plan may be authorized
but unissued common shares or treasury shares.
In addition to the provisions of the Stock Plan, we also have stock-based compensation provisions under our Restricted
Stock Plan for Non-Employee Directors and our Employee Stock Purchase Plan (ESPP).
Each of the active stock-based compensation arrangements is discussed below.
Stock options
The majority of our options are generally issued during the second quarter of the year. All stock options under the
Stock Plan are granted at the fair market value of our common stock at the grant date. Employee stock options generally vest
ratably over a three-year period and expire 10 years from the grant date. Compensation expense for stock options is generally
recognized on a straight line basis over the entire vesting period.
The following table represents our stock options activity during 2017.
Outstanding at January 1, 2017
Granted
Exercised
Forfeited/expired
Outstanding at December 31, 2017
Exercisable at December 31, 2017
Number
of Shares
(in millions)
Weighted
Average
Exercise
Price
per Share
Weighted
Average
Remaining
Contractual
Term (years)
Aggregate
Intrinsic
Value
(in millions)
20.6 $
2.5
(1.4)
(0.7)
21.0 $
15.0 $
44.01
48.39
36.60
47.99
44.92
45.04
6.3 $
5.4 $
138
105
The total intrinsic value of options exercised was $21 million in 2017, $25 million in 2016 and $9 million in 2015. As
of December 31, 2017, there was $48 million of unrecognized compensation cost, net of estimated forfeitures, related to
nonvested stock options, which is expected to be recognized over a weighted average period of approximately two years.
Cash received from issuance of common stock was $158 million during 2017, $186 million during 2016 and $167
million during 2015, of which $53 million, $80 million and $23 million related to proceeds from exercises of stock options in
2017, 2016 and 2015, respectively. The remainder relates to cash proceeds from the issuance of shares related to our employee
stock purchase plan.
The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The
expected volatility of options granted was a blended rate based upon implied volatility calculated on actively traded options on
our common stock and upon the historical volatility of our common stock. The expected term of options granted was based
upon historical observation of actual time elapsed between date of grant and exercise of options for all employees. The
assumptions and resulting fair values of options granted were as follows:
59
Expected term (in years)
Expected volatility
Expected dividend yield
Risk-free interest rate
Year Ended December 31
2017
5.24
32%
2016
5.21
37%
2015
5.16
39%
1.28 - 1.72% 1.35 - 2.46% 1.51 - 1.85%
1.79 - 2.14% 1.13 - 1.84% 1.43 - 1.72%
Weighted average grant-date fair value per share
$13.11
$12.33
$13.47
Restricted stock
Restricted shares issued under the Stock Plan are restricted as to sale or disposition. These restrictions lapse
periodically generally over a period of five years. Restrictions may also lapse for early retirement and other conditions in
accordance with our established policies. Upon termination of employment, shares on which restrictions have not lapsed must
be returned to us, resulting in restricted stock forfeitures. The fair market value of the stock on the date of grant is amortized
and charged to income on a straight-line basis over the requisite service period for the entire award.
The following table represents our restricted stock awards and restricted stock units granted, vested and forfeited
during 2017.
Nonvested shares at January 1, 2017
Granted
Vested
Forfeited
Nonvested shares at December 31, 2017
Number of
Shares
(in millions)
Weighted
Average
Grant-Date Fair
Value per Share
44.96
15.1 $
5.6
(4.5)
(1.1)
15.1 $
45.99
44.40
46.25
45.42
The weighted average grant-date fair value of shares granted was $45.99 during 2017, $42.87 during 2016 and $43.24
during 2015. The total fair value of shares vested was $204 million during 2017, $223 million during 2016, and $211 million
during 2015. As of December 31, 2017, there was $448 million of unrecognized compensation cost, net of estimated forfeitures,
related to nonvested restricted stock, which is expected to be recognized over a weighted average period of three years.
Employee Stock Purchase Plan
Under the ESPP, eligible employees may have up to 10% of their earnings withheld, subject to some limitations, to be
used to purchase shares of our common stock. The ESPP contains four three-month offering periods commencing on January 1,
April 1, July 1 and October 1 of each year. The price at which common stock may be purchased under the ESPP is equal to 85%
of the lower of the fair market value of the common stock on the commencement date or last trading day of each offering
period. Under this plan, 74 million shares of common stock have been reserved for issuance. The stock to be offered may be
authorized but unissued common shares or treasury shares. As of December 31, 2017, 46 million shares have been sold through
the ESPP since the inception of the plan and 28 million shares are available for future issuance.
The fair value of ESPP shares was estimated using the Black-Scholes option pricing model. The expected volatility
was a one-year historical volatility of our common stock. The assumptions and resulting fair values were as follows:
Expected volatility
Expected dividend yield
Risk-free interest rate
29%
1.51%
0.86%
36%
1.87%
0.25%
Weighted average grant-date fair value per share
$
9.95 $
8.61 $
35%
1.82%
0.01%
8.62
Year Ended December 31
2017
2016
2015
60
Note 11. Income per Share
Basic income or loss per share is based on the weighted average number of common shares outstanding during the
period. Diluted income per share includes additional common shares that would have been outstanding if potential common
shares with a dilutive effect had been issued. Antidilutive securities represent potentially dilutive securities which are excluded
from the computation of diluted income or loss per share as their impact was antidilutive.
A reconciliation of the number of shares used for the basic and diluted income per share computations is as follows:
Millions of shares
Basic weighted average common shares outstanding
Dilutive effect of awards granted under our stock incentive plans
Diluted weighted average common shares outstanding
Antidilutive shares:
Options with exercise price greater than the average market price
Options which are antidilutive due to net loss position
Total antidilutive shares
Year Ended December 31
2017
2016
2015
870
—
870
6
2
8
861
—
861
11
1
12
853
—
853
10
2
12
Note 12. Financial Instruments and Risk Management
At December 31, 2017, we held $106 million of investments in fixed income securities with maturities ranging from
less than one year to November 2020, of which $69 million are classified as “Other current assets” and $37 million are
classified as “Other assets” on our consolidated balance sheets. At December 31, 2016, we held $92 million of investments in
fixed income securities. These securities consist primarily of corporate bonds and other debt instruments, are accounted for as
available-for-sale and are recorded at fair value based on quoted prices for identical assets in less active markets, which are
categorized within level 2 on the fair value hierarchy.
We have an interest-bearing promissory note with our primary customer in Venezuela. At December 31, 2017, the
carrying amount of this note was $32 million compared to its par value of $175 million. At December 31, 2016, the carrying
amount of this note was $70 million compared to its par value of $200 million. Fair market value was measured based on
pricing data points for similar assets in an illiquid market and categorized within level 3 on the fair value hierarchy. We had
been using an effective interest method to accrete the carrying amount to its par value as it matures with accretion income being
recorded through “Interest expense, net of interest income” on our consolidated statements of operations. During the fourth
quarter of 2017, we changed our accounting for our promissory note from held-to-maturity to available-for-sale and will no
longer accrete the value of the note going forward. Instead, we are required to mark the note to its fair market value on a
quarterly basis with any unrealized gains and losses included as a component of accumulated other comprehensive loss. See
Note 3 for additional information about our promissory note from our primary customer in Venezuela.
The carrying amount of cash and equivalents, receivables and accounts payable, as reflected in the consolidated
balance sheets, approximates fair value due to the short maturities of these instruments.
The carrying amount and fair value of our total debt, including short-term borrowings and current maturities of long
term debt, is as follows:
December 31, 2017
December 31, 2016
Millions of dollars
Level 1
Level 2
Total debt
$
3,285 $
9,172 $
Total fair
value
12,457 $
Carrying
value
10,942 $
Level 1
Level 2
753 $
12,812 $
Total fair
value
13,565 $
Carrying
value
12,384
Our debt categorized within level 1 on the fair value hierarchy is calculated using quoted prices in active markets for
identical liabilities with transactions occurring on the last two days of period-end. Our debt categorized within level 2 on the
fair value hierarchy is calculated using significant observable inputs for similar liabilities where estimated values are
determined from observable data points on our other bonds and on other similarly rated corporate debt or from observable data
points of transactions occurring prior to two days from period-end and adjusting for changes in market conditions. Our total fair
61
value and carrying value of debt decreased in 2017 compared to 2016 primarily due to the early extinguishment of $1.4 billion
of senior notes. Additionally, differences between the periods presented in our level 1 and level 2 classification of our long-term
debt relate to the timing of when transactions are executed. We have no debt categorized within level 3 on the fair value
hierarchy based on unobservable inputs.
We are exposed to market risk from changes in foreign currency exchange rates and interest rates. We selectively
manage these exposures through the use of derivative instruments, including forward foreign exchange contracts, foreign
exchange options and interest rate swaps. The objective of our risk management strategy is to minimize the volatility from
fluctuations in foreign currency and interest rates. We do not use derivative instruments for trading purposes. The fair value of
our forward contracts, options and interest rate swaps was not material as of December 31, 2017 or December 31, 2016. The
counterparties to our derivatives are primarily global commercial and investment banks.
Foreign currency exchange risk
We have operations in many international locations and are involved in transactions denominated in currencies other
than the United States dollar, our functional currency, which exposes us to foreign currency exchange rate risk. Techniques in
managing foreign currency exchange risk include, but are not limited to, foreign currency borrowing and investing and the use
of currency exchange instruments. We attempt to selectively manage significant exposures to potential foreign currency
exchange losses based on current market conditions, future operating activities and the associated cost in relation to the
perceived risk of loss. The purpose of our foreign currency risk management activities is to minimize the risk that our cash
flows from the purchase and sale of products and services in foreign currencies will be adversely affected by changes in
exchange rates.
We use forward contracts and options to manage our exposure to fluctuations in the currencies of certain countries in
which we do business internationally. These instruments are not treated as hedges for accounting purposes, generally have an
expiration date of one year or less and are not exchange traded. While these instruments are subject to fluctuations in value, the
fluctuations are generally offset by the value of the underlying exposures being managed. The use of some of these instruments
may limit our ability to benefit from favorable fluctuations in foreign currency exchange rates.
Derivatives are not utilized to manage exposures in some currencies due primarily to the lack of available markets or
cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency
exposure in non-traded currencies and recognize that pricing for the services and products offered in these countries should
account for the cost of exchange rate devaluations. We have historically incurred transaction losses in non-traded currencies.
The notional amounts of open foreign exchange derivatives were $633 million at December 31, 2017 and $603 million
at December 31, 2016. The notional amounts of these instruments do not generally represent amounts exchanged by the parties,
and thus are not a measure of our exposure or of the cash requirements related to these contracts. As such, cash flows related to
these contracts are typically not material. The amounts exchanged are calculated by reference to the notional amounts and by
other terms of the contracts, such as exchange rates.
Interest rate risk
We are subject to interest rate risk on our existing long-term debt and some of our long-term investments in fixed
income securities. Our short-term borrowings and short-term investments in fixed income securities do not give rise to
significant interest rate risk due to their short-term nature. We had fixed rate long-term debt totaling $10.4 billion at
December 31, 2017 and $12.2 billion at December 31, 2016. We also had $37 million of long-term investments in fixed income
securities at December 31, 2017 with maturities that extend through November 2020.
62
We maintain an interest rate management strategy that is intended to mitigate the exposure to changes in interest rates
in the aggregate for our debt portfolio. We use interest rate swaps to effectively convert a portion of our fixed rate debt to
floating LIBOR-based rates. Our interest rate swaps, which expire when the underlying debt matures, are designated as fair
value hedges of the underlying debt and are determined to be highly effective. These derivative instruments are marked to
market with gains and losses recognized currently in interest expense to offset the respective gains and losses recognized on
changes in the fair value of the hedged debt. During the first quarter of 2017, we terminated a series of our interest rate swaps
with a notional amount of $1.4 billion in conjunction with our early redemption of senior notes. We included the gain from the
swap termination in our calculation of early debt extinguishment costs. See Note 6 for further information. As of December 31,
2017, we had one remaining interest rate swap relating to one of our debt instruments with a total notional amount of $100
million. The fair value of our interest rate swaps as of December 31, 2017 and December 31, 2016 are included in “Other
assets” in our consolidated balance sheets and were immaterial. The fair value of our interest rate swaps are categorized within
level 2 on the fair value hierarchy and were determined using an income approach model with inputs, such as the notional
amount, LIBOR rate spread and settlement terms that are observable in the market or can be derived from or corroborated by
observable data.
Credit risk
Financial instruments that potentially subject us to concentrations of credit risk are primarily cash equivalents,
investments in fixed income securities, trade receivables and a promissory note we hold with our primary customer in
Venezuela. It is our practice to place our cash equivalents and investments in fixed income securities in high quality
investments with various institutions. Our revenue is generated from selling products and providing services to the energy
industry. Our trade receivables are from a broad and diverse group of customers and are generally not collateralized. As of
December 31, 2017, 42% of our net trade receivables were from customers in the United States. As of December 31, 2016, 27%
of our net trade receivables were from customers in the United States and 15% were from customers in Venezuela. We maintain
an allowance for bad debts based upon several factors, including historical collection experience, current aging status of the
customer accounts and financial condition of our customers. See Note 3 for further information.
We do not have any significant concentrations of credit risk with any individual counterparty to our derivative
contracts. We select counterparties to those contracts based on our belief that each counterparty’s profitability, balance sheet and
capacity for timely payment of financial commitments is unlikely to be materially adversely affected by foreseeable events.
Note 13. Retirement Plans
Our company and subsidiaries have various plans that cover a significant number of our employees. These plans
include defined contribution plans, defined benefit plans and other postretirement plans:
- our defined contribution plans provide retirement benefits in return for services rendered. These plans provide an
individual account for each participant and have terms that specify how contributions to the participant’s account are
to be determined rather than the amount of pension benefits the participant is to receive. Contributions to these plans
are based on pretax income and/or discretionary amounts determined on an annual basis. Our expense for the
defined contribution plans for continuing operations totaled $173 million in 2017, $111 million in 2016 and $288
million in 2015. The increase in 2017 resulted from an increase in the domestic workforce and the reinstatement of
discretionary contributions in 2017.
- our defined benefit plans, which include both funded and unfunded pension plans, define an amount of pension
benefit to be provided, usually as a function of age, years of service and/or compensation. The unfunded obligations
and net periodic benefit cost of our United States defined benefit plans were not material for the periods presented;
and
- our postretirement plans other than pensions are offered to specific eligible employees. The accumulated benefit
obligations and net periodic benefit cost for these plans were not material for the periods presented.
Funded status
For our international pension plans, at December 31, 2017, the projected benefit obligation was $1.2 billion and the
fair value of plan assets was $940 million, which resulted in an unfunded obligation of $280 million. At December 31, 2016, the
projected benefit obligation was $1.1 billion and the fair value of plan assets was $865 million, which resulted in an unfunded
obligation of $241 million. The accumulated benefit obligation was approximately the same as the projected benefit obligation
for our international plans in both years presented.
63
The following table presents additional information about our international pension plans.
Millions of dollars
Amounts recognized on the Consolidated Balance Sheets
Accrued employee compensation and benefits
Employee compensation and benefits
Pension plans in which projected benefit obligation exceeded plan assets
Projected benefit obligation
Fair value of plan assets
Pension plans in which accumulated benefit obligation exceeded plan assets
Accumulated benefit obligation
Fair value of plan assets
$
$
$
December 31
2017
2016
15 $
267
1,202 $
920
1,139 $
920
16
227
1,083
840
1,037
840
Fair value measurements of plan assets
The fair value of our plan assets categorized within level 1 on the fair value hierarchy is based on quoted prices in
active markets for identical assets. The fair value of our plan assets categorized within level 2 on the fair value hierarchy is
based on significant observable inputs for similar assets. The fair value of our plan assets categorized within level 3 on the fair
value hierarchy is based on significant unobservable inputs.
The following table sets forth the fair values of assets held by our international pension plans by level within the fair
value hierarchy.
Millions of dollars
Cash and equivalents
Common/collective trust funds (a)
Equity funds (b)
Bond funds (c)
Alternatives funds (d)
Real estate funds (e)
Other assets
Fair value of plan assets at December 31, 2017
Cash and equivalents
Common/collective trust funds (a)
Equity funds (b)
Bond funds (c)
Alternatives funds (d)
Real estate funds (e)
Other assets
Fair value of plan assets at December 31, 2016
Level 1
Level 2
Level 3
Total
— $
—
—
—
—
7
7 $
— $
—
—
—
—
5
5 $
11 $
204
323
184
98
22
842 $
49 $
197
232
221
36
20
755 $
— $
—
46
—
28
17
91 $
— $
—
44
—
35
26
105 $
11
204
369
184
126
46
940
49
197
276
221
71
51
865
$
$
$
$
(a) Common/collective trust funds are valued at the net asset value of units held by the plans at year-end.
(b) Strategy is to invest in diversified funds of global common stocks.
(c) Strategy is to invest in diversified funds of fixed income securities of varying geographies and credit quality and whose cash flows approximate the
maturities of the benefit obligation.
(d) Strategy is to invest in a fund of diversifying investments, including but not limited to reinsurance, commodities and currencies.
(e) Strategy is to invest in diversified funds of real estate investment trusts and private real estate.
Our investment strategy varies by country depending on the circumstances of the underlying plan. Risk management
practices include diversification by issuer, industry and geography, as well as the use of multiple asset classes and investment
managers within each asset class. Our investment strategy for our United Kingdom pension plan, which constituted 84% of our
international pension plans’ projected benefit obligation at December 31, 2017 and is no longer accruing service benefits, aims
to achieve full funding of the benefit obligation, with the plan's assets increasingly composed of investments whose cash flows
match the maturities of the obligation.
64
Net periodic benefit cost
Net periodic benefit cost for our international pension plans was $30 million in 2017, $30 million in 2016 and $42
million in 2015. Included in net periodic benefit cost were $13 million in 2017 and $8 million in 2016 of net curtailment and
settlement cost arising from reductions in workforce during these years.
Actuarial assumptions
Certain weighted-average actuarial assumptions used to determine benefit obligations of our international pension
plans at December 31 were as follows:
Discount rate
Rate of compensation increase
2017
2.8%
5.5%
2016
2.9%
4.8%
Certain weighted-average actuarial assumptions used to determine net periodic benefit cost of our international
pension plans for the years ended December 31 were as follows:
Discount rate
Expected long-term return on plan assets
Rate of compensation increase
2017
2.9%
4.2%
4.8%
2016
4.2%
5.3%
5.4%
2015
4.1%
5.9%
5.3%
Assumed long-term rates of return on plan assets, discount rates for estimating benefit obligations and rates of
compensation increases vary by plan according to local economic conditions. Where possible, discount rates were determined
based on the prevailing market rates of a portfolio of high-quality debt instruments with maturities matching the expected
timing of the payment of the benefit obligations. Expected long-term rates of return on plan assets were determined based upon
an evaluation of our plan assets and historical trends and experience, taking into account current and expected market
conditions.
Other information
Contributions. Funding requirements for each plan are determined based on the local laws of the country where such
plan resides. In certain countries the funding requirements are mandatory, while in other countries they are discretionary. We
currently expect to contribute $17 million to our international pension plans in 2018.
Benefit payments. Expected benefit payments over the next 10 years for our international pension plans are as follows:
$68 million in 2018, $61 million in 2019, $63 million in 2020, $67 million in 2021, $72 million in 2022 and $424 million in
years 2023 through 2027.
Note 14. New Accounting Pronouncements
Standards adopted in 2017
Stock-Based Compensation
On January 1, 2017, we adopted an accounting standards update issued by the Financial Accounting Standards Board
(FASB) which simplifies several aspects of accounting for share-based payment transactions, including the income tax
consequences, classification of awards as either equity or liabilities and the classification on the statement of cash flows. In
addition, the update allows an entity-wide accounting policy election to either estimate the number of awards that are expected
to vest or account for forfeitures when they occur. The element of the update that has the most impact on our financial
statements is income tax consequences. Excess tax benefits and tax deficiencies on stock-based compensation awards are now
included in our tax provision within our consolidated statement of operations as discrete items in the reporting period in which
they occur, rather than previous accounting of recording in additional paid-in capital on our consolidated balance sheets. We
have also elected to continue our current policy of estimating forfeitures of stock-based compensation awards at the time of
grant and revising in subsequent periods to reflect actual forfeitures. We applied the update prospectively beginning January 1,
2017, and the adoption did not have a material impact on our consolidated financial statements.
65
Intra-Entity Transfers of Assets
On January 1, 2017, we adopted an accounting standards update issued by the FASB to improve the accounting for the
income tax consequences of intra-entity transfers of assets other than inventory. The update requires an entity to recognize the
income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs, rather than the
previous requirement to defer recognition of current and deferred income taxes for an intra-entity asset transfer until the asset
had been sold to an outside party. Two common examples of assets included in the scope of this update are intellectual property
and property, plant and equipment. The update was applied on a modified retrospective basis resulting in a cumulative-effect
adjustment of $384 million recorded directly to retained earnings as of January 1, 2017.
Inventory
On January 1, 2017, we adopted an accounting standards update issued by the FASB which simplifies the
measurement of inventory. The update now requires inventory measured using the first in, first out or average cost methods to
be subsequently measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the
ordinary course of business, less reasonably predictable cost of completion, disposal and transportation. The update eliminated
the requirement to subsequently measure inventory at the lower of cost or market, which could be replacement cost, net
realizable value, or net realizable value less an approximately normal profit margin. The adoption of this update did not impact
our consolidated financial statements.
Standards not yet adopted
Revenue Recognition
In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede existing revenue
recognition guidance under U.S. GAAP. The core principle of the new guidance is that a company should recognize revenue to
depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the
company expects to be entitled in exchange for those goods or services. The standard creates a five step model that requires
companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard
allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods
presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in
the financial statements with a cumulative-effect adjustment reflected in retained earnings. The standard also requires expanded
disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of
revenue and cash flows arising from contracts with customers. This new revenue recognition standard will be effective for
annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.
We performed a detailed review of our contract portfolio representative of our different businesses and compared
historical accounting policies and practices to the new standard. Because the standard will impact our business processes,
systems and controls, we also developed a comprehensive change management project plan to guide the implementation. Over
the course of 2017, we have conducted training sessions for those in our global organization that will be impacted by the new
standard and have developed a web-based training course providing a detailed overview of the key changes within the new
standard. Our services are primarily short-term in nature, and we do not expect the new revenue recognition standard to have a
material impact on our financial statements. We adopted the new standard effective January 1, 2018 utilizing the modified
retrospective method. The cumulative-effect adjustment to retained earnings upon adoption is not material.
Leases
In February 2016, the FASB issued an accounting standards update related to accounting for leases, which requires the
assets and liabilities that arise from leases to be recognized on the balance sheet. Currently only capital leases are recorded on
the balance sheet. This update will require the lessee to recognize a lease liability equal to the present value of the lease
payments and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases longer than
12 months. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of
underlying asset not to recognize lease assets and liabilities and recognize the lease expense for such leases generally on a
straight-line basis over the lease term. The new lease standard will be effective for fiscal periods beginning after December 15,
2018, including interim periods within that reporting period. We are currently evaluating the impact that this update will have
on our consolidated financial statements.
66
HALLIBURTON COMPANY
Selected Financial Data
(Unaudited)
Millions of dollars except per share
2017
2016
2015
2014
2013
Year ended December 31
Revenue
Operating income (loss)
Income (loss) from continuing operations
Basic income (loss) per share from continuing operations
Diluted income (loss) per share from continuing operations
Cash dividends per share
Net working capital
Total assets
Long-term debt
Total shareholders’ equity
Capital expenditures
$
20,620 $
15,887 $
23,633 $
32,870 $
29,402
1,362
(449)
(0.51)
(0.51)
0.72
5,915
25,085
10,430
8,349
1,373
(6,778)
(5,767)
(6.69)
(6.69)
0.72
7,654
27,000
12,214
9,448
798
(165)
(662)
(0.78)
(0.78)
0.72
14,733
36,942
14,687
15,495
2,184
5,097
3,437
4.05
4.03
0.63
8,781
32,165
7,765
16,298
3,283
3,138
2,116
2.35
2.33
0.525
8,678
29,223
7,816
13,615
2,934
67
HALLIBURTON COMPANY
Quarterly Data and Market Price Information
(Unaudited)
Quarter
Millions of dollars except per share data
First
Second
Third
Fourth
Year
2017
Revenue
Operating income
Net income (loss)
Amounts attributable to company shareholders:
Income (loss) from continuing operations
Loss from discontinued operations
Net income (loss) attributable to company
Basic and diluted per share attributable to company shareholders:
Income (loss) from continuing operations
Loss from discontinued operations
Net income (loss)
Cash dividends paid per share
Common stock prices (1)
High
Low
2016
Revenue
Operating income (loss)
Net income (loss)
Amounts attributable to company shareholders:
Income (loss) from continuing operations
Loss from discontinued operations
Net income (loss) attributable to company
Basic and diluted net income (loss) per share
Cash dividends paid per share
Common stock prices (1)
High
Low
$
4,279 $
4,957 $
5,444 $
5,940 $
20,620
203
(32)
(32)
—
(32)
(0.04)
—
(0.04)
0.18
146
28
28
—
28
0.03
—
0.03
0.18
634
361
365
—
365
0.42
—
0.42
0.18
379
(825)
(805)
(19)
(824)
(0.92)
(0.02)
(0.94)
0.18
1,362
(468)
(444)
(19)
(463)
(0.51)
(0.02)
(0.53)
0.72
58.78
47.52
51.26
41.36
46.18
38.18
49.29
40.72
58.78
38.18
$
4,198 $
3,835 $
3,833 $
4,021 $
15,887
(3,079)
(2,418)
(3,880)
(3,205)
(2,410)
(3,208)
(2)
—
(2,412)
(3,208)
(2.81)
0.18
(3.73)
0.18
128
7
6
—
6
0.01
0.18
53
(153)
(6,778)
(5,769)
(149)
(5,761)
—
(149)
(0.17)
0.18
(2)
(5,763)
(6.69)
0.72
36.74
27.64
46.69
33.26
46.90
40.12
56.08
44.23
56.08
27.64
Note: Results for the fourth quarter of 2017 include charges for U.S. tax reform and Venezuela receivables. See Note 8 and Note 3 for further information. Results for 2016
include merger-related costs and termination fee and impairments and other charges.
(1) New York Stock Exchange – composite transactions high and low intraday price.
68
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The information required for the directors of the Registrant is incorporated by reference to the Halliburton Company
Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the captions “Election of Directors”
and “Involvement in Certain Legal Proceedings.” The information required for the executive officers of the Registrant is
included under Part I on pages 5 through 6 of this annual report. The information required for a delinquent form required under
Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the Halliburton Company Proxy Statement
for our 2018 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Section 16(a) Beneficial Ownership
Reporting Compliance,” to the extent any disclosure is required. The information for our code of ethics is incorporated by
reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492)
under the caption “Corporate Governance.” The information regarding our Audit Committee and the independence of its
members, along with information about the audit committee financial expert(s) serving on the Audit Committee, is incorporated
by reference to the Halliburton Company Proxy Statement for our 2018 Annual Meeting of Stockholders (File No. 001-03492)
under the caption “The Board of Directors and Standing Committees of Directors.”
Item 11. Executive Compensation.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual
Meeting of Stockholders (File No. 001-03492) under the captions “Compensation Discussion and Analysis,” “Compensation
Committee Report,” “Summary Compensation Table,” “Grants of Plan-Based Awards in Fiscal 2017,” “Outstanding Equity
Awards at Fiscal Year End 2017,” “2017 Option Exercises and Stock Vested,” “2017 Nonqualified Deferred Compensation,”
“Employment Contracts and Change-in-Control Arrangements,” “Post-Termination or Change-in-Control Payments,” “Equity
Compensation Plan Information” and “Directors’ Compensation.”
Item 12(a). Security Ownership of Certain Beneficial Owners.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual
Meeting of Stockholders (File No. 001-03492) under the caption “Stock Ownership of Certain Beneficial Owners and
Management.”
Item 12(b). Security Ownership of Management.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual
Meeting of Stockholders (File No. 001-03492) under the caption “Stock Ownership of Certain Beneficial Owners and
Management.”
Item 12(c). Changes in Control.
Not applicable.
Item 12(d). Securities Authorized for Issuance Under Equity Compensation Plans.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual
Meeting of Stockholders (File No. 001-03492) under the caption “Equity Compensation Plan Information.”
Item 13. Certain Relationships and Related Transactions, and Director Independence.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual
Meeting of Stockholders (File No. 001-03492) under the caption “Corporate Governance” to the extent any disclosure is
required and under the caption “The Board of Directors and Standing Committees of Directors.”
Item 14. Principal Accounting Fees and Services.
This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2018 Annual
Meeting of Stockholders (File No. 001-03492) under the caption “Fees Paid to KPMG LLP.”
69
PART IV
Item 15. Exhibits.
1.
Financial Statements:
The reports of the Independent Registered Public Accounting Firm and the financial statements of Halliburton
Company as required by Part II, Item 8, are included on pages 38 through 40 and pages 41 through 66 of this
annual report. See index on page (i).
Financial Statement Schedules:
The schedules listed in Rule 5-04 of Regulation S-X (17 CFR 210.5-04) have been omitted because they are
not applicable or the required information is shown in the consolidated financial statements or notes thereto.
Exhibits:
2.
3.
Exhibit
Number
Exhibits
3.1
3.2
4.1
4.2
4.3
4.4
4.5
Restated Certificate of Incorporation of Halliburton Company filed with the Secretary of State of Delaware on
May 30, 2006 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed June 5, 2006, File No.
001-03492).
By-laws of Halliburton Company revised effective December 7, 2017 (incorporated by reference to Exhibit 3.1
to Halliburton’s Form 8-K filed December 12, 2017, File No. 001-03492).
Form of debt security of 8.75% Debentures due February 12, 2021 (incorporated by reference to Exhibit 4(a) to
the Form 8-K of Halliburton Company, now known as Halliburton Energy Services, Inc. (the Predecessor),
dated as of February 20, 1991, File No. 001-03492).
Senior Indenture dated as of January 2, 1991 between the Predecessor and The Bank of New York Trust
Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee (incorporated by
reference to Exhibit 4(b) to the Predecessor’s Registration Statement on Form S-3 (Registration No. 33-38394)
originally filed with the Securities and Exchange Commission on December 21, 1990), as supplemented and
amended by the First Supplemental Indenture dated as of December 12, 1996 among the Predecessor,
Halliburton and the Trustee (incorporated by reference to Exhibit 4.1 of Halliburton’s Registration Statement
on Form 8-B dated December 12, 1996, File No. 001-03492).
Resolutions of the Predecessor’s Board of Directors adopted at a meeting held on February 11, 1991 and of the
special pricing committee of the Board of Directors of the Predecessor adopted at a meeting held on February
11, 1991 and the special pricing committee’s consent in lieu of meeting dated February 12, 1991 (incorporated
by reference to Exhibit 4(c) to the Predecessor’s Form 8-K dated as of February 20, 1991, File No. 001-03492).
Second Senior Indenture dated as of December 1, 1996 between the Predecessor and The Bank of New York
Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, as
supplemented and amended by the First Supplemental Indenture dated as of December 5, 1996 between the
Predecessor and the Trustee and the Second Supplemental Indenture dated as of December 12, 1996 among the
Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.2 of Halliburton’s Registration
Statement on Form 8-B dated December 12, 1996, File No. 001-03492).
Third Supplemental Indenture dated as of August 1, 1997 between Halliburton and The Bank of New York
Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, to the Second
Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.7 to Halliburton’s Form
10-K for the year ended December 31, 1998, File No. 001-03492).
70
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
Fourth Supplemental Indenture dated as of September 29, 1998 between Halliburton and The Bank of New
York Trust Company, N.A. (as successor to Texas Commerce Bank National Association), as Trustee, to the
Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.8 to
Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 001-03492).
Resolutions of Halliburton’s Board of Directors adopted by unanimous consent dated December 5, 1996
(incorporated by reference to Exhibit 4(g) of Halliburton’s Form 10-K for the year ended December 31, 1996,
File No. 001-03492).
Form of debt security of 6.75% Notes due February 1, 2027 (incorporated by reference to Exhibit 4.1 to
Halliburton’s Form 8-K dated as of February 11, 1997, File No. 001-03492).
Copies of instruments that define the rights of holders of miscellaneous long-term notes of Halliburton
Company and its subsidiaries have not been filed with the Commission. Halliburton Company agrees to furnish
copies of these instruments upon request.
Form of Indenture dated as of April 18, 1996 between Dresser and The Bank of New York Trust Company,
N.A. (as successor to Texas Commerce Bank National Association), as Trustee (incorporated by reference to
Exhibit 4 to Dresser’s Registration Statement on Form S-3/A filed on April 19, 1996, Registration No. 333-
01303), as supplemented and amended by Form of First Supplemental Indenture dated as of August 6, 1996
between Dresser and The Bank of New York Trust Company, N.A. (as successor to Texas Commerce Bank
National Association), Trustee, for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4.1 to
Dresser’s Form 8-K filed on August 9, 1996, File No. 1-4003).
Second Supplemental Indenture dated as of October 27, 2003 between DII Industries, LLC and The Bank of
New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Indenture dated as
of April 18, 1996 (incorporated by reference to Exhibit 4.15 to Halliburton’s Form 10-K for the year ended
December 31, 2003, File No. 001-03492).
Third Supplemental Indenture dated as of December 12, 2003 among DII Industries, LLC, Halliburton
Company and The Bank of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as
Trustee, to the Indenture dated as of April 18, 1996, (incorporated by reference to Exhibit 4.16 to Halliburton’s
Form 10-K for the year ended December 31, 2003, File No. 001-03492).
Indenture dated as of October 17, 2003 between Halliburton Company and The Bank of New York Trust
Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to
Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 001-03492).
Second Supplemental Indenture dated as of December 15, 2003 between Halliburton Company and The Bank
of New York Trust Company, N.A. (as successor to JPMorgan Chase Bank), as Trustee, to the Senior Indenture
dated as of October 17, 2003 (incorporated by reference to Exhibit 4.27 to Halliburton’s Form 10-K for the
year ended December 31, 2003, File No. 001-03492).
4.15
Form of note of 7.6% debentures due 2096 (included as Exhibit A to Exhibit 4.14 above).
4.16
Fourth Supplemental Indenture, dated as of September 12, 2008, between Halliburton Company and The Bank
of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank, to the Senior
Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K
filed September 12, 2008, File No. 001-03492).
4.17
Form of Global Note for Halliburton’s 6.70% Senior Notes due 2038 (included as part of Exhibit 4.16).
4.18
Fifth Supplemental Indenture, dated as of March 13, 2009, between Halliburton Company and The Bank of
New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank, to the Senior Indenture
dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K filed March
13, 2009, File No. 001-03492).
71
4.19
Form of Global Note for Halliburton’s 7.45% Senior Notes due 2039 (included as part of Exhibit 4.18).
4.20
Sixth Supplemental Indenture, dated as of November 14, 2011, between Halliburton Company and The Bank
of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank, to the Senior
Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K
filed November 14, 2011, File No. 001-03492).
4.21
Form of Global Note for Halliburton’s 3.25% Senior Notes due 2021 (included as part of Exhibit 4.20).
4.22
Form of Global Note for Halliburton’s 4.50% Senior Notes due 2041 (included as part of Exhibit 4.20).
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
Seventh Supplemental Indenture, dated as of August 5, 2013, between Halliburton Company and The Bank of
New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank (incorporated by
reference to Exhibit 4.2 of Halliburton’s Form 8-K filed August 5, 2013, File No. 001-03492).
Form of Global Note for Halliburton’s 2.00% Senior Notes due 2018 (included as part of Exhibit 4.23).
Form of Global Note for Halliburton’s 3.50% Senior Notes due 2023 (included as part of Exhibit 4.23).
Form of Global Note for Halliburton’s 4.75% Senior Notes due 2043 (included as part of Exhibit 4.23).
Eighth Supplemental Indenture, dated as of November 13, 2015, between Halliburton Company and The Bank
of New York Mellon Trust Company, N.A., as successor trustee to JPMorgan Chase Bank (incorporated by
reference to Exhibit 4.2 to Halliburton’s Form 8-K filed November 13, 2015, File No. 001-03492).
Form of Global Note for Halliburton’s 3.800% Senior Notes due 2025 (included as part of Exhibit 4.27).
Form of Global Note for Halliburton’s 4.850% Senior Notes due 2035 (included as part of Exhibit 4.27).
Form of Global Note for Halliburton’s 5.000% Senior Notes due 2045 (included as part of Exhibit 4.27).
†
10.1
Halliburton Company Restricted Stock Plan for Non-Employee Directors (incorporated by reference to
Appendix B of the Predecessor’s proxy statement dated March 23, 1993, File No. 001-03492).
†
10.2
†
10.3
10.4
10.5
Dresser Industries, Inc. Deferred Compensation Plan, as amended and restated effective January 1, 2000
(incorporated by reference to Exhibit 10.16 to Halliburton’s Form 10-K for the year ended December 31, 2000,
File No. 001-03492).
ERISA Excess Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1, 1995
(incorporated by reference to Exhibit 10.7 to Dresser’s Form 10-K for the year ended October 31, 1995, File
No. 1-4003).
Form of Indemnification Agreement for Officers (incorporated by reference to Exhibit 10.1 to Halliburton’s
Form 8-K filed August 3, 2007, File No. 001-03492).
Form of Indemnification Agreement for Directors (incorporated by reference to Exhibit 10.2 to Halliburton’s
Form 8-K filed August 3, 2007, File No. 001-03492).
72
10.6
10.7
†
10.8
†
10.9
Form of Indemnification Agreement for Officers (first elected after January 1, 2013) (incorporated by reference
to Exhibit 10.2 to Halliburton's Form 10-Q for the quarter ended March 31, 2013, File No. 001-03492).
Form of Indemnification Agreement for Directors (first elected after January 1, 2013) (incorporated by
reference to Exhibit 10.1 of Halliburton’s Form 8-K filed March 22, 2013, File No. 001-03492).
2008 Halliburton Elective Deferral Plan, as amended and restated effective January 1, 2008 (incorporated by
reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No. 001-
03492).
Halliburton Company Supplemental Executive Retirement Plan, as amended and restated effective January 1,
2008 (incorporated by reference to Exhibit 10.4 to Halliburton’s Form 10-Q for the quarter ended September
30, 2007, File No. 001-03492).
†
10.10
Halliburton Company Benefit Restoration Plan, as amended and restated effective January 1, 2008
(incorporated by reference to Exhibit 10.5 to Halliburton’s Form 10-Q for the quarter ended September 30,
2007, File No. 001-03492).
†
10.11
Halliburton Company Pension Equalizer Plan, as amended and restated effective March 1, 2007 (incorporated
by reference to Exhibit 10.8 to Halliburton’s Form 10-Q for the quarter ended September 30, 2007, File No.
001-03492).
†
10.12
Halliburton Company Directors' Deferred Compensation Plan, as amended and restated effective as of May 16,
2012 (incorporated by reference to Exhibit 10.5 to Halliburton's Form 10-Q for the quarter ended June 30,
2012, File No. 001-03492).
†
10.13
Retirement Plan for the Directors of Halliburton Company, as amended and restated effective July 1, 2007
(incorporated by reference to Exhibit 10.10 to Halliburton’s Form 10-Q for the quarter ended September 30,
2007, File No. 001-03492).
†
10.14
Halliburton Company Employee Stock Purchase Plan, as amended and restated effective February 24, 2015
(incorporated by reference to Appendix C of Halliburton’s proxy statement filed April 7, 2015, File No. 001-
03492).
†
10.15
First Amendment to Halliburton Company Supplemental Executive Retirement Plan, as amended and restated
effective January 1, 2008 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed September
21, 2009, File No. 001-03492).
†
10.16
Amendment No. 1 to Halliburton Company Benefit Restoration Plan, as amended and restated effective
January 1, 2008 (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-K filed September 21,
2009, File No. 001-03492).
†
10.17
Amendment No. 1 to 2008 Halliburton Elective Deferral Plan, as amended and restated effective January 1,
2008 (incorporated by reference to Exhibit 10.41 to Halliburton’s Form 10-K for the year ended December 31,
2010, File No. 001-03492).
10.18
U.S. $3,000,000,000 Five Year Revolving Credit Agreement among Halliburton Company, as Borrower, the
Banks party thereto, and Citibank, N.A., as Agent, effective July 21, 2015 (incorporated by reference to Exhibit
10.1 to Halliburton's Form 10-Q for the quarter ended June 30, 2015, File No. 001-03492).
†
10.19
First Amendment to the Retirement Plan for the Directors of Halliburton Company, effective September 1,
2007 (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended March 31,
2011, File No. 001-03492).
73
†
10.20
†
10.21
†
10.22
First Amendment to Halliburton Company Restricted Stock Plan for Non-Employee Directors (incorporated by
reference to Exhibit 10.41 to Halliburton’s Form 10-K for the year ended December 31, 2011, File No. 001-
03492).
Second Amendment to Restricted Stock Plan for Non-Employee Directors of Halliburton Company
(incorporated by reference to Exhibit 10.4 to Halliburton's Form 10-Q for the quarter ended June 30, 2012, File
No. 001-03492).
Third Amendment to Restricted Stock Plan for Non-Employee Directors of Halliburton Company effective
December 1, 2012 (incorporated by reference to Exhibit 10.44 to Halliburton’s Form 10-K for the year ended
December 31, 2012, File No. 001-03492).
†
10.23
First Amendment dated December 1, 2012 to Halliburton Company Directors' Deferred Compensation Plan, as
amended and restated effective May 16, 2012 (incorporated by reference to Exhibit 10.45 to Halliburton’s
Form 10-K for the year ended December 31, 2012, File No. 001-03492).
†
10.24
Executive Agreement (Myrtle L. Jones) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q
for the quarter ended March 31, 2013, File No. 001-03492).
†
10.25
†
10.26
10.27
Executive Agreement (Timothy McKeon) (incorporated by reference to Exhibit 10.49 to Halliburton’s Form
10-K filed February 7, 2014, File No. 001-03492).
Executive Agreement (Charles E. Geer, Jr.) (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-
K filed December 9, 2014, File No. 001-03492).
HESI Punitive Damages and Assigned Claims Settlement Agreement dated September 2, 2014, entered into
between Halliburton Company and Halliburton Energy Services, Inc. and counsel for The Plaintiffs Steering
Committee in MDL 2179 and the Deepwater Horizon Economic and Property Damages Settlement Class
(incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q for the quarter ended September 30,
2014, File No. 001-03492).
†
10.28
Form of Non-Employee Director Restricted Stock Agreement (Directors Plan) (incorporated by reference as
Exhibit 99.5 of Halliburton's Form S-8 filed May 21, 2009, Registration No. 333-159394).
†
10.29
Form of Non-Employee Director Restricted Stock Agreement (Stock and Incentive Plan) (incorporated by
reference to Exhibit 10.43 to Halliburton's Form 10-K for the year ended December 31, 2011, Registration No.
001-03492).
10.30
Termination Agreement, dated as of April 30, 2016, between the Company and Baker Hughes (incorporated by
reference to Exhibit 10.1 to Halliburton’s Form 8-K filed May 4, 2016, File No. 001-03492).
† 10.31
Amendment No. 2 to Halliburton Company Benefit Restoration Plan, as amended and restated effective
January 1, 2008 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended
September 30, 2016, File No. 001-03492).
† 10.32
Second Amendment to Halliburton Company Supplemental Executive Retirement Plan, as amended and
restated effective January 1, 2008 (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the
quarter ended September 30, 2016, File No. 001-03492).
† 10.33
Executive Agreement (Joe D. Rainey) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 8-K
filed December 12, 2017, File No. 001-03492).
†
10.34
Executive Agreement (Anne Lyn Beaty) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 10-Q
filed April 28, 2017, File No. 001-03492).
74
†
10.35
Executive Agreement (David J. Lesar) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 8-K
filed May 23, 2017, File No. 001-03492).
†
10.36
Executive Agreement (James S. Brown) (incorporated by reference to Exhibit 10.2 to Halliburton's Form 8-K
filed May 23, 2017, File No. 001-03492).
†
10.37
Executive Agreement (Jeffrey A. Miller) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 8-K
filed June 5, 2017, File No. 001-03492).
†
10.38
Halliburton Company Stock and Incentive Plan, as amended and restated effective February 8, 2017
(incorporated by reference to Appendix B of Halliburton's proxy statement filed April 7, 2017, File No. 001-
03492).
†
10.39
Form of Nonstatutory Stock Option Agreement (U.S.) (incorporated by reference as Exhibit 99.2 of
Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
†
10.40
Form of Nonstatutory Stock Option Agreement (International) (incorporated by reference as Exhibit 99.3 of
Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
†
10.41
Form of Restricted Stock Agreement (incorporated by reference as Exhibit 99.4 of Halliburton's Form S-8 filed
June 7, 2017, Registration No. 333-218568).
†
10.42
Form of Restricted Stock Unit Agreement (International) (incorporated by reference as Exhibit 99.5 of
Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
†
10.43
Form of Restricted Stock Unit Agreement (U.S. Expat) (incorporated by reference as Exhibit 99.6 of
Halliburton's Form S-8 filed June 7, 2017, Registration No. 333-218568).
†
10.44
Executive Agreement (Christopher T. Weber) (incorporated by reference to Exhibit 10.1 to Halliburton's Form
8-K filed June 13, 2017, File No. 001-03492).
†
10.45
Form of Non-Management Director Restricted Stock Unit Agreement (Stock and Incentive Plan) (incorporated
by reference as Exhibit 10.1 of Halliburton's Form 10-Q filed October 27, 2017, File No. 001-03492).
*† 10.46
Executive Agreement (Eric J. Carre).
*† 10.47
Executive Agreement (Lawrence J. Pope).
*† 10.48
Executive Agreement (Robb L. Voyles).
*
*
*
*
12.1
Statement of Computation of Ratio of Earnings to Fixed Charges.
21.1
Subsidiaries of the Registrant.
23.1
Consent of KPMG LLP.
24.1
Powers of attorney for the following directors signed in January 2018:
Abdulaziz F. Al Khayyal
William E. Albrecht
Alan M. Bennett
75
James R. Boyd
Milton Carroll
Nance K. Dicciani
Murry S. Gerber
José C. Grubisich
David J. Lesar
Robert A. Malone
J. Landis Martin
Debra L. Reed
*
*
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
** 32.1
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
** 32.2
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*
*
*
*
*
*
*
95
Mine Safety Disclosures.
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema Document
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB XBRL Taxonomy Extension Label Linkbase Document
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF XBRL Taxonomy Extension Definition Linkbase Document
* Filed with this Form 10-K.
** Furnished with this Form 10-K.
† Management contracts or compensatory plans or arrangements.
Item 16. Form 10-K Summary.
None.
76
SIGNATURES
As required by Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has authorized this report to be signed
on its behalf by the undersigned authorized individuals on this 9th day of February, 2018.
HALLIBURTON COMPANY
By
/s/ Jeffrey A. Miller
Jeffrey A. Miller
President and Chief Executive Officer
As required by the Securities Exchange Act of 1934, this report has been signed below by the following persons in the
capacities indicated on this 9th day of February, 2018.
Signature
Title
/s/ Jeffrey A. Miller
Jeffrey A. Miller
President, Director and
Chief Executive Officer
/s/ Christopher T. Weber
Christopher T. Weber
Executive Vice President and
Chief Financial Officer
/s/ Charles E. Geer, Jr.
Charles E. Geer, Jr.
Vice President and
Corporate Controller
77
Signature
* Abdulaziz F. Al Khayyal
Abdulaziz F. Al Khayyal
* William E. Albrecht
William E. Albrecht
* Alan M. Bennett
Alan M. Bennett
* James R. Boyd
James R. Boyd
* Milton Carroll
Milton Carroll
* Nance K. Dicciani
Nance K. Dicciani
* Murry S. Gerber
Murry S. Gerber
* José C. Grubisich
José C. Grubisich
* David J. Lesar
David J. Lesar
* Robert A. Malone
Robert A. Malone
* J. Landis Martin
J. Landis Martin
* Debra L. Reed
Debra L. Reed
/s/ Robb L. Voyles
*By Robb L. Voyles, Attorney-in-fact
Title
Director
Director
Director
Director
Director
Director
Director
Director
Executive Chairman of the Board and Director
Director
Director
Director
78
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SHARES LISTED
New York Stock Exchange
Symbol: HAL
TRANSFER AGENT & REGISTRAR
Computershare Investor Services
462 South 4th Street, Suite 1600
Louisville, KY 40202
Telephone: 800-279-1227
www.computershare.com/investor
To contact Halliburton Investor Relations,
shareholders may call the Company at
888.669.3920 or 281.871.2688, or send a
message via email to:
investors@halliburton.com
281.871.2699
www.halliburton.com
©2018 Halliburton. All Rights Reserved.
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