281.871.2699
www.halliburton.com
© 2013 Halliburton. All Rights Reserved.
Printed in the USA
H09980
look
l
o
o
k
b
e
n
e
a
t
h
t
h
e
s
u
r
f
a
c
e
H
A
L
L
I
B
U
R
T
O
N
2
0
1
2
A
n
n
u
a
l
R
e
p
o
r
t
beneath the
surface
2012 Annual Report
shareholder information
Shares Listed
New York Stock Exchange
Symbol: HAL
Transfer Agent and Registrar
Computershare Shareowner Services
480 Washington Boulevard
Jersey City, New Jersey 07310-1900
Telephone: 800.279.1227
www.bnymellon.com/shareowner/isd
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
The world we live in:
90MM BBL/D
61%
3x
Global oil consumption in
2013 will approach 90 million
barrels per day. Over 4 million
barrels per day will be needed
to meet demand and offset
declining production.
Rapid economic development
and higher standards of living
are expected to drive a 61 percent
increase in energy demand from
emerging nations over the next
two decades.
To meet global energy demand
in 2030, natural gas is the largest
incremental fuel source, growing
at nearly three times the rate
of oil.
Look beneath the surface to
discover all that Halliburton
is doing to create value for
customers and shareholders.
At Halliburton, we look beyond the way things have always been done to help customers unlock the
full value of their oil and gas assets. Discover the value our technologies and solutions are creating in
growth markets all across the globe.
a clear strategy
our three key areas of growth
unconventional
deepwater
mature fields
Unconventionals – shale gas, tight gas and their
liquid counterparts – have completely changed
the worldwide energy picture. With two-thirds
of the world’s recoverable natural gas reserves
classified as unconventional, Halliburton has
invested in the technology and capital needed to
unlock these assets, and is positioned to benefit
from its leadership position in North America
and growth in international activity.
Deepwater is the most challenging and
expensive play in the world today. To
help address the high costs of exploration
and development, Halliburton is bringing
new efficiencies to deepwater with
reliable equipment, resourceful people
and innovative technologies.
Mature Fields – those past peak production –
comprise nearly three-fourths of the world’s
oil and gas supply. With our global presence
in oil-producing regions and a strong portfolio
of capabilities for data acquisition and well
diagnosis, interventions and completions, we
are positioned to help our customers increase
recovery rates in these proven resources.
Percentage of
worldwide natural gas
reserves classified
as unconventional
64%
Percentage of
projected IOC
offshore spending
over the next
five years dedicated
to deepwater
50%
Percentage of global
oil and gas production
from mature fields
70%
global reach
k Brazil – World-class deepwater technology
center in Rio de Janeiro, Brazil is a key
commitment to sustainable growth in the
largest deepwater market in the world.
l Saudi Arabia – Began construction on a
new technology center in Saudi Arabia to
focus on unconventional reservoirs.
m Singapore – New Singapore manufacturing
facility expands our footprint to serve the
growing Asia-Pacific markets.
02
look beneath the surfaceHalliburton 2012 annual reportklm financial highlights
technology
We are dedicated to collaborating with
our customers to deliver practical,
focused solutions to their challenges.
Our technological leadership is supported
by global technology centers, allowing
us to continue to serve our customers
better, more economically and more
reliably. The passion with which we innovate
is a reflection of our dedication to the
long-term sustainability of our business.
R&D Spending
in millions
$366
$401
$460
(Millions of dollars and shares, except per share data)
2012
2011
2010
Revenue
Operating Income
Amounts Attributable to
Company Shareholders:
$ 28,503
$ 24,829
$
17,973
$ 4,159
$
4,737
$ 3,009
Income from Continuing Operations
Net Income
$ 2,577
$ 2,635
$
$
3,005
2,839
$
$
1,795
1,835
Diluted Income per Share Attributable
to Company Shareholders:
Income from Continuing Operations
Net Income
Cash Dividends per Share
Diluted Common Shares Outstanding
Working Capital 1
Capital Expenditures
Long-Term Debt
Debt to Total Capitalization2
Depreciation, Depletion and Amortization
Return on Average Capital Employed 3
Total Capitalization4
$
$
$
2.78
2.84
0.36
928
$ 8,334
$ 3,566
$ 4,820
$
$
$
$
$
$
$
$
$
3.26
3.08
0.36
922
1.97
2.01
0.36
911
7,456
$
6,129
2,953
$ 2,069
4,820
$
3,824
24%
27%
27%
$
1,628
$
1,359
$
1,119
15%
19%
15%
10
11
12
$ 20,764
$
18,097
$
14,241
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.
03
Revenuein billions$18.0$24.8$28.5101112Return on Average Capital Employed15%19%15%101112Operating Incomein billions$3.0$4.7$4.2101112
2012 highlights
Revenue
$28.5 Billion
Operating Income
$4.2 Billion
Net Income
$2.6 Billion
Cash Dividends Per Share
$0.36
Capital Expenditures
$3.6B
Return on Average
Capital Employed
15 percent
Earnings Per Diluted Share
$2.84
Active Patents
Over 3,000
Employees
Over 72,000
a strong focus
During 2012, Halliburton continued to execute the successful
strategies that have enabled us to double the size of the company
over the past three years and outgrow our competition. Increased
demand for our services and solid execution drove record revenues
of $28.5 billion and operating income of $4.2 billion. In addition to
industry-leading revenue growth in 2012, Halliburton delivered
return on average capital employed of 15 percent. This was the third
consecutive year of superior returns relative to our primary competitors,
an achievement which demands a look beneath the surface.
industry trends benefit Halliburton
I am optimistic about Halliburton’s ability to create sustainable value for our shareholders
and customers. Strengthening world economies are driving steady growth in energy demand,
and this is supporting continued investment by our customers. Much of the investment is
occurring in the three market segments where Halliburton has concentrated its attention and
built deep capabilities over the past several years: unconventional assets; complex deepwater
environments; and an increased focus on improving the performance of mature fields.
leading in unconventional Plays
In North America, we continue to demonstrate leadership and are committed to delivering
the lowest cost per barrel of oil equivalent produced from our customers’ unconventional
wells. With the 2012 release of our “Frac of the Future” program, we elevated our service
platform to a higher level of efficiency, providing the most effective and reliable hydraulic
fracturing system available today. At the core of this program is a new hydraulic pump,
the Q-10, which reduces our well site footprint by 20 percent and can be configured to use
clean-burning natural gas as a fuel source. This year also saw a shift to downhole innovation
in the domains of customized chemistry and new simulation technologies to enhance
subsurface understanding.
Internationally, 2012 was a turning point for the development of unconventional market
resources. We expanded our presence in key unconventional markets such as Australia,
Saudi Arabia, Mexico and China, building our service footprint and establishing basin-
oriented technology teams to help our customers develop their assets. As these countries
seek to unlock their unconventional assets, Halliburton is using expertise and technology
leadership developed in North America to the benefit of our international customers.
Making Deepwater advances
Over the last six years, the deepwater rig fleet has grown 40 percent, and the market has
expanded beyond the scope of the traditional “golden triangle” – Gulf of Mexico, Brazil
and West Africa – into East Africa, the Mediterranean, the Red Sea and other emerging
deepwater markets. The growth of deepwater activity spans from exploration and appraisal to
development, where we can leverage our core strengths in drilling and formation evaluation,
and our leadership in deepwater completions.
04
look beneath the surfaceHalliburton 2012 annual report As deepwater production becomes a greater portion of our customers’ portfolios, our
reputation for reliability has made us a provider of choice across the globe. We are also seeing
the payoff of our recent international infrastructure investments, resulting in leading market
positions in deepwater in East Africa, Malaysia and Brazil – three robust markets that
accounted for 9 of the top 10 discoveries in 2012.
Maximizing Mature Field Performance
Mature fields, those past peak production, demonstrate production declines that are
typically estimated to be in excess of 3% per year. In addition, 65% of oil reserves are typically
bypassed during production. As a result, our customers place a significant emphasis on the
assurance of their production and improvement in recovery rates in their mature fields. This
is an area of significant focus for Halliburton, and in 2012 we made investments in the areas of
specialty chemicals and artificial lift to strengthen our global capabilities. These investments,
along with our Boots & Coots product line, have allowed us to more than double the
size of our mature field business over the last two years.
We are helping our customers rediscover their reservoirs; providing technology to access
bypassed zones and improving the recovery rates of their proven resources. Our global
presence in all major oil-producing regions and strong portfolio of capabilities for data
acquisition, well diagnosis, intervention and completion, position Halliburton for continued
growth in this important arena.
Expanding Opportunities
Over the coming year, our business in North America stands to benefit as material cost
headwinds experienced in 2012 abate. Bolstered by strengthening offshore activity in the
Gulf of Mexico, we remain focused on maintaining our leadership position in North America.
Internationally, robust deepwater activity, growing interest in unconventional resource
development and expanding mature field opportunities will provide a diverse platform
for continued growth. I believe we will continue to expand our international operations,
building our market share position, strengthening our margins and achieving balance in
our geographic portfolio.
We have a sound strategy and a track record of exceptional execution. I am optimistic
about our future and the expanding global opportunities for Halliburton, and we remain
committed to delivering superior growth, margins and returns. We appreciate the support
of our shareholders and customers as well as the exceptional contributions of our board
of directors, employees and suppliers, all of whom are vital to our success.
David J. Lesar
David J. Lesar
Chairman of the Board,
President and Chief Executive Officer
Jeffrey A. Miller
Executive Vice President and
Chief Operating Officer
Timothy J. Probert
President, Strategy and
Corporate Development
Mark A. McCollum
Executive Vice President
and Chief Financial Officer
Albert O. Cornelison, Jr.
Executive Vice President and
General Counsel
Lawrence J. Pope
Executive Vice President of Administration
and Chief Human Resources Officer
05
“technology
developments in
the pipeline today
will afford us
with unparalleled
opportunities to
monitor reservoir
performance, introduce
chemistries that act on
our command, automate
basic processes and
visualize data – all
aimed at allowing us
to go deeper, farther,
faster and safer.”
Tim Probert
applied technology
kk
ll
mm
nn
Halliburton is combining surface efficiency,
subsurface precision and proprietary chemistries
to improve the economics of unconventional
energy production. At the surface, our “frac of
the future” innovations have cut on-site capital
requirements by 20 percent and headcount by
15 percent. Subsurface, our superior reservoir
insight, increases precision well placement and
maximizes reservoir contact. Our specialized
chemistries have increased well productivity
by as much as 25 percent.
k Sandcastles are upright, gravity-fed
sand silos that replace belt-fed horizontal
sand bins, improving reliability and saving
thousands of gallons of diesel every day.
l Our Q-10 pump trucks are designed for
prolonged horizontal operations. They
run more than twice as long between
maintenance cycles as conventional pumps,
reducing non-productive time on location.
m Proprietary downhole chemistries such as
Sirocco,™ CleanStim™ and PermStim™
result in cleaner, more productive wells.
n Knoesis software enables us to model
fracture propagation in complex reservoirs,
to optimize well placement and minimize
the cost to develop an asset.
Halliburton’s 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
developing technologies to meet these challenges that are practical,
quickly deployed and complement our reputation for outstanding
service delivery.
As the search for new energy resources moves into increasingly complex and high-cost
environments, new technology is the key to our customers’ success. Technology is the
lifeblood of our business and we have doubled our annual research and development
investment over the last five years. Using a disciplined approach, we have created a
comprehensive portfolio of applied technologies that help customers achieve their
exploration, development and production objectives.
Global Footprint Promotes Mutual Success
In 2012, we opened a state-of-the art technology center in Houston that fosters an
unparalleled degree of internal collaboration between technical disciplines and across
business lines. We are globalizing our technology footprint through a network of
regional technology centers that enable us to be more responsive to customers. A new
80,000 square-foot facility in Rio de Janeiro, Brazil will serve as our global center for
technology advancement in deepwater exploration and development. A similar technology
center in Saudi Arabia will be completed in 2013 with a focus on unconventional reservoirs.
Solutions for Growing Markets
In the unconventional markets, we are rolling out our “frac of the future” technologies,
reducing capital and labor requirements at the well site with increased levels of reliability
and efficiency. With a focus on production at the lowest cost per barrel equivalent for our
customers, we are delivering customized chemistry and enhanced levels of subsurface
understanding, including reservoir and fracture simulations, which can improve well
performance while using less water, chemicals and proppant.
Deepwater is a technically demanding, high-operating cost environment. Halliburton’s
technology focus is on reducing geological uncertainty, providing exceptional reservoir
characterization capability and ultra-reliable well construction and completion solutions
that collectively increase our customers’ chances of successful exploitation of these
challenging reservoirs.
Mature fields typically have tight economic sensitivity, and we have focused on developing
cost-effective technology to help our customers revitalize assets and access previously
uneconomic reserves. Our EquiFlow® Autonomous Infield Control Device optimizes the
flow of production and restricts unwanted fluids such as water or gas, which earned it the
prestigious “Spotlight on New Technology” award at the 2012 Offshore Technology
Conference. With complementary acquisitions in production chemicals and artificial lift,
we now offer a total life-of-field portfolio of solutions for our customers’ mature fields.
We remain committed to increasing the quality and depth of our technology investments.
We will continue to expand our global technology footprint and drive pragmatic solutions in
an environment of collaboration with our customers and suppliers that supports our mission.
07
look beneath the surface
integrated solutions
Integration of technology and capability is the key to efficiency and
outstanding execution at Halliburton. Integration drives consistency
in the way we operate throughout the world. It allows us to meet
specific technology challenges that cut across discipline boundaries.
It also drives robust workflows that allow us to bring complex projects
to a successful conclusion, on time and on budget.
A focus on well construction efficiency by upstream energy companies has increased the
demand for integrated solutions and created new growth opportunities for Halliburton.
Customers who once contracted and coordinated individual products and services are
increasingly seeking integrated service providers who can take a larger role in project
planning and execution. Revenue from Halliburton’s integrated project execution business
has doubled in the last two years, and is on a solid growth trajectory, supported by recent
major contract awards in Malaysia, Mexico, Norway and Russia.
A customer in Russia recently selected Halliburton to provide an integrated services
solution to increase production from the complex and challenging tight oil reserves in
the Em-Yoga license area of Russia’s Krasnoleninskoe field in Nyagan, Western Siberia.
Halliburton provides project management, well construction and completion services
for multiple wells on this important project in Nyagan.
Customer Collaboration
Collaboration is a key to our global success. Collaborating means tying together our
experience and technology with our customers’ own expertise to provide the best possible
solution to either develop a new project or revitalize an existing asset. Our customers see
our ability to collaborate effectively as a differentiator across the spectrum of technology,
well construction, well completion and production monitoring.
Sperry Drilling Services’ DrillDOC® tool provides
real-time measurements of weight, torque and
bending on bit.
By leveraging DecisionSpace® InSite® real-time
drilling software, our engineers can identify
weight transference and make real-time
adjustments to optimize drilling, minimize
wasted energy and maximize performance.
“Our expanding role in planning and
executing customer projects is driving
heightened levels of collaboration and
integration at Halliburton. Our domain
experts mine the deep science of their
individual product lines and work together
to deliver enhanced value to our customers.”
Jeff Miller
08
HallIburTon 2012 a nnual r eporT
Our new Advanced Perforating Flow Lab utilizes the latest computed tomography
imaging to evaluate perforator performance and reservoir inflow. The laboratory is
able to conduct tests that replicate downhole reservoir conditions, simulating
pressures and temperatures up to 50,000 psi and 400ºF.
The Extreme HT-200
Sensors extend the reach
of Sperry MWD/LWD
sensors from temperatures
of 347°F/175°C to
392°F/200°C, providing
reliable directional data
and steering capabilities
in the most extreme
downhole environments.
The Geo-Pilot EDL
(Enhanced Dog Leg)
rotary steerable system
is the only rotary
steerable system that
allows for sharper turns
(10º/100ft) to the
horizontal, enhancing
the effectiveness
and cost of drilling
operations.
The unique chemistry
of the Low Equivalent
Circulating Density
(Low-ECD) Fluid
provides a low viscosity
and excellent suspen-
sion properties, ideal
for low pressure
formations, including
depleted zones, high
angle drilling and slim
wellbores. Reservoirs
that were once thought
inaccessible due to
technical or economic
constraints can now
be explored.
international opportunity
With bold international infrastructure investments,
Halliburton is extending its comprehensive global footprint.
Our excellent record of international growth is driving
balance in our global geographic portfolio.
Exceptional strength and success in North America is just part of the Halliburton
story. Active in more than 80 countries, we have substantial international operations
and opportunities. In 2012, we derived 44 percent of our revenue outside of
North America and continued expanding our presence and position in key global
markets. Over the past two years, we have expanded our facilities in over 20 countries –
including entry into several new markets. We have a disciplined approach to
growth, pursuing only work that will produce acceptable life-of-project returns.
Our talented and diverse workforce, which is 92 percent nationalized around the
globe, is an important differentiator and a competitive advantage in pursuing
international business.
East Africa, a Model for Growth
In the emerging deepwater exploration market of East Africa, we leveraged a
first-mover advantage to build a leading position since entering the region less than
three years ago. We have opened or expanded facilities in four countries, and our
investments are paying off, culminating in the recent award of the largest contract
ever tendered in this market.
The bold commitment to East Africa now serves as a model for expanding our
footprint and market share in other regions, both offshore and onshore. Over the
last year, we’ve added capabilities and facilities in other key markets such as Mexico,
Australia and Malaysia. In Singapore, a new manufacturing facility gives us a local
footprint to serve the growing Asia-Pacific market. In Brazil, our new world-class
deepwater technology center in Rio de Janeiro is a key commitment to sustainable
growth in the largest deepwater market in the world.
A World of Opportunity
Our international revenue grew a robust 20 percent in 2012. For 2013, customer
spending is expected to rise and our expectations are for a continuation of this
growth trend. Recent wins, market share gains in regions where we have made
strategic investments and the ongoing introduction of new technology give us
increasing confidence in the strength of our international operations.
n 2008
n 2012
Deepwater opportunities are Expanding
across the Globe
In 2008, 80 percent of deepwater energy
exploration and production was concentrated
in the “golden triangle” – the Gulf of Mexico,
Brazil and West Africa, with a few assets
scattered around the globe. In 2012, deepwater
exploration activity opened up new markets
while continuing to grow in the areas where it
began. About half of our international revenue
in 2012 came from offshore and about a quarter
of that from deepwater.
“Our strategic areas of focus provide a
strong platform for international growth.
Unconventional resource opportunities
are expanding globally. Deepwater activity
is the fastest growing segment of the offshore
rig count. And with nearly three-quarters
of the world’s oil coming from mature fields,
the need for cost-effective technology to
enhance production and improve recovery
is more important than ever.
We are focused on exploiting these
opportunities with rigorous capital discipline
to continue delivering superior returns for
years to come.”
Mark McCollum
11
a clear perspective
board of directors
David J. Lesar
Chairman of the Board,
President and Chief Executive Officer,
Halliburton Company (2000)
S. Malcolm Gillis
University Professor,
Rice University
(2005) (A) (C)
Alan M. Bennett
Retired President and
Chief Executive Officer,
H&R Block, Inc.
(2006) (A) (D)
James R. Boyd
Retired Chairman of the Board,
Arch Coal, Inc.
(2006) (A) (B)
Milton Carroll
Chairman of the Board,
CenterPoint Energy, Inc.
(2006) (B) (D)
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)
Nance K. Dicciani
Retired President and
Chief Executive Officer,
Honeywell International Specialty Materials
(2009) (A) (C)
Debra L. Reed
Chief Executive Officer,
Sempra Energy
(2001) (B) (D)
Murry S. Gerber
Retired Chairman and
Chief Executive Officer,
EQT Corporation
(2012) (A) (B)
corporate officers
David J. Lesar
Chairman of the Board, President and
Chief Executive Officer
Jeffrey A. Miller
Executive Vice President and
Chief Operating Officer
Mark A. McCollum
Executive Vice President and
Chief Financial Officer
Albert O. Cornelison, Jr.
Executive Vice President and
General Counsel
Lawrence J. Pope
Executive Vice President of Administration
and Chief Human Resources Officer
Timothy J. Probert
President,
Strategy and Corporate Development
James S. Brown
President, Western Hemisphere
Joe D. Rainey
President, Eastern Hemisphere
Evelyn M. Angelle
Senior Vice President,
Chief Accounting Officer
Christian Garcia
Senior Vice President and Treasurer
Sherry D. Williams
Senior Vice President,
Chief Ethics and Compliance Officer
Christina M. Ibrahim
Vice President and Corporate Secretary
(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
look beneath the surfaceHalliburton 2012 annual report 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, 2012
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 Common Stock held by nonaffiliates on June 30, 2012, determined using the per share closing price on the
New York Stock Exchange Composite tape of $28.39 on that date, was approximately $26,216,000,000.
As of February 1, 2013, there were 931,813,112 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.
Portions of the Halliburton Company Proxy Statement for our 2013 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, 2012
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
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART 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).
Item 8.
Item 9.
Item 9(a).
Item 9(b).
MD&A AND FINANCIAL STATEMENTS
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Shareholders’ Equity
Notes to Consolidated Financial Statements
Selected Financial Data (Unaudited)
Quarterly Data and Market Price Information (Unaudited)
PART III
Item 10.
Item 11.
Item 12(a).
Item 12(b).
Item 12(c).
Item 12(d).
Item 13.
Item 14.
PART IV
Item 15.
SIGNATURES
Directors, Executive Officers, and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners
Security Ownership of Management
Changes in Control
Securities Authorized for Issuance Under Equity Compensation Plans
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits
(i)
PAGE
1
6
15
16
17
26
27
28
28
28
28
28
29
29
30
50
51
53
54
55
56
57
58
86
87
88
88
88
88
88
88
88
88
89
96
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 Halliburton Production
Enhancement, Cementing, Completion Tools, Boots & Coots, and Multi-Chem. Effective January 1, 2013,
Halliburton Artificial Lift will be included as a product service line within this segment.
- our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and wellbore
placement solutions that enable customers to model, measure, and optimize their well construction activities.
The segment consists of Halliburton Drill Bits and Services, Wireline and Perforating, Testing and Subsea,
Baroid, Sperry Drilling, Landmark Software and Services, and Halliburton 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, Mexico, 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 to our customers that maximize their production and recovery and realize proven reserves from
difficult environments. Our objectives are to:
- create a balanced portfolio of services and products supported by global infrastructure and anchored by
technological innovation with a well-integrated digital strategy to further differentiate our company;
-
reach a distinguished level of operational excellence that reduces costs and creates real value from everything
we do;
- preserve a dynamic workforce by being a preferred employer to attract, develop, and retain the best global
talent; and
- uphold the ethical and business standards of the company 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.
1
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 2012,
2011, and 2010, based on the location of services provided and products sold, 53%, 55%, and 46% 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, a meaningful estimate of the total number of competitors cannot be made. 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 be material to the conduct of our operations taken as a
whole.
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 $460 million in 2012, $401 million in 2011, and $366 million in 2010. These expenditures were over 95%
company-sponsored 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, 2012, we employed approximately 73,000 people worldwide compared to approximately 68,000 at
December 31, 2011. At December 31, 2012, approximately 16% 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,
Item 1(a), “Risk Factors,” and Item 3, “Legal Proceedings.”
2
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.
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 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.
3
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, Room 1580, 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 2012, 2011, or 2010. 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 11,
2013, including all offices and positions held by each in the past five years:
Name and Age
Offices Held and Term of Office
Evelyn M. Angelle
(Age 45)
Senior Vice President and Chief Accounting Officer of Halliburton
Company, since January 2011
Vice President, Corporate Controller, and Principal Accounting Officer
of Halliburton Company, January 2008 to January 2011
James S. Brown
(Age 58)
President, Western Hemisphere of Halliburton Company, since January
2008
* Albert O. Cornelison, Jr.
Executive Vice President and General Counsel of Halliburton Company,
(Age 63)
since December 2002
Christian A. Garcia
(Age 49)
Senior Vice President and Treasurer of Halliburton Company, since
September 2011
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
* David J. Lesar
(Age 59)
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
(Age 53)
Company, since January 2008
* Jeffrey A. Miller
(Age 49)
Executive Vice President and Chief Operating Officer of Halliburton
Company, since 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
4
Name and Age
Offices Held and Term of Office
* Lawrence J. Pope
(Age 44)
Executive Vice President of Administration and Chief Human Resources
Officer of Halliburton Company, since January 2008
* Timothy J. Probert
President, Strategy and Corporate Development of Halliburton
(Age 61)
Company, since January 2011
President, Global Business Lines and Corporate Development of
Halliburton Company, January 2010 to January 2011
President, Drilling and Evaluation Division and Corporate Development
of Halliburton Company, March 2009 to December 2009
Executive Vice President, Strategy and Corporate Development of
Halliburton Company, January 2008 to March 2009
Joe D. Rainey
(Age 56)
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
Vice President, Asia Pacific Region of Halliburton Company, February
2005 to December 2008
* 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.
5
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 & Production,
Inc. (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 400 complaints, most of which are alleged class-
actions, involving pollution damage claims and at least seven 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. BP Exploration and one of
its affiliates have filed claims against us seeking subrogation and contribution, including with respect to liabilities under the Oil
Pollution Act of 1990 (OPA), and direct damages, and alleging negligence, gross negligence, fraudulent conduct, and fraudulent
concealment. Certain other defendants in the lawsuits have filed claims against us seeking, among other things, indemnification
and contribution, including with respect to liabilities under the OPA, and alleging, among other things, negligence and gross
negligence. See Item 3, “Legal Proceedings.” Additional lawsuits may be filed against us, including criminal and civil charges
under federal and 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, numerous industry participants, governmental agencies, and
Congressional committees 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 and ordered us and the BSEE to file notice within 15 days after the
conclusion of the multi-district litigation (MDL) and, within 60 days after the MDL court issues a final decision, 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.
In addition, as part of its criminal investigation, the Department of Justice (DOJ) is examining certain aspects of our
conduct after the incident, including with respect to record-keeping, record retention, post-incident testing and modeling and the
retention thereof, securities filings, and public statements by us or our employees, to evaluate whether there has been any
violation of federal law.
6
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 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
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, whether the MDL will proceed to trial, the results of any such 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. At the request of the court, in late February 2012 we
participated in a series of discussions with the Magistrate Judge in the MDL relating to whether the MDL could be settled.
Although these discussions did not result in a settlement, we recorded a $300 million liability during the first quarter of 2012 for
an estimated loss contingency relating to the MDL. This loss contingency, which is included in “Other liabilities” in our
consolidated balance sheet as of December 31, 2012 and in “Cost of services” on the consolidated statement of operations for the
year ended December 31, 2012, represents a loss contingency that is probable and for which a reasonable estimate of loss or
range of loss can be made. 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 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.
7
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. In addition, the
BSEE has noted that it may propose regulations to require, among other things, increased employee involvement in certain safety
measures and third-party audits of operators’ safety and environmental management systems. The BSEE has also stated 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 has 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 are typically indemnified by our
customers 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
existing 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 their 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.
8
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, 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.
9
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.
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 nontraded 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."
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.
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;
the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;
- weather conditions and natural disasters;
- worldwide political, military, and economic conditions;
-
- oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
-
- potential acceleration of development of alternative fuels.
the cost of producing and delivering oil and natural gas; and
10
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 changes that may materially and adversely affect us
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.
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.
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 Fuerte, 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."
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
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.
We are one of several unrelated companies who received a subpoena from the Office of the New York Attorney General,
dated June 17, 2011. The subpoena sought information and documents relating to, among other things, natural gas development
and hydraulic fracturing. We have provided information in response to the Attorney General's requests.
11
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. For any particular federal or state superfund site,
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. 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.
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.
Doing business with national oil companies exposes us to greater risks of cost overruns, delays, and project losses, as
well as unsettled political conditions that can heighten these risks.
Much of the world’s oil and natural gas reserves are controlled by national or state-owned oil companies (NOCs).
Several NOCs are among our top 20 customers. Increasingly, NOCs are turning to oilfield services companies like us to provide
the services, technologies, and expertise needed to develop their reserves. Reserve estimation is a subjective process that
involves estimating location and volumes based on a variety of assumptions and variables that cannot be directly measured. As
such, the NOCs may provide us with inaccurate information in relation to their reserves that may result in cost overruns, 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 types of issues may also result in similar cost overruns, delays, and project losses.
A downward trend in estimates of production volumes or commodity prices, or an upward trend in production costs,
could have a material adverse effect on our consolidated results of operations and result in impairment of or a change in the
depletion rate on our oil and natural gas properties.
We have interests in oil and natural gas properties primarily in North America totaling approximately $78 million, net of
accumulated depletion, which we account for under the successful efforts method. These oil and natural gas properties are
assessed for impairment whenever changes in facts and circumstances indicate that the properties’ carrying amounts may not be
recoverable. The expected future cash flows used for impairment reviews and related fair-value calculations are based on
judgmental assessments of future production volumes, prices, and costs, considering all available information at the date of
review.
A downward trend in estimates of production volumes or prices, or an upward trend in production costs, could have a
material adverse effect on our consolidated results of operations and result in impairment charges or a change in the depletion
rate on our oil and natural gas properties.
12
Some of our customers require us to enter into long-term, fixed-price contracts that may require us to assume
additional risks associated with cost over-runs, operating cost inflation, labor availability and productivity, supplier and
contractor pricing and performance, and potential claims for liquidated damages.
Our customers, primarily NOCs, may require integrated, long-term, fixed-price contracts that could require us to
provide integrated project management services outside our normal discrete business to act as project managers as well as
service providers. Providing services on an integrated basis 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. For example, we generally rely on third-party subcontractors and equipment providers to assist us
with the completion of our contracts. To the extent that we cannot engage subcontractors or acquire equipment or materials, our
ability to complete a project in a timely fashion 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.
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.
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.
Failure on our part to comply 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.
13
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 the worldwide 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.
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.
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.
14
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 technology, 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 technology, 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 and 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.
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.
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.
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 these 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.
Item 1(b). Unresolved Staff Comments.
None.
15
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:
Arbroath, United Kingdom
Johor, Malaysia
Lafayette, Louisiana
Monterrey, Mexico
Sao Jose dos Campos, Brazil
Singapore, Singapore
Stavanger, Norway
Alvarado, Texas
Nisku, Canada
Singapore, Singapore
The Woodlands, Texas
Shared/corporate facilities:
Carrollton, Texas
Dubai, United Arab Emirates
Duncan, Oklahoma
Houston, Texas
Pune, India
In addition, we have 180 international and 120 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.
16
Item 3. Legal Proceedings.
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). The flow of hydrocarbons from the well ceased on July
15, 2010, and the well was permanently capped on September 19, 2010. Numerous attempts at estimating the volume of oil
spilled have been made by various groups, and on August 2, 2010 the federal government published an estimate that
approximately 4.9 million barrels of oil were discharged from the well. 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 beginning of the
multi-district litigation (MDL) trial referred to below has been set for February 25, 2013. 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, whether the MDL will proceed to trial, the results of any such 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. At the request of the court, in late February 2012 we
participated in a series of discussions with the Magistrate Judge in the MDL relating to whether the MDL could be settled.
Although these discussions did not result in a settlement, we recorded a $300 million liability during the first quarter of 2012
for an estimated loss contingency relating to the MDL. This loss contingency, which is included in “Other liabilities” in our
consolidated balance sheet as of December 31, 2012 and in “Cost of services” on the consolidated statement of operations for
the year ended December 31, 2012, represents a loss contingency that is probable and for which a reasonable estimate of a loss
or range of 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, we cannot conclude that a probable loss
associated with the MDL is zero. 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
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. The United States Coast Guard, a component of the United States Department of
Homeland Security, and the Bureau of Ocean Energy Management, Regulation and Enforcement (formerly known as the
Minerals Management Service and which was replaced effective October 1, 2011 by two new, independent bureaus – the
Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Ocean Energy Management), a bureau of the
United States Department of the Interior, shared jurisdiction over the investigation into the Macondo well incident and formed a
joint investigation team that reviewed information and held hearings regarding the incident (Marine Board Investigation). We
were named as one of the 16 parties-in-interest in the Marine Board Investigation. The Marine Board Investigation, as well as
investigations of the incident that were conducted by The National Commission on the BP Deepwater Horizon Oil Spill and
Offshore Drilling (National Commission) and the National Academy of Sciences, have been completed, 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, 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.
17
In October 2011, the 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 and
ordered us and the BSEE to file notice within 15 days after the conclusion of the MDL and, within 60 days after the MDL court
issues a final decision, 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.
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 the joint investigation
team for the Marine Board Investigation 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.
At this time we cannot predict the impact of the investigations or reports referred to above, or the conclusions 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, whether federal or state and
whether criminal or civil.
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 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), The Migratory Bird Treaty Act of 1918 (MBTA), and the
Endangered Species Act of 1973 (ESA). As part of its criminal investigation, the DOJ is examining certain aspects of our
conduct after the incident, including with respect to record-keeping, record retention, post-incident testing and modeling and the
retention thereof, securities filings, and public statements by us or our employees, to evaluate whether there has been any
violation of federal law.
The CWA provides authority for civil and criminal 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. Criminal
sanctions under the CWA can be assessed for negligent discharges (up to $50,000 per day per violation), for knowing
discharges (up to $100,000 per day per violation), and for knowing endangerment (up to $2 million per violation), and federal
agencies could be precluded from contracting with a company that is criminally sanctioned 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.
18
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 MBTA and the ESA provide penalties for injury and death to wildlife and bird species. The MBTA provides that
violators are strictly liable and such violations are misdemeanor crimes subject to fines of up to $15,000 per bird killed and
imprisonment of up to six months. The ESA provides for civil penalties for knowing violations that can range up to $25,000 per
violation and, in the case of criminal penalties, up to $50,000 per violation.
In addition, federal law provides for a variety of fines and penalties, the most significant of which is the Alternative
Fines Act. In lieu of the express amount of the criminal fines that may be imposed under some of the statutes described above,
the Alternative Fines Act provides for a fine in the amount of twice the gross economic loss suffered by third parties, which
amount, although difficult to estimate, is significant.
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 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.
We have not been 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 are not included in the DOJ’s civil complaint, there
can be no assurance that the DOJ or other federal or state governmental authorities will not bring an action, whether civil or
criminal, against us under the CWA, the OPA, and/or other statutes or regulations. In connection with the DOJ’s filing of the
civil action, it announced that its criminal and civil investigations are continuing and that it will employ efforts to hold
accountable those who are responsible for the incident.
A federal grand jury has been convened in Louisiana to investigate potential criminal conduct in connection with the
Macondo well incident. We are cooperating fully with the DOJ’s criminal investigation. As of February 11, 2013, the DOJ has
not commenced any criminal proceedings against us. We cannot predict the status or outcome of the DOJ’s criminal
investigation or estimate the potential impact the investigation may have on us or our liability assessment, all of which may
change as the investigation progresses. We have had and expect to continue to have discussions with the DOJ regarding the
Macondo well incident and associated pre-incident and post-incident conduct.
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.
19
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. Transocean's civil and criminal settlements are subject to
court approval, and its civil settlement is also subject to public notice and comment.
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 400 complaints,
most of which are alleged class actions, involving pollution damage claims and at least seven 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. Plaintiffs originally filed the lawsuits described above in federal and state courts throughout the United States. Except
for certain 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. 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 MBTA, the ESA, the OCSLA, the Longshoremen and Harbor
Workers Compensation Act, general maritime law, state common law, and various state environmental and products liability
statutes.
Furthermore, the pollution complaints include suits brought against us by governmental entities, including the State of
Alabama, the State of Louisiana, Plaquemines Parish, the City of Greenville, and three Mexican states. Complaints brought
against us by at least seven other parishes in Louisiana were dismissed with prejudice, and the dismissal is being appealed by
those parishes. 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.
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 will be 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, we believe the judge will determine the liability, limitation, exoneration, and fault allocation with regard
to all of the defendants in a trial, which is scheduled to occur in at least two phases beginning on February 25, 2013. The first
phase of this portion of the trial is scheduled to cover 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. The MDL court has projected September 2013 for the
beginning of the second phase of this portion of the trial, which is scheduled to cover actions relating to attempts to control the
flow of hydrocarbons from the well and the quantification of hydrocarbons discharged from the well. Subsequent proceedings
would be held to the extent triable issues remain unsolved by the first two phases of the trial, settlements, motion practice, or
stipulation. While the DOJ will participate in the first two phases of the trial with regard to BP's conduct and the amount of
hydrocarbons discharged from the well, it is anticipated that the DOJ's civil action for the CWA and OPA violations, fines, and
penalties will be addressed by the court in a subsequent proceeding. We do not believe that a single apportionment 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.
Damages for the cases tried in the MDL proceeding, including punitive damages, are expected to be tried following the
two 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. Document discovery and depositions among the
parties to the MDL are ongoing.
20
In April and May 2011, certain defendants in the proceedings described above filed numerous cross claims and third
party claims against certain other defendants. BP Exploration and BP America Production Company filed claims against us
seeking subrogation, contribution, including with respect to liabilities under the OPA, and direct damages, and alleging
negligence, gross negligence, fraudulent conduct, and fraudulent concealment. Transocean filed claims against us seeking
indemnification, and subrogation and contribution, including with respect to liabilities under the OPA and for the total loss of
the Deepwater Horizon, and alleging comparative fault and breach of warranty of workmanlike performance. Anadarko filed
claims against us seeking tort indemnity and contribution, and alleging negligence, gross negligence and willful misconduct,
and MOEX Offshore 2007 LLC (MOEX), who had an approximate 10% interest in the Macondo well at the time of the
incident, filed a claim against us alleging negligence. Cameron International Corporation (Cameron) (the manufacturer and
designer of the blowout preventer), M-I Swaco (provider of drilling fluids and services, among other things), Weatherford U.S.
L.P. and Weatherford International, Inc. (together, Weatherford) (providers of casing components, including float equipment
and centralizers, and services), and Dril-Quip, Inc. (Dril-Quip) (provider of wellhead systems), each filed claims against us
seeking indemnification and contribution, including with respect to liabilities under the OPA in the case of Cameron, and
alleging negligence. Additional civil lawsuits may be filed against us. In addition to the claims against us, generally the
defendants in the proceedings described above filed claims, including for liabilities under the OPA and other claims similar to
those described above, against the other defendants described above. BP has since announced that it has settled those claims
between it and each of MOEX, Weatherford, Anadarko, and Cameron. Also, BP and M-I Swaco have dismissed all claims
between them.
In April 2011, we filed claims against BP Exploration, BP p.l.c. and BP America Production Company (BP
Defendants), M-I Swaco, Cameron, Anadarko, MOEX, Weatherford, Dril-Quip, and numerous entities involved in the post-
blowout remediation and response efforts, in each case seeking contribution and indemnification and alleging negligence. Our
claims also alleged gross negligence and willful misconduct on the part of the BP Defendants, Anadarko, and Weatherford. We
also filed claims against M-I Swaco and Weatherford for contractual indemnification, and against Cameron, Weatherford and
Dril-Quip for strict products liability, although the court has since issued orders dismissing all claims asserted against Dril-Quip
and Weatherford in the MDL and we have dismissed our contractual indemnification claim against M-I Swaco. We filed our
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 dismissed all claims brought under state law
causes of action; (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.
In September 2011, we filed claims in Harris County, Texas against the BP Defendants seeking damages, including
lost profits and exemplary damages, and alleging negligence, grossly negligent misrepresentation, defamation, common law
libel, slander, and business disparagement. Our claims allege that the BP Defendants knew or should have known about an
additional hydrocarbon zone in the well that the BP Defendants failed to disclose to us prior to our designing the cement
program for the Macondo well. The location of the hydrocarbon zones is critical information required prior to performing
cementing services and is necessary to achieve desired cement placement. We believe that had the BP Defendants disclosed the
hydrocarbon zone to us, we would not have proceeded with the cement program unless it was redesigned, which likely would
have required a redesign of the production casing. In addition, we believe that the BP Defendants withheld this information
from the report of BP's internal investigation team and from the various investigations discussed above. In connection with the
foregoing, we also moved to amend our claims against the BP Defendants in the MDL proceeding to include fraud. The BP
Defendants have denied all of the allegations relating to the additional hydrocarbon zone and filed a motion to prevent us from
adding our fraud claim in the MDL. In October 2011, our motion to add the fraud claim against the BP Defendants in the MDL
proceeding was denied. The court’s ruling does not, however, prevent us from using the underlying evidence in our pending
claims against the BP Defendants.
In December 2011, BP filed a motion for sanctions against us alleging, among other things, that we destroyed evidence
relating to post-incident testing of the foam cement slurry on the Deepwater Horizon and requesting adverse findings against us.
The magistrate judge in the MDL proceeding denied BP’s motion. BP appealed that ruling, and Judge Barbier affirmed the
magistrate judge’s decision.
21
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. BP has estimated that the cost of the settlements would be
approximately $8.5 billion, including payments to claimants who opt out of the settlements, administration costs, and plaintiffs’
attorneys’ fees and expenses, and has stated that it is possible the actual cost could be higher. 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. In April and May, 2012, BP and the PSC filed two settlement
agreements and amendments with the MDL court, one agreement addressing economic claims and one agreement addressing
medical claims, as well as numerous supporting documents and motions requesting that the court approve, among other things,
the certification of the classes for both settlements and a schedule for holding a fairness hearing and approving the settlements.
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. We are unable to predict at this time the effect that the settlements may have on
claims against us.
In October 2012, the MDL court issued an order dismissing three types of plaintiff claims: (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. 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.
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.
Macondo derivative case. In February 2011, a shareholder who had previously made a demand on our Board of
Directors with respect to another derivative lawsuit filed a shareholder derivative lawsuit relating to the Macondo well incident.
In 2012, we settled those lawsuits and the cases were dismissed. See “Shareholder derivative cases” below.
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.
22
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. 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.
In responding to similar motions for summary judgment between Transocean and BP, the court also held that public
policy would not bar Transocean’s claim for indemnification of compensatory damages, even if Transocean was found to be
grossly negligent. The court also held, among other things, that Transocean’s contractual right to indemnity does not extend to
punitive damages or civil penalties under the CWA.
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, 2012, we have incurred legal
fees and related expenses of approximately $175 million, of which $158 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.
Barracuda-Caratinga arbitration
We agreed to provide indemnification in favor of our former subsidiary, KBR, Inc. (KBR), under the Master
Separation Agreement for liabilities KBR may incur after November 20, 2006 as a result of certain allegedly defective subsea
flowline bolts installed in connection with the Barracuda-Caratinga project. Prior to that, at the inception of the project, we
provided a guarantee to Barracuda & Caratinga Leasing Company BV (BCLC), a subsidiary of our customer, Petrobras, of
KBR's obligations with respect to the project.
In March 2006, BCLC commenced arbitration against KBR claiming $220 million plus interest for the cost of
monitoring and replacing the allegedly defective bolts and all related costs and expenses of the arbitration, including the cost of
attorneys' fees. During the third quarter of 2011, an arbitration panel issued an award against KBR in the amount of
approximately $201 million, plus post-judgment interest. BCLC filed a motion to confirm, and KBR filed a motion to vacate,
the arbitration award with the United States District Court for the Southern District of New York. In December 2012, BCLC
sent us a demand for payment of the arbitration award under the terms of our guarantee. In January 2013, the matter was
resolved by our payment of $219 million to BCLC under the guarantee. BCLC has agreed that our obligations under the
guarantee have been satisfied. See Note 7 for further discussion of the Barracuda-Caratinga matter.
23
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 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 and the case is stayed at the district court pending this
appeal. The Fifth Circuit is set to hear oral argument in the appeal in March 2013. In spite of its age, the case is at an early
stage, and we cannot predict the outcome or consequences thereof. We intend to vigorously defend this case.
Shareholder derivative cases
In May 2009, two shareholder derivative lawsuits involving us and KBR were filed in Harris County, Texas, naming as
defendants various current and retired Halliburton directors and officers and current KBR directors. These cases allege that the
individual Halliburton defendants violated their fiduciary duties of good faith and loyalty, to our detriment and the detriment of
our shareholders, by failing to properly exercise oversight responsibilities and establish adequate internal controls. The District
Court consolidated the two cases, and the plaintiffs filed a consolidated petition against only current and former Halliburton
directors and officers containing various allegations of wrongdoing including violations of the FCPA, claimed KBR offenses
while acting as a government contractor in Iraq, claimed KBR offenses and fraud under United States government contracts,
Halliburton activity in Iran, and illegal kickbacks. Subsequently, a shareholder made a demand that the Board take remedial
action respecting the FCPA claims in the pending lawsuit. Our Board of Directors designated a special committee of certain
independent and disinterested directors to oversee the investigation of the allegations made in the lawsuits and shareholder
demand. Upon receipt of the special committee’s findings and recommendations, the independent and disinterested members of
the Board determined that the shareholder claims were without merit and not otherwise in our best interest to pursue. The Board
directed our counsel to report its determinations to the plaintiffs and demanding shareholder.
In 2012, we agreed to settle the consolidated lawsuit, and the court approved the settlement and dismissed the case.
Pursuant to the settlement, we paid the plaintiffs' legal fees which were not material to our consolidated financial statements,
and we have implemented certain changes to our corporate governance policies.
24
In February 2011, the same shareholder who had made the demand on our Board of Directors in connection with one
of the derivative lawsuits discussed above filed a shareholder derivative lawsuit in Harris County, Texas naming us as a nominal
defendant and certain of our directors and officers as defendants. This case alleges that these defendants, among other things,
breached fiduciary duties of good faith and loyalty by failing to properly exercise oversight responsibilities and establish
adequate internal controls, including controls and procedures related to cement testing and the communication of test results, as
they relate to the Macondo well incident. Our Board of Directors designated a special committee of certain independent and
disinterested directors to oversee the investigation of the allegations made in the lawsuit and shareholder demand. Upon receipt
of the special committee’s findings and recommendations, the independent and disinterested members of the Board determined
that the shareholder claims were without merit and not otherwise in our best interest to pursue. The Board directed our counsel
to report its determinations to the plaintiffs and demanding shareholder.
In 2012, we agreed to settle this lawsuit, and the court approved the settlement and dismissed the case. Pursuant to the
settlement, we paid the plaintiffs' legal fees which were not material to our consolidated financial statements, and we have
implemented certain changes to our corporate governance and health, safety, and environmental policies.
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.
Since the third quarter of 2011, we have been participating in meetings with the DOJ and the SEC to brief them on the
status of our investigation and have been producing documents to them both voluntarily and as a result of SEC subpoenas to the
company and certain of our current and former officers and employees.
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.
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 the investigations. 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 OPA.
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 and the Duncan, Oklahoma matter described below, 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. 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.
25
In November 2012, the Company 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. We are currently negotiating with the PADEP to resolve this matter in an amicable
manner. We expect the PADEP to assess a penalty in excess of $100,000. We do not expect this matter to have a material
adverse effect on our liquidity, consolidated results of operations, or consolidated financial position.
Between approximately 1965 and 1991, one or more former Halliburton units performed work (as a contractor or
subcontractor) for the U.S. Department of Defense cleaning solid fuel from missile motor casings at a semi-rural facility on the
north side of Duncan, Oklahoma. In addition, from approximately November 1983 through December 1985, a discrete portion
of the site was used to conduct a recycling project on stainless steel nuclear fuel rod racks from Omaha Public Power District’s
Fort Calhoun Station. We closed the site in coordination with the Oklahoma Department of Environmental Quality (DEQ) in
the mid-1990s, but continued to monitor the groundwater at the DEQ’s request. A principal component of the missile fuel was
ammonium perchlorate, a salt that is highly soluble in water, which has been discovered in the soil and groundwater on our site
and in certain residential water wells near our property. In August 2011, we entered into the DEQ’s Voluntary Cleanup Program
and executed a voluntary Memorandum of Agreement and Consent Order for Site Characterization and Risk Based
Remediation with the DEQ relating to the remediation of this site.
Commencing in October 2011, a number of lawsuits were filed against us, including a putative class action case in
federal court in the Western District of Oklahoma and other lawsuits filed in Oklahoma state courts. The lawsuits generally
allege, among other things, that operations at our Duncan facility caused releases of pollutants, including ammonium
perchlorate and, in the case of the federal lawsuit, nuclear or radioactive waste, into the groundwater, and that we knew about
those releases and did not take corrective actions to address them. It is also alleged that the plaintiffs have suffered from certain
health conditions, including hypothyroidism, a condition that has been associated with exposure to perchlorate at sufficiently
high doses over time. These cases seek, among other things, damages, including punitive damages, and the establishment of a
fund for future medical monitoring. The cases allege, among other things, strict liability, trespass, private nuisance, public
nuisance, and negligence and, in the case of the federal lawsuit, violations of the U.S. Resource Conservation and Recovery Act
(RCRA), resulting in personal injuries, property damage, and diminution of property value.
The lawsuits generally allege that the cleaning of the missile casings at the Duncan facility contaminated the
surrounding soils and groundwater, including certain water wells used in a number of residential homes, through the migration
of, among other things, ammonium perchlorate. The federal lawsuit also alleges that our processing of radioactive waste from a
nuclear power plant over 25 years ago resulted in the release of “nuclear/radioactive” waste into the environment. In April
2012, the judge in the federal lawsuit dismissed the plaintiffs’ RCRA claim. The other claims brought in that lawsuit remain
pending.
To date, soil and groundwater sampling relating to the allegations discussed above has confirmed that the alleged
nuclear or radioactive material is confined to the soil in a discrete area of the onsite operations and is not presently believed to
be in the groundwater onsite or in any areas offsite. The radiological impacts from this discrete area are not believed to present
any health risk for offsite exposure. With respect to ammonium perchlorate, we have made arrangements to supply affected
residents with bottled drinking water and, if needed, with access to temporary public water supply lines, at no cost to the
residents. We have worked with the City of Duncan and the DEQ to expedite expansion of the city water supply to the relevant
areas at our expense.
The lawsuits described above are at an early stage, and additional lawsuits and proceedings may be brought against us.
We cannot predict their outcome or the consequences thereof. As of December 31, 2012, we had accrued $25 million related to
our initial estimate of response efforts, third-party property damage, and remediation related to the Duncan, Oklahoma matter.
We intend to vigorously defend the lawsuits and do not believe that these lawsuits will have a material adverse effect on our
liquidity, consolidated results of operations, or consolidated financial condition.
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, 2012, those nine
sites accounted for approximately $6 million of our $72 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.
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.
26
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 87 of this annual report. Cash dividends on our common stock in the amount of $0.09 per
share were paid in March, June, September, and December of 2012 and 2011. Our Board of Directors intends to consider the
payment of quarterly dividends on the outstanding shares of our common stock in the future. The declaration and payment of
future dividends, however, 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.
The following graph and table compare total shareholder return on our common stock for the five-year period ended
December 31, 2012, 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, 2007, 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
$
2007
100.00 $
100.00
100.00
2008
2009
48.54 $
40.53
63.00
81.66 $
65.71
79.68
2010
112.12 $
83.40
91.70
2011
2012
95.54 $
74.61
93.61
97.11
76.94
108.59
27
At February 1, 2013, there were 15,458 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, 2012.
Period
October 1 - 31
November 1 - 30
December 1 - 31
Total
Total Number
of Shares
Purchased (a)
Average
Price Paid
per Share
30,007
25,503
123,291
178,801
$33.44
$31.58
$33.66
$33.33
Total Number
of Shares
Purchased as
Part of Publicly
Announced Plans
or Programs
Maximum
Number (or
Approximate
Dollar Value) of
Shares that may yet
be Purchased Under
the Program (b)
—
—
—
—
$—
$—
$—
$1,731,208,803
(a) All of the 178,801 shares purchased during the three-month period ended December 31, 2012 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
shares.
(b) Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the fourth
quarter of 2012, 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 86 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 30 through 49 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 47 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, 2012, 2011, and 2010
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011, and 2010
Consolidated Balance Sheets at December 31, 2012 and 2011
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2012, 2011, and 2010
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.
50
51
53
54
55
56
57
58
86
87
28
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, 2012 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, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial
reporting.
See page 50 for Management’s Report on Internal Control Over Financial Reporting and page 51 for Report of
Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
Item 9(b). Other Information.
None.
29
HALLIBURTON COMPANY
Management’s Discussion and Analysis of Financial Condition and Results of Operations
EXECUTIVE OVERVIEW
Financial results
During 2012, we produced revenue of $28.5 billion and operating income of $4.2 billion, reflecting an operating
margin of 15%. Revenue increased $3.7 billion, or 15%, from 2011, while operating income decreased $578 million, or 12%,
from 2011. Overall, revenue improved compared to 2011 due to higher drilling activity in oil and liquids-rich basins in North
America, as well as increased activity in all our international regions. However, operating income decreased in 2012 primarily
due to the escalating cost of guar gum (a blending additive used in our hydraulic fracturing process), pricing pressure in North
America, and a $300 million, pre-tax, loss contingency for the Macondo well incident.
Business outlook
We continue to believe in the strength of the long-term fundamentals of our business. Energy demand is expected to
increase in 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 supply uncertainties associated with geopolitical tensions in the
Middle East. Furthermore, development of new resources is expected to be more complex, resulting in increasing service
intensity.
In North America, the industry has experienced an activity shift from natural gas plays to oil and liquids-rich basins
due to low natural gas prices resulting from continued strong natural gas production. As a result, operators have been
optimizing their budgets by focusing on basins with better economics. For those customers remaining in natural gas basins, we
have continued to provide services, despite lower margins. This has strengthened our relationships with those customers and
positions us well for when natural gas activity rebounds. We anticipate further pricing pressure for our production enhancement
services in 2013. To adapt, we plan to remain focused on capital and cost discipline for our pressure pumping businesses and
currently intend to direct less capital toward the North America market in the coming year.
Our Gulf of Mexico business has reached record levels due to an increase in permit approvals for deepwater drilling
and our increased market share. We remain optimistic about activity in the Gulf of Mexico as our customers adapt to new
regulations and new permit approvals are issued. Also, additional deepwater rigs are expected to arrive in the Gulf of Mexico in
2013, which will provide us with further growth opportunities.
Outside of North America, revenue and operating income increased in 2012 compared to 2011. We expect to see
gradual activity and pricing improvements in those international markets where we anticipate the addition of deepwater rigs and
those in which we have made strategic investments in capital and technologies. We also believe that new international
unconventional oil and natural gas projects may contribute to activity improvements in 2013.
We executed several key initiatives in 2012. These initiatives included increasing manufacturing production in the
Eastern Hemisphere and reinventing our service delivery platform to lower our delivery costs. We plan to continue to invest in
these initiatives in 2013. In addition, we plan to continue executing the following strategies:
-
increasing our market share in the more economic, unconventional plays 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 capital to accelerate growth opportunities. To that end, we are
continuing to push our technology and manufacturing development, 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. In 2011, we
launched a project in North America to redesign our frac of the future service delivery platform for services
through the rollout of improved equipment designs and improved field procedures to reduce cost and improve
efficiency;
- expanding capabilities in mature fields to expand our service and consulting capabilities;
- continuing to seek ways to be one of the most cost efficient service providers in the industry by using 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.”
30
Financial markets, liquidity, and capital resources
The global financial markets can potentially create additional risks for our business. We believe we have invested our
cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations.
For additional information, see “Liquidity and Capital Resources” and “Business Environment and Results of Operations.”
31
LIQUIDITY AND CAPITAL RESOURCES
We ended 2012 with cash and equivalents of $2.5 billion compared to $2.7 billion at December 31, 2011. As of
December 31, 2012, $470 million of the $2.5 billion of cash and equivalents was held by our foreign subsidiaries that would be
subject to tax if repatriated. If these funds are needed for our operations in the United States, we would be required to accrue
and pay United States taxes to repatriate these funds. However, our intent is to permanently reinvest these funds outside of the
United States and our current plans do not demonstrate a need to repatriate them to fund our United States operations. We also
held $398 million of investments in fixed income securities (both short- and long-term) at December 31, 2012, compared to
$150 million (short-term) at December 31, 2011, bringing our total cash and investment securities to $2.9 billion at
December 31, 2012, which is essentially flat from the prior year.
Significant sources of cash
Cash flows provided by operating activities were $3.7 billion in 2012.
We sold $395 million of property, plant, and equipment during 2012.
Further available sources of cash. We have an unsecured $2.0 billion five-year revolving credit facility expiring in
2016. 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, 2012.
Significant uses of cash
Capital expenditures were $3.6 billion in 2012. The capital expenditures in 2012 were predominantly made in our
production enhancement, drilling, cementing, and wireline and perforating product service lines. We have also invested
additional working capital to support the growth of our business.
During 2012, our primary components of net working capital, receivables, inventories and accounts payable, increased
by $1.1 billion, primarily due to increased business activity and delays in receiving payment on trade receivables from one of
our primary customers in Venezuela. See "Customer receivables" below.
We paid $333 million of dividends to our shareholders in 2012.
During 2012, we purchased $248 million of investment securities, net of investment securities sold.
Future uses of cash. Capital spending for 2013 is currently expected to be approximately $3.0 billion. The capital
expenditures plan for 2013 is primarily directed toward our production enhancement, drilling, cementing, Boots and Coots, and
wireline and perforating product service lines. We currently intend to direct less capital toward the North America market in
2013 than we did during 2012.
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
large operations.
Subject to Board of Directors approval, we expect to pay quarterly dividends of approximately $83 million during
2013. We also have approximately $1.7 billion remaining available under our share repurchase authorization, which may be
used for open market share purchases.
In January 2013, we made a $219 million payment to BCLC under a guarantee we issued for the Barracuda-Caratinga
project. See Part I, Item 3, "Legal Proceedings – Barracuda-Caratinga Arbitration."
The following table summarizes our significant contractual obligations and other long-term liabilities as of
December 31, 2012:
Millions of dollars
Long-term debt
Interest on debt (a)
Operating leases
Purchase obligations (b)
Pension funding obligations (c)
Other long-term liabilities
Total
Payments Due
2013
2014
2015
2016
2017
Thereafter
Total
$ — $ — $ — $ — $ — $
4,820 $
275
287
2,374
27
14
276
214
389
—
4
281
146
281
—
3
284
102
177
—
3
288
48
152
—
3
5,432
164
42
—
7
4,820
6,836
961
3,415
27
34
$ 2,977 $
883 $
711 $
566 $
491 $
10,465 $
16,093
(a) Interest on debt includes 84 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.
(b) Primarily represents certain purchase orders for goods and services utilized in the ordinary course of our business.
(c) Includes international plans and is based on assumptions that are subject to change. We are currently not able to
reasonably estimate our contributions for years after 2013.
32
We had $296 million of gross unrecognized tax benefits at December 31, 2012, of which we estimate $124 million
may require a cash payment. We estimate that $99 million of the cash payment will not be settled within the next 12 months.
We are not able to reasonably estimate in which future periods this amount will ultimately be settled and paid.
Other factors affecting liquidity
Financial position in current market. As of December 31, 2012, we had $2.5 billion of cash and equivalents and $398
million in fixed income securities. We also had $2.0 billion of available committed bank credit under our revolving credit
facility. 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 any capital
expenditures, working capital investments, and dividends in 2013 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 above in Part I,
Item 3, “Legal Proceedings,” 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 $1.9 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2012,
including $277 million of surety bonds related to Venezuela. See “Business Environment and Results of Operations –
International Operations” for further discussion related to Venezuela. 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. For example, we continue to see delays in receiving payment on our
receivables from one of our primary customers in Venezuela. Our total outstanding trade receivables in Venezuela at
December 31, 2012 were $491 million, which represents approximately 9% of our gross trade receivables at that date. 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” for further discussion related to Venezuela.
33
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. The majority 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 2012, 2011, and 2010, based on the
location of services provided and products sold, 53%, 55%, and 46% 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 major, national, and independent oil and natural gas companies. Also impacting our
activity is the status of the global economy, which impacts oil and natural gas consumption.
Some of the more significant measures of current and future spending levels of oil and natural gas companies 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.
This table shows the average oil and natural gas prices for West Texas Intermediate (WTI), United Kingdom Brent
crude oil, and Henry Hub natural gas:
Average Oil Prices (dollars per barrel)
West Texas Intermediate
United Kingdom Brent
2012
2011
2010
$
94.15 $
95.13 $
111.60
111.53
79.36
79.66
Average United States Natural Gas Prices (dollars per
thousand cubic feet, or Mcf)
Henry Hub
$
2.81 $
4.09 $
4.52
34
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
2012
2011
2010
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
1,509
32
1,541
349
2
351
789
305
1,094
2,986
2,647
339
Oil vs. Natural Gas
United States (incl. Gulf of Mexico):
2012
2011
2010
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
1,359
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
593
948
1,541
201
150
351
840
254
1,094
2,986
1,634
1,352
2012
2011
2010
1,151
1,074
552
216
571
230
822
501
218
1,919
1,875
1,541
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. The opposite is true for
higher oil and natural gas prices.
35
WTI oil prices, which generally influence customer spending in North America, have fluctuated throughout 2012,
ranging from a high of $109 per barrel in February to a low of $78 per barrel in June. Outside of North America, customer
spending is heavily influenced by Brent oil prices, which have fluctuated during 2012 from a high of $128 per barrel in March
to a low of $89 per barrel in June. Prices were somewhat volatile as geopolitical tension in the Middle East, global economic
uncertainty surrounding the European debt crisis, and slower growth expectations in China and Brazil impacted demand. The
outlook for world petroleum demand for 2013 is mixed, with the International Energy Agency’s (IEA) January 2013 “Oil
Market Report” forecasting a 1% increase in petroleum demand from 2012 levels. The IEA expects modest declines in mature
economies to be more than offset by relatively strong growth in emerging markets, particularly in China.
Henry Hub natural gas prices declined during the first half of 2012 due to a mild winter and strong production levels
associated with unconventional drilling activity. During the second half of 2012, decreased natural gas drilling activity resulted
in lower natural gas storage injections relative to expectations. This, coupled with increased natural gas demand from the power
generation sector due to a warm summer, resulted in higher natural gas prices. Natural gas prices during 2012 ranged from a
low of $1.82 per Mcf in April to a high of $3.77 per Mcf in November. Near the end of 2012 and into early-2013, natural gas
prices began to decline due to warmer than normal weather. The United States Energy Information Administration (EIA)
January 2013 “Short Term Energy Outlook” forecast expects Henry Hub natural gas prices to average $3.74 per Mcf in 2013
compared to $2.81 per Mcf in 2012.
The outlook for activity thus faces some uncertainties as the global economy continues to recover. However, 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. In North America
during 2012, the average natural gas directed rig count fell by 369 rigs, or 36%, from 2011, while the average oil directed rig
count has increased by 354 rigs, or 28%, over the same period. The curtailment of natural gas drilling activity along with an
influx of stimulation equipment into the industry have resulted in overcapacity and pricing pressure for hydraulic fracturing
services, which we expect to persist through 2013. In addition, our higher priced guar inventory negatively impacted our
margins for our Production Enhancement product service line in 2012.
Going forward, we expect North America rig count to grow from current levels but to average down slightly for the
full year 2013 in comparison to the full year 2012. However, 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
2012, we saw average drilling days per horizontal well drop approximately 15% compared to 2011 and we anticipate continued
efficiency improvement in 2013. 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, liquids-rich, and natural gas 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, deepwater drilling activity has returned to levels experienced before the Macondo incident. In
some cases, the timing of our customers' projects was disrupted during the third quarter of 2012 due to Hurricane Issac. 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 2012, with the average international rig count improving 6%
over 2011. These volume increases have led to a meaningful absorption of equipment supply and we are now seeing
opportunities for price improvements in select geographies. However, we anticipate moderate margin improvements and
gradual activity increases, although the operator spending outlook could be impacted by ongoing macroeconomic concerns.
We believe that international growth in 2013 will come from a combination of several factors, including volume
increases as we ramp up on recent wins and new projects, from continued improvement in those markets where we have made
strategic investments, from the introduction of new technology, and from 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. In December 2010, the Venezuelan government set the fixed exchange rate at 4.3 Bolívar Fuerte to one
United States dollar effective January 1, 2011, eliminating the dual exchange rate scheme implemented in early 2010. This
change had no impact on us because we have applied the 4.3 Bolívar Fuerte fixed exchange rate since the previously disclosed
January 2010 devaluation.
On May 24, 2011, the United States government imposed sanctions on the state-owned oil company of Venezuela. The
sanctions do not, however, apply to that company’s subsidiaries and do not prohibit the export of crude oil to the United States.
We do not expect these sanctions to have a material impact on our operations in Venezuela.
36
As of December 31, 2012, our total net investment in Venezuela was approximately $328 million, including net
monetary assets of $74 million denominated in Bolívar Fuerte. At December 31, 2012, our total outstanding trade receivables in
Venezuela were $491 million, which represented approximately 9% of our gross trade receivables at that date. We continue to
see delays in receiving payment on our receivables from our primary customer in Venezuela. In addition, at December 31, 2012
we had $277 million of surety bond guarantees outstanding relating to our Venezuelan operations.
In February 2013, the Venezuelan government announced a devaluation of the Bolívar Fuerte, from the preexisting
exchange rate of 4.3 Bolívar Fuertes per United States dollar to 6.3 Bolívar Fuertes per United States dollar. As a result of the
devaluation, we are estimating a foreign currency loss of approximately $30 million in the first quarter of 2013. The February
devaluation did not impact our 2012 results of operations, financial position, or cash flows. Further devaluation of the Bolívar
Fuerte could impact our operations. For additional information, see Part I, Item 1(a), “Risk Factors” in this Form 10-K.
37
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
Favorable
Percentage
2012
2011
(Unfavorable)
Change
$
$
17,380 $
15,143 $
11,123
9,686
28,503 $
24,829 $
2,237
1,437
3,674
15%
15
15%
$
12,157 $
10,907 $
1,250
11%
1,415
2,099
1,709
17,380
3,847
2,279
2,411
2,586
11,123
16,004
3,694
4,510
4,295
1,117
1,746
1,373
15,143
3,506
1,865
2,210
2,105
9,686
14,413
2,982
3,956
3,478
298
353
336
2,237
341
414
201
481
1,437
1,591
712
554
817
27
20
24
15
10
22
9
23
15
11
24
14
23
38
$
$
$
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
Favorable
Percentage
2012
2011
3,144 $
1,675
(660)
4,159 $
(Unfavorable)
(589)
272
(261)
(578)
3,733 $
1,403
(399)
4,737 $
2,260 $
3,341 $
206
347
331
3,144
680
393
246
356
159
48
185
3,733
641
305
191
266
1,675
1,403
2,940
599
593
687
3,982
464
239
451
(1,081)
47
299
146
(589)
39
88
55
90
272
(1,042)
135
354
236
Change
(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.
39
Completion and Production increase in revenue compared to 2011 was primarily a result of 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.
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
Interest expense, net of interest income increased $35 million in 2012 compared to 2011 primarily due to higher
interest costs incurred resulting from our issuance of $1.0 billion of senior notes in the fourth quarter of 2011.
Other, net increased $14 million from 2011 due primarily to foreign currency fluctuations.
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 a $219 million payment we made to BCLC under that guarantee.
40
RESULTS OF OPERATIONS IN 2011 COMPARED TO 2010
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
2011
2010
(Unfavorable)
Change
Favorable
Percentage
$
$
15,143 $
9,686
9,997 $
7,976
24,829 $
17,973 $
5,146
1,710
6,856
$
10,907 $
6,183 $
4,724
1,117
1,746
1,373
15,143
3,506
1,865
2,210
2,105
9,686
14,413
2,982
3,956
3,478
839
1,797
1,178
9,997
2,644
1,390
2,117
1,825
7,976
8,827
2,229
3,914
3,003
278
(51)
195
5,146
862
475
93
280
1,710
5,586
753
42
475
51%
21
38%
76%
33
(3)
17
51
33
34
4
15
21
63
34
1
16
41
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
2011
2010
(Unfavorable)
Change
Favorable
Percentage
$
$
$
3,733 $
1,403
(399)
4,737 $
2,032 $
1,213
(236)
3,009 $
3,341 $
1,423 $
159
48
185
3,733
641
305
191
266
115
301
193
2,032
453
175
283
302
1,403
1,213
3,982
464
239
451
1,876
290
584
495
1,701
190
(163)
1,728
1,918
44
(253)
(8)
1,701
188
130
(92)
(36)
190
2,106
174
(345)
(44)
84%
16
69
57%
135%
38
(84)
(4)
84
42
74
(33)
(12)
16
112
60
(59)
(9)
The 38% increase in consolidated revenue in 2011 compared to 2010 was primarily due to higher rig count and
increased demand for our services and products in North America. We experienced a 63% increase in North America revenue
compared to an approximate 21% increase in average North America rig count during 2011 compared to 2010. Revenue outside
of North America was 42% of consolidated revenue in 2011 and 51% of consolidated revenue in 2010.
The 57% increase in consolidated operating income compared to 2010 was mainly due to improved pricing and
increased demand in North America, particularly in our Completion and Production division. 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. Operating income in 2010 was adversely impacted by a $50 million non-
cash impairment charge for an oil and natural gas property in Bangladesh.
Following is a discussion of our results of operations by reportable segment.
Completion and Production increase in revenue compared to 2010 was primarily a result of higher activity in North
America. North America revenue rose 76%, primarily due to increased cementing services and higher activity in production
enhancement from an increased demand for hydraulic fracturing in the United States. Latin America revenue increased 33%
due to improved activity in all product service lines across the region. Europe/Africa/CIS revenue decreased 3%, as less activity
in North Africa and lower vessel utilization in the North Sea and Nigeria was partially offset by higher activity in our Boots &
Coots product service line in Angola and Norway. Middle East/Asia revenue grew 17% due to higher activity in all product
service lines in Australia, Malaysia, and Indonesia, partially offset by lower completion tools sales in China. Revenue outside of
North America was 28% of total segment revenue in 2011 and 38% of total segment revenue in 2010.
42
The Completion and Production segment operating income increase compared to 2010 was primarily due to the North
America region, where operating income grew $1.9 billion on higher demand for production enhancement services in
unconventional basins located in the United States land market. Latin America operating income increased 38% due to higher
demand for cementing services in Colombia, Brazil, and Argentina, partially offset by higher costs and pricing adjustments in
Mexico. Europe/Africa/CIS operating income declined 84% due to an impairment charge on an asset held for sale and activity
disruptions in North Africa, including the Libya-related reserve for certain account receivables and inventory. Middle East/Asia
operating income decreased 4% due to higher costs across most of the region and higher start-up costs associated with the
commencement of work in Iraq, which were partially offset by higher activity levels in Australia, Malaysia, and Indonesia.
Drilling and Evaluation revenue increased 21% compared to 2010 as drilling activity improved across all regions,
especially North America and Latin America. North America revenue grew 33% on substantial activity increases in the United
States land market. Latin America revenue increased 34% due to higher demand in most product services lines in Brazil,
Mexico, Venezuela, and Colombia. Europe/Africa/CIS revenue increased 4% due to improved drilling service in Angola,
Nigeria, and Norway and increased fluid demand in Egypt, partially offset by lower activity in Libya. Middle East/Asia revenue
rose 15% primarily due to the commencement of work in Iraq, increased fluid demand in Southeast Asia, and higher wireline
direct sales. Revenue outside North America was 64% of total segment revenue in 2011 and 67% of total segment revenue in
2010.
Segment operating income compared to 2010 increased 16% due to increased activity in North America and Latin
America, partially offset by lower activity associated with the disruptions in North Africa and less favorable pricing in the
Eastern Hemisphere. North America operating income increased 42% from improved pricing and increased demand for most of
our services and products. Latin America operating income grew 74% as a result of activity increases in Mexico, Venezuela,
and Brazil. The Europe/Africa/CIS region operating income fell 33% due to costs associated with activity disruptions in North
Africa, including the reserve charge for certain account receivables and inventory, partially offset by improved drilling service
in Norway and Nigeria and higher fluid demand in Angola. Middle East/Asia operating income decreased 12% mainly due to
start-up costs associated with the commencement of work in Iraq and higher costs in Saudi Arabia. Operating income in 2010
was adversely impacted by a $50 million non-cash impairment charge for an oil and natural gas property in Bangladesh.
Corporate and other expenses were $399 million, including a $37 million environmental-related matter in 2011,
compared to $236 million in 2010. The 69% increase was primarily due to higher legal and environmental costs and additional
expenses associated with strategic investments in our operating model and creating competitive advantages by repositioning our
technology, supply chain, and manufacturing infrastructure.
NONOPERATING ITEMS
Interest expense, net of interest income decreased $34 million in 2011 compared to 2010 primarily due to less interest
expense as a result of the retirement of $750 million principal amount of our 5.5% senior notes in October 2010 and lower
interest rates on a portion of our debt as a result of our interest rate swaps. This was partially offset by higher interest costs
incurred in the fourth quarter of 2011 resulting from our issuance of $1.0 billion of senior notes.
Other, net decreased $32 million from 2010 due to a $31 million loss on foreign currency exchange recognized in 2010
as a result of the devaluation of the Venezuelan Bolívar Fuerte.
Income (loss) from discontinued operations, net decreased $206 million in 2011 compared to 2010 primarily due to a
$163 million charge, after-tax, recognized in 2011 related to a ruling in an arbitration proceeding between BCLC and our
former subsidiary, KBR, whom we agreed to indemnify.
43
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, construction-type 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.
44
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.
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, 2012, we have accrued an
estimate of the probable and estimable costs for the resolution of some of these 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. Beginning in 2011, we elected to perform a qualitative assessment for our annual
goodwill impairment test. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting
unit is less than its carrying amount, or if we elect to not perform a qualitative assessment, then we would be required to
perform a quantitative impairment test for goodwill. 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. 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. Our goodwill impairment assessment for 2010 indicated
the fair value of each of our reporting units exceeded its carrying amount by a significant margin. See Note 1 to the
consolidated financial statements for accounting policies related to long-lived assets and intangible assets.
45
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.
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
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 weighted-average discount rate utilized in 2012 to determine the projected benefit obligation at the measurement
date for our United Kingdom pension plan, which constituted 78% of our international plans’ pension obligations, was 4.6%,
compared to a discount rate of 4.9% utilized in 2011. The expected long-term rate of return assumption used for our United
Kingdom pension plan expense in 2012 and 2011 was 6.7%. 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 2012
Pension Benefit Obligation
at December 31, 2012
1 $
(1)
2
(2)
45
(43)
NA
NA
Our international defined benefit plans reduced pretax income by $26 million in 2012, $27 million in 2011, and $28
million in 2010. Included in these amounts was income from expected pension returns of $45 million in 2012, $47 million in
2011, and $43 million in 2010. Actual returns on international plan assets totaled $87 million in 2012, compared to $13 million
in 2011. Our net actuarial loss, net of tax, related to international pension plans at December 31, 2012 was $208 million. In our
international plans where employees earn additional benefits for continued service, actuarial gains and losses are being
recognized in operating income over a period of 12 to 18 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 are being recognized in operating income over a period of one to 35 years, which represents the
estimated average remaining lifetime of the benefit obligations. The broad range of one to 35 years reflects varying maturity
levels among these plans.
During 2012, we made contributions of $24 million to fund our international defined benefit plans. We expect to make
contributions of approximately $16 million to our international defined benefit plans in 2013.
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
46
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, 2012, allowance for bad debts totaled $92 million, or 1.6% of
notes and accounts receivable before the allowance. At December 31, 2011, allowance for bad debts totaled $137 million, or
2.7% 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, 2012 would have resulted in a $58 million
adjustment to 2012 total operating costs and expenses. See Note 3 to the consolidated financial statements for further
information.
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. Currently, long-term contracts accounted for under the percentage-of-completion method
of accounting do not comprise a significant portion of our business. See Note 1 to the consolidated financial statements for
further information.
OFF BALANCE SHEET ARRANGEMENTS
At December 31, 2012, 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 – Significant uses of cash – Future uses of cash.”
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 exchange contracts 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 exchange contracts
and interest rate swaps are global commercial and investment banks.
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.
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 derivative instruments. We attempt to selectively manage significant exposures to potential foreign currency
exchange losses based on current market conditions, future operating activities, and the associated cost in relation to the
perceived risk of loss. The purpose of our foreign currency risk management activities is to minimize the risk that our cash
flows from the sale and purchase of services and products in foreign currencies will be adversely affected by changes in
exchange rates.
We use forward exchange contracts to manage our exposure to fluctuations in the currencies of the countries in which
we do the majority of our international business. These forward exchange contracts are not treated as hedges for accounting
purposes, generally have an expiration date of one year or less, and are not exchange traded. While forward exchange contracts
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 contracts may limit our ability to benefit from favorable fluctuations in foreign currency
exchange rates.
47
Forward exchange contracts 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 forward exchange contracts were $324 million at December 31, 2012 and $268 million
at December 31, 2011. The notional amounts of our forward exchange contracts 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.
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, 2012 would result in a $75 million, pre-tax, loss for our net monetary
assets denominated in currencies other than United States dollars.
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 investments in fixed income securities and short-term borrowings do not give rise to significant
interest rate risk due to their short-term nature. We had fixed rate long-term debt totaling $4.8 billion at both December 31,
2012 and December 31, 2011, with none maturing before May 2017. We also had $128 million of long-term investments in
fixed income securities at December 31, 2012 with maturities that extend through December 2015.
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 two of our debt instruments with
a total notional amount of $1.0 billion at a weighted-average, LIBOR-based, floating rate of 3.3% as of December 31, 2012. 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, 2012 and December 31, 2011. 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, 2012, we had fixed rate debt aggregating $3.8 billion and variable rate debt
aggregating $1.0 billion, after taking into account the effects of the interest rate swaps. The fair value of our interest rate swaps
was not material as of December 31, 2012 or December 31, 2011.
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, 2012.
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, although a significant amount of our trade receivables are generated in the United States.
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.
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, Part I, Item 1(a), “Risk
Factors,” and Item 3, “Legal Proceedings – Environmental.”
48
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
the results of operations may vary materially.
We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether
factors change as a result of new information, future events, or for any other reason. You should review any additional
disclosures we make in our press releases and Forms 10-K, 10-Q, and 8-K filed with or furnished to the SEC. We also suggest
that you listen to our quarterly earnings release conference calls with financial analysts.
49
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, 2012 based upon criteria set forth in the Internal Control - Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of December 31, 2012,
our internal control over financial reporting is effective.
The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2012 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
50
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,
2012 and 2011, and the related consolidated statements of operations, shareholders' equity, comprehensive income, and cash flows
for each of the years in the
period ended December 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash
flows for each of the years in the
period ended December 31, 2012, 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, 2012, based on criteria established in Internal
Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
and our report dated February 11, 2013 expressed an unqualified opinion on the effectiveness of Halliburton Company's internal
control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 11, 2013
51
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, 2012, based on criteria
established in Internal Control - Integrated Framework 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, 2012, based on criteria established in Internal Control - Integrated Framework 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, 2012 and 2011, 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, 2012, and our report dated February 11, 2013 expressed an unqualified opinion on those
consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 11, 2013
52
HALLIBURTON COMPANY
Consolidated Statements of Operations
Millions of dollars and shares except per share data
Year Ended December 31
2012
2011
2010
Revenue:
Services
Product sales
Total revenue
Operating costs and expenses:
Cost of services
Cost of sales
General and administrative
Total operating costs and expenses
Operating income
Interest expense, net of interest income of $7, $5, and $11
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 (provision) benefit
of $82, $(18), and $75
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.
$
22,196 $
19,692 $
6,307
28,503
18,747
5,322
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
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
$
$
$
$
$
$
$
$
13,779
4,194
17,973
11,227
3,508
229
14,964
3,009
(297)
(57)
2,655
(853)
1,802
40
1,842
(7)
1,835
1,795
40
1,835
1.98
0.04
2.02
1.97
0.04
2.01
908
911
53
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 loss, net of income taxes
Comprehensive income
Comprehensive loss attributable to noncontrolling interest
Comprehensive income attributable to company shareholders
See notes to consolidated financial statements.
Year Ended December 31
2012
2011
2010
$
2,645 $
2,844 $
1,842
(33)
(3)
(36)
2,609 $
(10)
2,599 $
(34)
—
(34)
2,810 $
(4)
2,806 $
(27)
(1)
(28)
1,814
(6)
1,808
$
$
54
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 $92 and $137)
Inventories
Current deferred income taxes
Other current assets
Total current assets
Property, plant, and equipment, net of accumulated depreciation of $8,056 and $7,096
Goodwill
Other assets
Total assets
Current liabilities:
Accounts payable
Liabilities and Shareholders’ Equity
$
$
Accrued employee compensation and benefits
Deferred revenue
Other current liabilities
Total current liabilities
Long-term debt
Employee compensation and benefits
Other liabilities
Total liabilities
Shareholders’ equity:
Common shares, par value $2.50 per share – authorized 2,000 shares,
issued 1,073 and 1,073 shares
Paid-in capital in excess of par value
Accumulated other comprehensive loss
Retained earnings
Treasury stock, at cost – 144 and 152 shares
Company shareholders’ equity
Noncontrolling interest in consolidated subsidiaries
Total shareholders’ equity
Total liabilities and shareholders’ equity
See notes to consolidated financial statements.
55
December 31
2012
2011
$
2,484 $
5,787
3,186
351
1,278
13,086
10,257
2,135
1,932
27,410 $
2,698
5,084
2,570
321
904
11,577
8,492
1,776
1,832
23,677
2,041 $
1,826
930
307
1,474
4,752
4,820
607
1,441
862
309
1,124
4,121
4,820
534
986
11,620
10,461
2,682
486
(309)
17,182
(4,276)
15,765
25
15,790
$
27,410 $
2,683
455
(273)
14,880
(4,547)
13,198
18
13,216
23,677
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
(Benefit) provision for deferred income taxes, continuing operations
(Income) loss from discontinued operations, net
Other changes:
Receivables
Inventories
Accounts payable
Other
Total cash flows from operating activities
Cash flows from investing activities:
Capital expenditures
Purchases of investment securities
Sales of property, plant, and equipment
Sales of investment securities
Acquisitions of business assets, net of cash acquired
Other investing activities
Total cash flows from investing activities
Cash flows from financing activities:
Dividends to shareholders
Proceeds from exercises of stock options
Payments to reacquire common stock
Proceeds from long-term borrowings, net of offering costs
Payments on long-term borrowings
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.
56
Year Ended December 31
2012
2011
2010
$
2,645 $
2,844 $
1,842
1,628
1,359
1,119
300
165
(58)
(682)
(611)
200
67
3,654
(3,566)
(506)
395
258
(214)
(55)
(3,688)
(333)
107
(33)
—
—
87
(172)
(8)
(214)
2,698
—
(30)
166
(1,218)
(564)
649
478
3,684
(2,953)
(501)
160
1,001
(880)
(17)
(3,190)
(330)
160
(43)
978
—
68
833
(27)
1,300
1,398
—
124
(40)
(902)
(331)
330
70
2,212
(2,069)
(1,282)
227
1,925
(523)
(33)
(1,755)
(327)
102
(141)
—
(790)
42
(1,114)
(27)
(684)
2,082
$
2,484 $
2,698 $
1,398
$
$
294 $
261 $
1,098 $
1,285 $
310
804
HALLIBURTON COMPANY
Consolidated Statements of Shareholders' Equity
Company Shareholders’ Equity
Millions of dollars
Balance at December 31, 2009
Cash dividends paid ($0.36 per share)
Stock plans
Common shares repurchased
Tax loss from exercise of options and restricted stock
Other
Total dividends and other transactions with shareholders
Treasury shares issued for acquisition
Comprehensive income (loss):
Net income
Other comprehensive income (loss):
Defined benefit and other postretirement plans
adjustments, net
Other
Total comprehensive income
Balance at December 31, 2010
Cash dividends paid ($0.36 per share)
Stock plans
Tax loss from exercise of options and restricted stock
Total dividends and other transactions with shareholders
Comprehensive income (loss):
Net income
Other comprehensive income (loss):
Defined benefit and other postretirement plans
adjustments, net
Total comprehensive income
Balance at December 31, 2011
Cash dividends paid ($0.36 per share)
Stock plans
Other
Total dividends and other transactions with shareholders
Comprehensive income (loss):
Net income
Other comprehensive income (loss):
Defined benefit and other postretirement plans
adjustments, net
Other
Total comprehensive income
Balance at December 31, 2012
See notes to consolidated financial statements.
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
$ 2,669 $
411 $ (5,002) $10,863 $
(213) $
29 $ 8,757
—
5
—
—
—
5
—
—
—
—
—
—
(37)
—
(18)
—
(55)
(17)
—
—
—
—
—
225
(114)
—
—
111
120
(327)
—
—
—
—
(327)
—
— 1,835
—
—
—
—
— 1,835
—
—
—
—
—
—
—
—
(26)
(1)
(27)
—
—
—
—
(21)
(21)
—
(327)
193
(114)
(18)
(21)
(287)
103
7
1,842
(1)
—
6
(27)
(1)
1,814
$ 2,674 $
339 $ (4,771) $12,371 $
(240) $
14 $10,387
—
9
—
9
—
—
—
—
82
34
116
—
224
—
224
(330)
—
—
(330)
—
— 2,839
—
—
—
—
— 2,839
—
—
—
—
—
(33)
(33)
$ 2,683 $
455 $ (4,547) $14,880 $
(273) $
—
(1)
—
(1)
—
—
—
—
—
25
6
31
—
—
—
—
—
271
—
271
(333)
—
—
(333)
— 2,635
—
—
—
—
— 2,635
—
—
—
—
—
(33)
(3)
(36)
—
—
—
—
(330)
315
34
19
5
2,844
(1)
4
(34)
2,810
18 $13,216
—
—
(3)
(3)
(333)
295
3
(35)
10
2,645
—
—
10
(33)
(3)
2,609
$ 2,682 $
486 $ (4,276) $17,182 $
(309) $
25 $15,790
57
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 2012, we adopted the provisions of new accounting standards. 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 $460 million in
2012, $401 million in 2011, and $366 million in 2010.
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.
58
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 also 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.
The changes in the carrying amount of goodwill are detailed below by reportable segment.
Millions of dollars
Balance at December 31, 2010:
Current year acquisitions
Purchase price adjustments for previous acquisitions
Balance at December 31, 2011:
Current year acquisitions
Purchase price adjustments for previous acquisitions
Balance at December 31, 2012:
Completion
and Production
Drilling and
Evaluation
Total
$
$
$
767 $
411
37
548 $
13
—
1,215 $
561 $
100
196
62
1
1,511 $
624 $
1,315
424
37
1,776
162
197
2,135
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.
Beginning in 2011, we elected to perform a qualitative assessment for our annual goodwill impairment test. If the qualitative
assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or if we
elect to not perform a qualitative assessment, then we would be required to perform a quantitative impairment test for goodwill.
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. 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. Our goodwill impairment assessment for 2010 indicated the fair value of each of our reporting
units exceeded its carrying amount by a significant margin. In addition, there were no triggering events that occurred in 2012,
2011, or 2010 requiring us to perform additional impairment reviews. As such, there were no impairments of goodwill recorded
in the three-year period ended December 31, 2012.
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.
59
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.
60
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 Halliburton Production Enhancement, Cementing, Completion
Tools, Boots & Coots, and Multi-Chem. Effective January 1, 2013, Halliburton Artificial Lift will be included as a product
service line within this segment.
Halliburton 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.
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.
Drilling and Evaluation provides field and reservoir modeling, drilling, evaluation, and wellbore placement solutions
that enable customers to model, measure, and optimize their well construction activities. The segment consists of Halliburton
Drill Bits and Services, Wireline and Perforating, Testing and Subsea, Baroid, Sperry Drilling, Landmark Software and
Services, and Halliburton Consulting and Project Management.
Halliburton 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.
Halliburton 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 and losses not
attributable to a particular business segment, such as the $300 million loss contingency related to the Macondo well incident
recorded in “Corporate and other” during the first quarter of 2012.
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.
61
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
2011
2010
2012
$
$
17,380 $
15,143 $
11,123
9,686
9,997
7,976
28,503 $
24,829 $
17,973
$
3,144 $
3,733 $
1,675
1,403
4,819
(660)
4,159 $
(298) $
(39)
3,822 $
5,136
(399)
4,737 $
(263) $
(25)
4,449 $
2,177 $
1,669 $
1,318
71
1,231
53
2,032
1,213
3,245
(236)
3,009
(297)
(57)
2,655
1,010
1,058
1
3,566 $
2,953 $
2,069
843 $
680 $
783
2
676
3
537
578
4
$
1,628 $
1,359 $
1,119
December 31
2012
2011
$
$
13,313 $
9,290
1,376
3,431
27,410 $
10,953
8,212
1,249
3,263
23,677
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.
62
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
Long-lived assets:
United States
Other countries
Total
Year Ended December 31
2011
2010
2012
$
$
15,057 $
13,446
28,503 $
13,548 $
11,281
24,829 $
8,209
9,764
17,973
December 31
2012
2011
$
$
7,219 $
6,633
13,852 $
6,602
5,189
11,791
Note 3. Receivables
Our trade receivables are generally not collateralized. At December 31, 2012 and December 31, 2011, 36% and 45% 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.
The following table presents a rollforward of our allowance for bad debts for 2010, 2011, and 2012.
Millions of dollars
Year ended December 31, 2010
Year ended December 31, 2011
Year ended December 31, 2012
Balance at
Beginning of
Period
Charged to
Costs and
Expenses
$
90 $
91
137
5 $
53
(40)
Write-Offs
Balance at
End of
Period
(4) $
(7)
(5)
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, which totaled $139 million at December 31, 2012 and $160 million at December 31, 2011. If the average cost
method had been used, total inventories would have been $41 million higher than reported at December 31, 2012 and $36
million higher than reported at December 31, 2011. 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
2012
2011
$
$
2,264 $
793
129
3,186 $
1,801
673
96
2,570
Finished products and parts are reported net of obsolescence reserves of $114 million at December 31, 2012 and $108
million at December 31, 2011.
63
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
2012
2011
$
145 $
1,861
16,307
18,313
8,056
10,257 $
$
123
1,609
13,856
15,588
7,096
8,492
Classes of assets, excluding oil and natural gas investments, are depreciated over the following useful lives:
Buildings and Property
Improvements
2012
14%
46%
14%
26%
2011
13%
47%
13%
27%
Machinery, Equipment,
and Other
2012
20%
74%
6%
2011
19%
75%
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 at both December 31, 2012 and 2011:
Millions of dollars
6.15% senior notes due September 2019
7.45% senior notes due September 2039
6.7% senior notes due September 2038
3.25% senior notes due November 2021
4.5% senior notes due November 2041
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
$
$
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.
Revolving credit facilities
We have an unsecured $2.0 billion five-year revolving credit facility expiring in 2016. 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, 2012.
Debt maturities
$45 million of our long-term debt is due in 2017. The remainder is due in 2018 and thereafter.
64
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 and a Tax Sharing Agreement. We recorded a liability reflecting the estimated fair value of the
indemnities provided to KBR as described below. 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 liabilities are primarily included in “Other liabilities”
in our consolidated balance sheets and totaled $219 million as of December 31, 2012 and $201 million as of December 31,
2011.
Barracuda-Caratinga arbitration
We agreed to provide indemnification in favor of KBR under the Master Separation Agreement for liabilities KBR
may incur after the effective date of the Master Separation Agreement as a result of certain allegedly defective subsea flowline
bolts installed in connection with the Barracuda-Caratinga project. Prior to that, at the inception of the project, we had provided
a guarantee to Barracuda & Caratinga Leasing Company BV (BCLC), a subsidiary of our customer, Petrobras, of KBR's
obligations with respect to the project.
During the third quarter of 2011, an arbitration panel issued an award against KBR in the amount of approximately
$201 million, plus post-judgment interest. At that time, we adjusted our liability related to the indemnification under the Master
Separation Agreement to reflect the award. In December 2012, BCLC sent us a demand for payment of the arbitration award
under the terms of our guarantee. In January 2013, the matter was resolved by our payment of $219 million to BCLC under the
guarantee. We recorded an $80 million tax benefit in 2012 related to the satisfaction of this obligation under the guarantee. See
Note 8 for further discussion of the Barracuda-Caratinga matter.
Tax sharing agreement
The Tax Sharing Agreement provides for the calculation and allocation of United States and certain other jurisdiction
tax liabilities between us and KBR for the periods 2001 through the date of separation. The Tax Sharing Agreement is complex,
and finalization of amounts owed between KBR and us under the Tax Sharing Agreement 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 as required by the Tax Sharing Agreement to KBR requesting the
appointment of an arbitrator in accordance with the terms of the Tax Sharing Agreement. This request asked the arbitrator to
find that KBR owes us $256 million pursuant to the Tax Sharing Agreement. KBR denied that it owes us any amount and
asserted instead that we owe KBR certain amounts under the Tax Sharing Agreement. KBR also asserted that they believe the
Master Separation Agreement controls this matter and demanded arbitration under that agreement. On July 10, 2012, we filed
suit in the District Court of Harris County, Texas, seeking to compel KBR to arbitrate this dispute in accordance with the
provisions of the Tax Sharing Agreement, rather than the Master Separation Agreement. KBR filed a cross-motion seeking to
compel arbitration under the Master Separation Agreement. In September 2012, the court denied our motion and granted KBR's
motion to compel arbitration under the Master Separation Agreement. We have filed a notice of appeal, which is pending. No
anticipated recovery amounts or liabilities related to this matter have been recognized in the consolidated financial statements.
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). The flow of hydrocarbons from the well ceased on July
15, 2010, and the well was permanently capped on September 19, 2010. Numerous attempts at estimating the volume of oil
spilled have been made by various groups, and on August 2, 2010 the federal government published an estimate that
approximately 4.9 million barrels of oil were discharged from the well. There were eleven fatalities and a number of injuries as
a result of the Macondo well incident.
65
We are currently unable to fully estimate the impact the Macondo well incident will have on us. The beginning of the
multi-district litigation (MDL) trial referred to below has been set for February 25, 2013. 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, whether the MDL will proceed to trial, the results of any such 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. At the request of the court, in late February 2012 we
participated in a series of discussions with the Magistrate Judge in the MDL relating to whether the MDL could be settled.
Although these discussions did not result in a settlement, we recorded a $300 million liability during the first quarter of 2012
for an estimated loss contingency relating to the MDL. This loss contingency, which is included in “Other liabilities” in our
consolidated balance sheet as of December 31, 2012 and in “Cost of services” on the consolidated statement of operations for
the year ended December 31, 2012, represents a loss contingency that is probable and for which a reasonable estimate of a loss
or range of 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, we cannot conclude that a probable loss
associated with the MDL is zero. 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
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. The United States Coast Guard, a component of the United States Department of
Homeland Security, and the Bureau of Ocean Energy Management, Regulation and Enforcement (formerly known as the
Minerals Management Service and which was replaced effective October 1, 2011 by two new, independent bureaus – the
Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Ocean Energy Management), a bureau of the
United States Department of the Interior, shared jurisdiction over the investigation into the Macondo well incident and formed a
joint investigation team that reviewed information and held hearings regarding the incident (Marine Board Investigation). We
were named as one of the 16 parties-in-interest in the Marine Board Investigation. The Marine Board Investigation, as well as
investigations of the incident that were conducted by The National Commission on the BP Deepwater Horizon Oil Spill and
Offshore Drilling (National Commission) and the National Academy of Sciences, have been completed, 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, 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 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 and
ordered us and the BSEE to file notice within 15 days after the conclusion of the MDL and, within 60 days after the MDL court
issues a final decision, 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.
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 the joint investigation
team for the Marine Board Investigation 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.
66
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.
At this time we cannot predict the impact of the investigations or reports referred to above, or the conclusions 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, whether federal or state and
whether criminal or civil.
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 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), The Migratory Bird Treaty Act of 1918 (MBTA), and the
Endangered Species Act of 1973 (ESA). As part of its criminal investigation, the DOJ is examining certain aspects of our
conduct after the incident, including with respect to record-keeping, record retention, post-incident testing and modeling and the
retention thereof, securities filings, and public statements by us or our employees, to evaluate whether there has been any
violation of federal law.
The CWA provides authority for civil and criminal 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. Criminal
sanctions under the CWA can be assessed for negligent discharges (up to $50,000 per day per violation), for knowing
discharges (up to $100,000 per day per violation), and for knowing endangerment (up to $2 million per violation), and federal
agencies could be precluded from contracting with a company that is criminally sanctioned 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 MBTA and the ESA provide penalties for injury and death to wildlife and bird species. The MBTA provides that
violators are strictly liable and such violations are misdemeanor crimes subject to fines of up to $15,000 per bird killed and
imprisonment of up to six months. The ESA provides for civil penalties for knowing violations that can range up to $25,000 per
violation and, in the case of criminal penalties, up to $50,000 per violation.
In addition, federal law provides for a variety of fines and penalties, the most significant of which is the Alternative
Fines Act. In lieu of the express amount of the criminal fines that may be imposed under some of the statutes described above,
the Alternative Fines Act provides for a fine in the amount of twice the gross economic loss suffered by third parties, which
amount, although difficult to estimate, is significant.
67
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 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.
We have not been 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 are not included in the DOJ’s civil complaint, there
can be no assurance that the DOJ or other federal or state governmental authorities will not bring an action, whether civil or
criminal, against us under the CWA, the OPA, and/or other statutes or regulations. In connection with the DOJ’s filing of the
civil action, it announced that its criminal and civil investigations are continuing and that it will employ efforts to hold
accountable those who are responsible for the incident.
A federal grand jury has been convened in Louisiana to investigate potential criminal conduct in connection with the
Macondo well incident. We are cooperating fully with the DOJ’s criminal investigation. As of February 11, 2013, the DOJ has
not commenced any criminal proceedings against us. We cannot predict the status or outcome of the DOJ’s criminal
investigation or estimate the potential impact the investigation may have on us or our liability assessment, all of which may
change as the investigation progresses. We have had and expect to continue to have discussions with the DOJ regarding the
Macondo well incident and associated pre-incident and post-incident conduct.
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. Transocean's civil and criminal settlements are subject to
court approval, and its civil settlement is also subject to public notice and comment.
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 400 complaints,
most of which are alleged class actions, involving pollution damage claims and at least seven 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. Plaintiffs originally filed the lawsuits described above in federal and state courts throughout the United States. Except
for certain 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. 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 MBTA, the ESA, the OCSLA, the Longshoremen and Harbor
Workers Compensation Act, general maritime law, state common law, and various state environmental and products liability
statutes.
68
Furthermore, the pollution complaints include suits brought against us by governmental entities, including the State of
Alabama, the State of Louisiana, Plaquemines Parish, the City of Greenville, and three Mexican states. Complaints brought
against us by at least seven other parishes in Louisiana were dismissed with prejudice, and the dismissal is being appealed by
those parishes. 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.
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 will be 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, we believe the judge will determine the liability, limitation, exoneration, and fault allocation with regard
to all of the defendants in a trial, which is scheduled to occur in at least two phases beginning on February 25, 2013. The first
phase of this portion of the trial is scheduled to cover 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. The MDL court has projected September 2013 for the
beginning of the second phase of this portion of the trial, which is scheduled to cover actions relating to attempts to control the
flow of hydrocarbons from the well and the quantification of hydrocarbons discharged from the well. Subsequent proceedings
would be held to the extent triable issues remain unsolved by the first two phases of the trial, settlements, motion practice, or
stipulation. While the DOJ will participate in the first two phases of the trial with regard to BP's conduct and the amount of
hydrocarbons discharged from the well, it is anticipated that the DOJ's civil action for the CWA and OPA violations, fines, and
penalties will be addressed by the court in a subsequent proceeding. We do not believe that a single apportionment 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.
Damages for the cases tried in the MDL proceeding, including punitive damages, are expected to be tried following the
two 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. Document discovery and depositions among the
parties to the MDL are ongoing.
In April and May 2011, certain defendants in the proceedings described above filed numerous cross claims and third
party claims against certain other defendants. BP Exploration and BP America Production Company filed claims against us
seeking subrogation, contribution, including with respect to liabilities under the OPA, and direct damages, and alleging
negligence, gross negligence, fraudulent conduct, and fraudulent concealment. Transocean filed claims against us seeking
indemnification, and subrogation and contribution, including with respect to liabilities under the OPA and for the total loss of
the Deepwater Horizon, and alleging comparative fault and breach of warranty of workmanlike performance. Anadarko filed
claims against us seeking tort indemnity and contribution, and alleging negligence, gross negligence and willful misconduct,
and MOEX Offshore 2007 LLC (MOEX), who had an approximate 10% interest in the Macondo well at the time of the
incident, filed a claim against us alleging negligence. Cameron International Corporation (Cameron) (the manufacturer and
designer of the blowout preventer), M-I Swaco (provider of drilling fluids and services, among other things), Weatherford U.S.
L.P. and Weatherford International, Inc. (together, Weatherford) (providers of casing components, including float equipment
and centralizers, and services), and Dril-Quip, Inc. (Dril-Quip) (provider of wellhead systems), each filed claims against us
seeking indemnification and contribution, including with respect to liabilities under the OPA in the case of Cameron, and
alleging negligence. Additional civil lawsuits may be filed against us. In addition to the claims against us, generally the
defendants in the proceedings described above filed claims, including for liabilities under the OPA and other claims similar to
those described above, against the other defendants described above. BP has since announced that it has settled those claims
between it and each of MOEX, Weatherford, Anadarko, and Cameron. Also, BP and M-I Swaco have dismissed all claims
between them.
69
In April 2011, we filed claims against BP Exploration, BP p.l.c. and BP America Production Company (BP
Defendants), M-I Swaco, Cameron, Anadarko, MOEX, Weatherford, Dril-Quip, and numerous entities involved in the post-
blowout remediation and response efforts, in each case seeking contribution and indemnification and alleging negligence. Our
claims also alleged gross negligence and willful misconduct on the part of the BP Defendants, Anadarko, and Weatherford. We
also filed claims against M-I Swaco and Weatherford for contractual indemnification, and against Cameron, Weatherford and
Dril-Quip for strict products liability, although the court has since issued orders dismissing all claims asserted against Dril-Quip
and Weatherford in the MDL and we have dismissed our contractual indemnification claim against M-I Swaco. We filed our
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 dismissed all claims brought under state law
causes of action; (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.
In September 2011, we filed claims in Harris County, Texas against the BP Defendants seeking damages, including
lost profits and exemplary damages, and alleging negligence, grossly negligent misrepresentation, defamation, common law
libel, slander, and business disparagement. Our claims allege that the BP Defendants knew or should have known about an
additional hydrocarbon zone in the well that the BP Defendants failed to disclose to us prior to our designing the cement
program for the Macondo well. The location of the hydrocarbon zones is critical information required prior to performing
cementing services and is necessary to achieve desired cement placement. We believe that had the BP Defendants disclosed the
hydrocarbon zone to us, we would not have proceeded with the cement program unless it was redesigned, which likely would
have required a redesign of the production casing. In addition, we believe that the BP Defendants withheld this information
from the report of BP's internal investigation team and from the various investigations discussed above. In connection with the
foregoing, we also moved to amend our claims against the BP Defendants in the MDL proceeding to include fraud. The BP
Defendants have denied all of the allegations relating to the additional hydrocarbon zone and filed a motion to prevent us from
adding our fraud claim in the MDL. In October 2011, our motion to add the fraud claim against the BP Defendants in the MDL
proceeding was denied. The court’s ruling does not, however, prevent us from using the underlying evidence in our pending
claims against the BP Defendants.
In December 2011, BP filed a motion for sanctions against us alleging, among other things, that we destroyed evidence
relating to post-incident testing of the foam cement slurry on the Deepwater Horizon and requesting adverse findings against us.
The magistrate judge in the MDL proceeding denied BP’s motion. BP appealed that ruling, and Judge Barbier affirmed the
magistrate judge’s decision.
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. BP has estimated that the cost of the settlements would be
approximately $8.5 billion, including payments to claimants who opt out of the settlements, administration costs, and plaintiffs’
attorneys’ fees and expenses, and has stated that it is possible the actual cost could be higher. 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. In April and May, 2012, BP and the PSC filed two settlement
agreements and amendments with the MDL court, one agreement addressing economic claims and one agreement addressing
medical claims, as well as numerous supporting documents and motions requesting that the court approve, among other things,
the certification of the classes for both settlements and a schedule for holding a fairness hearing and approving the settlements.
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. We are unable to predict at this time the effect that the settlements may have on
claims against us.
70
In October 2012, the MDL court issued an order dismissing three types of plaintiff claims: (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. 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.
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.
Macondo derivative case. In February 2011, a shareholder who had previously made a demand on our Board of
Directors with respect to another derivative lawsuit filed a shareholder derivative lawsuit relating to the Macondo well incident.
In 2012, we settled those lawsuits and the cases were dismissed. See “Shareholder derivative cases” below.
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. 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.
In responding to similar motions for summary judgment between Transocean and BP, the court also held that public
policy would not bar Transocean’s claim for indemnification of compensatory damages, even if Transocean was found to be
grossly negligent. The court also held, among other things, that Transocean’s contractual right to indemnity does not extend to
punitive damages or civil penalties under the CWA.
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.
71
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, 2012, we have incurred legal
fees and related expenses of approximately $175 million, of which $158 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.
Barracuda-Caratinga arbitration
We agreed to provide indemnification in favor of our former subsidiary, KBR, under the Master Separation Agreement
for liabilities KBR may incur after November 20, 2006 as a result of certain allegedly defective subsea flowline bolts installed
in connection with the Barracuda-Caratinga project. Prior to that, at the inception of the project, we provided a guarantee to
Barracuda & Caratinga Leasing Company BV (BCLC), a subsidiary of our customer, Petrobras, of KBR's obligations with
respect to the project.
In March 2006, BCLC commenced arbitration against KBR claiming $220 million plus interest for the cost of
monitoring and replacing the allegedly defective bolts and all related costs and expenses of the arbitration, including the cost of
attorneys' fees. During the third quarter of 2011, an arbitration panel issued an award against KBR in the amount of
approximately $201 million, plus post-judgment interest. BCLC filed a motion to confirm, and KBR filed a motion to vacate,
the arbitration award with the United States District Court for the Southern District of New York. In December 2012, BCLC
sent us a demand for payment of the arbitration award under the terms of our guarantee. In January 2013, the matter was
resolved by our payment of $219 million to BCLC under the guarantee. BCLC has agreed that our obligations under the
guarantee have been satisfied. See Note 7 for further discussion of the Barracuda-Caratinga matter.
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.
72
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 and the case is stayed at the district court pending this
appeal. The Fifth Circuit is set to hear oral argument in the appeal in March 2013. In spite of its age, the case is at an early
stage, and we cannot predict the outcome or consequences thereof. As of December 31, 2012, we had not accrued any amounts
related to this matter because we do not believe that a loss is probable. Further, an estimate of possible loss or range of loss
related to this matter cannot be made. We intend to vigorously defend this case.
Shareholder derivative cases
In May 2009, two shareholder derivative lawsuits involving us and KBR were filed in Harris County, Texas, naming as
defendants various current and retired Halliburton directors and officers and current KBR directors. These cases allege that the
individual Halliburton defendants violated their fiduciary duties of good faith and loyalty, to our detriment and the detriment of
our shareholders, by failing to properly exercise oversight responsibilities and establish adequate internal controls. The District
Court consolidated the two cases, and the plaintiffs filed a consolidated petition against only current and former Halliburton
directors and officers containing various allegations of wrongdoing including violations of the United States Foreign Corrupt
Practices Act (FCPA), claimed KBR offenses while acting as a government contractor in Iraq, claimed KBR offenses and fraud
under United States government contracts, Halliburton activity in Iran, and illegal kickbacks. Subsequently, a shareholder made
a demand that the Board take remedial action respecting the FCPA claims in the pending lawsuit. Our Board of Directors
designated a special committee of certain independent and disinterested directors to oversee the investigation of the allegations
made in the lawsuits and shareholder demand. Upon receipt of the special committee’s findings and recommendations, the
independent and disinterested members of the Board determined that the shareholder claims were without merit and not
otherwise in our best interest to pursue. The Board directed our counsel to report its determinations to the plaintiffs and
demanding shareholder.
In 2012, we agreed to settle the consolidated lawsuit, and the court approved the settlement and dismissed the case.
Pursuant to the settlement, we paid the plaintiffs' legal fees which were not material to our consolidated financial statements,
and we have implemented certain changes to our corporate governance policies.
In February 2011, the same shareholder who had made the demand on our Board of Directors in connection with one
of the derivative lawsuits discussed above filed a shareholder derivative lawsuit in Harris County, Texas naming us as a nominal
defendant and certain of our directors and officers as defendants. This case alleges that these defendants, among other things,
breached fiduciary duties of good faith and loyalty by failing to properly exercise oversight responsibilities and establish
adequate internal controls, including controls and procedures related to cement testing and the communication of test results, as
they relate to the Macondo well incident. Our Board of Directors designated a special committee of certain independent and
disinterested directors to oversee the investigation of the allegations made in the lawsuit and shareholder demand. Upon receipt
of the special committee’s findings and recommendations, the independent and disinterested members of the Board determined
that the shareholder claims were without merit and not otherwise in our best interest to pursue. The Board directed our counsel
to report its determinations to the plaintiffs and demanding shareholder.
In 2012, we agreed to settle this lawsuit, and the court approved the settlement and dismissed the case. Pursuant to the
settlement, we paid the plaintiffs' legal fees which were not material to our consolidated financial statements, and we have
implemented certain changes to our corporate governance and health, safety, and environmental policies.
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.
Since the third quarter of 2011, we have been participating in meetings with the DOJ and the SEC to brief them on the
status of our investigation and have been producing documents to them both voluntarily and as a result of SEC subpoenas to the
company and certain of our current and former officers and employees.
73
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.
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 the investigations. 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 OPA.
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 and the Duncan, Oklahoma matter described below, 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
$72 million as of December 31, 2012 and $81 million as of December 31, 2011. 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, the Company 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. We are currently negotiating with the PADEP to resolve this matter in an amicable
manner. We expect the PADEP to assess a penalty in excess of $100,000 and have therefore accrued for an immaterial amount.
Between approximately 1965 and 1991, one or more former Halliburton units performed work (as a contractor or
subcontractor) for the U.S. Department of Defense cleaning solid fuel from missile motor casings at a semi-rural facility on the
north side of Duncan, Oklahoma. In addition, from approximately November 1983 through December 1985, a discrete portion
of the site was used to conduct a recycling project on stainless steel nuclear fuel rod racks from Omaha Public Power District’s
Fort Calhoun Station. We closed the site in coordination with the Oklahoma Department of Environmental Quality (DEQ) in
the mid-1990s, but continued to monitor the groundwater at the DEQ’s request. A principal component of the missile fuel was
ammonium perchlorate, a salt that is highly soluble in water, which has been discovered in the soil and groundwater on our site
and in certain residential water wells near our property. In August 2011, we entered into the DEQ’s Voluntary Cleanup Program
and executed a voluntary Memorandum of Agreement and Consent Order for Site Characterization and Risk Based
Remediation with the DEQ relating to the remediation of this site.
Commencing in October 2011, a number of lawsuits were filed against us, including a putative class action case in
federal court in the Western District of Oklahoma and other lawsuits filed in Oklahoma state courts. The lawsuits generally
allege, among other things, that operations at our Duncan facility caused releases of pollutants, including ammonium
perchlorate and, in the case of the federal lawsuit, nuclear or radioactive waste, into the groundwater, and that we knew about
those releases and did not take corrective actions to address them. It is also alleged that the plaintiffs have suffered from certain
health conditions, including hypothyroidism, a condition that has been associated with exposure to perchlorate at sufficiently
high doses over time. These cases seek, among other things, damages, including punitive damages, and the establishment of a
fund for future medical monitoring. The cases allege, among other things, strict liability, trespass, private nuisance, public
nuisance, and negligence and, in the case of the federal lawsuit, violations of the U.S. Resource Conservation and Recovery Act
(RCRA), resulting in personal injuries, property damage, and diminution of property value.
74
The lawsuits generally allege that the cleaning of the missile casings at the Duncan facility contaminated the
surrounding soils and groundwater, including certain water wells used in a number of residential homes, through the migration
of, among other things, ammonium perchlorate. The federal lawsuit also alleges that our processing of radioactive waste from a
nuclear power plant over 25 years ago resulted in the release of “nuclear/radioactive” waste into the environment. In April
2012, the judge in the federal lawsuit dismissed the plaintiffs’ RCRA claim. The other claims brought in that lawsuit remain
pending.
To date, soil and groundwater sampling relating to the allegations discussed above has confirmed that the alleged
nuclear or radioactive material is confined to the soil in a discrete area of the onsite operations and is not presently believed to
be in the groundwater onsite or in any areas offsite. The radiological impacts from this discrete area are not believed to present
any health risk for offsite exposure. With respect to ammonium perchlorate, we have made arrangements to supply affected
residents with bottled drinking water and, if needed, with access to temporary public water supply lines, at no cost to the
residents. We have worked with the City of Duncan and the DEQ to expedite expansion of the city water supply to the relevant
areas at our expense.
The lawsuits described above are at an early stage, and additional lawsuits and proceedings may be brought against us.
We cannot predict their outcome or the consequences thereof. As of December 31, 2012, we had accrued $25 million related to
our initial estimate of response efforts, third-party property damage, and remediation related to the Duncan, Oklahoma matter.
We intend to vigorously defend the lawsuits and do not believe that these lawsuits will have a material adverse effect on our
liquidity, consolidated results of operations, or consolidated financial condition.
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, 2012, those nine
sites accounted for approximately $6 million of our $72 million total environmental reserve. Despite attempts to resolve these
superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount
accrued. With respect to some superfund sites, we have been named a potentially responsible party by a regulatory agency;
however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims
with respect to environmental matters for which we have been named as a potentially responsible party.
Guarantee arrangements
In the normal course of business, we have agreements with financial institutions under which approximately $1.9
billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2012, including $277 million
of surety bonds related to Venezuela. 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 $850 million in 2012, $735
million in 2011, and $591 million in 2010.
Future total rentals on our noncancellable operating leases are $961 million in the aggregate, which includes the
following: $287 million in 2013; $214 million in 2014; $146 million in 2015; $102 million in 2016; $48 million in 2017; and
$164 million thereafter.
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
2011
2010
2012
$
$
(695) $
(328)
(47)
(1,070)
(168)
15
(12)
(165)
(1,235) $
(1,026) $
(334)
(109)
(1,469)
(28)
57
1
30
(1,439) $
(400)
(287)
(42)
(729)
(124)
3
(3)
(124)
(853)
75
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
2012
2011
2010
$
$
2,826 $
4,040 $
1,918
996
409
737
3,822 $
4,449 $
2,655
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
Impact of devaluation of Venezuelan Bolívar Fuerte
Other items, net
Year Ended December 31
2012
2011
2010
35.0%
(2.5)
(2.2)
1.6
(0.6)
(0.5)
—
1.5
35.0%
(0.5)
(2.1)
1.6
(1.5)
(0.4)
—
0.2
35.0%
(1.3)
(1.8)
1.5
(1.2)
(1.3)
0.8
0.4
Total effective tax rate on continuing operations
32.3%
32.3%
32.1%
On January 2, 2013, the American Taxpayer Relief Act of 2012 (Act) was enacted. The Act provides tax relief for
businesses by reinstating certain tax benefits and credits retroactively to January 1, 2012. There are several provisions of the
Act that impact us, most notably the extension of the Research and Development credit. Income tax accounting rules require tax
law changes to be recognized in the period of enactment; as such, the associated tax benefits of the Act will be recognized in
our provision for income taxes in the first quarter of 2013.
We have not provided United States income taxes and foreign withholding taxes on the undistributed earnings of
foreign subsidiaries as of December 31, 2012 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, 2012, the cumulative amount of earnings upon
which United States income taxes have not been provided is approximately $4.4 billion. It is not possible to estimate the
amount of unrecognized deferred tax liability related to these earnings at this time.
76
The primary components of our deferred tax assets and liabilities were as follows:
Millions of dollars
Gross deferred tax assets:
Net operating loss carryforwards
Employee compensation and benefits
Accrued liabilities
Insurance accruals
Software revenue recognition
Inventory
Capitalized research and experimentation
Other
Total gross deferred tax assets
Gross deferred tax liabilities:
Depreciation and amortization
Joint ventures, partnerships, and unconsolidated affiliates
Other
Total gross deferred tax liabilities
Valuation allowances – net operating loss carryforwards
Net deferred income tax asset (liability)
December 31
2012
2011
$
$
396 $
361
274
54
32
30
18
94
1,259
867
42
76
985
327
(53) $
380
345
64
48
44
30
29
110
1,050
648
38
68
754
285
11
At December 31, 2012, we had a total of $1.1 billion of foreign net operating loss carryforwards, of which $219
million will expire from 2013 through 2033. The balance will not expire due to indefinite expiration dates.
The following table presents a rollforward of our unrecognized tax benefits and associated interest and penalties.
Millions of dollars
Balance at January 1, 2010
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, 2010
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
Balance at December 31, 2012
Unrecognized
Tax Benefits
Interest
and Penalties
$
$
$
$
$
$
$
263
(74)
19
(28)
(3)
177
38
5
(12)
(3)
205 (a)
16
14
(3)
(4)
228 (a)(b) $
29
7
2
(5)
(1)
32
41
1
(3)
(2)
69
(1)
1
—
(1)
68
(a) Includes $59 million as of December 31, 2012 and $67 million as of December 31, 2011 in amounts to be settled in
accordance with our Tax Sharing Agreement with KBR and foreign unrecognized tax benefits that would give rise to a
United States tax credit. See Note 7 for further information. The remaining balance of $169 million as of
December 31, 2012 and $138 million as of December 31, 2011, 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 $43 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 tax years 2010 and 2011 are open for
review but no examination has been initiated.
77
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
2012
2011
2010
1,073
(144)
929
1,073
(152)
921
1,069
(159)
910
Our stock repurchase program has an authorization of $5 billion, of which $1.7 billion remained available at
December 31, 2012. The program does not require a specific number of shares to be purchased and the program may be
affected 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, 2012, we
have repurchased approximately 96 million shares of our common stock for approximately $3.3 billion at an average price per
share of $34.22. There were no stock repurchases under the program in 2012.
Preferred stock
Our preferred stock consists of five million total authorized shares at December 31, 2012, of which none are issued.
Accumulated other comprehensive loss
Accumulated other comprehensive loss consisted of the following:
Millions of dollars
Defined benefit and other postretirement liability adjustments (a)
Cumulative translation adjustment
Other
Total accumulated other comprehensive loss
December 31
2012
2011
2010
$
$
(241) $
(69)
1
(309) $
(208) $
(66)
1
(273) $
(175)
(66)
1
(240)
(a) Included net actuarial losses for our international pension plans of $208 million at December 31, 2012, $184
million at December 31, 2011, and $170 million at December 31, 2010.
Note 11. Stock-based Compensation
The following table summarizes stock-based compensation costs for the years ended December 31, 2012, 2011, and
2010.
Millions of dollars
Stock-based compensation cost
Tax benefit
Stock-based compensation cost, net of tax
Year Ended December 31
2012
2011
2010
$
$
217 $
(67)
150 $
198 $
(61)
137 $
158
(50)
108
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 or stock value equivalent awards outstanding.
78
Under the terms of the Stock Plan, approximately 158 million shares of common stock have been reserved for issuance
to employees and non-employee directors. At December 31, 2012, 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 2012.
Outstanding at January 1, 2012
Granted
Exercised
Forfeited/expired
Outstanding at December 31, 2012
Exercisable at December 31, 2012
Number
of Shares
(in millions)
Weighted
Average
Exercise
Price
per Share
Weighted
Average
Remaining
Contractual
Term (years)
Aggregate
Intrinsic
Value
(in millions)
14.9 $
4.8
(0.8)
(0.8)
18.1 $
10.6 $
31.74
32.20
18.65
36.88
32.23
30.38
6.7 $
5.2 $
92
75
The total intrinsic value of options exercised was $12 million in 2012, $102 million in 2011, and $38 million in 2010.
As of December 31, 2012, there was $65 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 $107 million during 2012, $160 million during 2011, and $102 million
during 2010.
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
2012
5.21
46%
2011
5.20
40%
2010
5.27
40%
0.99 – 1.24% 0.69 – 1.01% 0.99 – 1.71%
0.65 – 1.15% 0.93 – 2.29% 1.20 – 2.78%
Weighted average grant-date fair value per share
$11.99
$15.61
$9.94
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.
79
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, 2012, 145,600 restricted shares and 8,000 restricted stock units had been issued to non-employee
directors under this plan. There were 8,000 restricted stock units, and 7,200 shares and 8,000 shares of restricted stock awarded
under the Directors Plan in 2012, 2011, and 2010. In addition, during 2012, our non-employee directors were awarded 44,720
restricted stock units under the Stock Plan with the same terms and conditions as those described above for the Directors Plan,
which are included in the table below.
The following table represents our Stock Plan and Directors Plan restricted stock awards and restricted stock units
granted, vested, and forfeited during 2012.
Nonvested shares at January 1, 2012
Granted
Vested
Forfeited
Nonvested shares at December 31, 2012
Number of
Shares
(in millions)
Weighted
Average
Grant-Date Fair
Value per Share
14.2 $
5.7
(4.0)
(1.1)
14.8 $
33.45
32.17
32.24
34.77
33.17
The weighted average grant-date fair value of shares granted during 2011 was $43.35 and during 2010 was $29.39.
The total fair value of shares vested during 2012 was $126 million, during 2011 was $165 million, and during 2010 was $100
million. As of December 31, 2012, there was $357 million of unrecognized compensation cost, net of estimated forfeitures,
related to nonvested restricted stock, which is expected to be recognized over a weighted average period of three years.
Employee Stock Purchase Plan
Under the ESPP, eligible employees may have up to 10% of their earnings withheld, subject to some limitations, to be
used to purchase shares of our common stock. For the year ended December 31, 2012, the ESPP contained two six-month
offering periods, commencing on January 1 and July 1. Beginning in 2013, the ESPP will have 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. They may be authorized but unissued common shares or treasury shares. As of December 31, 2012, 29.5 million
shares have been sold through the ESPP.
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:
Offering period July 1 through December 31
2012
2011
2010
Expected term (in years)
Expected volatility
Expected dividend yield
Risk-free interest rate
0.5
49%
1.26%
0.15%
0.5
34%
0.70%
0.10%
Weighted average grant-date fair value per share
$
8.12
$
12.57
$
0.5
43%
1.44%
0.21%
6.72
80
Offering period January 1 through June 30
2012
2011
2010
Expected term (in years)
Expected volatility
Expected dividend yield
Risk-free interest rate
0.5
50%
1.05%
0.06%
0.5
43%
0.88%
0.20%
Weighted average grant-date fair value per share
$
9.82
$
10.99
$
0.5
48%
1.15%
0.19%
8.81
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 employee stock plans.
Excluded from the computation of diluted income per share are options to purchase seven million shares of common
stock that were outstanding in 2012, three million shares of common stock that were outstanding in 2011, and five million
shares of common stock that were outstanding in 2010. 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, 2012, we held $398 million of investments in fixed income securities with maturities that extend
through December 2015 compared to $150 million of short-term fixed income securities held at December 31, 2011. 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, 2012
December 31, 2011
Level 1
Level 2
Total
Level 1
Total
$
$
150
—
— $
248
150 $
248 $
150
248
398
$
$
150 $
—
150 $
150
—
150
(a) These securities are classified as "Other current assets" in our consolidated balance sheets.
(b) Of these securities, $120 million are classified as “Other current assets” and $128 million are classified as “Other
assets” in our consolidated balance sheets. These securities consist primarily of municipal bonds, corporate bonds, and
other debt instruments.
Our Level 1 assets' fair values are based on quoted prices in active markets and our Level 2 assets' 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:
December 31, 2012
December 31, 2011
Millions of dollars
Level 1
Level 2
Total fair
value
Carrying
value
Level 1
Level 2
Total fair
value
Carrying
value
Long-term debt
$
1,112 $
5,272 $
6,384 $
4,820
$
3,555 $
2,603 $
6,158 $
4,820
81
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 exchange contracts 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 exchange contracts and
interest rate swaps was not material as of December 31, 2012. The counterparties to our forward exchange contracts and interest
rate swaps are global commercial and investment banks.
Foreign currency exchange risk
We have operations in many international locations and are involved in transactions denominated in currencies other
than the United States dollar, our functional currency, which exposes us to foreign currency exchange rate risk. Techniques in
managing foreign currency exchange risk include, but are not limited to, foreign currency borrowing and investing and the use
of currency derivative instruments. We attempt to selectively manage significant exposures to potential foreign currency
exchange losses based on current market conditions, future operating activities, and the associated cost in relation to the
perceived risk of loss. The purpose of our foreign currency risk management activities is to minimize the risk that our cash
flows from the sale and purchase of services and products in foreign currencies will be adversely affected by changes in
exchange rates.
We use forward exchange contracts to manage our exposure to fluctuations in the currencies of the countries in which
we do the majority of our international business. These forward exchange contracts are not treated as hedges for accounting
purposes, generally have an expiration date of one year or less, and are not exchange traded. While forward exchange contracts
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 contracts may limit our ability to benefit from favorable fluctuations in foreign currency
exchange rates.
Forward exchange contracts 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 forward exchange contracts were $324 million at December 31, 2012 and $268 million
at December 31, 2011. The notional amounts of our forward exchange contracts 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. Our short-term borrowings do not give rise to significant
interest rate risk due to their short-term nature. We had fixed rate long-term debt totaling $4.8 billion at both December 31,
2012 and December 31, 2011, with none maturing before May 2017.
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 two of our debt instruments with
a total notional amount of $1.0 billion at a weighted-average, LIBOR-based, floating rate of 3.3% as of December 31, 2012. 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, 2012 and December 31, 2011. 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, 2012, we had fixed rate debt aggregating $3.8 billion and variable rate debt
aggregating $1.0 billion, after taking into account the effects of the interest rate swaps. The fair value of our interest rate swaps
was not material as of December 31, 2012 or December 31, 2011.
82
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, although 36% of our gross trade receivables at December 31, 2012 were in the United
States and 9% were in Venezuela. 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.
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 $293 million in 2012, $245 million in 2011, and
$196 million in 2010;
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, 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. At December 31, 2011, the
projected benefit obligation was $928 million and the fair value of plan assets was $705 million, which resulted in an unfunded
obligation of $223 million. The accumulated benefit obligation for our international plans was $961 million at December 31,
2012 and $868 million at December 31, 2011.
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
2012
2011
$
$
$
10 $
266
1,004 $
727
935 $
726
10
213
928
705
784
621
83
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, 2012
Common/collective trust funds (a)
Equity funds
Bond funds
Balanced funds
Corporate bonds
United States equity securities
Non-United States equity securities
Other assets
Fair value of plan assets at December 31, 2011
Level 1
Level 2
Level 3
Total
$
$
$
$
— $
—
—
130
110
—
27
267 $
— $
—
—
—
67
64
15
146 $
204 $
112
13
—
—
107
16
452 $
241 $
110
12
89
—
—
16
468 $
— $
—
—
—
—
—
35
35 $
— $
—
—
—
—
—
91
91 $
204
112
13
130
110
107
78
754
241
110
12
89
67
64
122
705
(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 assets' fair values are based on quoted prices in active markets for identical assets, our Level 2 assets' fair
values are based on significant observable inputs for similar assets, and our Level 3 assets' 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. Government bonds and corporate bonds are valued using quotes from independent pricing vendors based on recent
trading activity and other relevant information, including 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 78% of our international pension plans’ projected benefit
obligation at December 31, 2012, the target asset allocation is 65% equity securities and 35% fixed income securities.
Net periodic benefit cost
Net periodic benefit cost for our international pension plans was $26 million in 2012, $27 million in 2011, and $28
million in 2010.
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
2012
4.8%
5.5%
2011
5.2%
5.4%
84
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
2012
5.2%
6.5%
5.4%
2011
7.1%
5.7%
6.2%
2010
7.9%
5.6%
6.4%
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 $16 million to our international pension plans in 2013.
Benefit payments. Expected benefit payments over the next 10 years are approximately $35 million annually for our
international pension plans.
Note 15. Accounting Standards Recently Adopted
In July 2012, the Financial Accounting Standards Board (FASB) issued an update to existing guidance on the
impairment assessment of indefinite-lived intangibles. This update simplifies the impairment assessment of indefinite-lived
intangibles by allowing companies to consider qualitative factors to determine whether it is more likely than not that the fair
value of an indefinite-lived intangible asset is less than its carrying amount before performing the two step impairment review
process. We have elected to early adopt this update to be effective for the interim reporting period beginning July 1, 2012. The
adoption of this update did not have a material impact on our consolidated financial statements.
On January 1, 2012, we adopted an update issued by the FASB to existing guidance on the presentation of
comprehensive income. This update requires the presentation of the components of net income and other comprehensive
income either in a single continuous statement or in two separate but consecutive statements. The requirement to present
reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the
financial statement has been deferred by the FASB. Net income and other comprehensive income has been presented in two
separate but consecutive statements for the current reporting period and prior comparative period in our consolidated financial
statements.
85
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
2012
2011
2010
2009
2008
$ 28,503
$ 24,829
$ 17,973
$ 14,675
$ 18,279
$
$
$
$
$
$
$
$
$
$
$
$
4,159
(337)
3,822
(1,235)
2,587
58
2,645
(10)
2,635
2,577
58
2,635
2.78
2.85
2.78
2.84
0.36
$
$
$
$
$
$
4,737
(288)
4,449
(1,439)
3,010
(166)
2,844
(5)
2,839
3,005
(166)
2,839
3.27
3.09
3.26
3.08
0.36
$
$
$
$
$
$
3,009
(354)
2,655
(853)
1,802
40
1,842
(7)
1,835
1,795
40
1,835
1.98
2.02
1.97
2.01
0.36
1,994
(312)
1,682
(518)
1,164
(9)
1,155
(10)
1,145
1,154
(9)
1,145
1.28
1.27
1.28
1.27
0.36
$
$
$
$
$
$
4,010
(161)
3,849
(1,211)
2,638
(423)
2,215
9
2,224
2,647
(423)
2,224
3.00
2.52
2.91
2.45
0.36
18.17%
24.06%
19.17%
13.88%
30.24%
$
8,334
$
7,456
$
6,129
$
5,749
$
4,630
23,677
18,297
16,538
14,385
27,410
10,257
4,820
15,790
20,764
926
928
8,492
4,820
13,216
18,097
918
922
$
3,566
$
2,953
$
—
1,628
7,722
978
1,359
6,756
6,842
3,824
10,387
14,241
908
911
2,069
(790)
1,119
5,370
5,759
4,574
8,757
4,782
2,612
7,744
13,331
10,369
900
902
$
1,864
$
1,944
931
4,783
883
909
1,824
(861)
738
5,264
73,000
68,000
58,000
51,000
57,000
86
HALLIBURTON COMPANY
Quarterly Data and Market Price Information
(Unaudited)
Millions of dollars except per share data
First
Second
Third
Fourth
Year
Quarter
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 (1)
High
Low
2011
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 (1)
High
Low
$
6,868 $
7,234 $
7,111 $
7,290 $
28,503
1,023
630
1,201
739
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
954
604
608
(6)
602
0.66
(0.01)
0.65
0.65
—
0.65
0.09
981
672
589
80
669
0.63
0.09
0.72
0.63
0.09
0.72
0.09
4,159
2,645
2,577
58
2,635
2.78
0.07
2.85
2.78
0.06
2.84
0.36
39.19
32.02
35.32
26.28
38.00
27.62
36.00
29.83
39.19
26.28
$
5,282 $
5,935 $
6,548 $
7,064 $
24,829
814
511
512
(1)
511
0.56
—
0.56
0.56
—
0.56
0.09
1,161
741
1,332
685
1,430
907
739
—
739
0.81
—
0.81
0.80
—
0.80
0.09
848
(165)
683
0.92
(0.18)
0.74
0.92
(0.18)
0.74
0.09
906
—
906
0.98
—
0.98
0.98
—
0.98
0.09
4,737
2,844
3,005
(166)
2,839
3.27
(0.18)
3.09
3.26
(0.18)
3.08
0.36
50.47
37.68
51.45
44.47
57.77
30.48
40.43
27.21
57.77
27.21
(1) New York Stock Exchange – composite transactions high and low intraday price.
87
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 2013 Annual Meeting of Stockholders (File No. 1-3492) 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 4 through 5 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
2013 Annual Meeting of Stockholders (File No. 1-3492) 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 2013 Annual Meeting of Stockholders (File No. 1-3492) 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 2013 Annual Meeting of Stockholders (File No. 1-3492) 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 2013 Annual
Meeting of Stockholders (File No. 1-3492) under the captions “Compensation Discussion and Analysis,” “Compensation
Committee Report,” “Summary Compensation Table,” “Grants of Plan-Based Awards in Fiscal 2012,” “Outstanding Equity
Awards at Fiscal Year End 2012,” “2012 Option Exercises and Stock Vested,” “2012 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 2013 Annual
Meeting of Stockholders (File No. 1-3492) 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 2013 Annual
Meeting of Stockholders (File No. 1-3492) 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 2013 Annual
Meeting of Stockholders (File No. 1-3492) 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 2013 Annual
Meeting of Stockholders (File No. 1-3492) 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 2013 Annual
Meeting of Stockholders (File No. 1-3492) under the caption “Fees Paid to KPMG LLP.”
88
PART IV
Item 15. Exhibits.
1.
Financial Statements:
The reports of the Independent Registered Public Accounting Firm and the financial statements of the
Company as required by Part II, Item 8, are included on pages 51 and 52 and pages 53 through 85 of this
annual report. See index on page (i).
Financial Statement Schedules:
The schedules listed in Regulation 210.5-04 have been omitted because they are not applicable or the required
information is shown in the consolidated financial statements or notes thereto.
Exhibits:
2.
3.
Exhibit
Number
Exhibits
3.1
3.2
4.1
4.2
4.3
4.4
4.5
Restated Certificate of Incorporation of Halliburton Company filed with the Secretary of State of Delaware on
May 30, 2006 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed June 5, 2006, File No.
1-3492).
By-laws of Halliburton revised effective January 1, 2013 (incorporated by reference to Exhibit 3.1 to
Halliburton's Form 8-K filed January 2, 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. 1-3492).
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. 1-3492).
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. 1-3492).
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. 1-3492).
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. 1-3492).
89
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. 1-3492).
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. 1-3492).
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. 1-3492).
Copies of instruments that define the rights of holders of miscellaneous long-term notes of Halliburton and its
subsidiaries have not been filed with the Commission. Halliburton 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. 1-3492).
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. 1-3492).
Third Supplemental Indenture dated as of December 12, 2003 among DII Industries, LLC, Halliburton 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. 1-3492).
Indenture dated as of October 17, 2003 between Halliburton 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. 1-3492).
Second Supplemental Indenture dated as of December 15, 2003 between Halliburton 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. 1-3492).
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 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. 1-3492).
4.18
Form of Global Note for Halliburton’s 5.90% Senior Notes due 2018 (included as part of Exhibit 4.17).
90
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 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. 1-3492).
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 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. 1-3492).
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).
†
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. 1-3492).
†
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. 1-3492).
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. 1-3492).
†
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. 1-3492).
†
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. 1-3492).
†
10.8
Employment Agreement (Albert O. Cornelison) (incorporated by reference to Exhibit 10.3 to Halliburton’s
Form 10-Q for the quarter ended June 30, 2002, File No. 1-3492).
10.9
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. 1-3492).
91
10.10
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. 1-3492).
†
10.11
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.
1-3492).
†
10.12
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. 1-3492).
†
10.13
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. 1-3492).
†
10.14
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.
1-3492).
†
10.15
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 filed July 27, 2012, File No.
001-03492).
†
10.16
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. 1-3492).
†
10.17
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. 1-3492).
†
10.18
Executive Agreement (Lawrence J. Pope) (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K
filed December 12, 2008, File No. 1-3492).
†
10.19
Halliburton Company Stock and Incentive Plan, as amended and restated effective February 16, 2012
(incorporated by reference to Appendix B of Halliburton's proxy statement filed April 3, 2012, File No.
1-3492).
†
10.20
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.
1-3492).
†
10.21
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. 1-3492).
†
10.22
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. 1-3492).
†
10.23
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. 1-3492).
†
10.24
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).
92
†
10.25
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. 1-3492).
†
10.26
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. 1-3492).
†
10.27
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. 1-3492).
†
10.28
Executive Agreement (Evelyn M. Angelle) (incorporated by reference to Exhibit 10.34 to Halliburton’s Form
10-K for the year ended December 31, 2008, File No. 1-3492).
†
10.29
Executive Agreement (Timothy J. Probert) (incorporated by reference to Exhibit 10.36 to Halliburton’s Form
10-K for the year ended December 31, 2008, File No. 1-3492).
†
10.30
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. 1-3492).
†
10.31
Amendment to Executive Employment Agreement (Albert O. Cornelison) (incorporated by reference to
Exhibit 10.40 to Halliburton’s Form 10-K for the year ended December 31, 2008, File No. 1-3492).
†
10.32
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. 1-3492).
†
10.33
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. 1-3492).
†
10.34
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. 1-3492).
10.35
U.S. $2,000,000,000 Five Year Revolving Credit Agreement among Halliburton, 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. 1-3492).
†
10.36
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. 1-3492).
†
10.37
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. 1-3492).
10.38
Underwriting Agreement, dated November 8, 2011, among Halliburton and Citigroup Global Markets Inc.,
Deutsche Bank Securities Inc., HSBC Securities (USA) Inc., RBS Securities Inc., Credit Suisse Securities
(USA) LLC, Morgan Stanley & Co. LLC and the several other underwriters identified therein (incorporated by
reference to Exhibit 1.1 to Halliburton’s Form 8-K filed November 14, 2011, File No. 1-3492).
†
10.39
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. 1-3492).
93
†
10.40
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.
1-3492).
†
10.41
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. 1-3492).
†
10.42
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).
†
10.43
*† 10.44
*† 10.45
†
10.46
*† 10.47
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 filed July 27, 2012, File No.
001-03492).
Third Amendment to Restricted Stock Plan for Non-Employee Directors of Halliburton Company effective
December 1, 2012.
First Amendment dated December 1, 2012 to Halliburton Company Directors' Deferred Compensation Plan,
as amended and restated effective May 16, 2012.
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).
Second Amendment dated December 11, 2012 to Halliburton Company Employee Stock Purchase Plan, as
amended and restated effective February 11, 2009.
*
*
*
*
*
*
12.1
Statement of Computation of Ratio of Earnings to Fixed Charges.
21.1
Subsidiaries of the Registrant.
23.1
Consent of KPMG LLP.
24.1
Powers of attorney for the following directors signed in December 2012:
Alan M. Bennett
James R. Boyd
Milton Carroll
Nance K. Dicciani
Murry S. Gerber
S. Malcolm Gillis
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.
94
** 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.
95
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 11th day of February, 2013.
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 11th day of February, 2013.
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/ Evelyn M. Angelle
Evelyn M. Angelle
Senior Vice President and
Chief Accounting Officer
96
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
* S. Malcolm Gillis
S. Malcolm Gillis
* 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
97
shareholder information
Shares Listed
New York Stock Exchange
Symbol: HAL
Transfer Agent and Registrar
Computershare Shareowner Services
480 Washington Boulevard
Jersey City, New Jersey 07310-1900
Telephone: 800.279.1227
www.bnymellon.com/shareowner/isd
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
013
281.871.2699
www.halliburton.com
© 2013 Halliburton. All Rights Reserved.
Printed in the USA
H09980