281.871.2699
www.halliburton.com
© 2014 Halliburton. All Rights Reserved.
Printed in the USA
H010964
2013 Annual Report
WHAT
DRIVES
US
WHAT
DRIVES US
At Halliburton, the things that drive us
keep us ahead. In this report, you will
read about our insistence on setting
bold goals, our focus on execution
certainty and our determination to
live up to the commitments we make
to all of our stakeholders. You will also
read about how we are staying the
course with the consistent strategy
that drove our growth since our
2010 Analyst Day.
Key accomplishments over the past
three years:
DEEPWATER
Our deepwater revenue grew
31 percent per year, compared
to 13 percent for the industry.
MATURE FIELDS
We achieved our goal of
tripling the size of our
mature fields business.
UNCONVENTIONALS
We led in North America,
with revenue growth
exceeding 70%.
EXECUTION CERTAINTY
Frac of the Future,™ coupled with our
proprietary Battle Red smart phone field
management tools, takes efficiency and
reliability to new levels. In addition, we are
also seeing environmental benefits from
the use of natural gas-powered vehicles
and pump trucks.
SHAREHOLDER INFORMATION //
Shares Listed
New York Stock Exchange
Symbol: HAL
Transfer Agent and Registrar
Computershare
P.O. Box 30170
College Station, Texas 77842-3170
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
This annual report is printed on environmentally
responsible paper, which is FSC-certified (portions
of which are 100% post-consumer recycled paper).
DESIGN: SAVAGE BRANDS, HOUSTON, TX
APPLIED TECHNOLOGY
Halliburton continues to lead in delivering
pragmatic technologies that address our
customers’ challenges. With the opening
of new technology centers in Brazil and
Saudi Arabia, we continue globalizing
our technology footprint for greater
responsiveness to customer needs.
INTERNATIONAL FOOTPRINT
Our new completion tools manufacturing
facility in Singapore supports our
Eastern Hemisphere operations and greatly
reduces the delivery times and costs
needed to service this growing market.
This is part of a strategic initiative to locate
our infrastructure closer to the wellhead.
OVER
60%
CONSISTENT STRATEGY
In 2013, our three key
growth markets –
deepwater, mature fields
and unconventionals –
contributed over 60 percent
of our global revenue.
(Millions of dollars and shares, except per share data)
2013
2012
2011
Revenue
$ 29,402
3,138
Operating Income
ooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooo
$
$ 28,503
4,159
$
oooooooooooooooooooooo
$ 24,829
$ 4,737
oooooooooooooooooooooo
Amounts Attributable to
Company Shareholders:
Income from Continuing Operations
2,106
2,125
ooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooo
Net Income
$
$
Diluted Income per Share Attributable
to Company Shareholders:
Income from Continuing Operations
2.33
2.36
ooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooo
Net Income
$
$
Cash Dividends per Share
Diluted Weighted Average
Common Shares Outstanding
Working Capital 1
Capital Expenditures
Long-Term Debt
$ 0.525
902
$ 8,678
$ 2,934
$
7,816
CYPHER SM
CYPHER SM is an industry-leading integrated
seismic-to-stimulation software platform
incorporating seismic, logging, production and
other data to build a full-scale asset model capable
of predicting production with up to 93% accuracy
during early trials. With each successive well,
CYPHER SM gets “smarter” and becomes more
accurate at helping customers decide where to
drill their well, where to land their well, where
to complete and how to complete.
$ 2,577
$ 2,635
oooooooooooooooooooooo
$ 3,005
$ 2,839
oooooooooooooooooooooo
2.78
$
2.84
$
oooooooooooooooooooooo
$
0.36
928
$ 8,334
$
3,566
$ 4,820
3.26
$
3.08
$
oooooooooooooooooooooo
$
0.36
922
$
7,456
$ 2,953
$ 4,820
Debt to Total Capitalization2
37%
24%
27%
Depreciation, Depletion and Amortization
$
1,900
$
1,628
$
1,359
Return on Average Capital Employed3
11%
15%
19%
Total Capitalization4
$ 21,569
$ 20,764
$ 18,097
1 Working Capital is defined as total current assets less total current liabilities.
2 Debt to Total Capitalization is defined as total debt divided by the sum of total debt plus total shareholders’ equity.
3 Return on Average Capital Employed is defined as net income before net interest expense divided by average
capital employed. Capital employed includes total debt and total shareholders’ equity.
4 Total Capitalization is defined as total debt plus total shareholders’ equity.
Revenue
in billions
$24.8
Operating Income
in billions
*
$28.5
$29.4
$4.7
Return on Average
*
Capital Employed
19%
$4.2
$3.1
15%
11%
Gulf of Mexico
Successfully used for
three deepwater wells
in the Gulf of Mexico,
Halliburton’s Enhanced
Single-Trip Multizone™
completion system was
named “Best Deepwater
Technology” at the World
Oil awards.
11
12
13
11
12
13
11
12
13
* Includes a $1 billion
charge in 2013 and a
$300 million charge
in 2012 related to the
Macondo well incident.
2
HALLIBURTON // 2013 A N N UA L R EPORT
FINANCIAL HIGHLIGHTS //
ICE Core TM
ICE Core (Integrated Computational Element)
performs laboratory-grade analysis on downhole
fluids during drilling operations. Spectroscopy is
used to determine fluids composition, and the solid
state tool design ensures maximum reliability.
Bayan
Work began on the Bayan field in
Malaysia, a fully Integrated Asset
Management contract where
Halliburton can leverage its full
suite of products and services as
well as its extensive Consulting &
Project Management expertise.
A similar project was awarded in
the Humapa field of Mexico, where
work is expected to begin in 2014.
Saudi Arabia
Halliburton opened its new
Unconventional and Reservoir
Productivity Technology Center
in Saudi Arabia, providing state-of-
the-art solutions for conventional
and unconventional reservoirs in
the Kingdom and around the globe.
INTERNATIONAL OPPORTUNITY
Halliburton has invested aggressively to build its
international infrastructure and develop market
opportunities. Active in more than 80 countries,
we derived 48 percent of our 2013 revenue from
outside North America. We expect the balance to
continue shifting with the ongoing growth of our
international business.
APPLIED TECHNOLOGY
Our global team of experts work together, and
with our customers, to develop technology
solutions to some of the world’s most complex
energy challenges. We have a proven track record
of delivering technologies that are practical,
quickly deployed and complement our reputation
for outstanding service.
INTEGRATED SOLUTIONS
Integration of technologies and capabilities is the
key to efficiency and outstanding execution at
Halliburton. Integration drives consistency in our
operations all across the world, allows us to meet
technology challenges that cut across disciplines
and supports the robust workflows required to
execute complex projects.
3
WHAT DRIVES OUR GROWTH // At Halliburton, we believe in setting
bold goals that stretch our abilities,
drive our growth and reflect the
long-term prospects for our business.
Over the past three years, we grew
our deepwater business at double
the market rate, tripled the size of
our mature fields business, extended
our unconventionals leadership and
delivered superior returns relative
to our major competitors.
Halliburton’s success is rooted in a sound strategy executed by
an ambitious management team and a dedicated workforce that
is never satisfied with the status quo. We are driven to provide
execution certainty, deliver on our commitments and find new
ways to increase value for customers. Our strategic focus on
deepwater, mature fields and unconventionals has served us well,
and these high-growth segments will continue to fuel our growth.
Deepwater Shows Robust Activity
Over the past five years, 60 percent of the total volume of all
hydrocarbon discoveries were made in deepwater, and licensing
activity is at an all-time high. With deepwater activity expanding to
all regions of the world, the market is expected to grow 11 percent
annually over the next five years.
The development segment is projected to see the strongest
growth over the coming five years – 13 percent per year compared
to four percent for exploration. This trend will benefit Halliburton,
drawing on our number one position in completions, our
integration capabilities and our reputation for execution
certainty. By leveraging our infrastructure investments, building
on our leadership in deepwater development and introducing
technologies that maximize production from customer assets,
we believe we can continue to outgrow the deepwater market
by 25 percent over the next three years.
Mature Fields Play a Vital Role
On average, fields that are past their peak represent approximately
60 percent of International Oil Company (IOC) asset portfolios,
and their production is estimated to be declining by more than
eight percent per year. Compared to capital-intensive new
development projects, mature fields can generate attractive
returns for our customers and represent an important source
of cash flow for them.
Robust demand and a meaningful increase in service intensity
has multiplied revenue opportunities for large, integrated
service providers as the market moves from the provision of
discrete services to integrated solutions and ultimately to asset
management arrangements. Very few service companies have
the scale and the service portfolio to compete in this arena, which
offers stable, long-term growth with limited capital investment.
Our three-year goal is to again triple our mature fields business.
Unconventionals Market Gains Velocity
Over the past few years, the North American market shifted its
focus from natural gas to liquids. Full-scale development of major
unconventionals resource areas like the Permian Basin is now
underway for many of our customers, who are striving to achieve
the lowest cost per barrel of oil equivalent to ensure their economic
success. We believe Halliburton is ahead of the curve in serving this
market by providing the technologies, capabilities and expertise to
help our customers meet their objectives in this challenging high
velocity environment.
4
HALLIBURTON // 2013 A N N UA L R EPORT
WHAT DRIVES US //To Our Shareholders, Revenue
$29.4 Billion
Operating Income
$3.1 Billion
Net Income
$2.1 Billion
Cash Dividends
Per Share
$0.525
Capital
Expenditures
$2.9 Billion
Return on Average
Capital Employed
11 percent
We have made significant investments to ensure that we have
the correct tools and capabilities to deliver better producing wells,
built faster, at lower cost and with reduced risk. With the industry’s
most advanced delivery platform, we address both sides of the
value equation, offering cost savings through superior efficiency
plus advanced technologies and software that reduce uncertainty
and improve production. We plan to extend our leadership
position in North America and leverage our expertise to capture
opportunities in emerging international unconventional markets.
Delivering on Our Commitments
We are pleased with our operational performance in these key
markets. However, the ultimate measure of success for our
shareholders is how well we deliver on our financial commitments
to produce superior growth, margins and returns. During 2013, we
grew our revenue to a new record of $29.4 billion. We maintained
market leadership in North America and outgrew our primary
competitors in international markets, which now represent
48 percent of company revenue. International infrastructure
investments have supported our significant growth in these
markets and provide us a platform for future revenue and
margin growth.
During 2013, we demonstrated our strong commitment to
delivering superior shareholder returns and reiterated our continued
confidence in the strength of our business outlook. In addition to
raising our dividend twice, for a total payout increase of 67 percent
over our 2012 quarterly dividend rate, we repurchased approximately
$4.4 billion, or 10 percent, of our outstanding common shares.
We have been, and will continue to be, relentlessly focused on
delivering best-in-class returns.
Extending the Momentum
Through consistent execution of a proven strategy, we have built
a solid foundation on which to generate future growth and the
momentum to drive it forward. The established market leader in
North America, we continue to expand our global footprint to
address emerging growth opportunities in international markets.
We recognize the vital role our stakeholders play in our success.
We greatly appreciate the confidence our shareholders and
customers continue to show in Halliburton and the exceptional
contributions of our board of directors, employees and suppliers.
After reading this report and discovering what drives us, we are
confident that you will share our optimism and enthusiasm about
the road ahead for Halliburton.
DAVID J. LESAR
Chairman of the Board,
President and
Chief Executive Officer
JEFFREY A. MILLER
Executive Vice President,
Chief Operating Officer and
Chief Health, Safety and
Environment Officer
MARK A. McCOLLUM
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
and General Counsel
TIMOTHY J. PROBERT
Strategic Advisor to the
Chief Executive Officer
5
Halliburton’s deepwater growth rate was more than double
that of the deepwater market over the past three years.
We have invested aggressively to build our global infrastructure,
technologies and capabilities, transforming the company from
an emerging alternative into a compelling choice for customers
seeking the technology and execution certainty we are known for.
The results we delivered over the past three years demonstrate the
strength of our strategy to tap the large and growing deepwater
market. We substantially exceeded our commitment to outgrow
the market by at least 25 percent. We achieved revenue growth of
31 percent per year in a market that grew an average of 13 percent
annually over the same period. More importantly, we built a solid
foundation for the future, winning major contracts, strengthening
key customer relationships and greatly increasing our
competitiveness across the globe.
Infrastructure and Footprint
With more than $1 billion of infrastructure investments, we
expanded our operations beyond the “golden triangle” – Gulf of
Mexico, West Africa and Brazil – into 30 countries, establishing
a presence in all of the world’s deepwater markets. In addition
to adding more than 50 operations facilities, our investments
strengthened our capabilities to develop advanced technologies
that provide a competitive advantage in the challenging deepwater
arena. Our new technology development facilities include an
acoustic center where we are accelerating the development of
next-generation sonic tools, a perforating flow lab where we can
simulate the effect of perforation under downhole conditions to
reduce uncertainty, and a technology center in Brazil, the world’s
largest deepwater market.
Growth Through Technology
Adding to our broad suite of technologies to service the deepwater
market, we have commercialized approximately 30 impactful
products and services over the past three years. In addition to
technologies that build on our leadership in the finding and
completing phases of operations, we have launched innovations
that strengthen our position in drilling and evaluation. Our focus
on pragmatic technologies that fill identified needs has resulted
in strong market adoption. Wireline and sampling jobs are up
260 percent, use of our Dynalink wireless testing system has grown
185 percent and our ESTMZ (Enhanced Single-Trip Multizone)
completion system has captured 70 percent of the lower tertiary
market in the Gulf of Mexico. We expect these high-end, high-
margin technologies to be an ongoing driver of growth.
“Our vastly expanded footprint and technological capabilities have
made Halliburton competitive in deepwater markets around the world.
With the majority of our infrastructure investment behind us, our
growing deepwater business will improve cost absorption and drive
margins higher.”
TIMOTHY J. PROBERT
Strategic Advisor to the Chief Executive Officer
6
HALLIBURTON // 2013 A N N UA L R EPORT
WHAT DRIVES US //
Deepwater
7
WHAT DRIVES US //
Mature Fields
8
HALLIBURTON // 2013 A N N UA L R EPORT
Sixty-five percent of hydrocarbons discovered are left in
the reservoir today. With a large and growing percentage
of customer assets in decline, the significant incremental
production that can be delivered by increased recovery rates
has made mature fields a compelling growth segment in which
Halliburton tripled its revenue over the past three years.
The mature fields business offers a stable growth engine with
increasing levels of service intensity as new technologies are
deployed to boost recovery rates. Mature fields continue to
generate attractive returns and cash flow for our customers,
in turn driving strong demand for our services.
Opportunity Through Integration
We address the mature fields segment using three distinct
commercial models – discrete services, integrated projects and,
most recently, integrated asset management.
Halliburton’s comprehensive suite of discrete services and
technologies offers our customers a broad range of capabilities
to restore, maintain and grow production from mature assets.
Integrated solutions combine multiple technologies and services
needed to solve complex challenges across all aspects of mature
fields operations, including: sub-surface analysis, drilling and
completions infrastructure and facilities, and production
operations. Our integrated approach to service delivery increases
efficiency for our customers and provides enhanced growth
opportunities for Halliburton.
Well Positioned for Premium Segments
Halliburton is fortunate to be one of a select number of service
companies to have the technical, operational and financial
capability to execute integrated asset management engagement
on behalf of our customers. Over the past three years, we have
built mature asset capabilities and developed proprietary execution
models that have positioned us very well in this arena. These
projects are long in duration and provide a stable base for long-
term earnings. During 2013, we began work in the Bayan field in
Malaysia and received a contract for the Humapa field in Mexico,
where operations are expected to begin in 2014.
“Migrating our portfolio to incentivized asset management contracts is
a core element of our strategy to triple our mature fields business over
the next three years. By their integrated nature and long duration, these
arrangements allow us to leverage our service delivery infrastructure to
create steady revenue streams and attractive margins in an arena where
very few companies can compete.”
MARK A. McCOLLUM
Executive Vice President and Chief Financial Officer
9
Halliburton has built a leadership position in North American
unconventionals by anticipating the market’s evolution and
developing technology to meet emerging needs. Initiatives
underway for several years have prepared us for today’s high-
velocity environment where completing wells faster and better
are key elements in delivering the lowest cost per barrel of oil
equivalent (BOE).
Three years ago, we made a commitment to remain the undisputed
leader in unconventionals, and we have done so by executing on a
number of key strategies. We’ve focused holistically on the reservoir
performance and pioneered integrated solutions that cut across
product and service lines to solve customer challenges. More than
85 percent of our North American revenue now comes from
integrated services. We also have built the industry’s most efficient
and effective delivery platform and taken the lead in environmentally
sensitive solutions. Today, we are focused on leveraging proprietary
technologies like CYPHERSM to design and execute the best well
plans, and to be the lowest cost-per-barrel provider for our customers.
Introducing HALvantage™
Three years ago, we created a blueprint for Frac of the Future.™
Now a reality, this concept is a game changer that has improved all
aspects of surface efficiency, reducing our footprint as well as the
equipment, personnel and capital needed on location. We have
exceeded our own targets, reducing capital deployed by 20 percent,
lowering maintenance costs by 35 percent and improving completion
times by almost 40 percent at sites where Frac of the Future™ is
employed. This superior operational efficiency turns customer
well inventories into producing assets faster, lowers the cost to
deliver each BOE and represents a competitive differentiator
for Halliburton.
Frac of the Future™ is just one part of HALvantage,™ which is
extending our competitive advantage by taking efficiency to the
next level. After reinventing our delivery platform, we began
working to reduce non-operating time in the field. We are
implementing mobile technology to centralize and digitize internal
processes, eliminate touch points and bottlenecks, and streamline
operations – not just in unconventionals, but across all of our
product lines and businesses.
Expanding Internationally
Halliburton is carrying its unconventionals leadership into emerging
international markets, which are beginning to develop as countries
strive to gain energy independence. We drilled and completed
the first unconventional wells in many international markets.
In countries such as Australia, Argentina, China and Saudi Arabia,
we are able to leverage our established infrastructure to support
emerging unconventional opportunities.
“The initiatives that have created North America’s most efficient and
effective delivery platform are an example of how Halliburton continually
reinvents itself. Now we are refining efficiency even further, centralizing
and digitizing our internal processes across all of our product lines and
operations to extend the HALvantage.™”
JEFFREY A. MILLER
Executive Vice President, Chief Operating Officer and
Chief Health, Safety and Environment Officer
10
HALLIBURTON // 2013 A N N UA L R EPORT
WHAT DRIVES US //
Unconventionals
11
Vision & Leadership
Board of Directors
Corporate Officers
DAVID J. LESAR
Chairman of the Board,
President and Chief Executive Officer,
Halliburton Company (2000)
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
Retired President and
Chief Executive Officer,
Honeywell International Specialty Materials
(2009) (A) (C)
MURRY S. GERBER
Retired Executive Chairman of the Board,
EQT Corporation
(2012) (A) (B)
JOSÉ C. GRUBISICH
Chief Executive Officer,
Eldorado Brasil Celulose
(2013) (A) (C)
ABDALLAH S. JUM’AH
Retired President and
Chief Executive Officer,
Saudi Arabian Oil Company
(2010) (C) (D)
ROBERT A. MALONE
President and Chief Executive Officer,
First National Bank of Sonora, Texas
(2009) (B) (C)
J. LANDIS MARTIN
Founder and Managing Director,
Platte River Equity
(2005) (C) (D)
DEBRA L. REED
Chairman and Chief Executive Officer,
Sempra Energy
(2001) (B) (D)
DAVID J. LESAR
Chairman of the Board, President and
Chief Executive Officer
JEFFREY A. MILLER
Executive Vice President,
Chief Operating Officer and Chief
Health, Safety and Environment Officer
MARK A. McCOLLUM
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 and
General Counsel
TIMOTHY J. PROBERT
Strategic Advisor to the Chief Executive Officer
JAMES S. BROWN
President, Western Hemisphere
JOE D. RAINEY
President, Eastern Hemisphere
JAMES W. FERGUSON
Senior Vice President, Deputy General Counsel
and Chief Ethics and Compliance Officer
CHRISTIAN GARCIA
Senior Vice President and
Chief Accounting Officer
MYRTLE L. JONES
Senior Vice President, Tax
CHRISTINA M. IBRAHIM
Vice President and Corporate Secretary
TIMOTHY M. MCKEON
Vice President and Treasurer
(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
12
HALLIBURTON // 2013 A N N UA L R EPORT
WHAT DRIVES US // 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, 2013
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, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.
Large accelerated filer
Non-accelerated filer
[X]
[ ]
Accelerated filer
Smaller reporting 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, 2013, determined using the per share
closing price on the New York Stock Exchange Composite tape of $41.72 on that date, was approximately $38,003,000,000.
As of January 31, 2014, there were 850,866,860 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.
Portions of the Halliburton Company Proxy Statement for our 2014 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, 2013
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.
Directors, Executive Officers, and Corporate Governance
Executive Compensation
Item 12(a).
Security Ownership of Certain Beneficial Owners
Item 12(b).
Security Ownership of Management
Item 12(c).
Changes in Control
Item 12(d).
Securities Authorized for Issuance Under Equity Compensation Plans
Item 13.
Item 14.
PART IV
Item 15.
SIGNATURES
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits
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. We are a leading provider of services and products to the energy industry related to the exploration, development, and
production of oil and natural gas. 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:
- our Completion and Production segment delivers cementing, stimulation, intervention, pressure control, specialty
chemicals, artificial lift, and completion services. The segment consists of Production Enhancement, Cementing,
Completion Tools, Halliburton Boots & Coots, Multi-Chem, and Halliburton Artificial Lift.
- our Drilling and Evaluation segment 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 Baroid, Sperry Drilling, Wireline and Perforating, Drill Bits and Services, Landmark
Software and Services, Testing and Subsea, and Consulting and Project Management.
See Note 2 to the consolidated financial statements for further financial information related to each of our business
segments and a description of the services and products provided by each segment. We have significant manufacturing
operations in various locations, including the United States, Canada, Malaysia, Singapore, and the United Kingdom.
Business strategy
Our business strategy is to secure a distinct and sustainable competitive position as an oilfield service company by
delivering services and products that enable our customers to extract proven reserves and maximize recovery. 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.
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 (including the ability to deliver services and products on an “as needed, where needed” basis);
- 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 80 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 2013,
2012, and 2011, based on the location of services provided and products sold, 49%, 53%, and 55% 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 – Business Environment and
Results of Operations” and Note 2 to the consolidated financial statements for additional financial information about our
geographic operations in the last three years. 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 servicing and sales organizations.
Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil
unrest, expropriation or other governmental actions, 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 significantly impact the conduct of our operations
taken as a whole.
1
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 13 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.
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, hydrochloric acid, and gels, including guar gum (a blending additive used in
our hydraulic fracturing process). 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 $588 million in 2013, $460 million in 2012, and $401 million in 2011. We sponsored over 95% of these
expenditures in each year.
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 patents owned by others. 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 months normally results in reduced activity levels in the North Sea and Russia.
Additionally, customer spending patterns for software and various other oilfield services and products can result in
higher activity in the fourth quarter of the year.
Employees
At December 31, 2013, we employed approximately 77,000 people worldwide compared to approximately 73,000 at
December 31, 2012. At December 31, 2013, approximately 15% 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 8 to the consolidated financial statements and
Item 1(a), “Risk Factors.”
Hydraulic fracturing process
Hydraulic fracturing is a process that creates fractures extending from the well bore through the rock formation to
enable natural gas or oil to move more easily through the rock pores to a production well. 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.
We generally design and implement a hydraulic fracturing operation to “stimulate” the well, at the direction of our
customer, 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 supply the proppant (often sand) and any 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 of any
materials that are subsequently pumped out of the well, including flowback fluids and produced water.
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
the surface.
2
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. At the request of Congress, the EPA is currently undertaking another study of the relationship between hydraulic
fracturing and drinking water resources that will focus on the fracturing of shale natural gas wells.
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.
At the same time, we have invested considerable resources in developing our CleanSuite™ hydraulic fracturing
technologies, 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 to control the growth
of bacteria in hydraulic fracturing fluids that uses ultraviolet light, 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.
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 operations, 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.
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 at 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 that contains our reports, proxy and information statements, and our other SEC filings. The address of that web site
is www.sec.gov. 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 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 2013, 2012, or 2011. 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 7,
2014, including all offices and positions held by each in the past five years:
Name and Age
James S. Brown
(Age 59)
Offices Held and Term of Office
President, Western Hemisphere of Halliburton Company, since January 2008
3
Name and Age
Offices Held and Term of Office
Christian A. Garcia
(Age 50)
Senior Vice President and Chief Accounting Officer of Halliburton Company, since January
2014
Senior Vice President and Treasurer of Halliburton Company, September 2011 to December
2013
Senior Vice President, Investor Relations of Halliburton Company, January 2011 to August
2011
Vice President, Investor Relations of Halliburton Company, December 2007 to December
2010
Myrtle L. Jones
(Age 54)
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
* David J. Lesar
(Age 60)
Chairman of the Board, President, and Chief Executive Officer of Halliburton Company,
since August 2000
* Mark A. McCollum
Executive Vice President and Chief Financial Officer of Halliburton Company, since
(Age 54)
January 2008
Timothy M. McKeon
(Age 41)
Vice President and Treasurer of Halliburton Company, since January 2014
Assistant Treasurer of Halliburton Company, September 2011 to December 2013
Director of Finance, Drilling & Evaluation Division of Halliburton Company, February
2011 to August 2011
Director of Treasury Operations of Halliburton Company, March 2009 to January 2011
Senior Manager, Corporate Finance of Halliburton Company, August 2006 to February 2009
* Jeffrey A. Miller
Executive Vice President and Chief Operating Officer of Halliburton Company, since
(Age 50)
September 2012
Senior Vice President, Global Business Development and Marketing of Halliburton
Company, January 2011 to August 2012
Senior Vice President, Gulf of Mexico Region of Halliburton Company, January 2010 to
December 2010
Vice President, Baroid, May 2006 to December 2009
* Lawrence J. Pope
(Age 45)
Executive Vice President of Administration and Chief Human Resources Officer of
Halliburton Company, since January 2008
Joe D. Rainey
(Age 57)
President, Eastern Hemisphere of Halliburton Company, since January 2011
Senior Vice President, Eastern Hemisphere of Halliburton Company, January 2010 to
December 2010
Vice President, Eurasia Pacific Region of Halliburton Company, January 2009 to December
2009
* Robb L. Voyles
Executive Vice President and General Counsel of Halliburton Company, since January 2014
(Age 56)
Senior Vice President, Law of Halliburton Company, September 2013 to December 2013
Partner, Baker Botts L.L.P., January 1989 to August 2013
* Members of the Policy Committee of the registrant.
There are no family relationships between the executive officers of the registrant or between any director and any executive
officer of the registrant.
4
Item 1(a). Risk Factors.
The statements in this section describe the known material risks to our business and should be considered carefully.
We, among others, have been named as a defendant in numerous lawsuits and there have been numerous
investigations relating to the Macondo well incident that could have a material adverse effect on our liquidity, consolidated
results of operations, and consolidated financial condition.
The semisubmersible drilling rig, Deepwater Horizon, sank on April 22, 2010 after an explosion and fire onboard the rig
that began on April 20, 2010. The Deepwater Horizon was owned by Transocean Ltd. and had been drilling the Macondo
exploration well in Mississippi Canyon Block 252 in the Gulf of Mexico for the lease operator, BP Exploration (BP Exploration),
an indirect wholly owned subsidiary of BP p.l.c. (BP p.l.c., BP Exploration, and their affiliates, collectively, BP). There were
eleven fatalities and a number of injuries as a result of the Macondo well incident. Crude oil escaping from the Macondo well
site spread across thousands of square miles of the Gulf of Mexico and reached the United States Gulf Coast. We performed a
variety of services for BP Exploration, including cementing, mud logging, directional drilling, measurement-while-drilling, and
rig data acquisition services.
We are named along with other unaffiliated defendants in more than 1,800 complaints, most of which are alleged class-
actions, involving pollution damage claims and at least eight personal injury lawsuits involving four decedents and at least 10
allegedly injured persons who were on the drilling rig at the time of the incident. At least six additional lawsuits naming us and
others relate to alleged personal injuries sustained by those responding to the explosion and oil spill. Other defendants in the
lawsuits have filed claims against us seeking subrogation, indemnification, including with respect to liabilities under the Oil
Pollution Act of 1990 (OPA), contribution and direct damages, and alleging negligence, gross negligence, fraudulent conduct,
willful misconduct, and fraudulent concealment. See Note 8 to the consolidated financial statements. Additional lawsuits may be
filed against us, including civil actions under federal statutes and regulations, as well as criminal and civil actions under state
statutes and regulations. Those statutes and regulations could result in criminal penalties, including fines and imprisonment, as
well as civil fines, and the degree of the penalties and fines may depend on the type of conduct and level of culpability, including
strict liability, negligence, gross negligence, and knowing violations of the statute or regulation.
In addition to the claims and lawsuits described above, several regulatory agencies and others have investigated or are
investigating the cause of the explosion, fire, and resulting oil spill. Reports issued as a result of those investigations have been
critical of BP, Transocean, and us, among others. For example, one or more of those reports have concluded that primary cement
failure was a direct cause of the blowout, cement testing performed by an independent laboratory “strongly suggests” that the
foam cement slurry used on the Macondo well was unstable, and that numerous other oversights and factors caused or
contributed to the cause of the incident, including BP's failure to run a cement bond log, BP's and Transocean's failure to
properly conduct and interpret a negative-pressure test, the failure of the drilling crew and our surface data logging specialist to
recognize that an unplanned influx of oil, natural gas, or fluid into the well was occurring, communication failures among BP,
Transocean, and us, and flawed decisions relating to the design, construction, and testing of barriers critical to the temporary
abandonment of the well.
In October 2011, the Bureau of Safety and Environmental Enforcement (BSEE) issued a notification of Incidents of
Noncompliance (INCs) to us for allegedly violating federal regulations relating to the failure to take measures to prevent the
unauthorized release of hydrocarbons, the failure to take precautions to keep the Macondo well under control, the failure to
cement the well in a manner that would, among other things, prevent the release of fluids into the Gulf of Mexico, and the failure
to protect health, safety, property, and the environment as a result of a failure to perform operations in a safe and workmanlike
manner. According to the BSEE's notice, we did not ensure an adequate barrier to hydrocarbon flow after cementing the
production casing and did not detect the influx of hydrocarbons until they were above the blowout preventer stack. We
understand that the regulations in effect at the time of the alleged violations provide for fines of up to $35,000 per day per
violation. We have appealed the INCs to the Interior Board of Land Appeals (IBLA). In January 2012, the IBLA, in response to
our and the BSEE's joint request, suspended the appeal pending certain proceedings in the multi-district litigation (MDL) trial.
Once the MDL court issues a final decision in the trial, we expect to file a proposal for further action in the appeal. The BSEE
has announced that the INCs will be reviewed for possible imposition of civil penalties once the appeal has ended. The BSEE
has stated that this is the first time the Department of the Interior has issued INCs directly to a contractor that was not the well's
operator.
5
Our contract with BP Exploration relating to the Macondo well generally provides for our indemnification by BP
Exploration for certain potential claims and expenses relating to the Macondo well incident. BP Exploration, in connection with
filing its claims with respect to the MDL proceeding, asked the court to declare that it is not liable to us in contribution,
indemnification, or otherwise with respect to liabilities arising from the Macondo well incident. Other defendants in the litigation
have generally denied any obligation to contribute to any liabilities arising from the Macondo well incident. In January 2012, the
court in the MDL proceeding entered an order in response to our and BP's motions for summary judgment regarding certain
indemnification matters. The court held that BP is required to indemnify us for third-party compensatory claims, or actual
damages, that arise from pollution or contamination that did not originate from our property or equipment located above the
surface of the land or water, even if we are found to be grossly negligent. The court also held that BP does not owe us indemnity
for punitive damages or for civil penalties under the Clean Water Act (CWA), if any, and that fraud could void the indemnity on
public policy grounds. The court in the MDL proceeding deferred ruling on whether our indemnification from BP covers
penalties or fines under the Outer Continental Shelf Lands Act, whether our alleged breach of our contract with BP Exploration
would invalidate the indemnity, and whether we committed an act that materially increased the risk to or prejudiced the rights of
BP so as to invalidate the indemnity.
The rulings in the MDL proceeding regarding the indemnities are based on maritime law and may not bind the
determination of similar issues in lawsuits not comprising a part of the MDL proceeding. Accordingly, it is possible that different
conclusions with respect to indemnities will be reached by other courts.
Indemnification for criminal fines or penalties, if any, may not be available if a court were to find such indemnification
unenforceable as against public policy. In addition, certain state laws, if deemed to apply, would not allow for enforcement of
indemnification for gross negligence, and may not allow for enforcement of indemnification of persons who are found to be
negligent with respect to personal injury claims. We may not be insured with respect to civil or criminal fines or penalties, if any,
pursuant to the terms of our insurance policies.
BP's public filings indicate that BP has recognized in excess of $40 billion in pre-tax charges, excluding offsets for
settlement payments received from certain defendants in the MDL, as a result of the Macondo well incident. BP's public filings
also indicate that the amount of, among other things, certain natural resource damages with respect to certain OPA claims, some
of which may be included in such charges, cannot be reliably estimated as of the dates of those filings.
We are currently unable to fully estimate the impact the Macondo well incident will have on us. We cannot predict the
outcome of the many lawsuits and investigations relating to the Macondo well incident, including orders and rulings of the court
that impact the MDL, the results of the MDL trial, the effect that the settlements between BP and the Plaintiffs’ Steering
Committee (PSC) in the MDL and other settlements may have on claims against us, or whether we might settle with one or more
of the parties to any lawsuit or investigation. The first two phases of the MDL trial have concluded, and the MDL court could
begin issuing rulings at any time. A determination that the performance of our services on the Deepwater Horizon constituted
gross negligence could result in substantial liability to the numerous plaintiffs for punitive damages and potentially to BP with
respect to its direct claims against us.
As of December 31, 2013, our loss contingency reserve for the Macondo well incident, relating to the MDL, remained
at $1.3 billion, which represents a loss contingency that is probable and for which a reasonable estimate of loss can be made. We
have participated in intermittent discussions with the PSC regarding the potential for a settlement that would resolve a substantial
portion of the claims pending in the MDL trial. BP, however, has not participated in any recent settlement discussions with us.
Reaching a settlement involves a complex process, and there can be no assurance as to whether or when we may
complete a settlement. In addition, the settlement discussions we have had to date do not cover all parties and claims relating to
the Macondo well incident. Accordingly, there are additional loss contingencies relating to the Macondo well incident that are
reasonably possible but for which we cannot make a reasonable estimate. Given the numerous potential developments relating to
the MDL and other lawsuits and investigations, which could occur at any time, we may adjust our estimated loss contingency
reserve in the future. Liabilities arising out of the Macondo well incident could have a material adverse effect on our liquidity,
consolidated results of operations, and consolidated financial condition.
6
Certain matters relating to the Macondo well incident, including increased regulation of the United States offshore
drilling industry, and similar catastrophic events could have a material adverse effect on our liquidity, consolidated results of
operations, and consolidated financial condition.
The Macondo well incident and the subsequent oil spill resulted in offshore drilling delays, temporary drilling bans, and
increased federal regulation of our and our customers' operations, and more regulations and delays are possible. For example, the
BSEE has:
- issued regulations that provide revised casing and cementing requirements, including integrity testing standards, that
mandate independent third-party verifications, that impose blowout preventer capability, testing, and documentation
obligations, and that outline standards for specific well control training for deepwater operations, among other
requirements;
- issued revised regulations in 2013 to require, among other things, increased employee involvement in certain safety
measures and third-party audits of operators’ safety and environmental management systems;
- proposed stricter requirements for subsea drilling production equipment;
- stated that it intends to propose new standards for the design and maintenance of blowout preventers; and
- stated that it, together with the Bureau of Ocean Energy Management, is drafting new standards governing drilling in
the Arctic.
In addition, the BSEE contends that it has the legal authority to extend its regulatory reach to include contractors, like us, in
addition to operators, as evidenced by the INCs.
The increased regulation of the exploration and production industry as a whole that arises out of the Macondo well
incident has and could continue to result in higher operating costs for us and our customers, extended permitting and drilling
delays, and reduced demand for our services. We cannot predict to what extent increased regulation may be adopted in
international or other jurisdictions or whether we and our customers will be required or may elect to implement responsive
policies and procedures in jurisdictions where they may not be required.
In addition, the Macondo well incident negatively impacted and could continue to negatively impact the availability and
cost of insurance coverage for us, our customers, and our and their service providers. Also, our relationships with BP and others
involved in the Macondo well incident could be negatively affected. Our business may be adversely impacted by any negative
publicity relating to the incident, any negative perceptions about us by our customers, any increases in insurance premiums or
difficulty in obtaining coverage, and the diversion of management's attention from our operations to focus on matters relating to
the incident.
As illustrated by the Macondo well incident, the services we provide for our customers are performed in challenging
environments that can be dangerous. Catastrophic events such as a well blowout, fire, or explosion can occur, resulting in
property damage, personal injury, death, pollution, and environmental damage. While we have agreements with certain
customers that require them to indemnify us for these types of events and the resulting damages and injuries (except in some
cases, claims by our employees, loss or damage to our property, and any pollution emanating directly from our equipment), we
will be exposed to significant potential losses should such catastrophic events occur if adequate indemnification provisions or
insurance arrangements are not in place, if indemnity or related release from liability provisions are determined by a court to be
unenforceable or otherwise invalid, in whole or in part, or if our customers are unable or unwilling to satisfy any indemnity
obligations.
The matters discussed above relating to the Macondo well incident and similar catastrophic events could have a material
adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
7
Our operations are subject to political and economic instability, risk of government actions, and cyber attacks 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, force majeure, war, or 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, restrict payments, or limit the movement of funds;
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, the effects of 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, 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, Argentina, 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 also 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 or damage of intellectual property,
proprietary information, or customer data, having our business operations interrupted, and increased costs to prevent, respond to,
or mitigate cybersecurity attacks. 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 the FCPA, even though 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. Allegations of violations of applicable anti-corruption laws, including the FCPA, may result in internal,
independent, or government investigations. Violations of the FCPA 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, investigations by governmental authorities as well as 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. 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.
8
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.
We are a leading provider of hydraulic fracturing services. Various federal legislative and regulatory initiatives have
been undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations.
For example, the Department of Interior has issued proposed regulations that would apply to hydraulic fracturing operations on
wells that are subject to federal oil and gas leases and that would impose requirements regarding the disclosure of chemicals used
in the hydraulic fracturing process as well as requirements to obtain certain federal approvals before proceeding with hydraulic
fracturing at a well site. These regulations, if adopted, would establish additional levels of regulation at the federal level that
could lead to operational delays and increased operating costs. At the same time, legislation and/or regulations have been
adopted in several 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. 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 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.
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.
9
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, for example, 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; and
- the use of underground injection wells.
These and other requirements generally are becoming increasingly strict. Sanctions for failure to comply with the
requirements, many of which may be applied retroactively, may include:
- 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 could have a material adverse effect on our
liquidity, consolidated results of operations, and consolidated financial condition. We are also exposed to costs arising from
regulatory compliance, including compliance with changes in or expansion of applicable regulatory requirements, which 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, could have a negative impact on our
business if such laws, regulations, treaties, or international agreements reduce demand for oil and natural gas. 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.
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, including national oil 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.
10
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. Any
prolonged reduction in oil and natural gas prices will depress the immediate levels of exploration, development, and production
activity which could have a material adverse effect on our business, consolidated results of operations, and consolidated financial
condition. Even the perception of longer-term lower oil and natural gas prices by oil and natural gas companies can similarly
reduce or defer major expenditures given the long-term nature of many large-scale development projects. Factors affecting the
prices of oil and natural gas include:
- the level of supply and demand for oil and natural gas, especially demand for natural gas in the United States;
- 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 level of oil production by non-OPEC countries and the available excess production capacity within OPEC;
- 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
- potential acceleration of the development of alternative fuels.
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.
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 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 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 80 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 a tax year.
11
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, such as Venezuela, that have non-traded or “soft” currencies that,
because of their restricted or limited trading markets, may be more difficult to exchange for “hard” currency. We may accumulate
cash in soft currencies, and we may be limited in our ability to convert our profits into United States dollars or to repatriate the
profits from those countries. In addition, we may accumulate cash in foreign jurisdictions that may be subject to taxation if
repatriated to the United States. For further information, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Business Environment and Results of Operations" and Note 9 to the Consolidated Financial Statements,
"Income Taxes."
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.
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 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 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.
Our business in Venezuela subjects us to actions by the Venezuelan government and delays in receiving payments,
which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial
condition.
We believe there are risks associated with our operations in Venezuela, including the possibility that the Venezuelan
government could assume control over our operations and assets. We also continue to see a delay in receiving payment on our
receivables from our primary customer in Venezuela. If our customer further delays paying or fails 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.
12
The future results of our Venezuelan operations will be affected by many factors, including our ability to take actions to
mitigate the effect of a devaluation of the Bolívar, the foreign currency exchange rate, actions of the Venezuelan government, and
general economic conditions such as continued inflation and future customer payments and spending. For further information,
see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and
Results of Operations - International operations - Venezuela."
Some of our customers require bids for contracts in the form of long-term, fixed pricing 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.
Some of our customers, primarily NOCs, may require bids for contracts in the form of long-term, fixed pricing contracts
that may require us to provide integrated project management services outside our normal discrete business to act 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 are normally readily available. High levels of demand for, or shortage of, raw
materials, such as proppants, hydrochloric acid, and gels, including guar gum, 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.
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 ventures. 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 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 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;
- any dispositions, investments, acquisitions, or integrations would not divert management resources; or
- any dispositions, investments, acquisitions, or integrations would not have a material adverse effect on our liquidity,
consolidated results of operations, or consolidated financial condition.
13
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, where control may be shared with unaffiliated third parties. As with
any joint venture arrangement, differences in views among the joint venture participants may result in delayed decisions 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 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 employ and retain
technical personnel with the ability to design, utilize, and enhance these services and products. In addition, our ability to expand
our operations depends in part on our ability to increase our skilled labor force. 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.
Item 1(b). Unresolved Staff Comments.
None.
14
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. All of our owned
properties are unencumbered.
The following locations represent our major facilities by segment:
Completion and Production segment:
Drilling and Evaluation segment:
Shared/corporate facilities:
Arbroath, United Kingdom
Johor, Malaysia
Lafayette, Louisiana
Singapore, Singapore
Stavanger, Norway
Tianjin, China
Alvarado, Texas
Nisku, Canada
Singapore, Singapore
The Woodlands, Texas
Al-Khobar, Saudi Arabia
Carrollton, Texas
Denver, Colorado
Dubai, United Arab Emirates
Duncan, Oklahoma
Houston, Texas
Kuala Lumpur, Malaysia
Panama City, Panama
Pune, India
Rio de Janeiro, Brazil
San Antonio, Texas
In addition, we have 179 international and 124 United States field camps from which we deliver our services and
products. We also have numerous small facilities that include sales, project, and support offices and bulk storage facilities
throughout the world.
We believe all properties that we currently occupy are suitable for their intended use.
15
Item 3. Legal Proceedings.
Information related to Item 3. Legal Proceedings is included in Note 8 to the consolidated financial statements on
page 55 of this annual report.
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.
16
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 74 of this annual report. Quarterly cash dividends on our common stock, which were paid in
March, June, September, and December of each year, were $0.09 per share throughout 2012, $0.125 per share for the first three
quarters of 2013, and $0.15 per share in the fourth quarter of 2013. 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 pay dividends representing at least 15% to 20% of our net income on an annual basis.
The following graph and table compare total shareholder return on our common stock for the five-year period ended
December 31, 2013, 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, 2008, and the reinvestment of all dividends. The
shareholder return set forth is not necessarily indicative of future performance.
Halliburton
Philadelphia Oil Service Index (OSX)
Standard & Poor’s 500 ® Index
December 31
$
2008
100.00 $
100.00
100.00
2009
168.12 $
162.15
126.46
2010
230.75 $
205.80
145.51
2011
196.85 $
184.09
148.59
2012
200.13 $
189.86
172.37
2013
296.19
249.32
228.19
17
At January 31, 2014, there were 14,454 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, 2013.
Period
October 1 - 31
November 1 - 30
December 1 - 31
Total
Total Number
of Shares
Purchased (a)
Average
Price Paid
per Share
73,993
80,870
140,739
295,602
$49.96
$53.43
$50.41
$51.12
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)
—
—
—
—
$1,693,971,527
$1,693,971,527
$1,693,971,527
(a) All of the 295,602 shares purchased during the three-month period ended December 31, 2013 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 2013, 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 $1.7 billion of our common stock.
Item 6. Selected Financial Data.
Information related to selected financial data is included on page 73 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 20 through 38 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” on page 37 of this annual report and Note 13 to the consolidated
financial statements on page 68 of this annual report.
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, 2013, 2012, and 2011
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012, and 2011
Consolidated Balance Sheets at December 31, 2013 and 2012
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012, and 2011
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2013, 2012, and 2011
Notes to Consolidated Financial Statements
Selected Financial Data (Unaudited)
Quarterly Data and Market Price Information (Unaudited)
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Page No.
39
40
42
43
44
45
46
47
73
74
18
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, 2013 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, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial
reporting.
See page 39 for Management’s Report on Internal Control Over Financial Reporting and page 40 for Report of
Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
Item 9(b). Other Information.
None.
19
HALLIBURTON COMPANY
Management’s Discussion and Analysis of Financial Condition and Results of Operations
EXECUTIVE OVERVIEW
Financial results
During 2013, we produced revenue of $29.4 billion and operating income of $3.1 billion, reflecting an operating
margin of 11%. Revenue increased $0.9 billion, or 3%, from 2012, mainly due to increased activity in all of our international
regions and the Gulf of Mexico. We set new revenue records this year in all of our international regions and in both of our
divisions. Additionally, during 2013, our revenue outside of North America comprised 48% of consolidated revenue. The
percentage of our revenue that relates to our international operations has been steadily increasing and is representative of our
ongoing strategy to grow our international business and balance our geographic mix. Our increase in international activity and
revenue was partially offset by lower activity levels and pricing pressure in the United States land market, primarily for
production enhancement services. Operating income in 2013 was negatively impacted by a $1.0 billion, pre-tax, Macondo-
related loss contingency, as compared to a $300 million, pre-tax, Macondo-related loss contingency in 2012.
Business outlook
We continue to believe in the strength of the long-term fundamentals of our business. Energy demand is expected to
increase over the long term driven by economic growth in developing countries despite current underlying downside risks in the
industry, such as sluggish growth in developed countries and uncertainties associated with geopolitical tensions in the
Middle East and North Africa. Furthermore, development of new resources is expected to be more complex, resulting in
higher service intensity as our customers move increasingly to horizontal drilling.
In North America, we continue to experience pricing pressures, which have impacted our margins. However, we
believe the current environment and our focus on efficient cost structure continues to favor us. As a result of the industry's
activity shift from natural gas plays to oil and liquids-rich basins, operators have been allocating their budgets to basins with
better economics. In addition, we are observing a meaningful switch to multi-well pad activity among our customer base, which
is resulting in increased drilling and completion service efficiency. We believe the incremental efficiency gains provided by
multi-well pad drilling will enable us to leverage our operational scale and expertise.
Outside of North America, both revenue and operating income increased in 2013 compared to 2012. We believe that
international growth in 2014 will come from volume increases as we deploy resources on our recent contract wins and new
projects, continued improvement in markets where we have made strategic investments, the introduction of new technology,
and increased pricing and cost recovery on select contracts. We also believe that international unconventional oil and natural
gas, mature field, and deepwater projects will contribute to activity improvements over the long term, and we plan to leverage
our extensive experience in North America to capitalize on these opportunities. Consistent with our long-term strategy to grow
our operations outside of North America, we also expect to continue to invest in capital equipment for our international
operations. In Latin America, we expect 2014 to be a challenging year due to a decline in existing integrated project
management work in Mexico as we begin transitioning to newly-tendered projects, and due to reduced activity in Brazil.
However, this does not change our long-term outlook for Latin America, which we expect to contribute significantly to our
future growth and profitability.
20
We continued to execute several key initiatives in 2013. These initiatives included increasing manufacturing capacity
in the Eastern Hemisphere and repositioning our service delivery platform to lower our delivery costs. We plan to continue to
invest in these initiatives in 2014. In addition, we plan to continue executing the following strategies:
- focusing on unconventional plays, mature fields, and deepwater markets by leveraging our broad technology
offerings to provide value to our customers through integrated solutions and the ability to more efficiently drill and
complete their wells;
- exploring 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 large
operations;
- making key investments in technology and infrastructure to maximize growth opportunities. To that end, we are
continuing to push our technology and manufacturing capacity, as well as our supply chain, closer to our customers
in the Eastern Hemisphere;
- improving working capital, and managing our balance sheet to maximize our financial flexibility. We are deploying
a global project to improve service delivery that we expect to result in, among other things, additional investments in
our systems and significant improvements to our current order-to-cash and purchase-to-pay processes;
- growing our international revenues and margins by continuing to invest capital and resources in these markets;
- improving our North America margins by leveraging technologies and reducing costs through more efficient
operations;
- 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; and
- expanding our business with national oil companies.
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. For additional information, see “Liquidity and
Capital Resources” and “Business Environment and Results of Operations.”
21
LIQUIDITY AND CAPITAL RESOURCES
We ended 2013 with cash and equivalents of $2.4 billion compared to $2.5 billion at December 31, 2012. Additionally,
at December 31, 2013, we held $373 million of investments in fixed income securities compared to $398 million at
December 31, 2012, These securities are reflected in "Other current assets" and "Other assets" in our consolidated balance
sheets. As of December 31, 2013, approximately $306 million of the $2.4 billion of cash and equivalents was held by our
foreign subsidiaries, and would be subject to United States tax if repatriated. However, our intent is to permanently reinvest
these funds outside of the United States and our current plans do not suggest a need to repatriate them to fund our United States
operations.
Significant sources and uses of cash
Cash flows from operating activities were $4.4 billion in 2013.
In the third quarter of 2013, we issued $3.0 billion aggregate principal amount of senior notes and used the net
proceeds, along with cash on hand, to fund the repurchase of approximately 68 million shares of our common stock at an
aggregate cost of $3.3 billion pursuant to a modified Dutch auction cash tender offer. During 2013, we repurchased
approximately 93 million shares of our common stock under our share repurchase program at a total cost of approximately $4.4
billion.
Capital expenditures were $2.9 billion in 2013. The capital expenditures in 2013 were predominantly made in our
Production Enhancement, Sperry Drilling, Boots and Coots, Wireline and Perforating, and Cementing product service lines. We
have also invested additional working capital to support the growth of our business.
We paid $465 million of dividends to our shareholders in 2013. We increased our quarterly dividend rate by $0.035 per
share in the first quarter of 2013 and an additional $0.025 per share in the fourth quarter of 2013. Our current quarterly dividend
rate is $0.15 per share, or approximately $129 million per quarter, which represents a 67% increase over the quarterly dividend
rate during 2012.
During 2013, we sold $241 million of property, plant, and equipment.
Our primary components of net working capital (receivables, inventories and accounts payable) increased during the
year by a net $229 million, primarily due to increased business activity.
In the first quarter of 2013, we made a $219 million payment under a guarantee we issued for the Barracuda-Caratinga
project.
In the second quarter of 2013, we made a $172 million earn-out payment related to a prior year acquisition due to
significantly better than expected operating performance.
Future sources and uses of cash
Capital spending for 2014 is currently expected to be approximately $3.0 billion. The capital expenditures plan for
2014 is primarily directed towards our Production Enhancement, Sperry Drilling, Cementing, Boots & Coots, and Wireline and
Perforating product service lines, with an increasing amount dedicated to our international operations.
Subject to Board of Directors approval, our intention is to pay dividends representing at least 15% to 20% of our net
income on an annual basis. We have approximately $1.7 billion remaining available under our share repurchase authorization,
which may be used for open market and other share repurchases.
During 2013, the Congressional Joint Committee on Taxation approved a $135 million income tax refund, excluding
interest, to us for agreed upon tax items for the tax years 2003 through 2009. We expect to receive the refund in 2014.
In the third quarter of 2013, we were awarded $105 million by an arbitrator regarding amounts owed by KBR, Inc.
(KBR) related to our Tax Sharing Agreement with KBR. KBR is contesting the award and, although the arbitrator recently
issued a supplemental report that reaffirmed the original award, there is uncertainty as to the ultimate timing and amount of any
payment. See Note 7 to the consolidated financial statements for further information.
We are continuing to explore 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.
We had $209 million of gross unrecognized tax benefits at December 31, 2013, of which we estimate $146 million
may require a cash payment. We estimate that $141 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 any amounts will ultimately be settled and paid.
22
Contractual obligations
The following table summarizes our significant contractual obligations and other long-term liabilities as of
December 31, 2013:
Millions of dollars
2014
2015
2016
2017
2018 Thereafter
Total
Payments Due
Long-term debt
Operating leases
Interest on debt (a)
Purchase obligations (b)
$ — $ — $
7,834
8,308
946
3,544
54
20,686
(a) Interest on debt includes 83 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.
(b) Amount in 2014 primarily represents certain purchase orders for goods and services utilized in the ordinary course of
6,389 $
6,422
154
96
4
45 $
385
83
225
3
800 $
398
56
76
2
600 $
376
156
315
3
362
282
2,382
39
$ 3,065 $ 1,033 $ 1,450 $
365
215
450
3
741 $ 1,332 $
13,065 $
Other long-term liabilities (c)
Total
our business.
(c) Includes capital lease obligations and pension funding obligations. Amounts for pension funding obligations, which
include international plans and are based on assumptions that are subject to change, are only included for 2014 as we
are currently not able to reasonably estimate our contributions for years after 2014.
Other factors affecting liquidity
Financial position in current market. As of December 31, 2013, we had $2.4 billion of cash and equivalents, $373
million in fixed income investments, and a total of $3.0 billion of available committed bank credit under our revolving credit
facility. Reflecting the growth of our company, we executed an amendment to our revolving credit facility during 2013, which
increased the capacity from $2.0 billion to $3.0 billion and extended the maturity to 2018. 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. Although a portion of earnings from our foreign subsidiaries is reinvested outside the United States indefinitely, we do not
consider this to have a significant impact on our liquidity. We currently believe that capital expenditures, working capital
investments, and dividends, if any, in 2014 can be fully funded through cash from operations.
As a result, we believe we have a reasonable amount of liquidity and, if necessary, additional financing flexibility
given the current market environment to fund our potential contingent liabilities, if any. However, as discussed in Note 8 to the
consolidated financial statements, there are numerous future developments that may arise as a result of the Macondo well
incident that could have a material adverse effect on our liquidity.
Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which
approximately $2.1 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2013.
Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.
Credit ratings. Credit ratings for our long-term debt remain A2 with Moody’s Investors Service and A with Standard &
Poor’s. The credit ratings on our short-term debt remain P-1 with Moody’s Investors Service and A-1 with Standard & Poor’s.
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 “Business Environment and Results of Operations –
International operations – Venezuela” for further discussion related to Venezuela.
23
BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS
We operate in approximately 80 countries throughout the world to provide a comprehensive range of discrete and
integrated 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. We serve the
upstream oil and natural gas industry 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 field. Our two business segments are the Completion and Production segment and the Drilling and Evaluation
segment. The industry we serve is highly competitive with many substantial competitors in each segment. In 2013, 2012, and
2011, based on the location of services provided and products sold, 49%, 53%, and 55% 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, expropriation or other governmental actions, inflation, 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 levels within our business segments are 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, the world economy, the availability of credit, government regulation, and global stability, which together drive
worldwide drilling activity. Our financial performance is significantly affected by oil and natural gas prices and worldwide rig
activity, which are summarized in the following tables. Additionally, due to improved drilling and completion efficiencies as
more of our customers move to multi-well pad drilling, our financial performance is impacted by well count in the North
America market.
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)
2013
2012
2011
$
97.99 $
108.71
3.73
94.15 $
111.60
2.81
95.13
111.53
4.09
(1) Oil price measured in dollars per barrel
(2) Natural gas price measured in dollars per thousand cubic feet, or Mcf
24
The historical yearly average rig counts based on the Baker Hughes Incorporated 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
2013
2012
2011
1,705
56
1,761
352
2
354
978
318
1,296
3,411
3,035
376
1,872
47
1,919
363
1
364
931
303
1,234
3,517
3,166
351
1,843
32
1,875
422
1
423
863
304
1,167
3,465
3,128
337
Oil vs. Natural Gas
United States (incl. Gulf of Mexico):
2013
2012
2011
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
1,375
386
1,761
234
120
354
1,029
267
1,296
3,411
2,638
773
1,359
560
1,919
261
103
364
984
250
1,234
3,517
2,604
913
984
891
1,875
282
141
423
918
249
1,167
3,465
2,184
1,281
2013
2012
2011
1,102
1,151
1,074
435
224
552
216
571
230
1,761
1,919
1,875
Our customers’ cash flows, in most instances, depend upon the revenue they generate from the sale of oil and natural
gas. Lower oil and natural gas prices usually translate into lower exploration and production budgets, while the opposite is true
for higher oil and natural gas prices.
25
WTI oil prices, which generally influence customer spending in North America, fluctuated throughout 2013, ranging
from a high of $111 per barrel in September to a low of $87 per barrel in April. Outside of North America, customer spending is
heavily influenced by Brent oil prices, which fluctuated during 2013 from a high of $119 per barrel in February to a low of $97
per barrel in April. Oil prices were affected by production disruptions in Libya, Nigeria, and Iraq, offset by growing output by
certain OPEC members. Global oil demand growth appears to have gradually gained momentum in the past 18 months and the
International Energy Agency’s January 2014 “Oil Market Report” forecasts a 1% increase in global petroleum demand from
2013 levels. This is driven by economic recovery in the developed world and an increase in all regions except for Europe,
which is forecasted to remain flat.
Henry Hub natural gas prices in the United States have increased approximately 33% from 2012 as a result of an
increase in storage withdrawals due to cooler temperatures in the early part and December of 2013. This, coupled with higher
natural gas demand for industrial purposes, resulted in higher natural gas prices. Natural gas prices during 2013 ranged from a
low of $3.08 per Mcf in January to a high of $4.52 per Mcf in December. The United States Energy Information Administration
(EIA) January 2014 “Short Term Energy Outlook” forecast projects Henry Hub natural gas prices to average $3.89 per Mcf in
2014 compared to $3.73 per Mcf in 2013. Over the long term, the EIA expects natural gas consumption in the power sector to
increase to offset the retirement of coal power plants.
There has been an increase in natural gas prices over the past year and the global economy continues to recover. We
believe that, over the long-term, hydrocarbon demand will generally increase, and this, combined with the underlying trends of
smaller and more complex reservoirs, high depletion rates, and the need for continual reserve replacement, should drive the
long-term need for our services and products.
North America operations
Volatility in oil and natural gas prices can impact our customers’ drilling and production activities. During 2013, the
average natural gas-directed rig count in North America fell by 157 rigs, or 24%, from 2012 levels. The curtailment of natural
gas drilling activity along with an influx of stimulation equipment into the industry has resulted in overcapacity and pricing
pressure for hydraulic fracturing and other services. Despite the decreased rig count in the United States as compared to 2012,
drilling efficiencies and the trend toward multi-well pads are driving a more robust well count. Additionally, operators have
been, in some cases, increasing the numbers of hydraulic fracturing stages on horizontal wells.
We expect United States land rig count to modestly increase from 2013 levels, driven primarily by the continued shift
to horizontal rigs in the Permian Basin. We are seeing higher well efficiencies due to increased pad drilling, more 24-hour
operations, rig fleet upgrades, and significant advancements in drilling and completion technologies. In 2013, we saw average
drilling days per horizontal well drop approximately 14% compared to 2012 and we anticipate continued efficiency
improvements in 2014. We believe this continued shift towards efficiency will bode well for us in the coming years. In the long
run, we believe the shift to unconventional oil and liquids-rich basins in North America will continue to drive increased service
intensity and will require higher demand in fluid chemistry and other technologies required for these complex reservoirs which
will have beneficial implications for our operations.
In the Gulf of Mexico, improvements in the performance of many of our product service lines was due to a 19%
increase in the offshore rig count from 2012, in addition to the efficiencies and integrated solutions we offer that save our
customers time and enhance productivity. Over the long term, the continued growth in the Gulf of Mexico is dependent on,
among other things, governmental approvals for permits, our customers' actions, and new deepwater rigs entering the market.
International operations
The industry experienced steady volume increases during 2013, with the average international rig count improving 5%
over 2012 levels. These volume increases have led to an absorption of equipment supply and we are seeing sporadic
opportunities for price improvements in select geographies. We anticipate moderate margin improvements and gradual activity
increases in the Eastern Hemisphere, although the operator spending outlook could be impacted by ongoing macroeconomic
concerns. We believe 2014 will be a challenging year for Latin America, primarily in Brazil and Mexico. Over the long term,
however, we expect both of these countries to be strong contributors to our growth and profitability.
We believe that international growth in 2014 will come from volume increases as we deploy resources on our recent
contract and project wins, continued improvement in certain markets where we have made strategic investments, introduction
of new technology, and increased pricing and cost recovery on select contracts. We also believe that international
unconventional oil and natural gas, mature field, and deepwater projects will contribute to activity improvements over the long
term, and we plan to leverage our extensive experience in North America to optimize these opportunities. Consistent with our
long-term strategy to grow our operations outside of North America, we also expect to continue to invest in capital equipment
for our international operations.
Venezuela. As of December 31, 2013, our total net investment in Venezuela was approximately $411 million, including
net monetary assets of $124 million denominated in Bolívares. Also, at December 31, 2013 we had $192 million of surety bond
guarantees outstanding relating to our Venezuelan operations.
26
We continue to experience delays in collecting payment on our receivables from our primary customer in
Venezuela. These receivables are not disputed, and we have not historically had material write-offs relating to this customer.
Additionally, we routinely monitor the financial stability of our customers. Our total outstanding trade receivables in Venezuela
were $486 million, or approximately 8% of our gross trade receivables, as of December 31, 2013, compared to $491 million, or
approximately 9% of our gross trade receivables, as of December 31, 2012. Of the $486 million of receivables in Venezuela as
of December 31, 2013, $183 million has been classified as long-term and included within “Other assets” on our consolidated
balance sheets. Of the $491 million receivables in Venezuela as of December 31, 2012, $143 million has been classified as
long-term and included within “Other assets” on our consolidated balance sheets.
In February 2013, the Venezuelan government devalued the Bolívar, from the preexisting exchange rate of 4.3
Bolívares per United States dollar to 6.3 Bolívares per United States dollar, resulting in us incurring a foreign currency loss.
The net foreign currency impact of Bolívar activity in the first quarter of 2013 was not material, although further devaluation of
the Bolívar could impact our operations. For additional information, see Part I, Item 1(a), “Risk Factors” in this Form 10-K.
27
RESULTS OF OPERATIONS IN 2013 COMPARED TO 2012
REVENUE:
Millions of dollars
Completion and Production
Drilling and Evaluation
Total revenue
By geographic region:
Completion and Production:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Drilling and Evaluation:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Total revenue by region:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
2013
2012
(Unfavorable)
Change
Favorable
Percentage
$
$
$
17,506 $
11,896
29,402 $
17,380 $
11,123
28,503 $
126
773
899
11,417 $
1,586
2,391
2,112
17,506
12,157 $
1,415
2,099
1,709
17,380
3,795
2,323
2,834
2,944
11,896
15,212
3,909
5,225
5,056
3,847
2,279
2,411
2,586
11,123
16,004
3,694
4,510
4,295
(740 )
171
292
403
126
(52 )
44
423
358
773
(792 )
215
715
761
1 %
7
3 %
(6 )%
12
14
24
1
(1 )
2
18
14
7
(5 )
6
16
18
28
OPERATING INCOME:
Millions of dollars
Completion and Production
Drilling and Evaluation
Corporate and other
Total operating income
By geographic region:
Completion and Production:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Drilling and Evaluation:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Total operating income by region
(excluding Corporate and other):
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
2013
2012
(Unfavorable)
Change
Favorable
Percentage
$
$
$
2,875 $
1,770
(1,507 )
3,138 $
3,144 $
1,675
(660 )
4,159 $
(269 )
95
(847 )
(1,021 )
1,916 $
211
356
392
2,875
656
307
334
473
1,770
2,572
518
690
865
2,260 $
206
347
331
3,144
680
393
246
356
1,675
2,940
599
593
687
(344 )
5
9
61
(269 )
(24 )
(86 )
88
117
95
(368 )
(81 )
97
178
(9 )%
6
128
(25 )%
(15 )%
2
3
18
(9 )
(4 )
(22 )
36
33
6
(13 )
(14 )
16
26
Consolidated revenue in 2013 increased 3% compared to 2012, primarily driven by activity growth across all
international regions. This was partially offset by lower activity levels and pricing pressure in the United States land market.
Revenue outside of North America was 48% of consolidated revenue in 2013 and 44% of consolidated revenue in 2012.
The $1.0 billion decrease in consolidated operating income compared to 2012 was primarily related to Macondo-
related charges. Operating income in 2013 was impacted by the following pre-tax items: a $1.0 billion Macondo-related loss
contingency, $92 million of restructuring charges related to severance and asset write-offs, and a $55 million charge related to a
charitable contribution to the National Fish and Wildlife Foundation, partially offset by a $28 million value-added tax refund
receivable in Brazil. Operating income in 2012 was impacted by the following pre-tax items: a $300 million Macondo-related
loss contingency, along with a $48 million charge related to an earn-out adjustment due to significantly better than expected
performance of a past acquisition, partially offset by a $20 million gain related to the settlement of a patent infringement
lawsuit.
Following is a discussion of our results of operations by reportable segment.
Completion and Production revenue increased slightly compared to 2012 due to strong international growth, which
was partially offset by a decline in North America activity. North America revenue decreased 6%, primarily due to pricing
pressures in the United States hydraulic fracturing market and lower activity in Canada. Latin America revenue was up 12%
due to increased completion tools sales in Brazil and higher activity in most product service lines in Mexico and Argentina.
Europe/Africa/CIS revenue grew 14%, driven by strong demand for cementing services in Norway, West Africa, and Russia and
completion tools throughout the region. Middle East/Asia revenue improved 24% due to higher activity in most product service
lines in Saudi Arabia, Australia, Indonesia, and China, increased completion tools sales in Malaysia, and higher demand for
cementing services in Thailand. Revenue outside of North America was 35% of total segment revenue in 2013 and 30% of total
segment revenue in 2012.
29
Completion and Production operating income decreased 9% compared to 2012, primarily due to the North America
region, where operating income fell 15% due to pricing pressures in the United States hydraulic fracturing market and lower
activity in Canada. Latin America operating income was up 2% as a result of higher demand for cementing services in Mexico
and Venezuela and production enhancement services in Argentina. Europe/Africa/CIS operating income grew 3% compared to
2012, driven by higher completion tools activity in Angola and cementing activity in Norway. Middle East/Asia operating
income increased 18% due to higher activity levels in Saudi Arabia and Iraq, higher direct sales in China, and improved
profitability in Indonesia.
Drilling and Evaluation revenue increased 7% compared to 2012, driven by strong results in the Eastern Hemisphere.
North America revenue was essentially flat, as lower demand for drilling and wireline services was partially offset by fluids
activity across the United States land market and higher activity in the Gulf of Mexico. Latin America revenue was also
relatively flat, as higher demand for all product lines in Mexico and fluids throughout the region were partially offset by lower
drilling services activity in Colombia and wireline activity in Brazil. Europe/Africa/CIS revenue increased 18% due to
improved fluids activity in Norway and Angola and higher drilling services activity in Eurasia, Norway, Egypt, and Angola.
Middle East/Asia revenue rose 14% primarily due to strong demand in Saudi Arabia and Indonesia, higher drilling activity
throughout the region, and higher wireline activity in Asia Pacific. Revenue outside of North America was 68% of total segment
revenue in 2013 and 65% of total segment revenue in 2012.
Drilling and Evaluation operating income improved 6% compared to 2012, as increased activity in the Eastern
Hemisphere was partially offset by higher costs in Latin America. North America operating income was down 4% from 2012,
as a reduction in drilling and wireline services was partially offset by demand for fluids and consulting and project
management. Latin America operating income declined 22% due to higher costs in Brazil and Venezuela and lower activity in
Colombia. The Europe/Africa/CIS region operating income grew 36%, driven by fluids activity in Angola and Norway and
drilling services in Eurasia. Middle East/Asia operating income increased 33% as a result of higher activity in Iraq, Indonesia,
and Malaysia.
Corporate and other expenses were $1.5 billion in 2013 compared to $660 million in 2012. The significant increase
was primarily due to a $1.0 billion Macondo-related loss contingency that was recorded in the first quarter of 2013, compared
to a $300 million Macondo-related loss contingency recorded in the first quarter of 2012. Additionally, a $55 million charitable
contribution to the National Fish and Wildlife Foundation was expensed in the second quarter of 2013, reflecting our
commitment to making a positive environmental impact in our local communities.
NONOPERATING ITEMS
Effective tax rate. Our effective tax rate on continuing operations was 23.5% for 2013 and 32.3% for 2012. The 2013
effective tax rate on continuing operations was positively impacted by several items during the year, including federal tax
benefits of approximately $50 million due to the reinstatement of certain tax benefits and credits related to the first quarter
enactment of the American Taxpayer Relief Act of 2012. Also contributing to the lower tax rate in 2013 was a $1.0 billion loss
contingency related to the Macondo well incident, which was tax-effected at the United States statutory rate, as well as some
favorable tax items in Latin America in the fourth quarter. Additionally, our effective tax rate was positively impacted by lower
tax rates in certain foreign jurisdictions, as we continue to reposition our technology, supply chain, and manufacturing
infrastructure to more effectively serve our customers internationally.
30
RESULTS OF OPERATIONS IN 2012 COMPARED TO 2011
REVENUE:
Millions of dollars
Completion and Production
Drilling and Evaluation
Total revenue
By geographic region:
Completion and Production:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Drilling and Evaluation:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Total revenue by region:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
2012
2011
(Unfavorable)
Change
Favorable
Percentage
$
$
$
17,380 $
11,123
28,503 $
15,143 $
9,686
24,829 $
2,237
1,437
3,674
12,157 $
1,415
2,099
1,709
17,380
10,907 $
1,117
1,746
1,373
15,143
3,847
2,279
2,411
2,586
11,123
16,004
3,694
4,510
4,295
3,506
1,865
2,210
2,105
9,686
14,413
2,982
3,956
3,478
1,250
298
353
336
2,237
341
414
201
481
1,437
1,591
712
554
817
15 %
15
15 %
11 %
27
20
24
15
10
22
9
23
15
11
24
14
23
31
OPERATING INCOME:
Millions of dollars
Completion and Production
Drilling and Evaluation
Corporate and other
Total operating income
By geographic region:
Completion and Production:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Drilling and Evaluation:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total
Total operating income by region
(excluding Corporate and other):
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
$
$
$
2012
2011
(Unfavorable)
Change
Favorable
Percentage
3,144 $
1,675
(660 )
4,159 $
2,260 $
206
347
331
3,144
680
393
246
356
1,675
2,940
599
593
687
3,733 $
1,403
(399 )
4,737 $
3,341 $
159
48
185
3,733
641
305
191
266
1,403
3,982
464
239
451
(589 )
272
(261 )
(578 )
(1,081 )
47
299
146
(589 )
39
88
55
90
272
(1,042 )
135
354
236
(16 )%
19
65
(12 )%
(32 )%
30
623
79
(16 )
6
29
29
34
19
(26 )
29
148
52
The 15% increase in consolidated revenue in 2012 compared to 2011 was primarily due to higher activity in Latin
America, Middle East/Asia, and North America. On a consolidated basis, all product service lines experienced revenue growth
from 2011. Revenue outside of North America was 44% of consolidated revenue in 2012 and 42% of consolidated revenue in
2011.
The 12% decrease in consolidated operating income compared to 2011 was mainly due to higher costs, particularly of
guar gum, and pricing pressure for production enhancement services in North America. Operating income in 2012 was
negatively impacted by a $300 million, pre-tax, loss contingency related to the Macondo well incident reflected in Corporate
and other expenses. Additionally, our results were impacted by a $48 million, pre-tax, charge related to an earn-out adjustment
due to significantly better than expected performance of a past acquisition in the Latin America and North America regions as
well as a $20 million, pre-tax, gain related to the settlement of a patent infringement lawsuit that was recorded in Corporate and
other expense. Operating income in 2011 was adversely impacted by a $25 million, pre-tax, impairment charge on an asset held
for sale in the Europe/Africa/CIS region, $11 million, pre-tax, of employee separation costs in the Eastern Hemisphere, and a
$59 million, pre-tax, charge in Libya, to reserve for certain doubtful accounts receivable and inventory. During 2012, we
received $42 million related to the Libya reserve that was established in 2011 for receivables.
Following is a discussion of our results of operations by reportable segment.
Completion and Production revenue increased in all geographic regions compared to 2011, with strong international
growth. North America revenue rose 11%, primarily due to increased cementing services and completions tools sales, as well as
higher activity in production enhancement from an increased demand for hydraulic fracturing in the United States. Latin
America revenue increased 27% due to improved activity in most product service lines in Mexico, Brazil, and Venezuela.
Europe/Africa/CIS revenue increased 20%, driven by strong demand for completion tools across the region and increased
cementing services in Mozambique and Nigeria. Middle East/Asia revenue grew 24% due to higher activity in all product
service lines in Australia, Malaysia, and Indonesia, partially offset by lower completion tools sales in China and decreased
activity in Singapore. Revenue outside of North America was 30% of total segment revenue in 2012 and 28% of total segment
revenue in 2011.
32
The Completion and Production segment operating income decrease compared to 2011 was primarily due to the North
America region, where operating income fell $1.1 billion as a result of pricing pressure in the production enhancement product
service line and rising costs, particularly related to guar gum. Latin America operating income increased 30% due to higher
demand for completion tools in Mexico and Brazil, partially offset by higher costs and pricing adjustments in Argentina and
Colombia. Europe/Africa/CIS operating income grew $299 million compared to 2011 due to the recovery from activity
disruptions in North Africa, including collections in 2012 of $29 million from the original $36 million Libya-related reserve
recognized in 2011 for certain accounts receivable and inventory. Middle East/Asia operating income increased 79% due to cost
controls in Iraq, higher activity levels in Oman, and increased demand for production enhancement and cementing services in
Australia.
Drilling and Evaluation revenue increased 15% compared to 2011 as drilling activity improved across all regions,
especially Middle East/Asia and Latin America. North America revenue grew 10% due to increased demand for drilling fluids.
Latin America revenue increased 22% due to higher demand in most product services lines in Brazil, Mexico, Venezuela, and
Colombia. Europe/Africa/CIS revenue increased 9% due to improved drilling service in Tanzania, Nigeria, and the United
Kingdom, partially offset by service disruptions in Algeria. Middle East/Asia revenue rose 23% primarily due to the ongoing
work in Iraq and Saudi Arabia, increased activity in Malaysia, and higher wireline direct sales. Revenue outside North America
was 65% of total segment revenue in 2012 and 64% of total segment revenue in 2011.
Segment operating income compared to 2011 increased 19%, primarily due to increased activity in Middle East/Asia
and Latin America. North America operating income increased 6% from increased demand for drilling fluids and wireline and
perforating, which offset higher consulting and project management costs. Latin America operating income grew 29% as a
result of activity increases in Mexico, Venezuela, and Brazil. The Europe/Africa/CIS region operating income grew 29% due to
greater activity in Nigeria and the recovery in Libya where $13 million of the original $23 million reserve from 2011 mentioned
above was collected in 2012, which more than offset higher costs in Norway. Middle East/Asia operating income increased
34% mainly due to increased activity in Malaysia and Saudi Arabia.
Corporate and other expenses were $660 million in 2012 compared to $399 million in 2011. The 65% increase was
primarily due to a $300 million, pre-tax, loss contingency recorded in 2012 related to the Macondo well incident as well as
additional expenses in 2012 associated with strategic investments in our operating model and creating competitive advantages
by repositioning our technology, supply chain, and manufacturing infrastructure. These items were partially offset by, among
other things, a $20 million, pre-tax, gain recorded in 2012 related to the settlement of a patent infringement lawsuit.
NONOPERATING ITEMS
Income (loss) from discontinued operations, net increased $224 million in 2012 compared to 2011, primarily due to a
$163 million charge, after-tax, recognized in 2011 for an arbitration award against our former subsidiary, KBR, relating to the
Barracuda-Caratinga project, a project for which we had provided a guarantee of KBR's obligations. In 2012, we recorded an
$80 million tax benefit in discontinued operations related to the $219 million payment we made to Barracuda & Caratinga
Leasing Company BV under that guarantee.
33
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;
- pensions;
- allowance for bad debts; and
- percentage-of-completion accounting for long-term, integrated project management contracts.
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.
We have discussed the development and selection of these critical accounting policies and estimates with the Audit
Committee of our Board of Directors, and the Audit Committee has reviewed the disclosure presented below.
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 80 countries. Consequently, we are subject to the jurisdiction of a significant
number of taxing authorities. No single jurisdiction has a disproportionately low tax rate. 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.
34
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.
Legal, environmental, and investigation matters
As discussed in Note 8 of our consolidated financial statements, as of December 31, 2013, 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, our future financial results may be adversely affected. 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. We conduct impairment tests on long-lived assets whenever events or changes in circumstances indicate that
the carrying value may not be recoverable and on intangible assets quarterly. 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.
We review the carrying value of these assets based upon estimated future cash flows while taking into consideration
assumptions and estimates including the future use of the asset, remaining useful life of the asset, and service potential of the
asset.
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 test goodwill for impairment annually, during the third quarter, or if an event occurs or circumstances
change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. For purposes of
performing the goodwill impairment test our reporting units are the same as our reportable segments, the Completion and
Production division and the Drilling and Evaluation division. See Note 1 to the consolidated financial statements for our
accounting policies related to long-lived assets and intangible assets, as well as the results of our goodwill impairment test.
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 to assist in fair
value determination of inventories, identifiable intangible assets, and any other significant assets or liabilities when appropriate.
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.
Pensions
Our pension benefit obligations and expenses are calculated using actuarial models and methods. Two of the more
critical assumptions and estimates used in the actuarial calculations are the discount rate for determining the current value of
benefit obligations and the expected long-term rate of return on plan assets used in determining net periodic benefit cost. Other
critical assumptions and estimates used in determining benefit obligations and cost, including demographic factors such as
retirement age, mortality, and turnover, are also evaluated periodically and updated accordingly to reflect our actual experience.
Discount rates are determined annually and are based on the prevailing market rate 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 are determined annually and are based on an evaluation of our plan assets and historical trends and
experience, taking into account current and expected market conditions. Plan assets are comprised primarily of equity and debt
35
securities. As we have both domestic and international plans, these assumptions differ based on varying factors specific to each
particular country or economic environment.
The discount rate utilized in 2013 to determine the projected benefit obligation at the measurement date for our United
Kingdom pension plan, which constituted 81% of our international plans’ pension obligations, was 4.5%, compared to a
discount rate of 4.6% utilized in 2012. The expected long-term rate of return assumption used for our United Kingdom pension
plan expense was 6.5% in 2013, compared to 6.7% in 2012.
The following table illustrates the sensitivity to changes in certain assumptions, holding all other assumptions
constant, for our United Kingdom pension plan.
Millions of dollars
25-basis-point decrease in discount rate
25-basis-point increase in discount rate
25-basis-point decrease in expected long-term rate of return
25-basis-point increase in expected long-term rate of return
$
Effect on
Pretax Pension
Expense in 2013
Pension Benefit Obligation at
December 31, 2013
1 $
(1 )
2
(2 )
55
(51 )
NA
NA
Our international defined benefit plans reduced pretax income by $32 million in 2013, $26 million in 2012, and $27
million in 2011. Included in these amounts was income from expected pension returns of $44 million in 2013, $45 million in
2012, and $47 million in 2011. Actual returns on international plan assets totaled $117 million in 2013, compared to $87
million in 2012. Our net actuarial loss, net of tax, related to international pension plans was $222 million at December 31, 2013
and $208 million at December 31, 2012. In our international plans where employees earn additional benefits for continued
service, actuarial gains and losses will be recognized in operating income over a period of three to 17 years, which represents
the estimated average remaining service of the participant group expected to receive benefits. In our international plans where
benefits are not accrued for continued service, actuarial gains and losses will be recognized in operating income over a period
of 17 to 33 years, which represents the estimated average remaining lifetime of the benefit obligations. These ranges reflect
varying maturity levels among the plans.
During 2013, we made contributions of $26 million to fund our international defined benefit plans. We expect to make
contributions of approximately $17 million to our international defined benefit plans in 2014.
The actuarial assumptions used in determining our pension benefit obligations may differ materially from actual
results due to changing market and economic conditions, higher or lower withdrawal rates, and longer or shorter life spans of
participants. While we believe that the assumptions used are appropriate, differences in actual experience or changes in
assumptions may materially affect our financial position or results of operations. See Note 14 to the consolidated financial
statements for further information related to defined benefit and other postretirement benefit plans.
Allowance for bad debts
We evaluate our 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 1.6% to 3.0%. At December 31, 2013, allowance for bad debts totaled $117 million, or 1.9% of
notes and accounts receivable before the allowance. At December 31, 2012, allowance for bad debts totaled $92 million, or
1.6% 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, 2013 would have resulted in a $62 million
adjustment to 2013 total operating costs and expenses. See Note 3 to the consolidated financial statements for further
information.
36
Percentage of completion
Revenue from certain long-term, integrated project management contracts to provide well construction and completion
services is reported on the percentage-of-completion method of accounting. Progress is generally based upon physical progress
related to contractually defined units of work. At the outset of each contract, we prepare a detailed analysis of our estimated
cost to complete the project. Risks related to service delivery, usage, productivity, and other factors are considered in the
estimation process. The recording of profits and losses on long-term contracts requires an estimate of the total profit or loss
over the life of each contract. This estimate requires consideration of total contract value, change orders, and claims, less costs
incurred and estimated costs to complete. Anticipated losses on contracts are recorded in full in the period in which they
become evident. Profits are recorded based upon the total estimated contract profit times the current percentage complete for
the contract.
At least quarterly, significant projects are reviewed in detail by senior management. There are many factors that impact
future costs, including weather, inflation, labor and community disruptions, timely availability of materials, productivity, and
other factors as outlined in Item 1(a), “Risk Factors.” These factors can affect the accuracy of our estimates and materially
impact our future reported earnings. See Note 1 to the consolidated financial statements for further information.
OFF BALANCE SHEET ARRANGEMENTS
At December 31, 2013, we had no material off balance sheet arrangements, except for operating leases. For
information on our contractual obligations related to operating leases, see “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.
We use a sensitivity analysis model to measure the impact of a 10% adverse movement of foreign currency exchange
rates against the United States dollar. A hypothetical 10% adverse change in the value of all our foreign currency positions
relative to the United States dollar as of December 31, 2013 would result in an $89 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 the interest rate swaps, a hypothetical
100 basis point increase in the LIBOR rate would result in approximately an additional $10 million of interest charges for the
year ended December 31, 2013.
There are certain limitations inherent in the sensitivity analyses presented, primarily due to the assumption that interest
rates and exchange 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 13 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 8 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,” “believes,” “do not believe,” “plans,” “estimates,” “intends,”
“expects,” “do not expect,” “anticipates,” “do not anticipate,” “should,” “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
results of operations may vary materially.
37
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.
38
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.
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, 2013 based upon criteria set forth in the Internal Control - Integrated Framework (1992) issued by the Committee
of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of December 31,
2013, our internal control over financial reporting is effective.
The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2013 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/ David J. Lesar
David J. Lesar
Chairman of the Board,
President, and Chief Executive Officer
/s/ Mark A. McCollum
Mark A. McCollum
Executive Vice President and
Chief Financial Officer
39
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Halliburton Company:
We have audited the accompanying consolidated balance sheets of Halliburton Company and subsidiaries as of December 31,
2013 and 2012, and the related consolidated statements of operations, shareholders’ equity, comprehensive income, and cash
flows for each of the years in the three-year period ended December 31, 2013. These consolidated financial statements are the
responsibility of Halliburton Company’s management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of Halliburton Company and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and
their cash flows for each of the years in the three-year period ended December 31, 2013, 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),
Halliburton Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in
Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated February 7, 2014 expressed an unqualified opinion on the effectiveness of
Halliburton Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 7, 2014
40
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Halliburton Company:
We have audited Halliburton Company’s internal control over financial reporting as of December 31, 2013, based on criteria
established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Halliburton 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 Halliburton Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, 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.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Halliburton Company maintained, in all material respects, effective internal control over financial reporting as
of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2013 and 2012, and the related
consolidated statements of operations, shareholders’ equity, comprehensive income, and cash flows for each of the years in the
three-year period ended December 31, 2013, and our report dated February 7, 2014 expressed an unqualified opinion on those
consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 7, 2014
41
HALLIBURTON COMPANY
Consolidated Statements of Operations
Millions of dollars and shares except per share data
Year Ended December 31
2013
2012
2011
Revenue:
Services
Product sales
Total revenue
Operating costs and expenses:
Cost of services
Cost of sales
Loss contingency for Macondo well incident
General and administrative
Total operating costs and expenses
Operating income
Interest expense, net of interest income of $8, $7, and $5
Other, net
Income from continuing operations before income taxes
Provision for income taxes
Income from continuing operations
Income (loss) from discontinued operations, net of income tax benefit (provision)
of $1, $82, and $(18)
Net income
Noncontrolling interest in net income of subsidiaries
Net income attributable to company
Amounts attributable to company shareholders:
Income from continuing operations
Income (loss) from discontinued operations, net
Net income attributable to company
Basic income per share attributable to company shareholders:
Income from continuing operations
Income (loss) from discontinued operations, net
Net income per share
Diluted income per share attributable to company shareholders:
Income from continuing operations
Income (loss) from discontinued operations, net
Net income per share
Basic weighted average common shares outstanding
Diluted weighted average common shares outstanding
See notes to consolidated financial statements.
$
22,257 $
7,145
29,402
22,196 $
6,307
28,503
18,959
5,972
1,000
333
26,264
3,138
(331 )
(43 )
2,764
(648 )
2,116
19
2,135 $
(10 )
2,125 $
2,106 $
19
2,125 $
2.35 $
0.02
2.37 $
2.33 $
0.03
2.36 $
898
902
18,447
5,322
300
275
24,344
4,159
(298 )
(39 )
3,822
(1,235 )
2,587
58
2,645 $
(10 )
2,635 $
2,577 $
58
2,635 $
2.78 $
0.07
2.85 $
2.78 $
0.06
2.84 $
926
928
$
$
$
$
$
$
$
$
19,692
5,137
24,829
15,432
4,379
—
281
20,092
4,737
(263 )
(25 )
4,449
(1,439 )
3,010
(166 )
2,844
(5 )
2,839
3,005
(166 )
2,839
3.27
(0.18 )
3.09
3.26
(0.18 )
3.08
918
922
42
HALLIBURTON COMPANY
Consolidated Statements of Comprehensive Income
Millions of dollars
Net income
Other comprehensive income, net of income taxes:
Defined benefit and other postretirement plans adjustments
Other
Other comprehensive income (loss), net of income taxes
Comprehensive income
Comprehensive income attributable to noncontrolling interest
Comprehensive income attributable to company shareholders
See notes to consolidated financial statements.
Year Ended December 31
2013
2012
2011
$
2,135 $
2,645 $
2,844
—
2
2
2,137 $
(10 )
2,127 $
(33 )
(3 )
(36 )
2,609 $
(10 )
2,599 $
(34 )
—
(34 )
2,810
(4 )
2,806
$
$
43
HALLIBURTON COMPANY
Consolidated Balance Sheets
Millions of dollars and shares except per share data
Assets
Current assets:
Cash and equivalents
Receivables (less allowance for bad debts of $117 and $92)
Inventories
Prepaid expenses
Current deferred income taxes
Other current assets
Total current assets
Property, plant, and equipment, net of accumulated depreciation of $9,480 and $8,056
Goodwill
Other assets
Total assets
Current liabilities:
Accounts payable
Liabilities and Shareholders’ Equity
Accrued employee compensation and benefits
Deferred revenue
Loss contingency for Macondo well incident
Other current liabilities
Total current liabilities
Long-term debt
Loss contingency for Macondo well incident
Employee compensation and benefits
Other liabilities
Total liabilities
Shareholders’ equity:
Common shares, par value $2.50 per share (authorized 2,000 shares,
issued 1,072 and 1,073 shares)
Paid-in capital in excess of par value
Accumulated other comprehensive loss
Retained earnings
Treasury stock, at cost (223 and 144 shares)
Company shareholders’ equity
Noncontrolling interest in consolidated subsidiaries
Total shareholders’ equity
Total liabilities and shareholders’ equity
See notes to consolidated financial statements.
44
December 31
2013
2012
$
$
$
$
2,356 $
6,181
3,305
737
388
737
13,704
11,322
2,168
2,029
29,223 $
2,365 $
1,029
350
278
1,004
5,026
7,816
1,022
584
1,160
15,608
2,680
415
(307 )
18,842
(8,049 )
13,581
34
13,615
29,223 $
2,484
5,787
3,186
608
351
670
13,086
10,257
2,135
1,932
27,410
2,041
930
307
—
1,474
4,752
4,820
300
607
1,141
11,620
2,682
486
(309 )
17,182
(4,276 )
15,765
25
15,790
27,410
HALLIBURTON COMPANY
Consolidated Statements of Cash Flows
Millions of dollars
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation, depletion, and amortization
Loss contingency for Macondo well incident
Provision (benefit) for deferred income taxes, continuing operations
(Income) loss from discontinued operations, net
Other changes:
Receivables
Accounts payable
Payment of Barracuda-Caratinga obligation
Inventories
Other
Total cash flows from operating activities
Cash flows from investing activities:
Capital expenditures
Sales of investment securities
Purchases of investment securities
Sales of property, plant, and equipment
Acquisitions of business assets, net of cash acquired
Other investing activities
Total cash flows from investing activities
Cash flows from financing activities:
Payments to reacquire common stock
Proceeds from long-term borrowings, net of offering costs
Dividends to shareholders
Proceeds from exercises of stock options
Other financing activities
Total cash flows from 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 during the period for:
Interest
Income taxes
See notes to consolidated financial statements.
45
Year Ended December 31
2013
2012
2011
$
2,135 $
2,645 $
2,844
1,900
1,000
(132 )
(19 )
(449 )
327
(219 )
(107 )
11
4,447
(2,934 )
356
(329 )
241
(94 )
(110 )
(2,870 )
(4,356 )
2,968
(465 )
277
(178 )
(1,754 )
49
(128 )
2,484
2,356 $
1,628
300
165
(58 )
(682 )
200
—
(611 )
67
3,654
(3,566 )
258
(506 )
395
(214 )
(55 )
(3,688 )
—
—
(333 )
107
54
(172 )
(8 )
(214 )
2,698
2,484 $
1,359
—
(30 )
166
(1,218 )
649
—
(564 )
478
3,684
(2,953 )
1,001
(501 )
160
(880 )
(17 )
(3,190 )
—
978
(330 )
160
25
833
(27 )
1,300
1,398
2,698
293 $
913 $
294 $
1,098 $
261
1,285
$
$
$
Millions of dollars
Balance at December 31, 2010
Comprehensive income (loss):
Net income
Other comprehensive loss
Cash dividends ($0.36 per share)
Stock plans
Other
Balance at December 31, 2011
Comprehensive income (loss):
Net income
Other comprehensive loss
Cash dividends ($0.36 per share)
Stock plans
Other
Balance at December 31, 2012
Comprehensive income:
Net income
Other comprehensive income
Common shares repurchased
Stock plans
Cash dividends ($0.525 per share)
Other
Balance at December 31, 2013
See notes to consolidated financial statements.
HALLIBURTON COMPANY
Consolidated Statements of Shareholders' Equity
Company Shareholders’ Equity
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
$
2,674 $
339 $
(4,771 ) $ 12,371 $
(240 ) $
14 $ 10,387
—
—
—
9
—
—
—
—
82
34
—
—
—
224
—
2,839
—
(330 )
—
—
—
(33 )
—
—
—
5
(1 )
—
—
—
2,844
(34 )
(330 )
315
34
$
2,683 $
455 $
(4,547 ) $ 14,880 $
(273 ) $
18 $ 13,216
2,645
(36 )
10
—
—
—
(333 )
295
3
(3 )
25 $ 15,790
10
—
—
—
—
2,135
2
(4,356 )
484
(465 )
25
(1 )
34 $ 13,615
—
—
—
(1 )
—
2,682 $
—
—
—
(2 )
—
—
2,680 $
$
$
—
—
—
25
6
486 $
—
—
—
(97 )
—
26
415 $
—
—
—
271
—
2,635
—
(333 )
—
—
(4,276 ) $ 17,182 $
—
—
(4,356 )
583
—
—
2,125
—
—
—
(465 )
—
(8,049 ) $ 18,842 $
—
(36 )
—
—
—
(309 ) $
—
2
—
—
—
—
(307 ) $
46
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 are one of the world’s largest oilfield services companies. Our two business segments are the Completion and
Production segment and the Drilling and Evaluation segment. We provide a comprehensive range of services and products for
the exploration, development, and production of oil and natural gas around the world.
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, pensions, allowance for bad debts, and percentage-of-completion accounting for long-term contracts. 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 have 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 2013, we adopted the provisions of a new accounting standard. See Note 15 for further information. All periods
presented reflect these changes.
Revenue recognition
Overall. 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.
Software sales. Sales of perpetual software licenses, net of any deferred maintenance and support fees, are recognized
as revenue upon shipment. Sales of time-based licenses are recognized as revenue over the license period. Maintenance and
support fees are recognized as revenue ratably over the contract period, usually a one-year duration.
Percentage of completion. Revenue from certain long-term, integrated project management contracts to provide well
construction and completion services is reported on the percentage-of-completion method of accounting. Progress is generally
based upon physical progress related to contractually defined units of work. Physical percent complete is determined as a
combination of input and output measures as deemed appropriate by the circumstances. All known or anticipated losses on
contracts are provided for when they become evident. Cost adjustments that are in the process of being negotiated with
customers for extra work or changes in the scope of work are included in revenue when collection is deemed probable.
Research and development
Research and development costs are expensed as incurred. Research and development costs were $588 million in
2013, $460 million in 2012, and $401 million in 2011.
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 or market. 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.
47
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. Changes in the carrying amount of goodwill are detailed below by reportable segment.
Millions of dollars
Balance at December 31, 2011:
Current year acquisitions
Purchase price adjustments for previous acquisitions
Balance at December 31, 2012:
Current year acquisitions
Purchase price adjustments for previous acquisitions
Balance at December 31, 2013:
Completion and
Production
Drilling and
Evaluation
Total
$
$
$
1,215 $
100
196
1,511 $
43
(21 )
1,533 $
561 $
62
1
624 $
10
1
635 $
1,776
162
197
2,135
53
(20 )
2,168
The reported amounts of goodwill for each reporting unit are reviewed for impairment on an annual basis, during the
third quarter, and more frequently should negative conditions such as significant current or projected operating losses exist. In
2012 and 2011, we elected to perform a qualitative assessment for our annual goodwill impairment test. If a qualitative
assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we
would be required to perform a quantitative impairment test for goodwill. In 2013, we elected to bypass the qualitative
assessment and perform a quantitative impairment test. This two-step process involves comparing the estimated fair value of
each reporting unit to the reporting unit’s carrying value, including goodwill. If the fair value of a reporting unit exceeds its
carrying amount, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is
unnecessary. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill impairment test
would be performed to measure the amount of impairment loss to be recorded, if any. Our goodwill impairment assessment for
2013 indicated the fair value of each of our reporting units exceeded its carrying amount by a significant margin. Based on our
qualitative assessment of goodwill in 2012 and 2011, we concluded that it was more likely than not that the fair value of each of
our reporting units was greater than their carrying amount, and therefore no further testing was required. In addition, there were
no triggering events that occurred in 2013, 2012, or 2011 requiring us to perform additional impairment reviews. As such, there
were no impairments of goodwill recorded in the three-year period ended December 31, 2013.
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 three to twenty 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.
48
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.
We generally do not provide income taxes on the undistributed earnings of non-United States subsidiaries because
such earnings are intended to be reinvested indefinitely to finance foreign activities. These additional foreign earnings could be
subject to additional tax if remitted, or deemed remitted, as a dividend; however, it is not practicable to estimate the additional
amount, if any, of taxes payable. Taxes are provided as necessary with respect to earnings that are not permanently reinvested.
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. Income and expense accounts are translated at the
average rates in effect during the year, except for depreciation, cost of product sales and revenue, and expenses associated with
nonmonetary balance sheet accounts, which are translated at historical rates. Gains or losses from 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 11 for additional information related to stock-based compensation.
49
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.
Completion and Production delivers cementing, stimulation, intervention, pressure control, specialty chemicals,
artificial lift, and completion services. The segment consists of Production Enhancement, Cementing, Completion Tools,
Halliburton Boots & Coots, Multi-Chem, and Halliburton Artificial Lift.
Production Enhancement services include 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 services involve bonding the well and well casing while isolating fluid zones and maximizing wellbore
stability. Our cementing 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.
Halliburton Boots & Coots includes well intervention services, pressure control, equipment rental tools and services,
and pipeline and process services.
Multi-Chem includes oilfield production and completion chemicals and services that address production, processing,
and transportation challenges.
Halliburton Artificial Lift offers electrical submersible pumps, including the associated surface package for power,
control, and monitoring of the entire lift system, and provides installation, maintenance, repair, and testing services. The
objective of these services is to maximize reservoir and wellbore recovery by applying lifting technology and intelligent field
management solutions throughout the life of the well.
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
Drill Bits and Services, Wireline and Perforating, Testing and Subsea, Baroid, Sperry Drilling, Landmark Software and
Services, and Consulting and Project Management.
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.
Wireline and Perforating services include open-hole logging services that provide 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, which provide perforating, pipe recovery services, through-casing formation evaluation and
reservoir monitoring, casing and cement integrity measurements, and well intervention services. Borehole seismic services
include downhole seismic operations check-shots and vertical seismic profiles, and provide the link between surface seismic
and the wellbore. Finally, formation and reservoir solutions transform formation evaluation data into reservoir insight through
geoscience solutions.
Testing and Subsea services provide 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.
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. 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. Our drilling systems offer directional control for precise wellbore placement while providing
important measurements about the characteristics of the drill string and geological formations while drilling wells. Real-time
operating capabilities enable the monitoring of well progress and aid decision-making processes.
Landmark Software and Services is a supplier of integrated exploration, drilling and production software, and related
professional and data management services for the upstream oil and natural gas industry.
Consulting and Project Management provides oilfield project management and integrated solutions to independent,
integrated, and national oil companies. These offerings make use of all of our oilfield services, products, technologies, and
project management capabilities to assist our customers in optimizing the value of their oil and natural gas assets.
Corporate and other includes expenses related to support functions and corporate executives and is primarily
composed of cash and equivalents, deferred tax assets, and investment securities. Also included are certain gains, losses and
costs not attributable to a particular business segment (such as the loss contingencies related to the Macondo well incident
recorded during the first quarters of 2013 and 2012 and the $55 million charitable contribution expensed during the second
quarter of 2013).
50
Intersegment revenue and revenue between geographic areas are immaterial. Our equity in earnings and losses of
unconsolidated affiliates that are accounted for under the equity method of accounting is included in revenue and operating
income of the applicable segment.
The following tables present information on our business segments.
Operations by business segment
Millions of dollars
Revenue:
Completion and Production
Drilling and Evaluation
Total revenue
Operating income:
Completion and Production
Drilling and Evaluation
Total operations
Corporate and other
Total operating income
Interest expense, net of interest income
Other, net
Income from continuing operations before income taxes
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
Millions of dollars
Total assets:
Completion and Production
Drilling and Evaluation
Shared assets
Corporate and other
Total
Year Ended December 31
2012
2013
2011
$
$
$
$
$
$
$
$
$
$
17,506 $
11,896
29,402 $
17,380 $
11,123
28,503 $
15,143
9,686
24,829
2,875 $
1,770
4,645
(1,507 )
3,138 $
(331 ) $
(43 )
2,764 $
1,676 $
1,210
48
2,934 $
1,013 $
873
14
1,900 $
3,144 $
1,675
4,819
(660 )
4,159 $
(298 ) $
(39 )
3,822 $
2,177 $
1,318
71
3,566 $
843 $
783
2
1,628 $
3,733
1,403
5,136
(399 )
4,737
(263 )
(25 )
4,449
1,669
1,231
53
2,953
680
676
3
1,359
December 31
2013
2012
$
$
14,203 $
10,010
1,351
3,659
29,223 $
13,313
9,290
1,376
3,431
27,410
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.
51
Revenue by country is determined based on the location of services provided and products sold.
Operations by geographic area
Millions of dollars
Revenue:
United States
Other countries
Total
Millions of dollars
Net property, plant, and equipment:
United States
Other countries
Total
Year Ended December 31
2012
2013
2011
$
$
14,311 $
15,091
29,402 $
15,057 $
13,446
28,503 $
13,548
11,281
24,829
December 31
2013
2012
$
$
5,368 $
5,954
11,322 $
5,096
5,161
10,257
Note 3. Receivables
Our trade receivables are generally not collateralized. At December 31, 2013 and December 31, 2012, 34% and 36%
of our gross trade receivables were from customers in the United States. No other country or single customer accounted for
more than 10% of our gross trade receivables at these dates.
We continue to experience delays in collecting payment on our receivables from our primary customer in
Venezuela. These receivables are not disputed, and we have not historically had material write-offs relating to this customer.
Our total outstanding trade receivables in Venezuela were $486 million, or approximately 8% of our gross trade receivables, as
of December 31, 2013, compared to $491 million, or approximately 9% of our gross trade receivables, as of December 31,
2012. Of the $486 million receivables in Venezuela as of December 31, 2013, $183 million has been classified as long-term and
included within “Other assets” on our consolidated balance sheets. Of the $491 million receivables in Venezuela as of
December 31, 2012, $143 million has been classified as long-term and included within “Other assets” on our consolidated
balance sheets.
The following table presents a rollforward of our allowance for bad debts for 2011, 2012, and 2013.
Millions of dollars
Year ended December 31, 2011
Year ended December 31, 2012
Year ended December 31, 2013
Balance at
Beginning of
Period
$
Charged to
Costs and
Expenses Write-Offs
53 $
(40)
39
(7 ) $
(5 )
(14 )
Balance at
End of Period
137
92
117
91 $
137
92
Note 4. Inventories
Inventories are stated at the lower of cost or market. 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 and totaled $157 million at December 31, 2013 and $139 million at December 31, 2012. If the average cost method
had been used, total inventories would have been $35 million higher than reported at December 31, 2013 and $41 million
higher than reported at December 31, 2012. The cost of the remaining inventory was recorded on 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
2013
2012
$
$
2,445 $
720
140
3,305 $
2,264
793
129
3,186
Finished products and parts are reported net of obsolescence reserves of $130 million at December 31, 2013 and $114
million at December 31, 2012.
52
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
December 31
2013
2012
213 $
2,685
17,904
20,802
9,480
11,322 $
145
1,861
16,307
18,313
8,056
10,257
$
$
Classes of assets, excluding oil and natural gas investments, are depreciated over the following useful lives:
Buildings and Property
Improvements
2013
13%
43%
20%
24%
2012
14%
46%
14%
26%
Machinery, Equipment,
and Other
2013
22%
72%
6%
2012
20%
74%
6%
1 - 10 years
11 - 20 years
21 - 30 years
31 - 40 years
1 - 5 years
6 - 10 years
11 - 20 years
Note 6. Debt
Long-term debt consisted of the following:
Millions of dollars
3.5% senior notes due August 2023
6.15% senior notes due September 2019
7.45% senior notes due September 2039
4.75% senior notes due August 2043
6.7% senior notes due September 2038
1.0% senior notes due August 2016
3.25% senior notes due November 2021
4.5% senior notes due November 2041
2.0% senior notes due August 2018
5.9% senior notes due September 2018
7.6% senior debentures due August 2096
8.75% senior debentures due February 2021
Other
Total long-term debt
December 31
2013
2012
1,098 $
997
995
898
800
600
498
498
400
400
293
184
155
7,816 $
—
997
995
—
800
—
498
498
—
400
293
184
155
4,820
$
$
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 7.6% and
8.75% senior debentures may not be redeemed prior to maturity.
53
Revolving credit facilities
We have an unsecured $3.0 billion revolving credit facility expiring in 2018. The purpose of the facility is to
provide general working capital and credit for other corporate purposes. The full amount of the revolving credit facility was
available as of December 31, 2013.
Debt maturities
Our long-term debt matures as follows: $600 million in 2016, $45 million in 2017, $800 million in 2018, and the
remainder in 2019 and thereafter.
Note 7. KBR Separation
During 2007, we completed the separation of KBR, Inc. (KBR) from us by exchanging KBR common stock owned by
us for our common stock. We entered into various agreements relating to the separation of KBR, including, among others, a
Master Separation Agreement (MSA) and a Tax Sharing Agreement (TSA). We recorded a liability at that time reflecting the
estimated fair value of the indemnities provided to KBR. Since the separation, we have recorded adjustments to reflect changes
to our estimation of our remaining obligation. All such adjustments are recorded in “Income (loss) from discontinued
operations, net of income tax (provision) benefit.” Amounts accrued relating to our KBR indemnity obligations were included
in “Other liabilities” in our consolidated balance sheets and totaled $219 million as of December 31, 2012. In 2013, we paid
$219 million to satisfy our obligation under a guarantee related to the Barracuda-Caratinga matter, a legacy KBR project.
Accordingly, there were no amounts accrued for indemnities provided to KBR at December 31, 2013.
Tax sharing agreement
The TSA provides for the calculation and allocation of United States and certain other jurisdiction tax liabilities
between KBR and us for the periods 2001 through the date of separation. The TSA is complex, and finalization of amounts
owed between KBR and us under the TSA can occur only after income tax audits are completed by the taxing authorities and
both parties have had time to analyze the results.
During the second quarter of 2012, we sent a notice under the TSA to KBR requesting the appointment of an arbitrator
in accordance with the terms of the TSA. This request asked the arbitrator to find that KBR owed us a certain amount pursuant
to the TSA. KBR denied that it owed us any amount and asserted instead that we owed KBR a certain amount under the TSA.
KBR also asserted that it believes the MSA controls its defenses to our TSA claim and demanded arbitration of those defenses
under the MSA. In July 2012, we filed suit in the District Court of Harris County, Texas, seeking to compel KBR to arbitrate
the entire dispute in accordance with the provisions of the TSA, rather than the MSA. KBR filed a cross-motion seeking to
compel arbitration of its defenses under the MSA. In September 2012, the court denied our motion and granted KBR's motion
to compel arbitration under the MSA. We continue to believe that the TSA was intended to govern the entire matter and have
appealed. The appeal is pending.
In May 2013, KBR's defenses were arbitrated before a panel appointed pursuant to the MSA. In June 2013, the panel
issued its decision, finding it had jurisdiction to hear the dispute and that a portion of our claims made under the TSA were
barred by the time limitation provision in the MSA. In September 2013, we filed a motion and an application to vacate the
panel's decision with the District Court of Harris County, Texas. The court has not ruled on the motion or application.
The MSA panel also ordered the parties to return to the TSA arbitrator for determination of the parties' remaining
claims under the TSA. On October 9, 2013, the TSA arbitrator issued a report regarding the claims made by each party. The
report found that KBR owes us a net amount of approximately $105 million, plus interest, with each party bearing its own costs
related to the matter.
On October 21, 2013, KBR submitted a request for clarification and reconsideration of the TSA arbitrator's report. In
December 2013, the TSA arbitrator issued a supplemental report that reaffirmed the award.
In January 2014, KBR filed a motion with the MSA panel to enforce the panel's June 2013 decision. KBR's motion
claimed, among other things, that certain of our claims submitted to the TSA arbitrator were time-barred under the MSA and
that the TSA arbitrator misinterpreted the TSA. On February 3, 2014, we filed a response to KBR's motion and an application to
confirm the TSA arbitrator's award with the District Court of Harris County, Texas. Due to the uncertainty surrounding the
ultimate determination of the parties' claims under the TSA, no material anticipated recovery amounts or liabilities related to
this matter have been recognized in the consolidated financial statements as of December 31, 2013.
54
Note 8. Commitments and Contingencies
Macondo well incident
Overview. The semisubmersible drilling rig, Deepwater Horizon, sank on April 22, 2010 after an explosion and fire
onboard the rig that began on April 20, 2010. The Deepwater Horizon was owned by Transocean Ltd. and had been drilling the
Macondo exploration well in Mississippi Canyon Block 252 in the Gulf of Mexico for the lease operator, BP Exploration &
Production, Inc. (BP Exploration), an indirect wholly owned subsidiary of BP p.l.c. We performed a variety of services for BP
Exploration, including cementing, mud logging, directional drilling, measurement-while-drilling, and rig data acquisition
services. Crude oil flowing from the well site spread across thousands of square miles of the Gulf of Mexico and reached the
United States Gulf Coast. Efforts to contain the flow of hydrocarbons from the well were led by the United States government
and by BP p.l.c., BP Exploration, and their affiliates (collectively, BP). There were eleven fatalities and a number of injuries as
a result of the Macondo well incident.
We are currently unable to fully estimate the impact the Macondo well incident will have on us. The multi-district
litigation (MDL) proceeding referred to below is ongoing. We cannot predict the outcome of the many lawsuits and
investigations relating to the Macondo well incident, including orders and rulings of the court that impact the MDL, the results
of the MDL trial, the effect that the settlements between BP and the Plaintiffs' Steering Committee (PSC) in the MDL and other
settlements may have on claims against us, or whether we might settle with one or more of the parties to any lawsuit or
investigation. The first two phases of the MDL trial have concluded, and the MDL court could begin issuing rulings at any time.
A determination that the performance of our services on the Deepwater Horizon constituted gross negligence could result in
substantial liability to the numerous plaintiffs for punitive damages and potentially to BP with respect to its direct claims
against us.
As of December 31, 2013, our loss contingency reserve for the Macondo well incident, relating to the MDL, remained
at $1.3 billion, consisting of a current portion of $278 million and a non-current portion of $1.0 billion. This reserve represents
a loss contingency that is probable and for which a reasonable estimate of a loss can be made, although we continue to believe
that we have substantial legal arguments and defenses against any liability and that BP's indemnity obligation protects us as
described below. This loss contingency reserve does not include potential recoveries from our insurers.
We have participated in intermittent discussions with the PSC regarding the potential for a settlement that would
resolve a substantial portion of the claims pending in the MDL trial. BP, however, has not participated in any recent settlement
discussions with us. Reaching a settlement involves a complex process, and there can be no assurance as to whether or when we
may complete a settlement. In addition, the settlement discussions we have had to date do not cover all parties and claims
relating to the Macondo well incident. Accordingly, there are additional loss contingencies relating to the Macondo well
incident that are reasonably possible but for which we cannot make a reasonable estimate. Given the numerous potential
developments relating to the MDL and other lawsuits and investigations, which could occur at any time, we may adjust our
estimated loss contingency reserve in the future. Liabilities arising out of the Macondo well incident could have a material
adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
Investigations and Regulatory Action. Several regulatory agencies and others, including the specially constituted
National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (National Commission), conducted
investigations of the Macondo well incident, and reports issued as a result of those investigations have been critical of BP,
Transocean, and us, among others. For example, one or more of those reports have concluded that primary cement failure was a
direct cause of the blowout, that cement testing performed by an independent laboratory “strongly suggests” that the foam
cement slurry used on the Macondo well was unstable, and that numerous other oversights and factors caused or contributed to
the cause of the incident, including BP's failure to run a cement bond log, BP's and Transocean's failure to properly conduct and
interpret a negative-pressure test, the failure of the drilling crew and our surface data logging specialist to recognize that an
unplanned influx of oil, natural gas, or fluid into the well was occurring, communication failures among BP, Transocean, and
us, and flawed decisions relating to the design, construction, and testing of barriers critical to the temporary abandonment of the
well. The U.S. Chemical Safety and Hazard Investigation Board is also conducting an investigation of the incident.
In October 2011, the Bureau of Safety and Environmental Enforcement (BSEE) issued a notification of Incidents of
Noncompliance (INCs) to us for allegedly violating federal regulations relating to the failure to take measures to prevent the
unauthorized release of hydrocarbons, the failure to take precautions to keep the Macondo well under control, the failure to
cement the well in a manner that would, among other things, prevent the release of fluids into the Gulf of Mexico, and the
failure to protect health, safety, property, and the environment as a result of a failure to perform operations in a safe and
workmanlike manner. According to the BSEE's notice, we did not ensure an adequate barrier to hydrocarbon flow after
cementing the production casing and did not detect the influx of hydrocarbons until they were above the blowout preventer
stack. We understand that the regulations in effect at the time of the alleged violations provide for fines of up to $35,000 per day
per violation. We have appealed the INCs to the Interior Board of Land Appeals (IBLA). In January 2012, the IBLA, in
response to our and the BSEE's joint request, suspended the appeal pending certain proceedings in the MDL trial. Once the
MDL court issues a final decision in the trial, we expect to file a proposal for further action in the appeal within
55
60 days. The BSEE has announced that the INCs will be reviewed for possible imposition of civil penalties once the appeal has
ended. The BSEE has stated that this is the first time the Department of the Interior has issued INCs directly to a contractor that
was not the well's operator.
The Cementing Job and Reaction to Reports. We disagree with the reports referred to above regarding many of their
findings and characterizations with respect to our cementing and surface data logging services, as applicable, on the Deepwater
Horizon. We have provided information to the National Commission, its staff, and representatives of other investigatory bodies
that we believe has been overlooked or omitted from their reports, as applicable. We intend to continue to vigorously defend
ourselves in any investigation relating to our involvement with the Macondo well that we believe inaccurately evaluates or
depicts our services on the Deepwater Horizon.
The cement slurry on the Deepwater Horizon was designed and prepared pursuant to well condition data provided by
BP. Regardless of whether alleged weaknesses in cement design and testing are or are not ultimately established, and regardless
of whether the cement slurry was utilized in similar applications or was prepared consistent with industry standards, we believe
that had BP and Transocean properly interpreted a negative-pressure test, this test would have revealed any problems with the
cement. In addition, had BP designed the Macondo well to allow a full cement bond log test or if BP had conducted even a
partial cement bond log test, the test likely would have revealed any problems with the cement. BP, however, elected not to
conduct any cement bond log tests, and with Transocean misinterpreted the negative-pressure test, both of which could have
resulted in remedial action, if appropriate, with respect to the cementing services. Also, we believe that BP knew or should have
known about a critical, additional hydrocarbon zone in the well that BP failed to disclose to us prior to the design of the cement
program for the Macondo well.
At this time we cannot predict the impact of the investigations or reports referred to above, or the conclusions or
impact of future investigations or reports. We also cannot predict whether any investigations or reports will have an influence
on or result in us being named as a party in any action alleging liability or violation of a statute or regulation. We intend to
continue to cooperate fully with all hearings, investigations, and requests for information relating to the Macondo well incident.
We cannot predict the outcome of, or the costs to be incurred in connection with, any of these hearings or investigations, and
therefore we cannot predict the potential impact they may have on us.
DOJ Investigations and Actions. On June 1, 2010, the United States Attorney General announced that the United States
Department of Justice (DOJ) was launching civil and criminal investigations into the Macondo well incident to closely examine
the actions of those involved, and that the DOJ was working with attorneys general of states affected by the Macondo well
incident. The DOJ announced that it was reviewing, among other traditional criminal statutes, possible violations of and
liabilities under The Clean Water Act (CWA), The Oil Pollution Act of 1990 (OPA), and the Endangered Species Act of 1973
(ESA).
The CWA provides authority for civil penalties for discharges of oil into or upon navigable waters of the United States,
adjoining shorelines, or in connection with the Outer Continental Shelf Lands Act (OCSLA) in quantities that are deemed
harmful. A single discharge event may result in the assertion of numerous violations under the CWA. Civil proceedings under
the CWA can be commenced against an “owner, operator, or person in charge of any vessel, onshore facility, or offshore facility
from which oil or a hazardous substance is discharged” in violation of the CWA. The civil penalties that can be imposed against
responsible parties range from up to $1,100 per barrel of oil discharged in the case of those found strictly liable to $4,300 per
barrel of oil discharged in the case of those found to have been grossly negligent.
The OPA establishes liability for discharges of oil from vessels, onshore facilities, and offshore facilities into or upon
the navigable waters of the United States. Under the OPA, the “responsible party” for the discharging vessel or facility is liable
for removal and response costs as well as for damages, including recovery costs to contain and remove discharged oil and
damages for injury to natural resources and real or personal property, lost revenues, lost profits, and lost earning capacity. The
cap on liability under the OPA is the full cost of removal of the discharged oil plus up to $75 million for damages, except that
the $75 million cap does not apply in the event the damage was proximately caused by gross negligence or the violation of
certain federal safety, construction or operating standards. The OPA defines the set of responsible parties differently depending
on whether the source of the discharge is a vessel or an offshore facility. Liability for vessels is imposed on owners and
operators; liability for offshore facilities is imposed on the holder of the permit or lessee of the area in which the facility is
located.
The ESA establishes liability for injury and death to wildlife. The ESA provides for civil penalties for knowing
violations that can range up to $25,000 per violation.
56
On December 15, 2010, the DOJ filed a civil action seeking damages and injunctive relief against BP Exploration,
Anadarko Petroleum Corporation and Anadarko E&P Company LP (together, Anadarko), which had an approximate 25%
interest in the Macondo well, certain subsidiaries of Transocean Ltd., and others for violations of the CWA and the OPA. The
DOJ’s complaint seeks an action declaring that the defendants are strictly liable under the CWA as a result of harmful
discharges of oil into the Gulf of Mexico and upon United States shorelines as a result of the Macondo well incident. The
complaint also seeks an action declaring that the defendants are strictly liable under the OPA for the discharge of oil that has
resulted in, among other things, injury to, loss of, loss of use of, or destruction of natural resources and resource services in and
around the Gulf of Mexico and the adjoining United States shorelines and resulting in removal costs and damages to the United
States far exceeding $75 million. BP Exploration has been designated, and has accepted the designation, as a responsible party
for the pollution under the CWA and the OPA. Others have also been named as responsible parties, and all responsible parties
may be held jointly and severally liable for any damages under the OPA. A responsible party may make a claim for contribution
against any other responsible party or against third parties it alleges contributed to or caused the oil spill. In connection with the
proceedings discussed below under “Litigation,” in April 2011 BP Exploration filed a claim against us for equitable
contribution with respect to liabilities incurred by BP Exploration under the OPA or another law, which subsequent court filings
have indicated may include the CWA, and requested a judgment that the DOJ assert its claims for OPA financial liability
directly against us. We filed a motion to dismiss BP Exploration’s claim, and that motion is pending. In July 2013, we also filed
a motion for summary judgment requesting a court order that we are not liable to BP or Transocean for equitable
indemnification or contribution with regard to any CWA fines and penalties that have been assessed or may be assessed against
BP or Transocean. That motion is also pending.
We were not named as a responsible party under the CWA or the OPA in the DOJ civil action, and we do not believe
we are a responsible party under the CWA or the OPA. While we were not included in the DOJ’s civil complaint, there can be
no assurance that federal governmental authorities will not bring a civil action against us under the CWA, the OPA, and/or other
statutes or regulations.
In July 2013, we reached an agreement with the DOJ to conclude the federal government's criminal investigation of us
in relation to the Macondo well incident. Pursuant to a cooperation guilty plea agreement, Halliburton Energy Services, Inc.,
our wholly owned subsidiary (HESI), agreed to plead guilty to one misdemeanor violation of federal law concerning the
deletion of certain computer files created after the occurrence of the Macondo well incident. Pursuant to the plea agreement,
HESI agreed to pay a criminal fine of $0.2 million within five days of sentencing and agreed to three years' probation. The DOJ
has agreed that it will not pursue further criminal prosecution of us (including our subsidiaries) for any conduct relating to or
arising out of the Macondo well incident. We have agreed to continue to cooperate with the DOJ in any ongoing investigation
related to or arising from the incident. In September 2013, our guilty plea was entered and approved by a federal district court
judge on the terms and conditions of the plea agreement, and the DOJ closed its criminal investigation of us in relation to the
Macondo well incident.
In November 2012, BP announced that it reached an agreement with the DOJ to resolve all federal criminal charges
against it stemming from the Macondo well incident. BP agreed to plead guilty to 14 criminal charges, with 13 of those charges
based on the negligent misinterpretation of the negative-pressure test conducted on the Deepwater Horizon. BP also agreed to
pay $4.0 billion, including approximately $1.3 billion in criminal fines, to take actions to further enhance the safety of drilling
operations in the Gulf of Mexico, to a term of five years' probation, and to the appointment of two monitors with four-year
terms, one relating to process safety and risk management procedures concerning deepwater drilling in the Gulf of Mexico and
one relating to the improvement, implementation, and enforcement of BP's code of conduct.
In January 2013, Transocean announced that it reached an agreement with the DOJ to resolve certain claims for civil
penalties and potential criminal claims against it arising from the Macondo well incident. Transocean agreed to plead guilty to
one misdemeanor violation of the CWA for negligent discharge of oil into the Gulf of Mexico, to pay $1.0 billion in CWA
penalties and $400 million in fines and recoveries, to implement certain measures to prevent a recurrence of an uncontrolled
discharge of hydrocarbons, and to a term of five years' probation.
Litigation. Since April 21, 2010, plaintiffs have been filing lawsuits relating to the Macondo well incident. Generally,
those lawsuits allege either (1) damages arising from the oil spill pollution and contamination (e.g., diminution of property
value, lost tax revenue, lost business revenue, lost tourist dollars, inability to engage in recreational or commercial activities) or
(2) wrongful death or personal injuries. We are named along with other unaffiliated defendants in more than 1,800 complaints,
most of which are alleged class actions, involving pollution damage claims and at least eight personal injury lawsuits involving
four decedents and at least 10 allegedly injured persons who were on the drilling rig at the time of the incident. At least six
additional lawsuits naming us and others relate to alleged personal injuries sustained by those responding to the explosion and
oil spill.
The pollution complaints generally allege, among other things, negligence and gross negligence, property damages,
taking of protected species, and potential economic losses as a result of environmental pollution, and generally seek awards of
unspecified economic, compensatory, and punitive damages, as well as injunctive relief. Plaintiffs in these pollution cases have
brought suit under various legal provisions, including the OPA, the CWA, The Migratory Bird Treaty Act of 1918, the ESA, the
OCSLA, the Longshoremen and Harbor Workers Compensation Act, general maritime law, state common law, and various state
57
environmental and products liability statutes. Furthermore, the pollution complaints include suits brought against us by
governmental entities, including all of the coastal states of the Gulf of Mexico, numerous local governmental entities, the
Mexican State of Yucatan, and the United Mexican States.
The wrongful death and other personal injury complaints generally allege negligence and gross negligence and seek
awards of compensatory damages, including unspecified economic damages, and punitive damages. We have retained counsel
and are investigating and evaluating the claims, the theories of recovery, damages asserted, and our respective defenses to all of
these claims.
Plaintiffs originally filed the lawsuits described above in federal and state courts throughout the United States. Except
for a relatively small number of lawsuits not yet consolidated, the Judicial Panel on Multi-District Litigation ordered all of the
lawsuits against us consolidated in the MDL proceeding before Judge Carl Barbier in the United States Eastern District of
Louisiana.
Judge Barbier is also presiding over a separate proceeding filed by Transocean under the Limitation of Liability Act
(Limitation Action). In the Limitation Action, Transocean seeks to limit its liability for claims arising out of the Macondo well
incident to the value of the rig and its freight. While the Limitation Action has been formally consolidated into the MDL, the
court is nonetheless, in some respects, treating the Limitation Action as an associated but separate proceeding. In February
2011, Transocean tendered us, along with all other defendants, into the Limitation Action. As a result of the tender, we and all
other defendants are being treated as direct defendants to the plaintiffs' claims as if the plaintiffs had sued us and the other
defendants directly. In the Limitation Action, the judge intends to determine the allocation of liability among all defendants in
the hundreds of lawsuits associated with the Macondo well incident, including those in the MDL proceeding that are pending in
his court. Specifically, the judge intends to determine the liability, limitation, exoneration, and fault allocation with regard to all
of the defendants in a trial, which to date has occurred in two phases. We do not believe that a single determination of liability
in the Limitation Action is properly applied, particularly with respect to gross negligence and punitive damages, to the hundreds
of lawsuits pending in the MDL proceeding.
The defendants in the proceedings described above have filed numerous cross claims and third party claims against
certain other defendants. Claims against us seek subrogation, contribution, indemnification, including with respect to liabilities
under the OPA, and direct damages, and allege negligence, gross negligence, fraudulent conduct, willful misconduct, fraudulent
concealment, comparative fault, and breach of warranty of workmanlike performance. Additional civil lawsuits may be filed
against us. In addition to the claims against us, generally the defendants in the proceedings described above, including us, filed
claims, including for liabilities under the OPA and other claims similar to those described above, against the other defendants.
Our claims against the other defendants seek contribution and indemnification, and allege negligence, gross negligence and
willful misconduct. Several of the parties have settled claims among themselves, and claims against some parties have been
dismissed. We have also filed an answer to Transocean's Limitation petition denying Transocean's right to limit its liability,
denying all claims and responsibility for the incident, seeking contribution and indemnification, and alleging negligence and
gross negligence.
Judge Barbier has issued an order, among others, clarifying certain aspects of law applicable to the lawsuits pending in
his court. The court ruled that: (1) general maritime law will apply, and therefore all claims brought under state law causes of
action were dismissed; (2) general maritime law claims may be brought directly against defendants who are non-“responsible
parties” under the OPA with the exception of pure economic loss claims by plaintiffs other than commercial fishermen; (3) all
claims for damages, including pure economic loss claims, may be brought under the OPA directly against responsible parties;
and (4) punitive damage claims can be brought against both responsible and non-responsible parties under general maritime
law. As discussed above, with respect to the ruling that claims for damages may be brought under the OPA against responsible
parties, we have not been named as a responsible party under the OPA, but BP Exploration has filed a claim against us for
contribution with respect to liabilities incurred by BP Exploration under the OPA. The rulings in the court's order remain subject
to each applicable party's right to appeal. Certain parishes in Louisiana are currently appealing the dismissal of their state law
claims under the order.
In April 2012, BP announced that it had reached definitive settlement agreements with the PSC to resolve the
substantial majority of eligible private economic loss and medical claims stemming from the Macondo well incident. The PSC
acts on behalf of individuals and business plaintiffs in the MDL. According to BP, the settlements do not include claims against
BP made by the DOJ or other federal agencies or by states and local governments. In addition, the settlements provide that, to
the extent permitted by law, BP will assign to the settlement class certain of its claims, rights, and recoveries against Transocean
and us for damages, including BP's alleged direct damages such as damages for clean-up expenses and damage to the well and
reservoir. We do not believe that our contract with BP Exploration permits the assignment of certain claims to the settlement
class without our consent. The MDL court has since confirmed certification of the classes for both settlements and granted final
approval of the settlements. We objected to the settlements on the grounds set forth above, among other reasons. The MDL
court held, however, that we, as a non-settling defendant, lacked standing to object to the settlements but noted that it did not
express any opinion as to the validity of BP's assignment of certain claims to the settlement class and that the settlements do not
affect any of our procedural or substantive rights in the MDL. BP has been challenging certain provisions of its settlement of
economic loss claims in the MDL court and before the United States Fifth Circuit Court of Appeals. We are unable to predict at
58
this time the effect that the settlements, or any challenge, modification, or overturning of the settlements, may have on claims
against us.
The MDL court has dismissed: (1) claims by or on behalf of owners, lessors, and lessees of real property that allege to
have suffered a reduction in the value of real property even though the property was not physically touched by oil and the
property was not sold; (2) claims for economic losses based solely on consumers' decisions not to purchase fuel or goods from
BP fuel stations and stores based on consumer animosity toward BP; and (3) claims by or on behalf of recreational fishermen,
divers, beachgoers, boaters and others that allege damages such as loss of enjoyment of life from their inability to use portions
of the Gulf of Mexico for recreational and amusement purposes. In dismissing those claims, the MDL court also noted that we
are not liable with respect to those claims under the OPA because we are not a “responsible party” under OPA. A group of
plaintiffs appealed the order, but the Fifth Circuit dismissed the appeal.
The first phase of the MDL trial, which concluded in April 2013, covered issues arising out of the conduct and degree
of culpability of various parties allegedly relevant to the loss of well control, the ensuing fire and explosion on and sinking of
the Deepwater Horizon, and the initiation of the release of hydrocarbons from the Macondo well. At the conclusion of the
plaintiffs' case, we and the other defendants each submitted a motion requesting the MDL court to dismiss certain claims. In
March 2013, the MDL court denied our motion and declined to dismiss any claims, including those alleging gross negligence,
against BP, Transocean and us. In addition, the MDL court dismissed all claims against M-I Swaco and claims alleging gross
negligence against Cameron International Corporation (Cameron). In April 2013, the MDL court dismissed all remaining
claims against Cameron, leaving BP, Transocean, and us as the remaining defendants with respect to the matters addressed
during the first phase of the trial.
Also in March 2013, we advised the MDL court that we recently found a rig sample of dry cement blend collected at
another well that was cemented before the Macondo well using the same dry cement blend as used on the Macondo production
casing. In April 2013, we advised the MDL parties that we recently discovered some additional documents related to the
Macondo well incident. BP and others have asked the court to impose sanctions and adverse findings against us because,
according to their allegations, we should have identified the cement sample in 2010 and the additional documents by October
2011. BP also reasserted its previous allegations that we destroyed evidence relating to post-incident testing of the foam cement
slurry on the Deepwater Horizon. The MDL court has not ruled on the requests for sanctions and adverse findings. We believe
that the discoveries were the result of simple misunderstandings or mistakes and do not involve any material evidence, and that
sanctions are not warranted.
When our plea agreement with the DOJ was announced in July 2013, BP filed a motion requesting that the MDL court
re-open the evidence for phase one of the MDL trial to take into account our guilty plea and re-urging their request for
sanctions. After the plea was entered, the PSC and the States of Alabama and Louisiana (as coordinating counsel for the states
involved in the MDL) filed a motion likewise seeking to admit the guilty plea agreement and other court filings into evidence
and asking that the MDL court use that evidence as a basis for assessing punitive damages against us. We filed replies opposing
both motions and setting forth our position that the deleted post-incident computer simulations were not evidence, were not
relevant, and in any event were re-created. The MDL court has not ruled on the motions.
The second phase of the MDL trial was split into two parts, with testimony presented in October 2013. The first part
covered attempts to collect, control, or halt the flow of hydrocarbons from the well, while the second part covered the
quantification of hydrocarbons discharged from the well. The parties submitted proposed findings of fact and conclusions of
law, post-trial briefs and responses during December 2013 and January 2014. According to a stipulation and post-trial filings,
BP contends that 2.45 million barrels of oil were released into the Gulf of Mexico and the DOJ contends that a total of 4.2
million barrels were released. The MDL court has not issued a ruling on the questions that were the subject of the first two
phases of the trial, although those rulings could be issued at any time.
Subsequent proceedings would be held to the extent triable issues remain unresolved by the first two phases of the
trial, settlements, motion practice, or stipulation. Although the DOJ participated in the first two phases of the trial with regard to
BP's conduct and the amount of hydrocarbons discharged from the well, the MDL court anticipates that the DOJ's civil action
for the CWA violations, fines, and penalties will be addressed by the court in a third phase of the trial to the extent necessary.
Damages for the cases tried in the MDL proceeding, including punitive damages, are expected to be tried following the
issuance of the MDL court’s rulings regarding the phases of the trial described above. Under ordinary MDL procedures, such
cases would, unless waived by the respective parties, be tried in the courts from which they were transferred into the MDL. It
remains unclear, however, what impact the overlay of the Limitation Action will have on where these matters are tried. The
judge has indicated that he intends for the State of Alabama’s OPA compensatory damages claims against BP be tried as a test
case.
We intend to vigorously defend any litigation, fines, and/or penalties relating to the Macondo well incident and to
vigorously pursue any damages, remedies, or other rights available to us as a result of the Macondo well incident. We have
incurred and expect to continue to incur significant legal fees and costs, some of which we expect to be covered by indemnity
or insurance, as a result of the numerous investigations and lawsuits relating to the incident.
59
Indemnification and Insurance. Our contract with BP Exploration relating to the Macondo well generally provides for
our indemnification by BP Exploration for certain potential claims and expenses relating to the Macondo well incident,
including those resulting from pollution or contamination (other than claims by our employees, loss or damage to our property,
and any pollution emanating directly from our equipment). Also, under our contract with BP Exploration, we have, among other
things, generally agreed to indemnify BP Exploration and other contractors performing work on the well for claims for personal
injury of our employees and subcontractors, as well as for damage to our property. In turn, we believe that BP Exploration was
obligated to obtain agreement by other contractors performing work on the well to indemnify us for claims for personal injury
of their employees or subcontractors, as well as for damages to their property. We have entered into separate indemnity
agreements with Transocean and M-I Swaco, under which we have agreed to indemnify those parties for claims for personal
injury of our employees and subcontractors and they have agreed to indemnify us for claims for personal injury of their
employees and subcontractors.
In April 2011, we filed a lawsuit against BP Exploration in Harris County, Texas to enforce BP Exploration’s
contractual indemnity and alleging BP Exploration breached certain terms of the contractual indemnity provision. BP
Exploration removed that lawsuit to federal court in the Southern District of Texas, Houston Division. We filed a motion to
remand the case to Harris County, Texas, and the lawsuit was transferred to the MDL.
BP Exploration, in connection with filing its claims with respect to the MDL proceeding, asked that court to declare
that it is not liable to us in contribution, indemnification, or otherwise with respect to liabilities arising from the Macondo well
incident. Other defendants in the litigation discussed above have generally denied any obligation to contribute to any liabilities
arising from the Macondo well incident.
In January 2012, the court in the MDL proceeding entered an order in response to our and BP’s motions for summary
judgment regarding certain indemnification matters. The court held that BP is required to indemnify us for third-party
compensatory claims, or actual damages, that arise from pollution or contamination that did not originate from our property or
equipment located above the surface of the land or water, even if we are found to be grossly negligent. The court did not
express an opinion as to whether our conduct amounted to gross negligence, but we do not believe the performance of our
services on the Deepwater Horizon constituted gross negligence. The court also held, however, that BP does not owe us
indemnity for punitive damages or for civil penalties under the CWA, if any, and that fraud could void the indemnity on public
policy grounds, although the court stated that it was mindful that mere failure to perform contractual obligations as promised
does not constitute fraud. As discussed above, the DOJ is not seeking civil penalties from us under the CWA, but BP has filed a
claim for equitable contribution against us with respect to its liabilities. The court in the MDL proceeding deferred ruling on
whether our indemnification from BP covers penalties or fines under the OCSLA, whether our alleged breach of our contract
with BP Exploration would invalidate the indemnity, and whether we committed an act that materially increased the risk to or
prejudiced the rights of BP so as to invalidate the indemnity. We do not believe that we breached our contract with BP
Exploration or committed an act that would otherwise invalidate the indemnity. The court’s rulings will be subject to appeal at
the appropriate time.
The rulings in the MDL proceeding regarding the indemnities are based on maritime law and may not bind the
determination of similar issues in lawsuits not comprising a part of the MDL proceeding. Accordingly, it is possible that
different conclusions with respect to indemnities will be reached by other courts.
Indemnification for criminal fines or penalties, if any, may not be available if a court were to find such indemnification
unenforceable as against public policy. In addition, certain state laws, if deemed to apply, would not allow for enforcement of
indemnification for gross negligence, and may not allow for enforcement of indemnification of persons who are found to be
negligent with respect to personal injury claims.
In addition to the contractual indemnities discussed above, we have a general liability insurance program of $600
million. Our insurance is designed to cover claims by businesses and individuals made against us in the event of property
damage, injury, or death and, among other things, claims relating to environmental damage, as well as legal fees incurred in
defending against those claims. We have received and expect to continue to receive payments from our insurers with respect to
covered legal fees incurred in connection with the Macondo well incident. Through December 31, 2013, we have incurred legal
fees and related expenses of approximately $264 million, of which $235 million has been reimbursed under or is expected to be
covered by our insurance program. To the extent we incur any losses beyond those covered by indemnification, there can be no
assurance that our insurance policies will cover all potential claims and expenses relating to the Macondo well incident. In
addition, we may not be insured with respect to civil or criminal fines or penalties, if any, pursuant to the terms of our insurance
policies. Insurance coverage can be the subject of uncertainties and, particularly in the event of large claims, potential disputes
with insurance carriers, as well as other potential parties claiming insured status under our insurance policies.
BP’s public filings indicate that BP has recognized in excess of $40 billion in pre-tax charges, excluding offsets for
settlement payments received from certain defendants in the proceedings described above under “Litigation,” as a result of the
Macondo well incident. BP’s public filings also indicate that the amount of, among other things, certain natural resource
damages with respect to certain OPA claims, some of which may be included in such charges, cannot be reliably estimated as of
the dates of those filings.
60
Securities and related litigation
In June 2002, a class action lawsuit was filed against us in federal court alleging violations of the federal securities
laws after the Securities and Exchange Commission (SEC) initiated an investigation 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. Several of those lawsuits also named as defendants several of our present or
former officers and directors. The class action cases were later consolidated, and the amended consolidated class action
complaint, styled Richard Moore, et al. v. Halliburton Company, et al., was filed and served upon us in April 2003. As a result
of a substitution of lead plaintiffs, the case was styled Archdiocese of Milwaukee Supporting Fund (AMSF) v. Halliburton
Company, et al. AMSF has changed its name to Erica P. John Fund, Inc. (the Fund). We settled with the SEC in the second
quarter of 2004.
In June 2003, the lead plaintiffs filed a motion for leave to file a second amended consolidated complaint, which was
granted by the court. In addition to restating the original accounting and disclosure claims, the second amended consolidated
complaint included claims arising out of our 1998 acquisition of Dresser Industries, Inc., including that we failed to timely
disclose the resulting asbestos liability exposure.
In April 2005, the court appointed new co-lead counsel and named the Fund the new lead plaintiff, directing that it file
a third consolidated amended complaint and that we file our motion to dismiss. The court held oral arguments on that motion in
August 2005. In March 2006, the court entered an order in which it granted the motion to dismiss with respect to claims arising
prior to June 1999 and granted the motion with respect to certain other claims while permitting the Fund to re-plead some of
those claims to correct deficiencies in its earlier complaint. In April 2006, the Fund filed its fourth amended consolidated
complaint. We filed a motion to dismiss those portions of the complaint that had been re-pled. A hearing was held on that
motion in July 2006, and in March 2007 the court ordered dismissal of the claims against all individual defendants other than
our Chief Executive Officer (CEO). The court ordered that the case proceed against our CEO and us.
In September 2007, the Fund filed a motion for class certification, and our response was filed in November 2007. The
district court held a hearing in March 2008, and issued an order November 3, 2008 denying the motion for class certification.
The Fund appealed the district court’s order to the Fifth Circuit Court of Appeals. The Fifth Circuit affirmed the district court’s
order denying class certification. On May 13, 2010, the Fund filed a writ of certiorari in the United States Supreme Court. In
January 2011, the Supreme Court granted the writ of certiorari and accepted the appeal. The Court heard oral arguments in April
2011 and issued its decision in June 2011, reversing the Fifth Circuit ruling that the Fund needed to prove loss causation in
order to obtain class certification. The Court’s ruling was limited to the Fifth Circuit’s loss causation requirement, and the case
was returned to the Fifth Circuit for further consideration of our other arguments for denying class certification. The Fifth
Circuit returned the case to the district court, and in January 2012 the court issued an order certifying the class. We filed a
Petition for Leave to Appeal with the Fifth Circuit, which was granted. In April 2013, the Fifth Circuit issued an order affirming
the District Court's order certifying the class.
We filed a writ of certiorari with the United States Supreme Court seeking an appeal of the Fifth Circuit decision. In
November 2013, the Supreme Court granted our writ. Oral argument is scheduled to be held before the Supreme Court on
March 5, 2014. Fact discovery in this case has resumed. We cannot predict the outcome or consequences of this case, which we
intend to vigorously defend.
Investigations
We are conducting internal investigations of certain areas of our operations in Angola and Iraq, focusing on
compliance with certain company policies, including our Code of Business Conduct (COBC), and the FCPA and other
applicable laws.
In December 2010, we received an anonymous e-mail alleging that certain current and former personnel violated our
COBC and the FCPA, principally through the use of an Angolan vendor. The e-mail also alleges conflicts of interest, self-
dealing, and the failure to act on alleged violations of our COBC and the FCPA. We contacted the DOJ to advise them that we
were initiating an internal investigation.
During the second quarter of 2012, in connection with a meeting with the DOJ and the SEC regarding the above
investigation, we advised the DOJ and the SEC that we were initiating unrelated, internal investigations into payments made to
a third-party agent relating to certain customs matters in Angola and to third-party agents relating to certain customs and visa
matters in Iraq.
Since the initiation of the investigations described above, we have participated in meetings with the DOJ and the SEC
to brief them on the status of the investigations and have been producing documents to them both voluntarily and as a result of
SEC subpoenas to us and certain of our current and former officers and employees.
We expect to continue to have discussions with the DOJ and the SEC regarding the Angola and Iraq matters described
above and have indicated that we would further update them as our investigations progress. We have engaged outside counsel
and independent forensic accountants to assist us with these investigations.
During the second quarter of 2013, we received a civil investigative demand from the Antitrust Division of the DOJ
regarding pressure pumping services. We have engaged in discussions with the DOJ on this matter and have provided responses
61
to the DOJ's information requests. We understand there have been others in our industry who have received similar
correspondence from the DOJ, and we do not believe that we are being singled out for any particular scrutiny.
We intend to continue to cooperate with the DOJ's and the SEC's inquiries and requests in these investigations.
Because these investigations are ongoing, we cannot predict their outcome or the consequences thereof.
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, in addition
to the matters relating to the Macondo well incident described above, we are involved in other 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. Excluding our loss contingency for the
Macondo well incident, our accrued liabilities for environmental matters were $66 million as of December 31, 2013 and $72
million as of December 31, 2012. 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.
In November 2012, we received an Enforcement Notice from the Pennsylvania Department of Environmental
Protection (PADEP) regarding an alleged improper disposal of oil field acid in or around Homer City, Pennsylvania between
1999 and 2011. In February 2014, we agreed to resolve this matter for $2 million to settle the PADEP's claim for civil penalties.
Additionally, we have subsidiaries that have been named as potentially responsible parties along with other third
parties for nine federal and state Superfund sites for which we have established reserves. As of December 31, 2013, those nine
sites accounted for approximately $5 million of our $66 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 $2.1
billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2013, including $192 million
of surety bond guarantees related to our Venezuelan operations. Some of the outstanding letters of credit have triggering events
that would entitle a bank to require cash collateralization.
Leases
We are party to numerous operating leases, principally for the use of land, offices, equipment, manufacturing and field
facilities, and warehouses. Total rentals on our operating leases, net of sublease rentals, were $958 million in 2013, $850
million in 2012, and $735 million in 2011.
Future total rentals on our noncancellable operating leases are $946 million in the aggregate, which includes the
following: $282 million in 2014; $215 million in 2015; $156 million in 2016; $83 million in 2017; $56 million in 2018; and
$154 million thereafter.
62
Note 9. Income Taxes
The components of the (provision)/benefit 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
Provision for income taxes
Year Ended December 31
2012
2011
2013
$
$
(245 ) $
(485 )
(49 )
(779 )
4
125
2
131
(648 ) $
(695 ) $
(328 )
(47 )
(1,070 )
(168 )
15
(12 )
(165 )
(1,235 ) $
(1,026 )
(334 )
(109 )
(1,469 )
(28 )
57
1
30
(1,439 )
The United States and foreign components of income from continuing operations before income taxes were as follows:
Millions of dollars
United States
Foreign
Total
Year Ended December 31
2013
2012
2011
$
$
1,070 $
1,694
2,764 $
2,826 $
996
3,822 $
4,040
409
4,449
Reconciliations between the actual provision for income taxes on continuing operations and that computed by applying
the United States statutory rate to income from continuing operations before income taxes were as follows:
United States statutory rate
Impact of foreign income taxed at different rates
Domestic manufacturing deduction
State income taxes
Adjustments of prior year taxes
Other impact of foreign operations
Other items, net
Total effective tax rate on continuing operations
Year Ended December 31
2013
2012
2011
35.0 %
35.0 %
35.0 %
(9.3 )
(2.0 )
1.7
(1.3 )
(0.2 )
(0.4 )
23.5 %
(2.5 )
(2.2 )
1.6
(0.6 )
(0.5 )
1.5
32.3 %
(0.5 )
(2.1 )
1.6
(1.5 )
(0.4 )
0.2
32.3 %
Our effective tax rate on continuing operations was 23.5% for 2013 and 32.3% for 2012 and 2011. The 2013 effective
tax rate on continuing operations was positively impacted by several items during the year, including federal tax benefits of
approximately $50 million due to the reinstatement of certain tax benefits and credits related to the first quarter enactment of
the American Taxpayer Relief Act of 2012. Also contributing to the lower tax rate in 2013 was a $1.0 billion loss contingency
related to the Macondo well incident, which was tax-effected at the United States statutory rate, as well as some favorable tax
items in Latin America in the fourth quarter. Additionally, our effective tax rate was positively impacted by lower tax rates in
certain foreign jurisdictions, as we continue to reposition our technology, supply chain, and manufacturing infrastructure to
more effectively serve our customers internationally.
We have not provided United States income taxes and foreign withholding taxes on the undistributed earnings of
foreign subsidiaries as of December 31, 2013 because we intend to permanently reinvest such earnings outside the United
States. If these foreign earnings were to be repatriated in the future, the related United States tax liability may be reduced by
any foreign income taxes previously paid on these earnings. As of December 31, 2013, the cumulative amount of earnings upon
which United States income taxes have not been provided is approximately $6.1 billion. It is not practicable to estimate the
amount of unrecognized deferred tax liability related to these earnings at this time.
63
The primary components of our deferred tax assets and liabilities were as follows:
Millions of dollars
Gross deferred tax assets:
Net operating loss carryforwards
Accrued liabilities
Employee compensation and benefits
Other
Total gross deferred tax assets
Gross deferred tax liabilities:
Depreciation and amortization
Other
Total gross deferred tax liabilities
Valuation allowances – net operating loss carryforwards
Net deferred income tax asset (liability)
December 31
2013
2012
$
$
481 $
600
351
162
1,594
1,185
81
1,266
374
(46 ) $
474
329
375
160
1,338
859
137
996
395
(53 )
At December 31, 2013, we had $1.6 billion of net operating loss carryforwards, of which $161 million will expire
from 2014 through 2017, $295 million will expire from 2018 through 2022, and $53 million will expire from 2023 through
2033. The remaining balance will not expire.
The following table presents a rollforward of our unrecognized tax benefits and associated interest and penalties.
Unrecognized
Tax Benefits
Interest
and Penalties
$
$
Millions of dollars
Balance at January 1, 2011
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, 2011
Change in prior year tax positions
Change in current year tax positions
Cash settlements with taxing authorities
Lapse of statute of limitations
32
41
1
(3 )
(2 )
69
(1 )
1
—
(1 )
68
(9 )
1
(17 )
(9 )
34
(a) Includes $27 million as of December 31, 2013 and $59 million as of December 31, 2012 in foreign unrecognized tax
Balance at December 31, 2012
Change in prior year tax positions
Change in current year tax positions
Cash settlements with taxing authorities
Lapse of statute of limitations
177
38
5
(12 )
(3 )
205
16
14
(3 )
(4 )
228 (a)
(53 )
30
(21 )
(9 )
Balance at December 31, 2013
175 (a)(b) $
$
$
$
$
$
benefits that would give rise to a United States tax credit. The remaining balance of $138 million, which excludes $10
million of unrecognized tax benefits covered by an indemnification asset, as of December 31, 2013 and $169 million
as of December 31, 2012, if resolved in our favor, would positively impact the effective tax rate and, therefore, be
recognized as additional tax benefits in our statement of operations.
(b) Includes $3 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
before 2005. 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 year 2012 is open for review,
2003 through 2009 are under appeal for tax items not agreed, and 2010 through 2011 are under examination by the Internal
Revenue Service. During 2013, the Congressional Joint Committee on Taxation approved a $135 million income tax refund,
excluding interest, to us for tax items agreed upon for the tax years 2003 through 2009.
64
Note 10. 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
2013
2012
1,072
(223 )
849
1,073
(144 )
929
In July 2013, our Board of Directors increased the authorization to purchase Halliburton common stock under our
stock repurchase program by $4.3 billion, to a new total repurchase capacity of $5.0 billion. In August 2013, we repurchased
approximately 68 million shares of our common stock for an aggregate cost of $3.3 billion at a purchase price of $48.50 per
share, excluding fees and expenses, pursuant to a modified Dutch auction cash tender offer. Including the shares purchased
pursuant to the tender offer, during the year ended December 31, 2013, we repurchased approximately 93 million shares of our
common stock for a total cost of approximately $4.4 billion at an average price of $47.02 per share.
As of December 31, 2013, approximately $1.7 billion of purchase authorization remained available under the stock
repurchase program. 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. From the inception of this program in February 2006 through December 31, 2013, we
repurchased approximately 188 million shares of our common stock for approximately $7.6 billion at an average price per share
of $40.52.
Preferred stock
Our preferred stock consists of five million total authorized shares at December 31, 2013, of which none are issued.
Accumulated other comprehensive loss
Accumulated other comprehensive loss consisted of the following:
Millions of dollars
December 31
2013
2012
Other
Cumulative translation adjustment
Defined benefit and other postretirement liability adjustments (a)
(241 ) $
(69 )
3
(307 ) $
(a) Included net actuarial losses for our international pension plans of $222 million at
December 31, 2013 and $208 million at December 31, 2012.
Total accumulated other comprehensive loss
$
$
(241 )
(69 )
1
(309 )
Amounts reclassified out of accumulated other comprehensive loss and the tax effects allocated to each component of
other comprehensive income were not material for the year ended December 31, 2013 or 2012.
Note 11. Stock-based Compensation
The following table summarizes stock-based compensation costs for the years ended December 31, 2013, 2012, and
2011.
Millions of dollars
Stock-based compensation cost
Tax benefit
Stock-based compensation cost, net of tax
Year Ended December 31
2013
2012
2011
$
$
264 $
(81 )
183 $
217 $
(67 )
150 $
198
(61 )
137
65
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 172 million shares of common stock have been reserved for issuance
to employees and non-employee directors. At December 31, 2013, approximately 28 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 vest ratably over
a three- or four-year period and generally 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. No further stock option grants are being made under
the stock plans of acquired companies.
The following table represents our stock options activity during 2013.
Outstanding at January 1, 2013
Granted
Exercised
Forfeited/expired
Outstanding at December 31, 2013
Exercisable at December 31, 2013
Weighted
Average
Exercise Price
per Share
Weighted
Average
Remaining
Contractual
Term (years)
Number
of Shares
(in millions)
Aggregate
Intrinsic Value
(in millions)
18.1 $
5.4
(4.7 )
(0.7 )
18.1 $
9.0 $
32.23
43.06
27.35
37.37
36.57
33.48
7.1 $
5.3 $
256
156
The total intrinsic value of options exercised was $93 million in 2013, $12 million in 2012, and $102 million in 2011.
As of December 31, 2013, there was $83 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 option exercises was $277 million during 2013, $107 million during 2012, and $160 million
during 2011.
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:
Expected term (in years)
Expected volatility
Expected dividend yield
Risk-free interest rate
Year Ended December 31
2013
5.27
40%
2012
5.21
46%
2011
5.20
40%
0.94 - 1.33% 0.99 – 1.24% 0.69 – 1.01%
0.77 - 1.73% 0.65 – 1.15% 0.93 – 2.29%
Weighted average grant-date fair value per share
$14.34
$11.99
$15.61
66
Restricted stock
Restricted shares issued under the Stock Plan are restricted as to sale or disposition. These restrictions lapse
periodically over an extended period of time not exceeding 10 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.
Our Restricted Stock Plan for Non-Employee Directors (Directors Plan) allows for each non-employee director to
receive an annual award of 800 restricted shares of common stock or, beginning in 2012, an annual award of 800 restricted
stock units representing the right to receive shares of common stock as a part of their compensation. These awards have a
minimum restriction period of six months, and, with respect to the restricted share awards, the restrictions lapse upon the earlier
of mandatory director retirement at age 72 or early retirement from the Board after four years of service. With respect to the
restricted stock unit awards, the restrictions lapse 25% annually over four years of service. If the non-employee director has
made a timely election to defer receipt of the shares upon vesting, then the shares are distributed at the end of January in the
year following the year of the non-employee director's mandatory retirement at age 72 or early retirement from the Board after
four years of service in a single distribution or in annual installments over a 5- or 10-year period as elected by the director.
The fair market value of the stock on the date of grant is amortized over the lesser of the time from the grant date to
age 72 or the time from the grant date to completion of four years of service on the Board. We reserved 200,000 shares of
common stock for issuance to non-employee directors, which may be authorized but unissued common shares or treasury
shares. At December 31, 2013, 39,200 restricted shares and 13,506 restricted stock units were issued and outstanding under the
Directors Plan. In addition, during 2013, our non-employee directors were awarded 29,797 restricted stock units under the
Stock Plan with the same terms and conditions as those described above for the Directors Plan.
The following table represents our Stock Plan and Directors Plan restricted stock awards and restricted stock units
granted, vested, and forfeited during 2013.
Nonvested shares at January 1, 2013
Granted
Vested
Forfeited
Nonvested shares at December 31, 2013
Number of
Shares
(in millions)
Weighted
Average
Grant-Date Fair
Value per Share
33.17
42.93
32.14
35.65
37.43
14.8 $
6.6
(4.7 )
(1.0 )
15.7 $
The weighted average grant-date fair value of shares granted during 2012 was $32.17 and during 2011 was $43.35.
The total fair value of shares vested during 2013 was $208 million, during 2012 was $126 million, and during 2011 was $165
million. As of December 31, 2013, there was $420 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 four 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. For the years ended December 31, 2012 and 2011, the ESPP contained two six-
month offering periods commencing on January 1 and July 1. Beginning in 2013, the ESPP contained 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, 44 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, 2013,
33 million shares have been sold through the ESPP and 11 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
Weighted average grant-date fair value per share
$
67
Year Ended December 31
2013
2012
2011
27 %
1.12 %
0.06 %
8.40 $
49 %
1.16 %
0.11 %
8.93 $
38 %
0.78 %
0.14 %
11.88
Note 12. Income per Share
Basic income 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. Differences between basic and diluted weighted average common shares outstanding for all
periods presented resulted from the dilutive effect of awards granted under our stock incentive plans.
Excluded from the computation of diluted income per share are options to purchase three million shares of common
stock that were outstanding in 2013, seven million shares of common stock that were outstanding in 2012, and three million
shares of common stock that were outstanding in 2011. These options were outstanding during these years but were excluded
because they were antidilutive, as the option exercise price was greater than the average market price of the common shares.
Note 13. Financial Instruments and Risk Management
At December 31, 2013, we held $373 million of investments in fixed income securities with maturities that extend
through November 2016 compared to $398 million of investments in fixed income securities held at December 31, 2012. These
securities are accounted for as available-for-sale and recorded at fair value as follows:
Millions of dollars
Fixed Income Securities:
U.S. treasuries (a)
Other (b)
Total
December 31, 2013
December 31, 2012
Level 1
Level 2
Total
Level 1
Level 2
Total
$
$
$
100
—
100 $
$
—
273
273 $
$
100
273
373 $
$
150
—
150 $
$
—
248
248 $
150
248
398
(a) These securities are classified as "Other current assets" in our consolidated balance sheets.
(b) Of these securities, $139 million are classified as “Other current assets” and $134 million are classified as “Other
assets” on our consolidated balance sheets as of December 31, 2013, compared to $120 million classified as "Other
current assets" and $128 million classified as "Other assets" as of December 31, 2012. These securities consist
primarily of municipal bonds, corporate bonds, and other debt instruments.
Our Level 1 asset fair values are based on quoted prices in active markets and our Level 2 asset fair values are based
on quoted prices for identical assets in less active markets. We have no financial instruments measured at fair value using
unobservable inputs (Level 3). 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 long-term debt is as follows:
Millions of dollars
Long-term debt
December 31, 2013
Total fair
value
Level 2
Level 1
Carrying
value
Level 1
December 31, 2012
Total fair
value
Level 2
Carrying
value
$
8,405 $
292 $
8,697 $
7,816 $
1,112 $
5,272 $
6,384 $
4,820
Our Level 1 debt fair values are calculated using quoted prices in active markets for identical liabilities with
transactions occurring on the last two days of year-end. Our Level 2 debt fair values are 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 year-end and
adjusting for changes in market conditions. We have no debt measured at fair value using unobservable inputs (Level 3).
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, 2013 or December 31, 2012. The
counterparties to our derivatives are global commercial and investment banks.
68
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, some of which are designed to mitigate the impact of foreign currency risks related to the
Venezuelan bolívar. 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 sale and
purchase of services and products 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 the countries in
which we do the majority of our international business. 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 $769 million at December 31, 2013 and $324 million
at December 31, 2012. 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 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 $7.8 billion at December 31, 2013 and
$4.8 billion at December 31, 2012, with none maturing before 2016. We also had $134 million of long-term investments in
fixed income securities at December 31, 2013 with maturities that extend through November 2016.
We maintain an interest rate management strategy that is intended to mitigate the exposure to changes in interest rates
in the aggregate for our investment portfolio. We hold a series of interest rate swaps relating to three of our debt instruments
with a total notional amount of $1.5 billion at a weighted-average, LIBOR-based, floating rate of 3.8% as of December 31,
2013. We utilize interest rate swaps to effectively convert a portion of our fixed rate debt to floating rates. These 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. The fair value of our interest rate swaps is included in “Other assets” in our consolidated
balance sheets as of December 31, 2013 and December 31, 2012. The fair value of our interest rate swaps was 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 (Level 2). 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. At December 31, 2013, we had fixed rate debt aggregating $6.3
billion and variable rate debt aggregating $1.5 billion, after taking into account the effects of the interest rate swaps.
Credit risk
Financial instruments that potentially subject us to concentrations of credit risk are primarily cash equivalents,
investments in fixed income securities, and trade receivables. It is our practice to place our cash equivalents and investments in
fixed income securities in high quality investments with various institutions. We derive the majority of our revenue from selling
products and providing services to the energy industry. Within the energy industry, our trade receivables are generated from a
broad and diverse group of customers. As of December 31, 2013, 34% of our gross trade receivables were in the United States
and 8% were in Venezuela, compared to 36% in the United States and 9% in Venezuela at December 31, 2012. We maintain an
allowance for losses based upon the expected collectability of all trade accounts receivable.
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.
69
Note 14. 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 $313 million in 2013, $293 million in 2012, and $245
million in 2011;
- 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, 2013, the projected benefit obligation was $1.2 billion and the
fair value of plan assets was $887 million, which resulted in an unfunded obligation of $268 million. At December 31, 2012, the
projected benefit obligation was $1.0 billion and the fair value of plan assets was $754 million, which resulted in an unfunded
obligation of $276 million. The accumulated benefit obligation for our international plans was $1.1 billion at December 31,
2013 and $961 million at December 31, 2012.
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
2013
2012
$
$
$
17 $
251
1,123 $
854
1,046 $
854
10
266
1,004
727
935
726
70
Fair value measurements of plan assets
The following table sets forth by level within the fair value hierarchy the fair value of assets held by our international
pension plans.
Millions of dollars
Common/collective trust funds (a)
Equity funds
Bond funds
Balanced funds
Non-United States equity securities
United States equity securities
Corporate bonds
Other assets
Fair value of plan assets at December 31, 2013
Common/collective trust funds (a)
Equity funds
Bond funds
Balanced funds
$
$
$
Non-United States equity securities
United States equity securities
Corporate bonds
Other assets
Fair value of plan assets at December 31, 2012
Level 1
Level 2
Level 3
Total
— $
—
—
165
139
—
2
306 $
247 $
118
13
—
—
110
59
547 $
— $
—
—
—
—
—
34
34 $
— $
—
—
130
110
—
27
267 $
204 $
112
13
—
—
107
16
452 $
— $
—
—
—
—
—
35
35 $
247
118
13
165
139
110
95
887
204
112
13
130
110
107
78
754
$
(a) Strategies are generally to invest in equity or debt securities, or a combination thereof, that match or outperform
certain predefined indices.
Our Level 1 plan asset fair values are based on quoted prices in active markets for identical assets, our Level 2 plan
asset fair values are based on significant observable inputs for similar assets, and our Level 3 plan asset fair values are based on
significant unobservable inputs.
Equity securities are traded in active markets and valued based on their quoted fair value by independent pricing
vendors. Corporate bonds are valued using quotes from independent pricing vendors based on recent trading activity and other
relevant information, including other observable inputs such as market interest rate curves, referenced credit spreads, and
estimated prepayment rates. Common/collective trust funds are valued at the net asset value of units held by the plans at year-
end.
Our investment strategy varies by country depending on the circumstances of the underlying plan. Typically, less
mature plan benefit obligations are funded by using more equity securities, as they are expected to achieve long-term growth
while exceeding inflation. More mature plan benefit obligations are funded using more fixed income securities, as they are
expected to produce current income with limited volatility. The fixed income allocation is generally invested with a similar
maturity profile to that of the benefit obligations to ensure that changes in interest rates are adequately reflected in the assets of
the 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.
For our United Kingdom pension plan, which constituted 81% of our international pension plans’ projected benefit
obligation at December 31, 2013, the target asset allocation during 2013 and 2012 was 65% equity securities and 35% fixed
income securities. Beginning in 2014, we are implementing a de-risking program intended to improve the funded status, with
the plan's assets increasingly invested over time in low-risk fixed income securities.
Net periodic benefit cost
Net periodic benefit cost for our international pension plans was $32 million in 2013, $26 million in 2012, and $27
million in 2011.
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
2013
4.8%
5.5%
2012
4.8%
5.5%
71
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
2013
4.8%
6.4%
5.5%
2012
5.2%
6.5%
5.4%
2011
7.1%
5.7%
6.2%
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. 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 2014.
Benefit payments. Expected benefit payments over the next 10 years are approximately $40 million annually for our
international pension plans.
Note 15. Accounting Standards Recently Adopted
In February 2013, the Financial Accounting Standards Board issued an update to existing guidance on the presentation
of comprehensive income. This update requires companies to report the effect of significant reclassifications out of
accumulated other comprehensive income (AOCI) by component. For significant items reclassified out of AOCI to net income
in their entirety during the reporting period, companies must report the effect on the line items in the statement where net
income is presented. For significant items not reclassified to net income in their entirety during the period, companies must
provide cross-references in the notes to other disclosures that already provide information about those amounts. We adopted this
update effective January 1, 2013, and it did not have a material impact on our consolidated financial statements.
72
HALLIBURTON COMPANY
Selected Financial Data
(Unaudited)
Millions of dollars and shares
except per share and employee data
Total revenue
Total operating income
Nonoperating expense, net
Income from continuing operations before income taxes
Provision for income taxes
Income from continuing operations
Income (loss) from discontinued operations, net
Net income
Noncontrolling interest in net income of subsidiaries
Net income attributable to company
Amounts attributable to company shareholders:
Income from continuing operations
Income (loss) from discontinued operations, net
Net income
Basic income per share attributable to shareholders:
Income from continuing operations
Net income
Diluted income per share attributable to shareholders:
Income from continuing operations
Net income
Cash dividends per share
Return on average shareholders’ equity
Financial position:
Net working capital
Total assets
Property, plant, and equipment, net
Long-term debt (including current maturities)
Total shareholders’ equity
Total capitalization
Basic weighted average common shares outstanding
Diluted weighted average common shares outstanding
Other financial data:
Capital expenditures
Long-term borrowings (repayments), net
Depreciation, depletion, and amortization
Payroll and employee benefits
Number of employees
Year ended December 31
2009
2012
2013
2010
2011
$ 29,402 $ 28,503 $ 24,829 $ 17,973 $ 14,675
1,994
$
(312 )
1,682
(518 )
1,164
$
3,138 $
(374 )
2,764
(648 )
2,116 $
19
2,135 $
(10 )
2,125 $
4,159 $
(337 )
3,822
(1,235 )
2,587 $
58
2,645 $
(10 )
2,635 $
4,737 $
(288 )
4,449
(1,439 )
3,010 $
(166 )
2,844 $
(5 )
2,839 $
3,009 $
(354 )
2,655
(853 )
1,802 $
40
1,842 $
(7 )
1,835 $
(9 )
1,155
(10 )
1,145
2,106 $
19
2,125
2,577 $
58
2,635
3,005 $
(166 )
2,839
1,795 $
40
1,835
1,154
(9 )
1,145
2.35 $
2.37
2.78 $
2.85
3.27 $
3.09
1.98 $
2.02
1.28
1.27
2.33
2.36
0.525
14.45 %
2.78
2.84
0.36
18.17 %
3.26
3.08
0.36
24.06 %
1.97
2.01
0.36
19.17 %
1.28
1.27
0.36
13.88 %
8,678 $
29,223
11,322
7,816
13,615
21,569
898
902
8,334 $
27,410
10,257
4,820
15,790
20,764
926
928
7,456 $
23,677
8,492
4,820
13,216
18,097
918
922
6,129 $
18,297
6,842
3,824
10,387
14,241
908
911
5,749
16,538
5,759
4,574
8,757
13,331
900
902
2,934 $
2,968
1,900
8,421
77,000
3,566 $
—
1,628
7,722
73,000
2,953 $
978
1,359
6,756
68,000
2,069 $
(790 )
1,119
5,370
58,000
1,864
1,944
931
4,783
51,000
$
$
$
$
$
$
73
HALLIBURTON COMPANY
Quarterly Data and Market Price Information
(Unaudited)
Quarter
Millions of dollars except per share data
First (1)
Second
Third
Fourth
Year
2013
Revenue
Operating income (loss)
Net income (loss)
$
6,974 $
(98 )
(16 )
7,317 $
984
648
7,472 $
1,108
708
7,639 $
1,144
795
29,402
3,138
2,135
Amounts attributable to company shareholders:
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss) attributable to company
Basic income per share attributable to company shareholders:
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
Diluted income per share attributable to company shareholders:
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
Cash dividends paid per share
Common stock prices (2)
High
Low
2012
Revenue
Operating income
Net income
Amounts attributable to company shareholders:
Income from continuing operations
Income (loss) from discontinued operations
Net income attributable to company
Basic income per share attributable to company shareholders:
Income from continuing operations
Income (loss) from discontinued operations
Net income
Diluted income per share attributable to company shareholders:
Income from continuing operations
Income (loss) from discontinued operations
Net income
Cash dividends paid per share
Common stock prices (2)
High
(13 )
(5 )
(18 )
(0.01 )
(0.01 )
(0.02 )
(0.01 )
(0.01 )
(0.02 )
0.125
43.96
35.07
642
2
644
0.69
0.01
0.70
0.69
—
0.69
0.125
45.75
36.77
707
(1 )
706
0.79
—
0.79
0.79
—
0.79
0.125
50.50
41.86
770
23
793
0.91
0.02
0.93
0.90
0.03
0.93
0.15
56.52
47.99
2,106
19
2,125
2.35
0.02
2.37
2.33
0.03
2.36
0.525
56.52
35.07
$
6,868 $
1,023
630
7,234 $
1,201
739
7,111 $
954
604
7,290 $
981
672
28,503
4,159
2,645
635
(8 )
627
0.69
(0.01 )
0.68
0.69
(0.01 )
0.68
0.09
745
(8 )
737
0.81
(0.01 )
0.80
0.80
(0.01 )
0.79
0.09
608
(6 )
602
0.66
(0.01 )
0.65
0.65
—
0.65
0.09
589
80
669
0.63
0.09
0.72
0.63
0.09
0.72
0.09
2,577
58
2,635
2.78
0.07
2.85
2.78
0.06
2.84
0.36
Low
(1) Includes a $1.0 billion, pre-tax, charge in the first quarter of 2013, and a $300 million, pre-tax, charge in the first quarter of 2012 related to the Macondo well incident.
(2) New York Stock Exchange – composite transactions high and low intraday price.
39.19
32.02
35.32
26.28
38.00
27.62
36.00
29.83
39.19
26.28
74
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 2014 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 3 through 4 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 2014 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 2014 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 2014 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 2014 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 2013,” “Outstanding Equity
Awards at Fiscal Year End 2013,” “2013 Option Exercises and Stock Vested,” “2013 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 2014 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 2014 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 2014 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 2014 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 2014 Annual
Meeting of Stockholders (File No. 001-03492) under the caption “Fees Paid to KPMG LLP.”
75
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 40 and 41 and pages 42 through 72 of this
annual report. See index on page (i).
2.
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.
3.
Exhibits:
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 July 18, 2013 (incorporated by reference to Exhibit 3.1 to
Halliburton's Form 8-K filed July 19, 2013, 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).
76
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
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 debt security of 7.53% Notes due May 12, 2017 (incorporated by reference to Exhibit 4.4 to
Halliburton’s Form 10-Q for the quarter ended March 31, 1997, File No. 001-03492).
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).
4.16
Form of note of 7.6% debentures due 2096 (included as Exhibit A to Exhibit 4.15 above).
4.17
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).
4.18
Form of Global Note for Halliburton’s 5.90% Senior Notes due 2018 (included as part of Exhibit 4.17).
77
4.19
Form of Global Note for Halliburton’s 6.70% Senior Notes due 2038 (included as part of Exhibit 4.17).
4.20
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).
4.21
Form of Global Note for Halliburton’s 6.15% Senior Notes due 2019 (included as part of Exhibit 4.20).
4.22
Form of Global Note for Halliburton’s 7.45% Senior Notes due 2039 (included as part of Exhibit 4.20).
4.23
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).
4.24
Form of Global Note for Halliburton’s 3.25% Senior Notes due 2021 (included as part of Exhibit 4.23).
4.25
Form of Global Note for Halliburton’s 4.50% Senior Notes due 2041 (included as part of Exhibit 4.23).
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 1.00% Senior Notes due 2016 (included as part of Exhibit 4.26).
Form of Global Note for Halliburton’s 2.00% Senior Notes due 2018 (included as part of Exhibit 4.26).
Form of Global Note for Halliburton’s 3.50% Senior Notes due 2023 (included as part of Exhibit 4.26).
Form of Global Note for Halliburton’s 4.75% Senior Notes due 2043 (included as part of Exhibit 4.26).
† 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
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).
ERISA Compensation Limit Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1,
1995 (incorporated by reference to Exhibit 10.8 to Dresser’s Form 10-K for the year ended October 31, 1995,
File No. 1-4003).
† 10.5
Employment Agreement (David J. Lesar) (incorporated by reference to Exhibit 10(n) to the Predecessor’s
Form 10-K for the year ended December 31, 1995, File No. 001-03492).
78
† 10.6
Employment Agreement (Mark A. McCollum) (incorporated by reference to Exhibit 10.1 to Halliburton’s
Form 10-Q for the quarter ended September 30, 2003, File No. 001-03492).
† 10.7
Halliburton Company Performance Unit Program (incorporated by reference to Exhibit 10.2 to Halliburton’s
Form 10-Q for the quarter ended September 30, 2001, File No. 001-03492).
10.8
10.9
10.10
10.11
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).
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).
† 10.12
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).
† 10.13
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).
† 10.14
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).
† 10.15
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).
† 10.16
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).
† 10.17
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).
† 10.18
Employment Agreement (James S. Brown) (incorporated by reference to Exhibit 10.36 to Halliburton’s Form
10-K for the year ended December 31, 2007, File No. 001-03492).
† 10.19
Executive Agreement (Lawrence J. Pope) (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K
filed December 12, 2008, File No. 001-03492).
† 10.20
Halliburton Company Stock and Incentive Plan, as amended and restated effective February 20, 2013
(incorporated by reference to Appendix B of Halliburton's proxy statement filed April 2, 2013, File No. 001-
03492).
79
† 10.21
Halliburton Company Employee Stock Purchase Plan, as amended and restated effective February 11, 2009
(incorporated by reference to Appendix C of Halliburton’s proxy statement filed April 6, 2009, File No. 001-
03492).
† 10.22
Form of Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.4 of Halliburton’s
Form 10-Q for the quarter ended September 30, 2009, File No. 001-03492).
† 10.23
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.5 of Halliburton’s Form 10-Q for
the quarter ended September 30, 2009, File No. 001-03492).
† 10.24
Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.6 of Halliburton’s Form 10-
Q for the quarter ended September 30, 2009, File No. 001-03492).
† 10.25
Form of Non-Employee Director Restricted Stock Unit Agreement (Director Plan) (incorporated by reference
to Exhibit 99.8 of Halliburton's Form S-8 filed June 22, 2012, Registration No. 333-182284).
† 10.26
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).
† 10.27
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).
† 10.28
Halliburton Annual Performance Pay Plan, as amended and restated effective January 1, 2010 (incorporated by
reference to Exhibit 10.3 to Halliburton’s Form 8-K filed September 21, 2009, File No. 001-03492).
† 10.29
Amendment to Executive Employment Agreement (James S. Brown) (incorporated by reference to Exhibit
10.39 to Halliburton’s Form 10-K for the year ended December 31, 2008, File No. 001-03492).
† 10.30
Amendment to Executive Employment Agreement (Mark A. McCollum) (incorporated by reference to Exhibit
10.43 to Halliburton’s Form 10-K for the year ended December 31, 2008, File No. 001-03492).
† 10.31
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).
† 10.32
Executive Agreement (Joe D. Rainey) (incorporated by reference to Exhibit 10.43 to Halliburton’s Form 10-K
for the year ended December 31, 2010, File No. 001-03492).
10.33
U.S. $2,000,000,000 Five Year Revolving Credit Agreement among Halliburton Company, as Borrower, the
Banks party thereto, and Citibank, N.A., as Agent (incorporated by reference to Exhibit 10.1 to Halliburton’s
Form 8-K filed February 23, 2011, File No. 001-03492).
† 10.34
First Amendment dated February 10, 2011 to Halliburton Company Employee Stock Purchase Plan, as
amended and restated effective February 11, 2009 (incorporated by reference to Exhibit 10.2 to Halliburton’s
Form 10-Q for the quarter ended March 31, 2011, File No. 001-03492).
† 10.35
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).
80
† 10.36
Executive Agreement (Christian A. Garcia) (incorporated by reference to Exhibit 10.40 to Halliburton’s Form
10-K for the year ended December 31, 2011, File No. 001-03492).
† 10.37
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).
† 10.38
Form of Restricted Stock Agreement (Section 16 officers) (incorporated by reference to Exhibit 10.42 to
Halliburton’s Form 10-K for the year ended December 31, 2011, File No. 001-03492).
† 10.39
Form of Non-Employee Director Restricted Stock Unit Agreement (Stock and Incentive Plan) (incorporated by
reference to Exhibit 99.9 of Halliburton's Form S-8 filed June 22, 2012, Registration No. 333-182284).
† 10.40
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).
† 10.41
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).
† 10.42
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).
† 10.43
Executive Agreement (Jeffrey A. Miller) (incorporated by reference to Exhibit 10.1 to Halliburton's Form 8-K
filed September 21, 2012, File No. 001-03492).
† 10.44
Second Amendment dated December 11, 2012 to Halliburton Company Employee Stock Purchase Plan, as
amended and restated effective February 11, 2009 (incorporated by reference to Exhibit 10.47 to Halliburton’s
Form 10-K for the year ended December 31, 2012, File No. 001-03492).
† 10.45
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).
† 10.46
First Amendment dated April 23, 2013 of the Five Year Revolving Credit Agreement among Halliburton
Company, as Borrower, the Banks party thereto, and Citibank, N.A., as Agent effective February 22, 2011
(incorporated by reference to Exhibit 10.4 to Halliburton's Form 10-Q for the quarter ended March 31, 2013,
File No. 001-03492).
10.47
Underwriting Agreement, dated July 29, 2013, among Halliburton Company and Citigroup Global Markets
Inc., Deutsche Bank Securities Inc., HSBC Securities (USA) Inc., RBS Securities Inc. and the several other
underwriters identified therein (incorporated by reference to Exhibit 1.1 of Halliburton’s Form 8-K filed
August 1, 2013, File No. 001-03492).
*† 10.48
Executive Agreement (Robb L. Voyles).
*† 10.49
Executive Agreement (Timothy McKeon).
* 12.1
Statement of Computation of Ratio of Earnings to Fixed Charges.
* 21.1
Subsidiaries of the Registrant.
* 23.1
Consent of KPMG LLP.
81
* 24.1
Powers of attorney for the following directors signed in January 2014:
Alan M. Bennett
James R. Boyd
Milton Carroll
Nance K. Dicciani
Murry S. Gerber
José C. Grubisich
Abdallah S. Jum’ah
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.
82
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 7th day of February, 2014.
HALLIBURTON COMPANY
By
/s/ David J. Lesar
David J. Lesar
Chairman of the Board,
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 7th day of February, 2014.
Signature
Title
/s/ David J. Lesar
David J. Lesar
Chairman of the Board, President,
Chief Executive Officer, and Director
/s/ Mark A. McCollum
Mark A. McCollum
Executive Vice President and
Chief Financial Officer
/s/ Christian A. Garcia
Christian A. Garcia
Senior Vice President and
Chief Accounting Officer
83
Signature
* 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
* Abdallah S. Jum’ah
Abdallah S. Jum’ah
* Robert A. Malone
Robert A. Malone
* J. Landis Martin
J. Landis Martin
* Debra L. Reed
Debra L. Reed
/s/ Christina M. Ibrahim
*By Christina M. Ibrahim, Attorney-in-fact
Title
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
84
WHAT
DRIVES US
At Halliburton, the things that drive us
keep us ahead. In this report, you will
read about our insistence on setting
bold goals, our focus on execution
certainty and our determination to
live up to the commitments we make
to all of our stakeholders. You will also
read about how we are staying the
course with the consistent strategy
that drove our growth since our
2010 Analyst Day.
Key accomplishments over the past
three years:
DEEPWATER
Our deepwater revenue grew
31 percent per year, compared
to 13 percent for the industry.
MATURE FIELDS
We achieved our goal of
tripling the size of our
mature fields business.
UNCONVENTIONALS
We led in North America,
with revenue growth
exceeding 70%.
EXECUTION CERTAINTY
Frac of the Future,™ coupled with our
proprietary Battle Red smart phone field
management tools, takes efficiency and
reliability to new levels. In addition, we are
also seeing environmental benefits from
the use of natural gas-powered vehicles
and pump trucks.
SHAREHOLDER INFORMATION //
Shares Listed
New York Stock Exchange
Symbol: HAL
Transfer Agent and Registrar
Computershare
P.O. Box 30170
College Station, Texas 77842-3170
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
This annual report is printed on environmentally
responsible paper, which is FSC-certified (portions
of which are 100% post-consumer recycled paper).
DESIGN: SAVAGE BRANDS, HOUSTON, TX
281.871.2699
www.halliburton.com
© 2014 Halliburton. All Rights Reserved.
Printed in the USA
H010964
2013 Annual Report
WHAT
DRIVES
US