Halliburton Company Annual Report 2015

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FY2015 Annual Report · Halliburton Company

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281.871.2699
www.halliburton.com

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2015 Annual Report

2015 proved to be a challenging year for
2015 proved to be a challenging year for
the industry. We believe our customers
the industry. We believe our customers
will remain focused on optimizing their
will remain focused on optimizing their
cost per barrel of oil produced and higher
cost per barrel of oil produced and higher
levels of operating efficiency, which bodes
levels of operating efficiency, which bodes
well for Halliburton. Ultimately, when this
well for Halliburton. Ultimately, when this
market recovers we believe North America
market recovers we believe North America
will respond most quickly and offer the
will respond most quickly and offer the
greatest upside, and that Halliburton will
greatest upside, and that Halliburton will
be positioned to outperform.
be positioned to outperform.

Jeff Miller
Jeff Miller
President and Chief Health, Safety and
President and Chief Health, Safety and
Environment Officer
Environment Officer

$23.6B
in revenue

21%
reduction of
non-productive
time

$2.2B
Capital
Expenditures

$0.72
Cash dividends
per share

$614M
returned to
shareholders

Shares Listed

New York Stock Exchange
Symbol: HAL

Transfer Agent & 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

Design: Savage Brands, Houston TX

$23.6B
in revenue

21%
reduction of
non-productive
time

$2.2B
Capital
Expenditures

$0.72
Cash dividends
per share

$614M
returned to
shareholders

Halliburton 2015 Annual Report

Financial Highlights

(Millions of dollars and shares, except per share data)

2015

2014

2013

Revenue

Operating Income (Loss)

$ 23,633

(165)

$ 32,870

$ 5,097

$ 29,402

$ 3,138

Amounts Attributable to Company Shareholders:

Income (Loss) from Continuing Operations $
$

Net Income (Loss)

(666)
(671)

$ 3,436
$ 3,500

$ 2,106
$ 2,125

Diluted Income per Share Attributable

to Company Shareholders:

Income (Loss) from Continuing Operations $
$

Net Income (Loss)

(0.78)
(0.79)

Cash Dividends per Share

Diluted Common Shares Outstanding

Working Capital1

Capital Expenditures

0.72

853

$ 16,250

$ 2,184

Long-Term Debt, including Currrent Maturities

$ 15,346

$
$

4.03
4.11

0.63

852

$ 8,781

$ 3,283

7,779

$
$

2.33
2.36

$ 0.525

902

$ 8,678

$ 2,934

$ 7,816

Debt to Total Capitalization2

50%

33%

37%

Depreciation, Depletion and Amortization

$ 1,835

$ 2,126

$ 1,900

Return on Average Capital Employed3

(1)%

17%

11%

Total Capitalization4

$ 30,850

$ 24,196

$ 21,569

1 Working Capital is defined as total current assets less total current liabilities.

2 Debt to Total Capitalization is defined as total debt divided by the sum of total debt plus
total shareholders’ equity.

3 Return on Average Capital Employed is defined as net income before net interest expense divided
by average capital employed. Capital employed includes total debt and total shareholders’ equity.

4 Total Capitalization is defined as total debt plus total shareholders’ equity.

Revenue
in billions

4
9
2
$

9
2
3
$

6
3
2
$

Dividends to
Shareholders
in millions

5
6
4
$

3
3
5
$

4
1
6
$

Capital
Expenditures
in billions

9
2
$

3
3
$

2
2
$

www.halliburton.com

Strategic Focus Areas At A Glance

Unconventionals

Mature Fields

Deep Water

Unconventional formations became an

Mature fields account for over 70 percent

Deepwater economics continued to be

increasingly important part of the global

of the world’s oil and gas production, with

challenged throughout 2015, resulting in

energy equation in 2015. Revised technically

many of these assets now in secondary

reduced activity levels in every market,

recoverable reserve estimates project

or tertiary production phases. Maximizing

from the North Sea to the pre-salt fields

over 400 billion barrels of tight oil and over

recovery is a challenge, with oil fields

of Brazil, to emerging opportunities in

7,500 trillion cubic feet of shale gas are

yielding only 35 percent of oil in place on

India and Malaysia. However, deepwater

available, located in 101 basins across

average, and lower rates are common

production remains an important contributor

43 countries around the world. Halliburton

due to geological characteristics and the

to global oil and gas supply, as approximately

is at the forefront of developing the solutions

limitations of older technology. With

11 percent of global production came

and techniques to economically unlock

commodity headwinds facing the industry

from deepwater fields last year. As we look

unconventional assets in North America,

last year, customer interest in enhanced

ahead, deepwater is expected to remain a

and we are excited about leveraging our

recovery techniques became more acute.

significant source of oil and gas; over the

experience to help access this significant

global opportunity.

Our presence in mature fields expanded

during 2015 across the international

Halliburton continued to lead the industry

marketplace, as customers looked for new

last 5 years, approximately two-thirds of

oil and gas discoveries, by volume, were in

deepwater environments.

in developing environmentally responsible

solutions to address estimated global decline

During 2015, deepwater and ultra-deepwater

solutions during 2015, deploying the first

rates of 6 percent. In Latin America, we

activity generated more than 10 percent

hydraulic fracturing spread that is fully

began field management projects with

of Halliburton’s global revenue. Halliburton

compliant with the Environmental Protection

customers in Mexico and Ecuador focused

collaborated with our customers in deep

Agency’s 2015 Tier 4F emissions standard

on maximizing production in aged assets.

water to help deliver the lowest cost per

for non-road, high-horsepower engines. The

In the Eastern Hemisphere, we completed

barrel of oil equivalent. Our strategic focus

Tier 4F equipment was used on multiple

a successful infield drilling program in

continues to be on development projects,

wells in Pennsylvania gas fields, ultimately

Malaysia, mobilized new, large-scale projects

which are estimated to comprise more than

resulting in a more than 30 percent overall

in Russia, and expanded our presence in

50 percent of activity through the end of

reduction in emissions as a result of this

the Middle East.

the decade.

new equipment.

Halliburton 2015 Annual Report

To Our Shareholders

“

We are engaged with our
customers in their efforts to
reduce the cost of producing
each barrel of oil equivalent,
and have continued to offer
them products, services and
technologies that are more
efficient, reduce non-productive
time and improve performance.

In 2015, lower oil and gas prices led to substantial reductions in global upstream oil

and gas activity levels resulting in the most challenging year in decades. Halliburton’s

commitment to superior execution, our broad service offerings, and our long-standing

customer relationships enable us to manage through business cycles and prepare for the

market’s eventual recovery.

The downturn materialized very quickly, beginning in late 2014. As of December 31, 2015, the
activity level measured by the Baker Hughes U.S. land rig count declined by 64 percent from
the 2014 peak, and we experienced substantial declines in our international markets as well.
As our customers’ capital spend declined, so did Halliburton’s activity and the prices paid
for our products and services.

But this is a market that Halliburton knows well, and we have experienced these cycles
before. We have focused relentlessly on managing our costs. While this required difficult
staffing decisions, we are committed to aligning our cost structure with the market, and we
believe the actions and decisions taken in 2015 will enable Halliburton to emerge from this
downturn prepared to deliver competitive growth and returns.

Our playbook for a downturn is simple – we control what we can control, preserve our market
position and live within our cash flow. We continued to execute our key strategies in the
unconventionals, deep water and mature fields markets on a near real-time basis. We also
looked beyond the cycle, investing in strategic initiatives and preparing for future recovery.

Our international operations performed well given the global industry headwinds. Revenues
were lower than in 2014, compared with an 18 percent decline in the international drilling and
completion spend by our customers. However, aggressive cost control enabled the company
to maintain our international margins even with downward pressure on prices.

Halliburton traditionally has been aligned with operators that have strong balance sheets
and fairway acreage in the most important oil and gas basins in North America and across the
globe. We are engaged with our customers in their efforts to reduce the cost of producing
each barrel of oil equivalent, and have continued to offer them products, services and
technologies that are more efficient, reduce non-productive time and improve performance.

Frac of the Future™ is a prime example. While industry crew sizes have increased in recent
years because of higher hydraulic fracturing intensity, Halliburton’s average crew size has
been essentially flat. At year end, Frac of the Future™ spreads represented 60 percent of our
fleet – a more efficient, low-cost delivery platform that offers a clear competitive advantage
both in challenging times and during the recovery.

We drive this improvement by lowering costs at every step. We help operators optimize bit
designs and fluid compositions, reduce drilling days, and improve surface efficiency. We also
help increase estimated ultimate recoveries by collaborating with our customers to identify
the best targets and utilize the right chemistry to produce more barrels.

Halliburton is the execution company, and 2015 marked another year of improvement in
safety and service quality metrics, with significant, double-digit reductions from 2014 in both
areas. Even while the market is forcing us to streamline our footprint in the field, we are
improving our performance rates.

www.halliburton.com

David J. Lesar
Chairman of the Board and
Chief Executive Officer

In 2015, we continued to work diligently toward the closing of the pending acquisition of
Baker Hughes, including the pending regulatory reviews, the divestiture proposals, and
planning for integration activities.

We have tremendous appreciation for the contributions of Halliburton’s employees and
our Board of Directors, the confidence placed in us by our customers to help them find the
most efficient, cost-effective and safest means to achieve their goals, and the understanding
of our investors who have persevered with us during this challenging business cycle.

Turning the page to 2016, market visibility remains limited. Activity recovery will depend on
commodity prices, which will impact our customers’ ability to invest. We will continue to
strategically focus on offering services and solutions that improve our customers’ cost per
produced barrel.

The long-term fundamentals and outlook for the industry remain strong. We expect global
demand for oil will continue to grow, and supply levels will contract as output from aging
reservoirs decline and lower investment levels result in lower production. These fundamental
trends are likely to restore the balance between supply and demand and bring a recovery in
oilfield activity.

We are focused on maintaining a strong customer portfolio, investing in more efficient
technology and delivering reliable, best-in-class service quality for our customers, and we
are preparing the business for growth when the industry recovery begins.

David J. Lesar
Chairman of the Board and
Chief Executive Officer

Jeffrey A. Miller
President and Chief Health,
Safety and Environment Officer

Mark A. McCollum
Executive Vice President and
Chief Integration Officer

Lawrence J. Pope
Executive Vice President of
Administration and
Chief Human Resources Officer

Robb L. Voyles
Executive Vice President,
Secretary and General Counsel

James S. Brown
President, Western Hemisphere

Joe D. Rainey
President, Eastern Hemisphere

Christian A. Garcia
Senior Vice President, Finance,
and Acting Chief Financial Officer

Halliburton 2015 Annual Report

North America

Cost per Barrel

Cost per barrel is a simple concept that underscores
our strategy in the unconventional fields of North
America. Reducing the cost per barrel of oil equivalent
(BOE) for our customers requires focusing on both
sides of the equation by reducing the numerator –
improving efficiency and driving lower operator
costs – and increasing the denominator by improving
well productivity and estimated ultimate recovery.

Halliburton’s superior service quality and more efficient technology help our customers

unlock the value of their reserves by bending their cost curve, getting more from their

investment per barrel of oil equivalent. Reducing the cost per barrel requires focus on both

elements of the equation by reducing the numerator – improving efficiency and driving

lower operating costs – and increasing the denominator by improving well productivity

and estimated ultimate recovery.

Halliburton is a leader in the industry’s efforts to drive down costs at every step of drilling
and completion – optimizing bit designs, fluid compositions and well designs, in many cases
reducing drilling time by as much as 50 percent.

Well completion sizes continue to increase. For instance, the average sand volume per well
has doubled in just the last two years. We help our customers avoid disruption and reduce
costs through our world-class supply chain organization that manages Halliburton railcars, basin
inventory levels and well site sand deliveries in real time. We have reduced the time spent
waiting for sand by 70 percent. The cost to deliver a ton of proppant is the lowest it has been
in five years.

Bigger, more complex well completions put more strain on pumping equipment. Halliburton’s
Q10™ technology – the centerpiece of the Frac of the Future™ – enables us to do the same
quantity of work with 20 percent less capital on location and up to 45 percent less maintenance
cost. At year end, Frac of the Future™ spreads represented 60 percent of our fleet.

Surface efficiency helps operators drive down their costs. But customers are also focused
on better wells – identifying the best targets and using the right chemistry to produce more
barrels. Our belief is that for shale development – even within a single well – the rocks are
not the same. For Halliburton, that requires a focus on two high-level categories – sub-surface
insight to help identify the target zones and custom chemistry to help maximize the stimulated
rock volume.

Our DecisionSpace® Unconventionals software suite is designed to help improve well and
reservoir modeling and better predict technical and economic performance. Its dynamically-
updateable model supports E&P business processes to help reduce time for decision-making
and increase team collaboration.

MicroScoutSM Service, a recent addition to our custom chemistry portfolio, is a hydraulic
fracturing treatment designed to deliver proppant into far field microfractures, enhancing the
productive life of new wells. Early trials have indicated more than a 20 percent uplift in production
compared to offset wells.

Through the downturn, we have seen operators adopt these new solutions more quickly. After
years of efficiency improvements, it is our view that subsurface insight and custom chemistry
will drive the next leg in efficiency, helping our customers to further lower their cost per BOE
during the downturn as well as in the next upcycle. We believe Halliburton’s advantages in
North America – the largest oilfield service market in the world – will offer the greatest upside
in the recovery and propel Halliburton in the next phase of the cycle.

www.halliburton.com

NAHalliburton 2015 Annual Report

International

Superior Execution

In 2015, Halliburton continued to lead the
industry in quality management. During the
year, 37 Halliburton facilities received the
American Petroleum Institute Specification
Q2 Certification (API Q2), an advanced industry
certification standard for oil and natural gas
service companies. Our Brazil operations
were the first in Latin America to receive
the certification; other facilities included
Indonesia, Malaysia, Brunei, Kuwait, and
Mexico. API Q2 is a risk-based quality
management system approach that focuses
on competency, service design, contingency
planning, supply chain controls, preventive
maintenance, inspection, service quality
plans and management of change.

Halliburton’s international operations proved resilient in 2015, outperforming our peer group,

though we were not immune to the lower commodity price environment. We worked closely

with our customers to improve their project economics through technology and operating

efficiency, and responded quickly to market conditions to right-size our business. With our

continued focus on cost management, we were able to improve operating margins during

the year.

The bifurcation between land and offshore activity continued during 2015. Land-based
projects continued to move forward in many areas, notably in the Middle East, while most
offshore markets, including the North Sea, Angola and Australia, experienced project delays
and cancellations. In 2015, onshore projects represented nearly 60 percent of Halliburton’s
international revenue stream.

Onshore, Halliburton’s focus on mature fields is an important factor in the resilience of our
business; projects in Latin America, the Middle East, and Asia continue even in a low oil
price environment. We estimate that about 70 percent of production today is in mature fields;
this affects large companies, and also underpins the health of many international economies.
In this market, we strive to help our customers increase recovery rates and find bypassed
pay, frequently applying newer technology to older fields. This strategy was successful in
2015, leading to year-over-year revenue growth in several Middle East countries, despite the
challenging macro environment.

Offshore, the international rig count declined more than 13 percent year-over-year. We
believe deep water will be the most challenged market segment in the current commodity
price environment, with average exploration costs estimated to be more than $60 per barrel
of oil equivalent.

To help our customers improve their well economics, Halliburton focuses on reducing
uncertainty and increasing reliability. In a Latin America project, Landmark’s DecisionSpace®
software allowed our clients to reduce drilling days by integrating geological data with well
construction and rendering an interactive asset model. This insight helped eliminate one entire
directional build phase and reduced drilling time by 15 days, thereby reducing the structural
costs of the project while also delivering more productive wells.

With operations in approximately 80 countries around the globe, we believe Halliburton’s
services, technology and execution provide a strong platform for growth in a recovery, and
by focusing on our long-term mature fields and deep water strategies, we can continue to
outperform our competitors.

www.halliburton.com

INTLHalliburton 2015 Annual Report

Technology

The imperative to maximize production and reduce the cost per barrel of oil equivalent

led Halliburton’s customers to adopt our new technologies more rapidly even as activity

declined with lower commodity prices. New product revenue as a percent of total sales

once again increased over the prior year, continuing a multi-year trend.

Halliburton’s technologies help customers improve project economics and maximize the
value of their oil and gas assets by increasing operating efficiency, reducing non-productive
time, and lowering the cost to explore and develop new reserves, maximize recovery and
access reserves in difficult environments.

Halliburton employs a disciplined, multi-stage, gate research program that leverages
collaboration with our customers and programs to elevate ideas developed in the field,
helping us to be among the more efficient innovators in any industry. In 2015, Halliburton
secured new patents at a research and development cost of less than $1 million per patent.
This level of R&D efficiency places Halliburton in the same range as other top global U.S.
patent leaders and indicates a tremendous return on intellectual property.

Halliburton’s disciplined approach to developing differentiating solutions solidifies our
relationships with the world’s top energy producers.

Buoyancy Assisted Casing Equipment
(BACE™) Assembly

Winner of 2015 Hart’s Meritorious Engineering
Achievement Award

Buoyancy Assisted Casing Equipment (BACE)
assembly enables operators to run casing to the
bottom of directional or horizontal wellbores.
By trapping air or lightweight fluid and “floating”
the casing, Halliburton helps minimize the risk
of buckling or stuck casing in extended reach
horizontal wells. In current market conditions,
the BACE assembly helps make certain shale
field-development programs economically
feasible by potentially adding thousands of
feet to the productive zone of the well.

Illusion® Dissolvable Frac Plug

Illusion is a high-performance frac plug
that provides zonal isolation for stimulation
treatments up to 10,000psi. It combines
Halliburton’s leading frac plug designs with the
most advanced dissolvable metal and rubber
materials. This fully dissolvable plug helps
reduce the risk, cost and time associated with
conventional plug removal and upon complete
dissolution, provides the entire inner diameter
of the wellbore for future operations.

www.halliburton.com

SaltShield™ Cement

AccessFrac® Stimulation Service

SPECTRUMSM Intervention Services

Winner of 2015 Hart’s Meritorious Engineering
Achievement Award

Winner of the 2015 LAGCOE Spotlight Award

Winner of World Oil Technology Award

For many deepwater reservoirs there is no
recovery program without traversing up to
1 mile of salt. SaltShield cement is designed
to provide a dependable barrier that tolerates
the chemical effects of even aggressive salts,
while helping resist salts that can induce casing
collapse. SaltShield cement is tailored to help
mitigate the specific salt-zone risks of hole
closure, lost circulation, casing collapse, and
contamination during drilling and cementing
operations. This helps operators protect their
wells from harsh salt zones in order to preserve
and maximize production.

AccessFrac stimulation service helps optimize
the distribution of proppant in a well, improving
cluster completion efficiency and cluster
production efficiency, as well as increasing
long-term production performance. AccessFrac
combines diversion technology and conductivity
enhancement material to optimize the fracture
network and open new production channels,
which helps maximize the contact with the
reservoir. By replacing mechanical plug systems
with a self-degrading, environmentally benign
chemical alternative, AccessFrac reduces the
time spent during multi-zone fracturing.

SPECTRUM Real-Time Coiled Tubing Services
combines intervention and diagnostic services
to help operators monitor wells in real time,
resulting in greater efficiency and increased
reliability. Through telemetry systems such as
fiber optics, Spectrum combines distributed
and localized sensors to improve insight of
well conditions. By using real-time data from
the well, Halliburton helps operators quickly
assess downhole events, more accurately place
treatments, and ultimately optimize their well
intervention operations.

RezConnect™ Well Testing System

DecisionSpace® Unconventionals

Winner of Spotlight on New Technology –
2015 Offshore Technology Conference Awards

The RezConnect Well Testing System is the
industry’s first fully acoustically actuated Drill
Stem Test system powered by Halliburton’s
DynaLink® Telemetry System. RezConnect
provides two-way communication in the
wellbore, allowing operators to activate tools
remotely, as well as transmit measurement
and analysis of well-test data in real-time.

DecisionSpace Unconventionals is the
industry’s first comprehensive suite of geoscience,
reservoir, drilling, production, and economics
applications to be delivered on a single platform.
It combines sweet spot identification with a
complex fracture simulator into a 3D earth model,
helping operators optimize well placement and
improve asset productivity in unconventional
shales and tight formations.

Halliburton 2015 Annual Report

Leadership

Board of Directors

Corporate Officers

Robert A. Malone
Executive Chairman, President and
Chief Executive Officer,
First Sonora Bancshares, Inc.
(2009) (B) (C)

J. Landis Martin
Founder,
Platte River Equity
(1998) (C) (D)

Jeffrey A. Miller
President and Chief Health, Safety and
Environment Officer, Halliburton Company
(2014)

Debra L. Reed
Chairman and Chief Executive Officer,
Sempra Energy
(2001) (B) (D)

(A) Member of the Audit Committee
(B) Member of the Compensation Committee
(C) Member of the Health, Safety and

Environment Committee

(D) Member of the Nominating and

Corporate Governance Committee

David J. Lesar
Chairman of the Board and Chief Executive Officer,
Halliburton Company
(2000)

Abdulaziz F. Al Khayyal
Retired Senior Vice President of Industrial Relations,
Saudi Aramco
(2014) (C) (D)

Alan M. Bennett
Retired President and Chief Executive Officer,
H&R Block, Inc.
(2006) (A) (D)

James R. Boyd
Retired Chairman of the Board,
Arch Coal, Inc.
(2006) (A) (B)

Milton Carroll
Executive Chairman of the Board,
CenterPoint Energy, Inc.
(2006) (B) (D)

Nance K. Dicciani
Chair of the Board and Interim Co-Principal
Executive Officer, AgroFresh Solutions, Inc.
(2009) (A) (C)

Murry S. Gerber
Retired Executive Chairman of the Board,
EQT Corporation
(2012) (A) (B)

José C. Grubisich
Chief Executive Officer,
Eldorado Brasil Celulose
(2013) (A) (C)

David J. Lesar
Chairman of the Board and Chief Executive Officer

Jeffrey A. Miller
President and Chief Health, Safety and
Environment Officer

Mark A. McCollum
Executive Vice President and
Chief Integration Officer

Lawrence J. Pope
Executive Vice President of Administration and
Chief Human Resources Officer

Robb L. Voyles
Executive Vice President, Secretary and
General Counsel

James S. Brown
President, Western Hemisphere

Joe D. Rainey
President, Eastern Hemisphere

Christian A. Garcia
Senior Vice President, Finance and
Acting Chief Financial Officer

Myrtle L. Jones
Senior Vice President, Tax

Charles E. Geer, Jr.
Vice President and Corporate Controller

Timothy M. McKeon
Vice President and Treasurer

www.halliburton.com

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, 2015

[ ] 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

[ ]

[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

[ ]

[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

[ ]

[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

[ ]

[X]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.

Large accelerated filer
Non-accelerated filer

[X]
[ ]

Accelerated filer
Smaller reporting company

[ ]
[ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

The aggregate market value of Halliburton Company Common Stock held by nonaffiliates on June 30, 2015, determined using the per share
closing price on the New York Stock Exchange Composite tape of $43.07 on that date, was approximately $36.7 billion.

As of January 29, 2016, there were 858,342,017 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.

Portions of the Halliburton Company Proxy Statement for our 2016 Annual Meeting of Stockholders (File No. 001-03492) are incorporated by
reference into Part III of this report.

This Page Intentionally Left Blank

HALLIBURTON COMPANY
Index to Form 10-K
For the Year Ended December 31, 2015

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

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PART I

Item 1. Business.

General description of business
Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware
in 1924. We are a leading provider of services and products to the 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. 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 products and services. The segment consists of Production Enhancement,
Cementing, Completion Tools, Production Solutions, Pipeline and Process Services, Multi-Chem, and Artificial Lift.

- our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and precise

wellbore placement solutions that enable customers to model, measure, drill, and optimize their well construction
activities. The segment consists of Baroid, Sperry Drilling, Wireline and Perforating, Drill Bits and Services,
Landmark Software and Services, Testing and Subsea, and Consulting and Project Management.

See Note 4 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, China, Malaysia, Singapore, and the United Kingdom.

Pending Acquisition of Baker Hughes
In November 2014, we and Baker Hughes Incorporated (Baker Hughes) entered into a merger agreement under which,

subject to the conditions set forth in the merger agreement, we will acquire all the outstanding shares of Baker Hughes in a
stock and cash transaction. Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the
worldwide oil and natural gas industry. We are continuing our discussions with competition authorities to obtain approval of the
acquisition and recently offered an enhanced set of divestitures in an effort to resolve competition-related concerns. We have
agreed with Baker Hughes to extend the period to obtain required regulatory approvals to no later than April 30, 2016, and
remain focused on completing the transaction as early as possible in 2016. See Note 2 to the consolidated financial statements
for further information about the pending acquisition and Item 1(a). “Risk Factors” for risks associated with the pending
acquisition.

Business strategy
Our business strategy is to secure a distinct and sustainable competitive position as an oilfield service company by

delivering services and products that enable our customers to extract proven reserves and maximize recovery. Our objectives
are to:

- create a balanced portfolio of services and products supported by global infrastructure and anchored by

technological innovation to further differentiate our company;

- reach a distinguished level of operational excellence that reduces costs and creates real value;
- preserve a dynamic workforce by being a preferred employer to attract, develop, and retain the best global talent;

and

- uphold our strong ethical and business standards, and maintain the highest standards of health, safety, and

environmental performance.

Markets and competition
We are one of the world’s largest diversified energy services companies. Our services and products are sold in highly

competitive markets throughout the world. Competitive factors impacting sales of our services and products include:

- price;
- service delivery (including the ability to deliver services and products on an “as needed, where needed” basis);
- health, safety, and environmental standards and practices;
- service quality;
- global talent retention;
- understanding the geological characteristics of the hydrocarbon reservoir;
- product quality;
- warranty; and
- technical proficiency.
We conduct business worldwide in approximately 80 countries. The business operations of our divisions are organized

around four primary geographic regions: North America, Latin America, Europe/Africa/CIS, and Middle East/Asia. In 2015,
2014, and 2013, based on the location of services provided and products sold, 44%, 51%, and 49% 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 4 to the consolidated financial statements for additional financial information about our
geographic operations in the last three years. Because the markets for our services and products are vast and cross numerous
geographic lines, it is not practicable to provide a meaningful estimate of the total number of our competitors. The industries we
serve are highly competitive, and we have many substantial competitors. Most of our services and products are marketed
through our servicing and sales organizations.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil

unrest, expropriation or other governmental actions, changes in foreign currency exchange rates, foreign currency exchange
restrictions, and highly inflationary currencies, as well as other geopolitical factors. We believe the geographic diversification
of our business activities reduces the risk that loss of operations in any one country, other than the United States, would
significantly impact 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 14 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 $487 million in 2015, $601 million in 2014, and $588 million in 2013. We sponsored over 95% of these
expenditures in each year.
Patents
We own a large number of patents and have pending a substantial number of patent applications covering various

products and processes. We are also licensed to utilize technology covered by patents owned by others, and we license others to
utilize technology covered by our patents. We do not consider any particular patent to be material to our business operations.

Seasonality
Weather and natural phenomena can temporarily affect the performance of our services, but the widespread
geographical locations of our operations mitigate those effects. Examples of how weather can impact our business include:

- the severity and duration of the winter in North America can have a significant impact on natural gas storage levels

and drilling activity;

- the timing and duration of the spring thaw in Canada directly affects activity levels due to road restrictions;
- typhoons and hurricanes can disrupt coastal and offshore operations; and
- severe weather during the winter 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 typically

result in higher activity in the fourth quarter of the year.

Employees
At December 31, 2015, we employed approximately 65,000 people worldwide compared to more than 80,000 at

December 31, 2014. At December 31, 2015, approximately 17% 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 9 to the consolidated financial statements and
Item 1(a), “Risk Factors.”

Hydraulic fracturing process
Hydraulic fracturing is a process that creates fractures extending from the well bore into the rock formation to enable
natural gas or oil to move more easily from the rock pores to a production conduit. A significant portion of our Completion and
Production segment provides hydraulic fracturing services to customers developing shale natural gas and shale oil. From time
to time, questions arise about the scope of our operations in the shale natural gas and shale oil sectors, and the extent to which
these operations may affect human health and the environment.

We sometimes design and generally implement a hydraulic fracturing operation to 'stimulate' the well's production, 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 at
least a portion of the additives used in the overall fracturing fluid mixture. In addition, we mix the additives and proppant with
the base fluid and pump the mixture down the wellbore to create the desired fractures in the target formation. The customer is
responsible for disposing of any materials that are subsequently produced or 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
freshwater aquifers or the surface.

The potential environmental impacts of hydraulic fracturing have been studied by numerous government entities and

others. In 2004, the United States Environmental Protection Agency (EPA) conducted an extensive study of hydraulic fracturing
practices, focusing on coalbed methane wells, and their potential effect on underground sources of drinking water. The EPA’s
study concluded that hydraulic fracturing of coalbed methane wells poses little or no threat to underground sources of drinking
water. 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 hydraulic fracturing technologies, which
offer our customers a variety of especially environment-friendly alternatives related to the use of hydraulic fracturing fluid
additives and other aspects of our hydraulic fracturing operations. We created a hydraulic fracturing fluid system comprised of
materials sourced entirely from the food industry. In addition, we have engineered a process that uses ultraviolet light to control
the growth of bacteria in hydraulic fracturing fluids, allowing customers to minimize the use of chemical biocides. We are
committed to the continued development of innovative chemical and mechanical technologies that allow for more economical
and environmentally friendly development of the world’s oil and natural gas reserves.

In evaluating any environmental risks that may be associated with our hydraulic fracturing services, it is helpful to

understand the role that we play in the development of shale natural gas and shale oil. Our principal task generally is to manage
the process of injecting fracturing fluids into the borehole to 'stimulate' the well. Thus, based on the provisions in our contracts
and applicable law, the primary environmental risks we face are potential pre-injection spills or releases of stored fracturing
fluids and potential spills or releases of fuel or other fluids associated with pumps, blenders, conveyors, or other above-ground
equipment used in the hydraulic fracturing process.

Although possible concerns have been raised about hydraulic fracturing operations, the circumstances described above

have helped to mitigate those concerns. To date, we have not been obligated to compensate any indemnified party for any
environmental liability arising directly from hydraulic fracturing, although there can be no assurance that such obligations or
liabilities will not arise in the future.
Working capital
We fund our business operations through a combination of available cash and equivalents, short-term investments, and

cash flow generated from operations. In addition, our revolving credit facility is available for additional working capital needs.

Web site access
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to

those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 are made available free of
charge on our internet web site at www.halliburton.com as soon as reasonably practicable after we have electronically filed the
material with, or furnished it to, the Securities and Exchange Commission (SEC). The public may read and copy any materials
we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on
the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an
internet site that contains our reports, proxy and information statements, and our other SEC filings. The address of that web site
is www.sec.gov. We have posted on our web site our Code of Business Conduct, which applies to all of our employees and
Directors and serves as a code of ethics for our principal executive officer, principal financial officer, principal accounting
officer, and other persons performing similar functions. Any amendments to our Code of Business Conduct or any waivers from
provisions of our Code of Business Conduct granted to the specified officers above are disclosed on our web site within four
business days after the date of any amendment or waiver pertaining to these officers. There have been no waivers from
provisions of our Code of Business Conduct for the years 2015, 2014, or 2013. 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 5,

2016, including all offices and positions held by each in the past five years:

Name and Age

Offices Held and Term of Office

James S. Brown
(Age 61)

President, Western Hemisphere of Halliburton Company, since January 2008

* Christian A. Garcia

Senior Vice President, Finance and Acting Chief Financial Officer of Halliburton Company,

(Age 52)

since January 2015

Senior Vice President and Chief Accounting Officer of Halliburton Company, January 2014

to December 2014

Senior Vice President and Treasurer of Halliburton Company, September 2011 to December

2013

Senior Vice President, Investor Relations of Halliburton Company, January 2011 to August

2011

Charles E. Geer, Jr.

Vice President and Corporate Controller of Halliburton Company, since January 2015

(Age 45)

Vice President, Finance of Halliburton Company, December 2013 to December 2014
Vice President and Chief Accounting Officer of Select Energy Services, April 2011 to

November 2013

Vice President and Principal Accounting Officer of Weatherford International, June 2010 to

March 2011

Myrtle L. Jones

Senior Vice President, Tax of Halliburton Company, since March 2013

(Age 56)

* David J. Lesar

(Age 62)

Senior Managing Director of Tax and Internal Audit, Service Corporation International,

February 2008 to February 2013

Chairman of the Board and Chief Executive Officer of Halliburton Company, since August

2014

Chairman of the Board, President, and Chief Executive Officer of Halliburton Company,

August 2000 to July 2014

Mark A. McCollum

Executive Vice President and Chief Integration Officer of Halliburton Company, since

(Age 56)

January 2015

Executive Vice President and Chief Financial Officer of Halliburton Company, January 2008

to December 2014

Timothy M. McKeon

Vice President and Treasurer of Halliburton Company, since January 2014

(Age 43)

Assistant Treasurer of Halliburton Company, September 2011 to December 2013
Director of Finance, Drilling & Evaluation Division of Halliburton Company, February 2011

to August 2011

Director of Treasury Operations of Halliburton Company, March 2009 to January 2011

* Jeffrey A. Miller

Member of the Board of Directors and President of Halliburton Company, since August

(Age 52)

2014

Executive Vice President and Chief Operating Officer of Halliburton Company, September

2012 to July 2014

Senior Vice President, Global Business Development and Marketing of Halliburton

Company, January 2011 to August 2012

* Lawrence J. Pope

(Age 47)

Executive Vice President of Administration and Chief Human Resources Officer of

Halliburton Company, since January 2008

Joe D. Rainey
(Age 59)

President, Eastern Hemisphere of Halliburton Company, since January 2011

* Robb L. Voyles

Executive Vice President, Secretary and General Counsel of Halliburton Company, since

(Age 58)

May 2015

Executive Vice President and General Counsel of Halliburton Company, January 2014 to

April 2015

Senior Vice President, Law of Halliburton Company, September 2013 to December 2013
Partner, Baker Botts L.L.P., January 1989 to August 2013

* 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.

Item 1(a). Risk Factors.

The statements in this section describe the known material risks to our business and should be considered carefully.

We may be unable to obtain the necessary consents and approvals from governmental authorities required to

complete the Baker Hughes acquisition in a timely manner, or at all. Even if such consents and approvals are obtained,
governmental authorities may impose conditions that could adversely affect us or cause the acquisition to be abandoned.

To complete the acquisition, we and Baker Hughes must satisfy various closing conditions, including obtaining certain

consents and approvals from various governmental and regulatory authorities.

We have not yet obtained all of the regulatory consents and approvals required to complete the acquisition.
Governmental or regulatory agencies could seek to block or challenge the acquisition. Even if these regulatory consents and
approvals are obtained, they may not be obtained prior to April 30, 2016, the current deadline under the merger agreement to
obtain required regulatory approvals before either party is permitted to terminate the merger agreement. The governmental
authorities from which these approvals are required are expected to require significant divestitures, and may impose other
conditions on the completion of the acquisition that could have an adverse effect on the combined company following the
acquisition. We will be unable to complete the acquisition until consents and approvals are received from the European
Commission (EC) and various other governmental authorities (jointly, the “Regulatory Clearances”). Notwithstanding that the
statutory waiting period under U.S. law ended when our timing agreement with the U.S. Department of Justice (DOJ) expired
on December 15, 2015, and even after completion of the acquisition, the DOJ and other governmental authorities could seek to
block or challenge the acquisition as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a
competitor, customer or other third party could initiate a private action under the antitrust laws challenging or seeking to enjoin
the acquisition, before or after it is completed. Halliburton may not prevail and may incur significant costs in defending or
settling any action under the antitrust laws. The merger agreement may require us to accept conditions from these regulators
that could adversely impact the combined company. If we agree to undertake divestitures or comply with operating restrictions
in order to obtain any approvals required to complete the acquisition, we may be less able to realize anticipated benefits of the
acquisition, and the business and results of operations of the combined company after the acquisition may be adversely
affected.

In December 2015, the DOJ informed us that they did not believe that our previously announced proposed divestitures

were sufficient to address its concerns, and in January 2016, the EC issued a report detailing initial concerns about the
competition-related implications of the acquisition. Although we have recently presented to the DOJ and informally notified the
EC and other jurisdictions of an enhanced set of proposed divestitures, there can be no assurance that the proposed divestiture
package will be sufficient to satisfy their concerns, and there is no agreement to date with the DOJ or the EC as to the adequacy
of the proposed divestitures. Even if the proposed divestiture package is satisfactory to those and other authorities, there can be
no assurance that we will be able to reach an agreement with one or more buyers of those product lines. If the Regulatory
Clearances are not received, or they are not received on terms that satisfy the conditions set forth in the merger agreement, then
neither we nor Baker Hughes will be obligated to complete the acquisition.

If we are unable to complete the acquisition, we would be subject to a number of risks, including the following:
- we would not realize the anticipated benefits of the acquisition, including, among other things, increased operating

efficiencies;

- the attention of our management will have been diverted to the acquisition rather than to our own operations and the

pursuit of other opportunities that could have been beneficial to us;

- the potential loss of key personnel during the pendency of the acquisition as employees may have experienced

uncertainty about their future roles with the combined company;

- we will have been subject to certain restrictions on the conduct of our business, which may have prevented us from

making certain acquisitions or dispositions or pursuing certain business opportunities while the acquisition is
pending; and

- the trading price of our common stock may decline to the extent that the current market prices reflect a market

assumption that the acquisition will be completed.

If the acquisition is not completed, our ongoing businesses may be adversely affected. If we are unable to close the

acquisition by April 30, 2016, either Baker Hughes or we may terminate the merger agreement. Under the merger agreement,
we could be required, in certain circumstances where the termination of the merger agreement is related to failures to obtain the
Regulatory Clearances, to pay Baker Hughes a termination fee of $3.5 billion. If we do not complete the acquisition, we will
also recognize additional non-cash expenses as discussed further in Note 2 to the consolidated financial statements. Payment of
the termination fee and incurring such expenses could have material and adverse consequences to the financial condition and
operations of Halliburton.

We can provide no assurance that the various closing conditions will be satisfied and that the necessary Regulatory

Clearances and other approvals will be obtained, or that any required conditions will not materially adversely affect the
combined company following the acquisition. In addition, we can provide no assurance that these conditions will not result in

the abandonment or delay of the acquisition. The occurrence of any of these events individually or in combination could have a
material adverse effect on our results of operations and the trading price of our common stock.

Pending litigation against us and Baker Hughes could result in an injunction preventing the consummation of the

acquisition or may adversely affect our business, financial condition or results of operations following the acquisition.

Following the announcement of the acquisition, various lawsuits were filed in the Court of Chancery of the State of

Delaware and the U.S. District Court for the Southern District of Texas against Baker Hughes, the members of the Baker
Hughes Board, and us, alleging breaches of various fiduciary duties by the members of the Baker Hughes Board during the
acquisition negotiations and by entering into the merger agreement and approving the acquisition and alleging that we and
Baker Hughes aided and abetted such alleged breaches of fiduciary duties. Among other remedies, the plaintiffs sought to
enjoin the acquisition and rescind the merger agreement, in addition to certain unspecified damages and reimbursement of
costs. While we and Baker Hughes believe these suits are without merit and have entered into a memorandum of understanding
with the plaintiffs of such lawsuits to settle such claims, the outcome of any such litigation is inherently uncertain and is
contingent upon the acquisition closing and court approval. If the settlement is not approved or the lawsuits otherwise remain
unresolved after the closing of the acquisition, it may adversely affect the combined company’s business, financial condition or
results of operation.

Our stockholders will have a reduced ownership and voting interest after the Baker Hughes acquisition and will

exercise less influence over management of the combined company.

Our stockholders currently have the right to vote for our board of directors and on other matters affecting the company.

When the acquisition occurs, each Baker Hughes stockholder that receives shares of our common stock will become a
stockholder of ours and correspondingly, each of our stockholders will remain a stockholder of Halliburton Company with a
percentage ownership of the combined company that is significantly smaller than the stockholder’s percentage ownership prior
to the acquisition. Upon completion of the acquisition, former Baker Hughes stockholders are expected to hold approximately
37% of our common stock. As a result of these reduced ownership percentages, our stockholders will have less influence on the
management and policies of the combined company than they now have with respect to Halliburton Company.

We have incurred, and will continue to incur, significant transaction, acquisition-related and restructuring costs in

connection with the Baker Hughes acquisition and the combined company could incur substantial expenses related to the
integration of Baker Hughes.

We have incurred, and will continue to incur, significant costs associated with the expected combination of our

operations and the operations of Baker Hughes, as well as transaction fees and other costs related to the acquisition. Many of
these costs will be borne by us even if the acquisition is not completed. We have also incurred, will incur through completion of
the acquisition, and the combined company will incur following the completion of the acquisition, substantial expenses in
connection with integrating each company’s respective businesses, policies, procedures, operations, technologies and systems.
There are a large number of systems that must be integrated, including information management, purchasing, accounting and
finance, sales, billing, payroll and benefits, fixed asset and lease administration systems and regulatory compliance. Many of
the expenses that will be incurred, by their nature, are difficult to estimate accurately at the present time. These expenses could,
particularly in the near term, reduce the savings that we expect to achieve from the elimination of duplicative expenses and the
realization of economies of scale and cost savings related to the integration of the businesses following the completion of the
acquisition, and accordingly, any net benefits may not be achieved in the near term or at all. These integration expenses may
result in significant charges taken against earnings by us prior to completion of the acquisition and by the combined company
following the completion of the acquisition. During the year ended December 31, 2015, we incurred an aggregate of $411
million in costs related to the pending Baker Hughes acquisition, of which $308 million are acquisition and integration costs
included within our consolidated statements of operations and $103 million are capitalized divestiture costs included within
"Other current assets" on our consolidated balance sheets.

The market value of our common stock could decline if large amounts of our common stock are sold following the

Baker Hughes acquisition.

Following the acquisition, our stockholders and former stockholders of Baker Hughes will own interests in a combined

company operating an expanded business with more assets and a different mix of liabilities. Our current stockholders and the
current stockholders of Baker Hughes may not wish to continue to invest in the combined company, or may wish to reduce their
investment in the combined company, in order to comply with institutional investing guidelines, to increase diversification or to
track any rebalancing of stock indices in which our or Baker Hughes common stock is or was included. If, following the
acquisition, large amounts of our common stock are sold, the price of our common stock could decline.

The Baker Hughes acquisition may not be accretive, and may be dilutive, to our earnings per share in the near

term, which may negatively affect the market price of our common stock.

We anticipate that the acquisition may not be accretive, and may be dilutive, to earnings per share until the end of the
second calendar year after closing. This expectation is based on preliminary estimates that may materially change. In addition,
future events and conditions could decrease or delay any accretion, result in dilution or cause greater dilution than is currently
expected, including:

- further adverse changes in energy market conditions;
- commodity prices for oil, natural gas and natural gas liquids;
- production levels;
- operating results;
- competitive conditions;
- laws and regulations affecting the energy business;
- capital expenditure obligations;
- higher than expected integration costs;
- lower than expected synergies; and
- general economic conditions.

Any dilution of, or decrease or delay of any accretion to, our earnings per share could cause the price of our common

stock to decline.

The combined Halliburton and Baker Hughes company will record goodwill that could become impaired and

adversely affect the combined company’s operating results.

The acquisition will be accounted for as an acquisition by us in accordance with accounting principles generally

accepted in the United States. Under the acquisition method of accounting, the assets and liabilities of Baker Hughes will be
recorded, as of the acquisition closing date, at their respective fair values and added to those of Halliburton. Our reported
financial condition and results of operations issued after completion of the acquisition will reflect Baker Hughes balances and
results after completion of the acquisition, but will not be restated retroactively to reflect the historical financial position or
results of operations of Baker Hughes for periods prior to the acquisition. Under the acquisition method of accounting, the total
purchase price will be allocated to Baker Hughes’s tangible assets and liabilities and identifiable intangible assets based on their
fair values as of the acquisition closing date. The excess of the purchase price over those fair values will be recorded as
goodwill. We and Baker Hughes expect that the acquisition will result in the creation of goodwill based upon the application of
the acquisition method of accounting. To the extent the value of goodwill or intangibles becomes impaired, which is more
likely during adverse market conditions similar to the current environment, the combined company may be required to incur
material charges relating to such impairment. Such a potential impairment charge could have a material adverse impact on the
combined company’s operating results.

The pendency of the Baker Hughes acquisition could adversely affect us.
In connection with the pending acquisition, some of our suppliers and customers may delay or defer sales and
purchasing decisions, which could negatively impact revenues, earnings and cash flows regardless of whether the acquisition is
completed. We have agreed in the merger agreement to refrain from taking certain actions with respect to our business and
financial affairs during the pendency of the acquisition, which restrictions have been, and could continue to be, in place for an
extended period of time if completion of the acquisition is delayed and could adversely impact our financial condition, results
of operations or cash flows.

The combined Halliburton and Baker Hughes enterprise’s indebtedness following the acquisition will be greater

than Halliburton’s existing indebtedness. Therefore, it may be more difficult for the combined enterprise to pay or refinance
its debts or take other actions, and the combined enterprise may need to divert its cash flow from operations to debt service
payments.

In connection with the acquisition, we will incur additional debt to pay the merger consideration and transaction

expenses and the indebtedness of the combined enterprise will increase as a result of Baker Hughes’s outstanding debt.
Halliburton’s total liabilities as of December 31, 2015 were approximately $21.4 billion, including $15.3 billion of long-term
debt (including current maturities), which includes $7.5 billion aggregate principal amount of senior notes issued in November
2015 to finance a portion of the merger consideration. Baker Hughes’s total liabilities as of December 31, 2015 were
approximately $7.7 billion, including $4.0 billion of long-term debt (including current maturities). We could incur additional
debt or use cash on hand to finance the remainder of the cash portion of the merger consideration. If the Baker Hughes
acquisition is not completed, we will be required to redeem $2.5 billion of the senior notes issued in November 2015 at a price
of 101% of their principal amount. See Note 8 to the consolidated financial statements for further information about debt
financing for the pending acquisition. The combined enterprise’s debt service obligations with respect to this increased

indebtedness could have an adverse impact on its earnings and cash flows, which after the acquisition would include the
earnings and cash flows of Baker Hughes, for as long as the indebtedness is outstanding.

The combined enterprise’s increased indebtedness could also have important consequences to holders of our common

stock. For example, it could:

- make it more difficult for the combined enterprise to pay or refinance its debts as they become due during adverse

economic and industry conditions because any decrease in revenues could cause the combined enterprise to not have
sufficient cash flows from operations to make its scheduled debt payments;

- limit the combined enterprise’s flexibility to pursue other strategic opportunities or react to changes in its business

and the industry in which it operates and, consequently, place the combined enterprise at a competitive disadvantage
to its competitors with less debt;

- require a substantial portion of the combined enterprise’s cash flows from operations to be used for debt service

payments, thereby reducing the availability of its cash flow to fund working capital, capital expenditures,
acquisitions, dividend payments and other general corporate purposes;

- result in a downgrade in the rating of our indebtedness, which could limit our ability to borrow additional funds and
increase the interest rates applicable to our indebtedness (after the announcement of the acquisition, Standard &
Poor’s Ratings Services placed all of our ratings on negative watch, and all of Baker Hughes’s ratings on negative
watch, and in October 2015 Moody's placed all of our ratings on review for downgrade);

- result in higher interest expense in the event of increases in interest rates since some of our borrowings are, and will

continue to be, at variable rates of interest; or

- require the combined enterprise to repatriate foreign earnings to meet liquidity demands, resulting in a tax payment

that may not be accrued for.

Based upon current levels of operations, we expect the combined enterprise to be able to generate sufficient cash on a

consolidated basis to make all of the principal and interest payments when such payments are due under our existing credit
facilities, indentures and other instruments governing our outstanding indebtedness, and the indebtedness of Baker Hughes that
may remain outstanding after the acquisition, but there can be no assurance that the combined enterprise will be able to repay or
refinance such borrowings and obligations.

Following the Baker Hughes acquisition, the combined company may encounter difficulties in integrating

Halliburton's and Baker Hughes's businesses and realizing the anticipated benefits of the acquisition.

The acquisition involves the combination of two companies which currently operate as independent public companies.
The combined company will be required to devote management attention and resources to integrating its business practices and
operations, and prior to the acquisition, management attention and resources will be required to plan for such integration.
Potential difficulties the combined company may encounter in the integration process include the following:

- the inability to successfully integrate the respective businesses of the two companies in a manner that permits the
combined company to achieve the cost savings and operating synergies anticipated to result from the acquisition,
which could result in the anticipated benefits of the acquisition not being realized partly or wholly in the time frame
currently anticipated or at all;

- lost sales and customers as a result of certain customers of either or both of the two companies deciding not to do
business with the combined company, or deciding to decrease their amount of business in order to reduce their
reliance on a single company;

- integrating personnel from the two companies while maintaining focus on providing consistent, high quality

products and services;

- potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the

acquisition; and

- performance shortfalls at one or both of the two companies as a result of the diversion of management’s attention

caused by completing the acquisition and integrating the companies’ operations.

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.

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 the Gulf of Mexico for the lease operator, BP Exploration and Production, Inc. (BP). We performed a variety
of services on that well for BP. There were eleven fatalities and a number of injuries as a result of the Macondo well incident.
Numerous lawsuits relating to the Macondo well incident and alleging damages arising from the blowout were filed

against various parties, including BP, Transocean and us, most of which were consolidated in a Multi-District Litigation (MDL)
proceeding. In addition, the Bureau of Safety and Environmental Enforcement has issued a notification of Incidents of
Noncompliance (INCs) to us relating to the Macondo well incident. We understand that regulations in effect at the time of the
alleged violations provide for fines of up to $35,000 per day per violation.

Although the MDL proceeding has concluded and we, BP, Transocean and the plaintiff’s steering committee in the

MDL proceeding have settled all claims against each other, the MDL rulings are still subject to appeal and the settlements are
subject to court approval and other conditions before they become effective. In addition, we have appealed the INCs, but the
appeal has been suspended pending final resolution, including appeals, of the MDL. If the MDL court’s ruling that we were not
grossly negligent is overturned on appeal, and our settlement is not approved, liabilities resulting from the Macondo well
incident could have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial
condition. We are unable to predict whether or when the court will approve our MDL settlement or whether or when the
conditions of our MDL Settlement will be satisfied.

For additional information relating to the Macondo well incident, our MDL Settlement, the status of the MDL and the

INCs, see Note 9 to the consolidated financial statements.

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, other armed conflict, and sanctions;
• inflation; and
• currency fluctuations, devaluations, and conversion restrictions; and

- governmental actions that may:

• result in expropriation and nationalization of our assets in that country;
• result in confiscatory taxation or other adverse tax policies;
• limit or disrupt markets or our operations, restrict payments, or limit the movement of funds;
• result in the deprivation of contract rights; and
• result in the inability to obtain or retain licenses required for operation.

For example, due to the unsettled political conditions in many oil-producing countries, our operations, revenue, and

profits are subject to the adverse consequences of war, the effects of terrorism, civil unrest, strikes, currency controls, and
governmental actions. These and other risks described above could result in the loss of our personnel or assets, cause us to
evacuate our personnel from certain countries, cause us to increase spending on security worldwide, disrupt financial and
commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic
instability in some of the geographic areas in which we operate. Areas where we operate that have significant risk include, but
are not limited to: the Middle East, North Africa, Angola, 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 becoming increasingly dependent on digital technologies and services. We use these technologies

for internal purposes, including data storage, processing, and transmissions, as well as in our interactions with customers and
suppliers. Digital technologies are subject to the risk of cyber-attacks. If our systems for protecting against cybersecurity risks
prove not to be sufficient, we could be adversely affected by, among other things: loss of or damage to intellectual property,
proprietary or confidential information, or customer, supplier, or employee data; interruption of our business operations; and
increased costs required to prevent, respond to, or mitigate cybersecurity attacks. These risks could harm our reputation and our
relationships with customers, suppliers, employees, and other third parties, and may result in claims against us. In addition,
these risks could have a material adverse effect on our business, consolidated results of operations, and consolidated financial
condition.

Our operations outside the United States require us to comply with a number of United States and international

regulations, violations of which could have a material adverse effect on our business, consolidated results of operations, and
consolidated financial condition.

Our operations outside the United States require us to comply with a number of United States and international

regulations. For example, our operations in countries outside the United States are subject to the United States Foreign Corrupt
Practices Act (FCPA), which prohibits United States companies and their agents and employees from providing anything of
value to a foreign official for the purposes of influencing any act or decision of these individuals in their official capacity to
help obtain or retain business, direct business to any person or corporate entity, or obtain any unfair advantage. Our activities
create the risk of unauthorized payments or offers of payments by our employees, agents, or joint venture partners that could be
in violation of anti-corruption laws, even though 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 may result in internal,
independent, or government investigations. Violations of anti-corruption laws may result in severe criminal or civil sanctions,
and we may be subject to other liabilities, which could have a material adverse effect on our business, consolidated results of
operations, and consolidated financial condition.

In addition, the shipment of goods, services, and technology across international borders subjects us to extensive trade

laws and regulations. Our import activities are governed by the unique customs laws and regulations in each of the countries
where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods,
services and technology and impose related export recordkeeping and reporting obligations. Governments may also impose
economic sanctions against certain countries, persons, and entities that may restrict or prohibit transactions involving such
countries, persons and entities, which may limit or prevent our conduct of business in certain jurisdictions. During 2014, the
United States and European Union imposed sectoral sanctions directed at Russia’s oil and gas industry. Among other things,
these sanctions restrict the provision of goods, services, and technology in support of exploration or production for deep water,
Arctic offshore, or shale projects that have the potential to produce oil in Russia. These sanctions resulted in our winding down
and ending work on two projects in Russia in 2014, and have prevented us from pursuing certain other projects in Russia. Any
expansion of sanctions against Russia’s oil and gas industry could further hinder our ability to do business in Russia, which
could have a material adverse effect on our consolidated results of operations.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control, and

economic sanctions are complex and constantly changing. These laws and regulations can cause delays in shipments and
unscheduled operational downtime. Moreover, any failure to comply with applicable legal and regulatory trading obligations
could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from governmental contracts,
seizure of shipments and loss of import and export privileges. In addition, investigations by governmental authorities 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.

Changes in, compliance with, or our failure to comply with laws in the countries in which we conduct business may
negatively impact our ability to provide services in, make sales of equipment to, and transfer personnel or equipment among
some of those countries and could have a material adverse effect on our business and consolidated results of operations.

In the countries in which we conduct business, we are subject to multiple and, at times, inconsistent regulatory
regimes, including those that govern our use of radioactive materials, explosives, and chemicals in the course of our operations.
Various national and international regulatory regimes govern the shipment of these items. Many countries, but not all, impose
special controls upon the export and import of radioactive materials, explosives, and chemicals. Our ability to do business is
subject to maintaining required licenses and complying with these multiple regulatory requirements applicable to these special
products. In addition, the various laws governing import and export of both products and technology apply to a wide range of
services and products we offer. In turn, this can affect our employment practices of hiring people of different nationalities
because these laws may prohibit or limit access to some products or technology by employees of various nationalities. Changes
in, compliance with, or our failure to comply with these laws may negatively impact our ability to provide services in, make
sales of equipment to, and transfer personnel or equipment among some of the countries in which we operate and could have a
material adverse effect on our business and consolidated results of operations.

The adoption of any future federal, state, or local laws or implementing regulations imposing reporting obligations

on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil
wells and could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial
condition.

Various federal 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 regulations that apply to hydraulic fracturing operations on wells that are subject to federal oil and gas leases and that
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. The Department of Interior has been
preliminarily enjoined from enforcing these regulations pending the outcome of a federal court challenge. If they become
effective, these regulations would establish additional levels of regulation at the federal level that could lead to operational
delays and increased operating costs. At the same time, legislation and/or regulations have been adopted in several states that
require additional disclosure regarding chemicals used in the hydraulic fracturing process but that generally include protections
for proprietary information. Legislation and/or regulations are being considered at the state and local level that could impose
further chemical disclosure or other regulatory requirements (such as restrictions on the use of certain types of chemicals or
prohibitions on hydraulic fracturing operations in certain areas) that could affect our operations. Two states (New York and
Vermont) have banned the use of high volume hydraulic fracturing. Local jurisdictions in some states have adopted ordinances

that restrict or in certain cases prohibit the use of hydraulic fracturing for oil and gas development. In addition, governmental
authorities in various foreign countries where we have provided or may provide hydraulic fracturing services have imposed or
are considering imposing various restrictions or conditions that may affect hydraulic fracturing operations.

The adoption of any future federal, state, local, or foreign laws or implementing regulations imposing reporting
obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and
oil wells and could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial
condition.

Liability for cleanup costs, natural resource damages, and other damages arising as a result of environmental laws

could be substantial and could have a material adverse effect on our liquidity, consolidated results of operations, and
consolidated financial condition.

We are exposed to claims under environmental requirements and, from time to time, such claims have been made
against us. In the United States, environmental requirements and regulations typically impose strict liability. Strict liability
means that in some situations we could be exposed to liability for cleanup costs, natural resource damages, and other damages
as a result of our conduct that was lawful at the time it occurred or the conduct of prior operators or other third parties. Liability
for damages arising as a result of environmental laws could be substantial and could have a material adverse effect on our
liquidity, consolidated results of operations, and consolidated financial condition.

We are periodically notified of potential liabilities at federal and state superfund sites. These potential liabilities may

arise from both historical Halliburton operations and the historical operations of companies that we have acquired. Our
exposure at these sites may be materially impacted by unforeseen adverse developments both in the final remediation costs and
with respect to the final allocation among the various parties involved at the sites. The relevant regulatory agency may bring
suit against us for amounts in excess of what we have accrued and what we believe is our proportionate share of remediation
costs at any superfund site. We also could be subject to third-party claims, including punitive damages, with respect to
environmental matters for which we have been named as a potentially responsible party.

Failure on our part to comply with, and the costs of compliance with, applicable health, safety, and environmental

requirements could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated
financial condition.

Our business is subject to a variety of health, safety, and environmental laws, rules, and regulations in the United
States and other countries, including those covering hazardous materials and requiring emission performance standards for
facilities. For example, our well service operations routinely involve the handling of significant amounts of waste materials,
some of which are classified as hazardous substances. We also store, transport, and use radioactive and explosive materials in
certain of our operations. Applicable regulatory requirements include, for example, those concerning:

- the containment and disposal of hazardous substances, oilfield waste, and other waste materials;
- the importation and use of radioactive materials;
- the use of underground storage tanks;
- the use of underground injection wells; and
- the protection of worker safety both onshore and offshore.
These and other requirements generally are becoming increasingly strict. Sanctions for failure to comply with the

requirements, many of which may be applied retroactively, may include:

- administrative, civil, and criminal penalties;
- revocation of permits to conduct business; and
- corrective action orders, including orders to investigate and/or clean up contamination.
Failure on our part to comply with applicable environmental requirements could have a material adverse effect on our

liquidity, consolidated results of operations, and consolidated financial condition. We are also exposed to costs arising from
regulatory compliance, including compliance with changes in or expansion of applicable regulatory requirements, which could
have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate
change could have a negative impact on our business and may result in additional compliance obligations with respect to
the release, capture, and use of carbon dioxide that could have a material adverse effect on our liquidity, consolidated
results of operations, and consolidated financial condition.

Changes in environmental requirements related to greenhouse gases and climate change may negatively impact

demand for our services. For example, oil and natural gas exploration and production may decline as a result of environmental
requirements, including land use policies responsive to environmental concerns. State, national, and international governments
and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of
greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and

natural gas industry, existing or future laws, regulations, treaties, or international agreements related to greenhouse gases and
climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our
business if such laws, regulations, treaties, or international agreements reduce demand for oil and natural gas. Likewise, such
restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of carbon
dioxide that could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial
condition.

Trends in oil and natural gas prices affect the level of exploration, development, and production activity of our

customers and the demand for our services and products, which could have a material adverse effect on our business,
consolidated results of operations, and consolidated financial condition.

Demand for our services and products is particularly sensitive to the level of exploration, development, and production

activity of, and the corresponding capital spending by, oil and natural gas companies. The level of exploration, development,
and production activity is directly affected by trends in oil and natural gas prices, which historically have been volatile and are
likely to continue to be volatile.

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of

and demand for oil and natural gas, market uncertainty, and a variety of other economic factors that are beyond our control.
Crude oil prices have declined significantly since 2014, with West Texas Intermediate (WTI) oil spot prices declining from a
high of $108 per barrel in June 2014 to a low of $27 per barrel in January 2016, a level which has not been experienced since
2003. Crude oil prices are not forecast to improve significantly during 2016. We anticipate 2016 will be another challenging
year for us, as our customers continue to make downward revisions to their operating budgets. Therefore, we expect a
continued reduction in activity coupled with pricing pressures, and corresponding reductions in revenue and operating
performance in 2016. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of
Operations - Business Environment and Results of Operations.”

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. Should current market conditions worsen or persist for an extended period of time, we may be
required to record additional asset impairments, including an impairment of the carrying value of our goodwill. Such a potential
impairment charge could have a material adverse impact on our operating results. Even the perception of longer-term lower oil
and natural gas prices by oil and natural gas companies can similarly reduce or defer major expenditures given the long-term
nature of many large-scale development projects.

Factors affecting the prices of oil and natural gas include:
- the level of supply and demand for oil and natural gas, especially demand for natural gas in the United States;
- governmental regulations, including the policies of governments regarding the exploration for and production and

development of their oil and natural gas reserves;

- weather conditions and natural disasters;
- worldwide political, military, and economic conditions;
- the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;
- oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
- the cost of producing and delivering oil and natural gas; and
- potential acceleration of the development of alternative fuels.

Our business is dependent on capital spending by our customers, and reductions in capital spending could have a

material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

Our business is directly affected by changes in capital expenditures by our customers, and reductions in their capital
spending could reduce demand for our services and products and have a material adverse effect on our business, consolidated
results of operations, and consolidated financial condition. Some of the items that may impact our customer's capital spending
include:

- oil and natural gas prices, including volatility of oil and natural gas prices and expectations regarding future prices;
- the inability of our customers to access capital on economically advantageous terms;
- the consolidation of our customers;
- customer personnel changes; and
- adverse developments in the business or operations of our customers, including write-downs of reserves and

borrowing base reductions under customer credit facilities.

As a result of the decreases in commodity prices, many of our customers reduced capital spending in 2015 and have

continued a reduction in their capital spending budgets for 2016. We expect that further reductions in commodity prices or
prices remaining at current levels for a prolonged period of time may result in further capital budget reductions in the future.

Our business could be materially and adversely affected by severe or unseasonable weather where we have

operations.

Our business could be materially and adversely affected by severe weather, particularly in the Gulf of Mexico, Russia,

and the North Sea. Some experts believe global climate change could increase the frequency and severity of extreme weather
conditions. Repercussions of severe or unseasonable weather conditions may include:

- evacuation of personnel and curtailment of services;
- weather-related damage to offshore drilling rigs resulting in suspension of operations;
- weather-related damage to our facilities and project work sites;
- inability to deliver materials to jobsites in accordance with contract schedules;
- decreases in demand for natural gas during unseasonably warm winters; and
- loss of productivity.

Changes in or interpretation of tax law and currency/repatriation control could impact the determination of our

income tax liabilities for a tax year.

We have operations in approximately 80 countries. Consequently, we are subject to the jurisdiction of a significant

number of taxing authorities. The income earned in these various jurisdictions is taxed on differing bases, including net income
actually earned, net income deemed earned, and revenue-based tax withholding. The final determination of our income tax
liabilities involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction, as well as the
significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and
nature of income earned and expenditures incurred. Changes in the operating environment, including changes in or
interpretation of tax law and currency/repatriation controls, could impact the determination of our income tax liabilities for a
tax year.

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 restricted or limited trading markets for
their local currencies. We may accumulate cash in those geographies, but we may be limited in our ability to convert our profits
into United States dollars or to repatriate the profits from those countries. 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 10 to the consolidated financial statements.

Our failure to protect our proprietary information and any successful intellectual property challenges or

infringement proceedings against us could materially and adversely affect our competitive position.

We rely on a variety of intellectual property rights that we use in our services and products. We may not be able to
successfully preserve these intellectual property rights in the future, and these rights could be invalidated, circumvented, or
challenged. In addition, the laws of some foreign countries in which our services and products may be sold do not protect
intellectual property rights to the same extent as the laws of the United States. Our failure to protect our proprietary information
and any successful intellectual property challenges or infringement proceedings against us could materially and adversely affect
our competitive position.

If we are not able to design, develop, and produce commercially competitive products and to implement

commercially competitive services in a timely manner in response to changes in the market, customer requirements,
competitive pressures, and technology trends, our business and consolidated results of operations could be materially and
adversely affected, and the value of our intellectual property may be reduced.

The market for our services and products is characterized by continual technological developments to provide better

and more reliable performance and services. If we are not able to design, develop, and produce commercially competitive
products and to implement commercially competitive services in a timely manner in response to changes in the market,
customer requirements, competitive pressures, and technology trends, our business and consolidated results of operations could
be materially and adversely affected, and the value of our intellectual property may be reduced. Likewise, if our proprietary
technologies, equipment, facilities, or work processes become obsolete, we may no longer be competitive, and our business and
consolidated results of operations could be materially and adversely affected.

If our customers delay paying or fail to pay a significant amount of our outstanding receivables, it could have a

material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

We depend on a limited number of significant customers. While none of these customers represented more than 10%

of consolidated revenue in any period presented, the loss of one or more significant customers could have a material adverse
effect on our business and our consolidated results of operations.

In most cases, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or

failing to pay our invoices. In weak economic environments, we may experience increased delays and failures due to, among
other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets. If our customers
delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our
liquidity, consolidated results of operations, and consolidated financial condition.

Our business in Venezuela subjects us to actions by the Venezuelan government, the risk of delayed payments, and

currency risks, 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. Any delays in receiving payment on our receivables from our
primary customer in Venezuela or failure to pay us a significant amount of our outstanding receivables 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 the foreign currency

exchange rate, actions of the Venezuelan government, and general economic conditions such as continued inflation and future
customer payments and spending. For further information, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Business Environment and Results of Operations - International operations - Venezuela."

Some of our customers require bids for contracts in the form of long-term, fixed pricing contracts that may require

us to assume additional risks associated with cost over-runs, operating cost inflation, labor availability and productivity,
supplier and contractor pricing and performance, and potential claims for liquidated damages.

Some of our customers, primarily NOCs, may require bids for contracts in the form of long-term, fixed pricing

contracts that may require us to provide integrated project management services outside our normal discrete business to act as
project managers as well as service providers, and may require us to assume additional risks associated with cost over-runs.
These customers may provide us with inaccurate information in relation to their reserves, which is a subjective process that
involves location and volume estimation, that may result in cost over-runs, delays, and project losses. In addition, NOCs often
operate in countries with unsettled political conditions, war, civil unrest, or other types of community issues. These issues may
also result in cost over-runs, delays, and project losses.

Providing services on an integrated basis may also require us to assume additional risks associated with operating cost
inflation, labor availability and productivity, supplier pricing and performance, and potential claims for liquidated damages. We
rely on third-party subcontractors and equipment providers to assist us with the completion of these types of contracts. To the
extent that we cannot engage subcontractors or acquire equipment or materials in a timely manner and on reasonable terms, our
ability to complete a project in accordance with stated deadlines or at a profit may be impaired. If the amount we are required to
pay for these goods and services exceeds the amount we have estimated in bidding for fixed-price work, we could experience
losses in the performance of these contracts. These delays and additional costs may be substantial, and we may be required to
compensate our customers for these delays. This may reduce the profit to be realized or result in a loss on a project.

Constraints in the supply of, prices for, and availability of transportation of raw materials can have a material

adverse effect on our business and consolidated results of operations.

Raw materials essential to our business, such as proppants, hydrochloric acid, and gels, including guar gum, are

normally readily available. Shortage of raw materials as a result of high levels of demand or loss of suppliers during market
challenges can trigger constraints in the supply chain of those raw materials, particularly where we have a relationship with a
single supplier for a particular resource. Many of the raw materials essential to our business require the use of rail, storage, and
trucking services to transport the materials to our jobsites. These services, particularly during times of high demand, may cause
delays in the arrival of or otherwise constrain our supply of raw materials. These constraints could have a material adverse
effect on our business and consolidated results of operations. In addition, price increases imposed by our vendors for raw
materials used in our business and the inability to pass these increases through to our customers could have a material adverse
effect on our business and consolidated results of operations.

Our acquisitions, dispositions, and investments may not result in anticipated benefits and may present risks not

originally contemplated, which may have a material adverse effect on our liquidity, consolidated results of operations, and
consolidated financial condition.

We continually seek opportunities to maximize efficiency and value through various transactions, including purchases

or sales of assets, businesses, investments, or joint venture interests. These transactions are intended to (but may not) result in
the realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or
income, or the reduction of risk. Acquisition transactions may 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, or acquisitions, including integration efforts, would not divert management resources;

- any dispositions, investments, or acquisitions 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.

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. A significant increase in the
wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we
must pay, or both. If either of these events were to occur, our cost structure could increase, our margins could decrease, and any
growth potential could be impaired.

The loss or unavailability of any of our executive officers or other key employees could have a material adverse

effect on our business.

We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss

or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.

Item 1(b). Unresolved Staff Comments.

None.

Item 2. Properties.

We own or lease numerous properties in domestic and foreign locations. Our principal properties include
manufacturing facilities, research and development laboratories, technology centers, and corporate offices. We also have
numerous small facilities that include sales, project, and support offices and bulk storage facilities throughout the world. All of
our owned properties are unencumbered.

The following locations represent our major facilities by segment:
Completion and Production: Arbroath, United Kingdom; Johor Bahru, Malaysia; and Lafayette, Louisiana.
Drilling and Evaluation: Alvarado, Texas; Nisku, Canada; and The Woodlands, Texas.
Shared/corporate facilities: Carrollton, Texas; Denver, Colorado; Dhahran, Saudi Arabia; Dubai, United Arab Emirates

(corporate executive offices); Duncan, Oklahoma; Houston, Texas (corporate executive offices); Kuala Lumpur, Malaysia;
London, England; Moscow, Russia; Panama City, Panama; Pune, India; Rio de Janeiro, Brazil; Singapore; and Stavanger,
Norway.

We believe all properties that we currently occupy are suitable for their intended use.

Item 3. Legal Proceedings.

Information related to Item 3. Legal Proceedings is included in Note 9 to the consolidated financial statements.

Item 4. Mine Safety Disclosures.

Our barite and bentonite mining operations, in support of our fluid services business, are subject to regulation by the

federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning
mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and
Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this annual report.

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 77 of this annual report. Quarterly cash dividends on our common stock, which were paid in
March, June, September, and December of each year, were $0.15 per share for the first three quarters of 2014, and $0.18 per
share in the fourth quarter of 2014 and all four quarters of 2015. The declaration and payment of future dividends will be at the
discretion of the Board of Directors and will depend on, among other things, future earnings, general financial condition and
liquidity, success in business activities, capital requirements, and general business conditions. Subject to Board of Directors
approval, our intention is to pay dividends representing at least 15% to 20% of our net income on an annual basis.

The following graph and table compare total shareholder return on our common stock for the five-year period ended

December 31, 2015, 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, 2010, 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

2010
100.00 $
100.00
100.00

2011

2012

85.31 $
89.45
102.11

86.73 $
92.26
118.45

2013
128.36 $
121.15
156.82

2014
100.63 $
95.32
178.28

2015

88.69
71.30
180.75

At January 29, 2016, we had 13,484 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, 2015.

Period

October 1 - 31
November 1 - 30
December 1 - 31
Total

Total Number
of Shares
Purchased (a)
34,214
60,838
166,766
261,818

Average
Price Paid
per Share
$38.54
$38.65
$37.54
$37.93

Total Number
of Shares
Purchased as
Part of Publicly
Announced Plans
or Programs (b)
—
—
—
—

Maximum
Number (or
Approximate
Dollar Value) of
Shares that may yet
be Purchased Under
the Program (b)
$5,700,004,373
$5,700,004,373
$5,700,004,373

(a) All of the 261,818 shares purchased during the three-month period ended December 31, 2015 were acquired from

employees in connection with the settlement of income tax and related benefit withholding obligations arising from
vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common
stock.

(b) Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the fourth
quarter of 2015, we did not repurchase shares of our common stock pursuant to that plan. We have authorization
remaining to repurchase up to a total of approximately $5.7 billion of our common stock.

Item 6. Selected Financial Data.

Information related to selected financial data is included on page 76 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 21 through 41 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 40 of this annual report and Note 14 to the consolidated
financial statements on page 69 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, 2015, 2014, and 2013
Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014, and 2013
Consolidated Balance Sheets at December 31, 2015 and 2014
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014, and 2013
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2015, 2014, and 2013
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.

Item 9(a). Controls and Procedures.

Page No.
42
43
45
46
47
48
49
50
76
77

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, 2015 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, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial
reporting.

See page 42 for Management’s Report on Internal Control Over Financial Reporting and page 44 for Report of

Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.

Item 9(b). Other Information.

None.

HALLIBURTON COMPANY
Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE OVERVIEW

Pending acquisition of Baker Hughes
In November 2014, we and Baker Hughes entered into a merger agreement under which, subject to the conditions set
forth in the merger agreement, we will acquire all the outstanding shares of Baker Hughes in a stock and cash transaction. The
acquisition is expected to create a leading global oilfield services company and combine the companies’ product and service
capabilities to deliver exceptional depth and breadth of solutions to our customers. We are continuing our discussions with
competition authorities to obtain approval of the acquisition and recently offered an enhanced set of divestitures in an effort to
resolve competition-related concerns. We have agreed with Baker Hughes to extend the period to obtain required regulatory
approvals to no later than April 30, 2016, and remain focused on completing the transaction as early as possible in 2016. See
Note 2 to the consolidated financial statements for further information about the pending acquisition and Item 1(a). “Risk
Factors” for risks associated with the pending acquisition.

Financial results
We experienced a decline in revenue and operating income during 2015, as compared to 2014, as a result of the

depressed crude oil pricing environment and its corresponding negative impact on activity levels and pricing for our products
and services. The industry experienced an unprecedented decline in North America stimulation activity during 2015, which
significantly impacted our financial results. From its peak in November 2014 through December 31, 2015, the United States
land rig count declined approximately 64%, which in turn has resulted in pricing pressure across the services industry.

We generated $23.6 billion of revenue during 2015, a 28% decrease from the $32.9 billion of revenue generated in
2014. We reported an operating loss of $165 million in 2015, as compared to operating income of $5.1 billion in 2014. This
decrease was due to a decline in activity and pricing in most of our product services lines, particularly stimulation activity in
the United States land market, as well as our company-wide cost mitigation activities, as a result of which we recorded $2.2
billion of impairments and other charges during 2015. These charges were recorded primarily as a result of the downturn in the
energy market, and consisted of equipment write-offs, asset impairments, expenses and write-downs related to idle equipment,
impairments of intangible assets, inventory write-downs, severance costs, country and facility closures, and other items. We
took actions to reduce our cost structure, which included a global headcount reduction of approximately 25% since the
beginning of 2015, to help mitigate the current market conditions that we are experiencing. See Note 3 to the consolidated
financial statements for further information about these charges.

Business outlook
Reduced commodity prices made 2015 a challenging year, as this created widespread pricing pressure and activity

reductions on a global basis. We have taken actions throughout 2015 to help mitigate the effect on our business during the
downturn in the energy market, and we will continue to evaluate our cost structure and make further adjustments as required.
In North America, we experienced pricing pressures, which impacted our margins. Lower commodity prices resulted

in unprecedented reductions in rig count over the course of 2015, which in turn resulted in substantial pricing pressure across
all of our product service lines. While our global revenue declined 28% in 2015 as compared to 2014, revenue in North
America declined 39%. We anticipate 2016 being another challenging year for us in North America, and we will continue to
adapt our cost structure to market conditions, which we believe will position us well when the market ultimately recovers.

The international markets have been more resilient than North America, however they are not immune to the impacts

of the lower commodity price environment. We experienced pricing concessions and activity reductions in our international
operations throughout 2015, the impact of which was mitigated by our cost management initiatives. Despite a 16% year over
year reduction in our revenues, we were able to keep operating margins relatively stable during 2015, primarily due to a
relentless focus on cost management. We have continued to work with customers during this downturn to improve project
economics through technology and improved operating efficiency, but expect margins to be negatively impacted by lower
activity levels and pricing pressure throughout 2016. Going into 2016, we expect all international regions to experience activity
declines and price reductions again due to challenging economics and budget constraints, although the Middle East/Asia region
is expected to be the most resilient, as recent mature field project awards are anticipated to move forward.

While the intensity and duration of the current market downturn is uncertain, we are continuing to execute on our two-
pronged strategy in the downturn. The first part being to control what we can control in the short term, and the second is to look
beyond the cycle and prepare for the recovery. We will make further adjustments as required to adjust to market conditions.
Manufacturing our own equipment provides us with flexibility to adjust our capital spend based on our visibility of the market.
Given the continued decline in activity levels, we further reduced our capital budget for 2016 to an estimated $1.6 billion,
representing a 27% decline compared to 2015. We continue to believe in the strength of the long-term fundamentals of our
business. Despite the worldwide activity declines in 2015 and challenges we expect to face going into 2016, energy demand is
still anticipated to increase over the long term.

We plan to continue executing the following strategies in 2016:
- directing capital and resources into strategic growth markets, including unconventional plays, mature fields, and

deepwater;

- leveraging our broad technology offerings to provide value to our customers through integrated solutions and to

enable them to more efficiently drill and complete their wells;

- exploring additional opportunities for acquisitions that will enhance or augment our current portfolio of services and

products, including those with technologies or distribution networks in areas where we do not already have
significant operations;

- investing in technology that will help our customers reduce reservoir uncertainty and increase operational efficiency;
- improving working capital, and managing our balance sheet to maximize our financial flexibility; and
- continuing to seek ways to be one of the most cost-efficient service providers in the industry by maintaining capital

discipline and leveraging our scale and breadth of operations.

Our operating performance and business outlook are described in more detail in “Business Environment and Results of

Operations.”

Financial markets, liquidity, and capital resources
We believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any

near-term negative impact on our operations from adverse market conditions. In November 2015, we issued $7.5 billion
aggregate principal amount of senior notes with the intention of using the net proceeds to finance a portion of the cash
consideration of the Baker Hughes acquisition. We may incur additional debt or use cash on hand to finance the remainder of
the cash portion of the merger consideration. For additional information on market conditions and the pending acquisition of
Baker Hughes, see “Liquidity and Capital Resources,” “Business Environment and Results of Operations,” Note 2 to the
consolidated financial statements, and Note 8 to the consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES

As of December 31, 2015, we had $10.1 billion of cash and equivalents, compared to $2.3 billion at December 31,

2014. Additionally, at December 31, 2015, we held $96 million of investments in fixed income securities held offshore
compared to $103 million at December 31, 2014. These securities are reflected in "Other current assets" and "Other assets" in
our consolidated balance sheets. As of December 31, 2015, approximately $1.5 billion of the $10.1 billion of cash and
equivalents was held by our foreign subsidiaries, of which $861 million would be subject to United States tax if repatriated.
However, our intent is to permanently reinvest these funds outside of the United States and our current plans do not suggest a
need to repatriate them to fund our United States operations.

Significant sources and uses of cash
We had the following significant sources and uses of cash during the year ended December 31, 2015:
- Cash flows from operating activities were $2.9 billion in 2015.
- In November 2015, we received $7.4 billion in net proceeds from the issuance of debt. We intend to use the net
proceeds of this offering for general corporate purposes, including to finance a portion of the cash consideration
component of our pending Baker Hughes acquisition and to pay related fees and expenses. See Note 8 to the
consolidated financial statements for further information.

- Capital expenditures were $2.2 billion in 2015. The capital expenditures in 2015 were predominantly made in our
Production Enhancement, Cementing, Sperry Drilling, Production Solutions, and Wireline and Perforating product
service lines.

- Our primary components of net working capital (receivables, inventories, and accounts payable) decreased during
the year by a net $1.0 billion, primarily due to decreased business activity driven by current market conditions.

- We paid $614 million of dividends to our shareholders in 2015.
- During the third quarter of 2015, we made the second installment payment of $333 million related to the settlement
we reached during 2014 for the Macondo well incident. See Note 9 to the consolidated financial statements for
further information.

- We sold $168 million of property, plant, and equipment during 2015.

Future sources and uses of cash
We issued $7.5 billion aggregate principal amount of senior notes in November 2015 for general corporate purposes,

including to finance a portion of the cash consideration component of our pending acquisition of Baker Hughes. We may
finance the remainder of the cash portion of the consideration for the acquisition with cash on hand, additional debt financing,
or a combination thereof. We have $1.1 billion remaining under the senior unsecured bridge facility commitment we obtained
for the acquisition, although we may obtain other debt financing in lieu of utilizing all or a portion of the bridge facility. We
have not drawn any amounts under this facility as of December 31, 2015. See Note 8 to the consolidated financial statements
for further information. Additionally, we expect to receive cash proceeds from the sale of the businesses we are currently
marketing for sale as part of the regulatory review of the pending Baker Hughes acquisition. If the acquisition is not completed,
we could be required to pay Baker Hughes a termination fee of $3.5 billion in certain circumstances where the termination of
the merger agreement is related to failures to obtain regulatory clearances. See Note 2 to the consolidated financial statements
for further information about the pending acquisition and related divestitures.

We manufacture our own equipment, which allows us flexibility to increase or decrease our capital expenditures based

on market conditions. Capital spending for 2016 is currently expected to be approximately $1.6 billion, a reduction of
approximately $600 million, or 27%, from 2015 primarily due to the current market environment. The capital expenditures plan
for 2016 is primarily directed towards our Production Enhancement, Production Solutions, Wireline and Perforating, and
Cementing product service lines.

During 2014, we reached an agreement, subject to court approval, to settle a substantial portion of the plaintiffs' claims

asserted against us relating to the Macondo well incident. We have $472 million of Macondo-related liabilities as of
December 31, 2015, of which $400 million is expected to be paid in 2016. See Note 9 to the consolidated financial statements
for further information.

Subject to Board of Directors approval, our intention is to pay dividends representing at least 15% to 20% of our net
income on an annual basis. Currently, our quarterly dividend rate is $0.18 per share, or approximately $154 million per quarter.
Our Board of Directors has authorized a program to repurchase our common stock from time to time. Approximately

$5.7 billion remains authorized for repurchases as of December 31, 2015, and may be used for open market and other share
purchases. There were no repurchases made under the program during the year ended December 31, 2015.

We had $322 million of gross unrecognized tax benefits at December 31, 2015, of which we estimate $152 million

may require a cash payment. We estimate that $148 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.

Contractual obligations
The following table summarizes our significant contractual obligations and other long-term liabilities as of

December 31, 2015:

Millions of dollars
Long-term debt (a)
Interest on debt (b)
Operating leases
Purchase obligations (c)
Other long-term liabilities (d)
Total

Payments Due
2018

2017

2019

2020 Thereafter

2016

659 $
711
257
873
37

79 $

696
171
391
10

823 $ 1,013 $ 1,261 $
692
132
152
10

596
60
29
9

659
96
28
10

$ 2,537 $ 1,347 $ 1,809 $ 1,806 $ 1,955 $

11,643 $
9,446
228
50
32
21,399 $

Total
15,478
12,800
944
1,523
108
30,853

(a) Represents principal amounts of long-term debt, including current maturities, which excludes any unamortized debt

issuance costs and discounts. See Note 8 to the consolidated financial statements.

(b) Interest on debt includes 81 years of interest on $300 million of debentures at 7.6% interest that become due in 2096.
(c) Amount in 2016 primarily represents certain purchase orders for goods and services utilized in the ordinary course of

our business.

(d) Includes capital lease obligations and pension funding obligations. Amounts for pension funding obligations, which

include international plans and are based on assumptions that are subject to change, are only included for 2016 as we
are currently not able to reasonably estimate our contributions for years after 2016.

Other factors affecting liquidity
Financial position in current market. As of December 31, 2015, we had $10.1 billion of cash and equivalents, $96

million in fixed income investments, and a total of $3.0 billion of available committed bank credit under our revolving credit
facility. In July 2015, we executed a new five-year revolving credit agreement with an initial capacity of $3.0 billion, increasing
to $4.5 billion upon closing of the pending Baker Hughes acquisition. Furthermore, we have no financial covenants or material
adverse change provisions in our bank agreements, and our debt maturities extend over a long period of time. Although a
portion of earnings from our foreign subsidiaries is reinvested outside the United States indefinitely, we do not consider this to
have a significant impact on our liquidity. We currently believe that cash on hand, cash flows generated from operations and our
available credit facility will provide sufficient liquidity to manage our global cash needs in 2016, including capital
expenditures, working capital investments, dividends, if any, and contingent liabilities.

Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which

approximately $2.0 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2015.
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 (Moody's) and A with
Standard & Poor’s. The credit ratings on our short-term debt remain P-1 with Moody’s and A-1 with Standard & Poor’s. While
these credit ratings remained unchanged during 2015, after the 2014 announcement of the pending Baker Hughes acquisition,
Standard & Poor’s placed all of our ratings on negative watch, and in October 2015 Moody's placed all of our ratings on review
for downgrade.

Customer receivables. In line with industry practice, we bill our customers for our services in arrears and are,
therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience
increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers’ cash flow from
operations and their access to the credit markets as well as unsettled political conditions. If our customers delay paying or fail
to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity,
consolidated results of operations, and consolidated financial condition. See “Business Environment and Results of Operations
– International operations – Venezuela” for further discussion related to receivables from our primary customer in Venezuela.

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 80 countries throughout the world to provide a comprehensive range of services and

products to the upstream oil and natural gas industry. A significant amount of our consolidated revenue is derived from the sale
of services and products to major, national, and independent oil and natural gas companies worldwide. The industry we serve is
highly competitive with many substantial competitors in each segment of our business. In 2015, 2014, and 2013, based on the
location of services provided and products sold, 44%, 51%, and 49% of our consolidated revenue was from the United States.
No other country accounted for more than 10% of our revenue during these periods.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil

unrest, force majeure, war or other armed conflict, sanctions, expropriation or other governmental actions, inflation, changes in
foreign currency exchange rates, foreign currency exchange restrictions, and highly inflationary currencies, as well as other
geopolitical factors. We believe the geographic diversification of our business activities reduces the risk that loss of operations
in any one country, other than the United States, would be materially adverse to our consolidated results of operations.

Activity within our business segments is significantly impacted by spending on upstream exploration, development,
and production programs by our customers. Also impacting our activity is the status of the global economy, which impacts oil
and natural gas consumption.

Some of the more significant determinants of current and future spending levels of our customers are oil and natural
gas prices, global oil supply, the world economy, the availability of credit, government regulation, and global stability, which
together drive worldwide drilling activity. Due to improved drilling and completion efficiencies as more of our customers move
to multi-well pad drilling, our financial performance in North America is impacted by well count in the North America market.
Additionally, our financial performance is significantly affected by oil and natural gas prices and worldwide rig activity, which
are summarized in the following tables.

The following table shows the average oil and natural gas prices for West Texas Intermediate (WTI), United Kingdom

Brent crude oil, and Henry Hub natural gas:

Oil price - WTI (1)
Oil price - Brent (1)
Natural gas price - Henry Hub (2)

2015

2014

2013

48.69 $
52.36
2.63

93.37 $
99.04
4.39

97.99
108.71
3.73

(1) Oil price measured in dollars per barrel
(2) Natural gas price measured in dollars per million British thermal units (Btu), or MMBtu

The historical average rig counts based on the weekly 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

2015

2014

2013

943
35
978

189
2
191

884
283
1,167
2,336
2,016
320

1,804
57
1,861

378
2
380

1,011
326
1,337
3,578
3,193
385

1,705
56
1,761

352
2
354

978
318
1,296
3,411
3,035
376

Oil vs. Natural Gas
United States (incl. Gulf of Mexico):

2015

2014

2013

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

751
227
978

84
107
191

916
251
1,167
2,336
1,751
585

1,528
333
1,861

218
162
380

1,070
267
1,337
3,578
2,816
762

1,375
386
1,761

234
120
354

1,029
267
1,296
3,411
2,638
773

2015

2014

2013

744
139
95
978

1,274
376
211
1,861

1,102
435
224
1,761

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.

WTI oil spot prices declined significantly towards the second half of 2014 from a high of $108 per barrel in June 2014,

and continued to decline throughout 2015, ranging from a high of $61 per barrel in June 2015 to a low of $35 per barrel in
December 2015. WTI oil spot prices reduced further into January 2016 to a low of $27 per barrel, a level which has not been
experienced since 2003. Brent crude oil spot prices declined from a high of $115 per barrel in June 2014, and ranged from a

high of $66 per barrel in May 2015 to a low of $35 per barrel in December 2015, and declined further to $26 per barrel in
January 2016. Crude oil prices continue to be negatively affected as the combination of robust world crude oil supply growth
and weak global demand contribute to an increase in the rate of global inventory builds.

Brent crude oil spot prices had a monthly average in December 2015 of $38 per barrel, the lowest monthly average

price since July 2004, while WTI oil spot prices averaged $37 per barrel in December 2015, the lowest monthly average price
since April 2004. Prices continued to fall as OPEC producers indicated plans to continue the policy of defending market share
in a low oil price environment and as global oil inventories continued to build. Crude oil production in the United States
averaged an estimated 9.4 million barrels per day in 2015. The expansion of export possibilities in the United States
contributed to the decreased differential between WTI and Brent crude oil spot prices, which has narrowed from an average of
$3 per barrel in the third quarter of 2015 to $2 per barrel in the fourth quarter of 2015.

According to the United States Energy Information Administration (EIA) January 2016 "Short Term Energy Outlook,"

the EIA projects that Brent prices will average $40 per barrel in 2016. The EIA also noted that price projections reflect a
scenario in which the largest inventory builds occur in the first half of 2016, keeping Brent prices below $40 per barrel through
April. Global oil demand declined during the fourth quarter of 2015 as a result of mild temperatures in the early part of the
winter in Japan, Europe and the United States, alongside weak economic sentiment in China, Brazil, Russia and other
commodity-dependent economies. Although there are no signs that point to an immediate rebalance of the market, the
International Energy Agency's (IEA) January 2016 "Oil Market Report" forecasts the 2016 global demand to average
approximately 95.7 million barrels per day, which is up 1% from 2015, driven by an increase in the Asia Pacific region, while
all other regions remain approximately the same.

The average 2015 full year Henry Hub natural gas price in the United States decreased approximately 40% from 2014

as the mild winter resulted in higher natural gas storage levels in 2015. The Henry Hub natural gas spot price averaged $1.93
per MMBtu in December, a decline of $0.73 per MMBtu, or 27%, from September. Record inventory levels, production
growth, and forecasts for a warm winter contributed to spot prices remaining low. The EIA January 2016 “Short Term Energy
Outlook” projects Henry Hub natural gas prices to average $2.65 per MMBtu in 2016. Over the long term, the EIA expects
natural gas consumption in the residential and commercial sectors to increase, offsetting the decline in the power sector.

North America operations
Volatility in oil and natural gas prices can impact our customers’ drilling and production activities. During 2015, the
average full year natural gas-directed rig count in North America decreased 161 rigs, or 33%, while the average full year oil
directed rig count decreased 911 rigs, or 52%, from 2014. In the United States land market, there was a decline of 48% in the
average rig count from 2014 levels.

The United States land rig count has dropped approximately 64% since its peak in November 2014. Price erosion for
our services continued during 2015, specifically in North America, and we believe pricing pressure will continue until activity
stabilizes. Current market conditions aside, in the long run, we believe the shift to unconventional oil and liquids-rich basins in
the United States land market will continue to drive increased service intensity. This would create higher demand in fluid
chemistry and other technologies required for these complex reservoirs, which will have positive implications for our
operations when the energy market ultimately recovers.

In the Gulf of Mexico, the average offshore rig count for 2015 was down 39% compared to 2014. Activity 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 average international rig count for 2015 decreased by 13% compared to 2014. Declining crude oil prices have

caused several of our customers to reduce their budgets and defer several new projects; however, we have continued to work
with our customers to improve project economics through technology and improved operating efficiency. Although the
international markets have been more resilient than North America, they are not immune to the impacts of the lower commodity
price environment and, therefore, our international operations could be further impacted in the near term.

Venezuela. In February 2015, the Venezuelan government created a new foreign exchange rate mechanism, called the

Marginal Currency System, or SIMADI. The new mechanism, which is the third system in a three-tier exchange control
mechanism, is a floating market rate for the conversion of Bolívares to United States dollars. The three-tier exchange rate
mechanisms are as follows: (i) the National Center of Foreign Commerce official rate of 6.3 Bolívares per United States dollar,
which remains unchanged; (ii) the SICAD I, which will continue to hold periodic auctions for specific sectors of the economy
with a rate of 13.5 Bolívares per United States dollar at December 31, 2015; and (iii) the SIMADI, which replaces the SICAD
II system with a market rate of 199 Bolívares per United States dollar at December 31, 2015.

During the first quarter of 2015, we began utilizing the SIMADI mechanism to remeasure our net monetary assets
denominated in Bolívares, which resulted in us recording a foreign currency loss of $199 million during the first quarter of
2015. As of December 31, 2015, our total net investment in Venezuela was approximately $767 million, with only $8 million of
net monetary assets denominated in Bolívares. Also, at December 31, 2015 we had $31 million of surety bond guarantees
outstanding relating to our Venezuelan operations. The United States dollar value of our net monetary assets and surety bond
guarantees have significantly declined from December 31, 2014, primarily as a result of the currency devaluation in Venezuela.

Our total outstanding trade receivables in Venezuela were $704 million, which is more than 10% of our gross trade
receivables, as of December 31, 2015, compared to $670 million, or approximately 9% of our gross trade receivables, as of
December 31, 2014. We have experienced delays in collecting payment on our receivables from our primary customer in
Venezuela, which contributed to the increase in receivables during the period. This was partially offset by a decline due to the
currency devaluation. These receivables are not disputed, and we have not historically had material write-offs relating to this
customer. Additionally, we routinely monitor the financial stability of our customers. Of the $704 million receivables in
Venezuela as of December 31, 2015, the majority of which are United States dollar-denominated receivables, $175 million has
been classified as long-term and included within “Other assets” on our consolidated balance sheets.

For additional information, see Part I, Item 1(a), “Risk Factors.”

RESULTS OF OPERATIONS IN 2015 COMPARED TO 2014

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

2015

2014

Favorable
(Unfavorable)
(6,571)
(2,666)
(9,237)

20,253 $
12,617
32,870 $

Percentage
Change

(32)%
(21)
(28)%

(39)%
(18)
(20)
(18)
(32)

(38)
(19)
(28)
2
(21)

(39)
(19)
(24)
(6)

13,688 $
1,633
2,595
2,337
20,253

4,010
2,242
2,895
3,470
12,617

17,698
3,875
5,490
5,807

(5,336)
(293)
(514)
(428)
(6,571)

(1,506)
(433)
(801)
74

(2,666)

(6,842)
(726)
(1,315)
(354)

13,682 $
9,951
23,633 $

8,352 $
1,340
2,081
1,909
13,682

2,504
1,809
2,094
3,544
9,951

10,856
3,149
4,175
5,453

OPERATING INCOME:
Millions of dollars
Completion and Production
Drilling and Evaluation
Corporate and other
Impairments and other charges

Total operating income (loss)

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

2015

2014

1,069 $
1,519
(576)
(2,177)

(165)$

230 $
186
280
373
1,069

228
254
243
794
1,519

458
440
523
1,167

Favorable
(Unfavorable)
(2,601)
(221)
(392)
(2,048)

3,670 $
1,740
(184)
(129)

5,097 $

(5,262)

2,618 $
214
389
449
3,670

598
217
300
625
1,740

3,216
431
689
1,074

(2,388)
(28)
(109)
(76)
(2,601)

(370)
37
(57)
169
(221)

(2,758)

9
(166)
93

Percentage
Change

(71)%
(13)
213
1,588

(103)%

(91)%
(13)
(28)
(17)
(71)

(62)
17
(19)
27
(13)

(86)
2
(24)
9

Consolidated revenue in 2015 decreased 28% compared to 2014, associated with widespread pricing pressure and
activity reductions on a global basis, primarily attributable to pressure pumping in North America and Europe/Africa/CIS.
Revenue outside of North America was 54% of consolidated revenue in 2015 and 46% of consolidated revenue in 2014.

We reported a consolidated operating loss of $165 million in 2015, as compared to operating income of $5.1 billion in
2014. This $5.3 billion decrease was primarily driven by a significant decline in pressure pumping activity and pricing declines
in North America as a result of the global downturn in the energy market. Also impacting consolidated operating income was
$2.2 billion of impairments and other charges recorded in 2015 and $308 million of costs related to the pending Baker Hughes
acquisition. See Note 3 to the consolidated financial statements for further information about impairments and other charges.

•

Completion and Production
Revenue declined $6.6 billion, or 32%, compared to 2014, with activity decreases across all regions, mainly North America.
North America revenue dropped 39%, across most product service lines, mainly in the United States land market, as a
•
result of steep rig count declines, pricing concessions, and reduced stimulation activity.
Latin America revenue decreased 18%, mainly due to reduced activity and pricing in Mexico, primarily associated with
pressure pumping services and production solution services, and decreased cementing activity in Colombia, Brazil, and
Ecuador.
Europe/Africa/CIS revenue fell 20%, as a result of reduced well completion services and currency weakness in Norway,
lower pressure pumping services and currency weakness in Russia, a decrease in stimulation activity in Egypt, a reduction
in completion tools sales in Kazakhstan, and decreased pipeline and process services in the United Kingdom. These
reductions were partially offset by improved completion tool sales in Nigeria.

•

• Middle East/Asia revenue declined by 18%, primarily due to decreased pressure pumping and production solution services
in Australia and Saudi Arabia, reduced activity in the majority of our product service lines in Malaysia and Indonesia, and
lower pressure pumping services and completion tool sales in China, which were partially offset by higher completion tool
sales in Saudi Arabia and United Arab Emirates, and improved pipeline and process services in China.
Revenue outside of North America was 39% of total segment revenue in 2015 and 32% of total segment revenue in 2014.

•

Operating income was $1.1 billion, a decrease of $2.6 billion, or 71% compared to 2014, driven predominantly by the decline
in North America.
•

North America operating income declined 91%, primarily due to the fall in rig counts and decreased profitability for well
completion services and stimulation activity in the United States land market.
Latin America operating income declined 13%, due to lower pressure pumping services in Argentina and Mexico, reduced
cementing services in Colombia, and lower production solution services in Mexico, which were partially offset by
increased activity across most product service lines in Venezuela.
Europe/Africa/CIS operating income fell 28% compared to 2014, mainly due to reduced cementing services in Norway and
Nigeria, lower completion tool sales in Kazakhstan and Nigeria, and lower stimulation activity in Egypt, which were
partially offset by higher stimulation activity in Angola, and increased cementing and production solution services in
Algeria.

•

• Middle East/Asia operating income dropped 17%, primarily due to decreased pressure pumping services in Australia and
Saudi Arabia, lower completion tool sales in Malaysia, and reduced activity and pricing pressure for production solution
services in Saudi Arabia, which were partially offset by increased completion tools sales in Saudi Arabia.

Drilling and Evaluation
Revenue decreased $2.7 billion, or 21%, compared to 2014, primarily due to reduced activity across most product service lines.
North America revenue declined 38%, due to a drop in activity across all product service lines, primarily as a result of
•
pricing concessions and reduced activity levels in the United States land market, and lower drilling services in the Gulf of
Mexico and Canada.
Latin America revenue decreased 19%, as a result of reduced drilling activity in Colombia and Ecuador, lower software
sales and project management services in Mexico, and reduced logging services in Mexico and Venezuela, which were
partially offset by higher fluid services in Mexico.
Europe/Africa/CIS revenue fell 28%, due to a decline in fluid services in Norway, reduced drilling activity in Angola,
Egypt, Russia, and the United Kingdom, and lower offshore services in Nigeria.

•

• Middle East/Asia revenue was relatively flat as increased project management services throughout the region and higher
drilling services in Saudi Arabia and Kuwait were partially offset by lower drilling and offshore activity in Malaysia.
Revenue outside of North America was 75% of total segment revenue in 2015 and 68% of total segment revenue in 2014.

•

Operating income was $1.5 billion, a decrease of 13% compared to 2014. All regions benefited from the cessation of
recognizing depreciation expense on assets held for sale. See Note 2 to the consolidated financial statements for further
information.
•

North America operating income was down 62% from 2014 due to a decline in activity across all product service lines,
predominately driven by the United States land market.
Latin America operating income grew 17%, mainly due to improved fluid services in Venezuela, which was partially offset
by reduced offshore activity in Brazil and lower project management services in Mexico.
Europe/Africa/CIS operating income fell 19%, primarily due to lower fluid services in Norway, reduced drilling services in
Angola, and a decrease in logging services in Nigeria, which were partially offset by higher fluid services in Kazakhstan.
• Middle East/Asia operating income increased 27%, driven by higher fluid and logging services in Saudi Arabia and Iraq,
increased project management services in Saudi Arabia, Iraq, and India, increased fluid services in India, and higher
logging services in Kuwait.

•

Corporate and other expenses increased to $576 million in 2015 compared to $184 million in 2014, primarily due to
$308 million of costs related to the pending Baker Hughes acquisition recorded in 2015, as compared to $17 million in 2014.
Additionally, in 2014, we recorded a reduction of our Macondo-related loss contingency liability and an expected insurance
recovery totaling $195 million.

Impairments and other charges. As a result of the downturn in the energy market and its corresponding impact on our
business outlook, we recorded a total of approximately $2.2 billion in company-wide charges during 2015, which consisted of
equipment write-offs, asset impairments, expenses and write-downs related to idle equipment, inventory write-downs,
impairments of intangible assets, severance costs, facility closures, and other charges. During 2014, $129 million was recorded
for impairments and other charges. See Note 3 to the consolidated financial statements for further information.

NONOPERATING ITEMS

Interest expense, net increased $64 million in 2015, compared to 2014, primarily due to fees associated with the bridge
facility commitment related to the pending acquisition of Baker Hughes and additional interest expense associated with the $7.5
billion of senior notes issued in November 2015. See Note 8 to the consolidated financial statements for further information.

Other, net was a $324 million loss in 2015, as compared to a $2 million loss in 2014, primarily due to a $199 million

foreign exchange loss we incurred in Venezuela in the first quarter of 2015 as a result of utilizing the new SIMADI currency
exchange mechanism, coupled with foreign currency exchange losses in Brazil and Argentina. See Note 3 to the consolidated
financial statements and "Business Environment and Results of Operations" for further information about Venezuela.

Effective tax rate. Our effective tax rate was 29.3% for 2015 and 27.1% for 2014. The effective tax rates in both

periods were positively impacted by lower tax rates in certain foreign jurisdictions. The effective tax rate for 2015 was also
impacted by the tax effects of the $2.2 billion of impairments and other charges, a change in mix of geographic earnings in
which we experienced low levels of United States income during the year, additional valuation allowances booked on foreign
deferred tax assets, a $199 million foreign currency exchange loss in Venezuela, and non-deductible costs related to the pending
Baker Hughes acquisition. The effective tax rate for 2014 was positively impacted by a $201 million net operating loss
valuation allowance released as a result of a reorganization of our legal entity structure in Brazil. This was partially offset by
the following other items in 2014: tax expenses related to Macondo, which was tax-effected at the United States statutory rate, a
write-off of certain prepaid tax assets recorded in Iraq, additional tax expenses related to the settlement of a research and
development credit with the United States tax authorities, and tax expenses related to other unrecognized tax benefits. See Note
10 to the consolidated financial statements for further information regarding income taxes.

RESULTS OF OPERATIONS IN 2014 COMPARED TO 2013

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

Percentage
Change

16%
6
12%

20%
3
9
11
16

6
(3)
2
18
6

16
(1)
5
15

2014

2013

20,253 $
12,617
32,870 $

Favorable
(Unfavorable)
2,747
721
3,468

17,506 $
11,896
29,402 $

13,688 $
1,633
2,595
2,337
20,253

11,417 $
1,586
2,391
2,112
17,506

4,010
2,242
2,895
3,470
12,617

17,698
3,875
5,490
5,807

3,795
2,323
2,834
2,944
11,896

15,212
3,909
5,225
5,056

2,271
47
204
225
2,747

215
(81)
61
526
721

2,486

(34)
265
751

OPERATING INCOME:
Millions of dollars
Completion and Production
Drilling and Evaluation
Corporate and other
Impairments and other charges

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

2014

2013

Favorable
(Unfavorable)
795
(30)

3,670 $
1,740
(184)
(129)

5,097 $

2,618 $
214
389
449
3,670

598
217
300
625
1,740

3,216
431
689
1,074

2,875 $
1,770
(1,507)
—

3,138 $

1,916 $
211
356
392
2,875

656
307
334
473
1,770

2,572
518
690
865

Percentage
Change

28%
(2)
(88)
100

62%

37%
1
9
15
28

(9)
(29)
(10)
32
(2)

25
(17)
—
24

1,323
(129)

1,959

702
3
33
57
795

(58)
(90)
(34)
152
(30)

644
(87)
(1)

209

Consolidated revenue in 2014 increased 12% compared to 2013, primarily as a result of higher stimulation activity in
the United States land market and increased activity in almost all of our product service lines in the Eastern Hemisphere, which
were partially offset by lower activity in Latin America. Revenue outside of North America was 46% of consolidated revenue in
2014 and 48% of consolidated revenue in 2013.

The $2.0 billion increase in consolidated operating income compared to 2013 was primarily a result of various
corporate expense items in 2013 as well as increased stimulation activity in the United States land market and growth in Middle
East/Asia in 2014, which more than offset lower activity and margins experienced in Latin America. Operating income in 2014
was positively impacted by $195 million of Macondo-related items as a result of a reduction of our loss contingency liability
and an expected insurance recovery, offset by $129 million of impairments and other charges related to severance and asset
write-offs and $17 million of Baker Hughes acquisition-related costs. Operating income in 2013 was negatively impacted by
the following pre-tax items: a $1.0 billion increase in our loss contingency liability related to Macondo and a $55 million
charge related to a charitable contribution to the National Fish and Wildlife Foundation, partially offset by a $28 million value-
added tax refund receivable in Brazil.

Completion and Production
Revenue increased 16% compared to 2013, with activity increases across all regions and predominately in North America.
•
•

North America revenue rose 20% primarily as a result of increased stimulation activity in the United States land market.
Latin America revenue improved 3%, as increased activity levels in the majority of our product service lines in Venezuela
and Argentina more than offset a decrease in stimulation activity in Mexico and lower pressure pumping activity in Brazil.
Europe/Africa/CIS revenue grew 9%, driven by strong growth across most of our product service lines in Angola and the
United Kingdom, as well as increased completion tools sales in Nigeria, which were partially offset by lower pressure
pumping activity and currency weakness in Norway.

•

• Middle East/Asia revenue improved 11% primarily due to increased activity in the majority of our product service lines in
Saudi Arabia, higher cementing activity in Thailand, and increased stimulation and artificial lift activity in Australia, which
more than offset reduced activity levels in Oman and a decline in completion tools sales in Malaysia.
Revenue outside of North America was 32% of total segment revenue in 2014 and 35% of total segment revenue in 2013.

•

Operating income increased 28% compared to 2013, driven predominantly by strong growth in North America coupled with
modest improvement in the Eastern Hemisphere.
•

North America operating income rose 37% from 2013, primarily due to increased profitability for stimulation activity in
the United States land market.
Latin America operating income was flat as improved pressure pumping activity in Argentina and increased profitability
for well intervention services in Mexico and Venezuela were offset by reduced completion tools sales and profitability in
Brazil, Mexico and Trinidad.
Europe/Africa/CIS operating income grew 9% compared to 2013, primarily due to higher completion products sales in
Nigeria, Angola and the United Kingdom, which were partially offset by decreased well completion activity and currency
weakness in Russia and Norway.

•

• Middle East/Asia operating income rose by 15% primarily due to increased profitability for the majority of our product

services lines in Saudi Arabia, which was partially offset by reduced activity levels in China and Oman.

Drilling and Evaluation
Revenue increased 6% compared to 2013, primarily due to a strong performance in the Eastern Hemisphere, primarily in Saudi
Arabia, which was partially offset by a decrease in drilling activity and consulting services in Latin America.
•

North America revenue rose by 6% due to increased fluids activity in the United States land market and higher activity in
the majority of our product service lines in the Gulf of Mexico.
Latin America revenue decreased 3%, as reduced activity across all of our product service lines in Mexico and a decline in
drilling activity in Brazil more than offset increased activity across all of our product service lines in Venezuela and
Argentina.
Europe/Africa/CIS revenue was relatively flat as increased testing activity in Angola and Nigeria was offset by decreased
drilling and fluids activity in Egypt and Libya.

•

• Middle East/Asia revenue rose 18% as a result of increased activity in all of our product services lines in Saudi Arabia and

increased demand for drilling services in Thailand and fluids activity in Australia, India and Iraq.
Revenue outside of North America was 68% of total segment revenue in both 2014 and 2013.

•

Operating income decreased 2% compared to 2013, primarily due to lower drilling activity and margins in Latin America and
lower profitability in the Europe/Africa/CIS region. This decrease was partially offset by strong activity growth in the Middle
East/Asia region.
•

North America operating income was down 9% from 2013 due to a decline in drilling services in Canada and the United
States land market.
Latin America operating income declined 29% mainly due to reduced activity levels in Mexico and lower drilling activity
and pricing in Brazil, which were partially offset by improved activity levels in Argentina.
Europe/Africa/CIS operating income fell 10% primarily due to lower activity and currency weakness in Russia and
Norway.

•

• Middle East/Asia operating income increased 32% primarily due to an increase in demand and profitability for drilling
activity in Saudi Arabia, as well as improved demand for drilling services in Thailand, which were partially offset by
reduced drilling services and logging activity in China.

Corporate and other expenses were $184 million in 2014 compared to $1.5 billion in 2013. The significant decrease

was primarily due to Macondo-related items. In 2013, we recorded a $1.0 billion increase to our loss contingency for the
Macondo well incident, while in 2014 we recorded a reduction of our loss contingency liability and an expected insurance
recovery totaling $195 million. We recorded $17 million of costs in 2014 related to the pending Baker Hughes acquisition and a
$55 million charge in 2013 related to a charitable contribution to the National Fish and Wildlife Foundation. See Note 9 to the
consolidated financial statements for further information regarding the Macondo well incident.

Impairments and other charges. Primarily as a result of the downturn in the energy market and its corresponding

impact on the company’s business outlook, we recorded a total of approximately $129 million in company-wide charges during
2014, which consisted of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets,
severance costs, and other charges. See Note 3 to the consolidated financial statements for further information.

NONOPERATING ITEMS

Interest expense, net increased $52 million in 2014, compared to 2013, primarily due to higher interest expense as a

result of the issuance of $3.0 billion aggregate principal amount of senior notes in August 2013.

Effective tax rate. Our effective tax rate was 27.1% for 2014 and 23.5% for 2013. The effective tax rate for 2014 was

positively impacted by a $201 million net operating loss valuation allowance released as a result of a reorganization of our legal
entity structure in Brazil, as well as lower tax rates in certain foreign jurisdictions. Partially offsetting these items were tax
expenses related to Macondo items recorded during 2014, which was tax-effected at the United States statutory rate, as well as
total charges of approximately $150 million for a write-off of certain prepaid tax assets recorded in Iraq, additional tax
expenses related to the settlement of a research and development credit with the United States tax authorities, and tax expenses
related to other unrecognized tax benefits. Our effective tax rate for 2013 was also positively impacted by lower tax rates in
certain foreign jurisdictions; federal tax benefits of approximately $50 million due to the reinstatement of certain tax benefits
and credits related to the first quarter of 2013 enactment of the American Taxpayer Relief Act of 2012; and the tax impact
related to an increase of our Macondo-related loss contingency recorded during 2013, which was tax-effected at the United
States statutory rate. See Note 10 to the consolidated financial statements for further information regarding income taxes.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies
are described below to provide a better understanding of how we develop our assumptions and judgments about future events
and related estimations and how they can impact our financial statements. A critical accounting estimate is one that requires our
most difficult, subjective, or complex judgments and assessments and is fundamental to our results of operations. We identified
our most critical accounting estimates to be:

- forecasting our effective income tax rate, including our future ability to utilize foreign tax credits and the

realizability of deferred tax assets, and providing for uncertain tax positions;

- legal, environmental, and investigation matters;
- valuations of long-lived assets, including intangible assets and goodwill;
- purchase price allocation for acquired businesses;
- pensions;
- allowance for bad debts; and
- percentage-of-completion accounting for long-term, integrated project management contracts.
We base our estimates on historical experience and on various other assumptions we believe to be reasonable
according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical
accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and
judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our
consolidated financial statements and related notes included in this report.

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. As of December 31, 2015, we adopted a new accounting standard which requires that
all deferred tax assets and liabilities be classified as noncurrent on the balance sheet instead of separating deferred taxes into
current and noncurrent amounts. See Note 16 to the consolidated financial statements for additional information. We apply the
following basic principles in accounting for our income taxes:

- a current tax liability or asset is recognized for the estimated taxes payable or refundable on tax returns for the

current year;

- a deferred tax liability or asset is recognized for the estimated future tax effects attributable to temporary differences

and carryforwards;

- the measurement of current and deferred tax liabilities and assets is based on provisions of the enacted tax law, and

the effects of potential future changes in tax laws or rates are not considered; and

- the value of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available

evidence, are not expected to be realized.

We determine deferred taxes separately for each tax-paying component (an entity or a group of entities that is

consolidated for tax purposes) in each tax jurisdiction. That determination includes the following procedures:

- identifying the types and amounts of existing temporary differences;
- measuring the total deferred tax liability for taxable temporary differences using the applicable tax rate;
- measuring the total deferred tax asset for deductible temporary differences and operating loss carryforwards using

the applicable tax rate;

- measuring the deferred tax assets for each type of tax credit carryforward; and
- reducing the deferred tax assets by a valuation allowance if, based on available evidence, it is more likely than not

that some portion or all of the deferred tax assets will not be realized.

Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and

estimates. Additionally, we use forecasts of certain tax elements, such as taxable income and foreign tax credit utilization, as
well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of
such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly
impact these variables, and changes to these variables could have a material impact on our income tax accounts related to both
continuing and discontinued operations.

We have operations in approximately 80 countries. Consequently, we are subject to the jurisdiction of a significant
number of taxing authorities. 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 9 of our consolidated financial statements, as of December 31, 2015, we have accrued an

estimate of the probable and estimable costs for the resolution of some of our legal, environmental, and investigation matters.
For other matters for which the liability is not probable and reasonably estimable, we have not accrued any amounts. Attorneys
in our legal department monitor and manage all claims filed against us and review all pending investigations. Generally, the
estimate of probable costs related to these matters is developed in consultation with internal and outside legal counsel
representing us. Our estimates are based upon an analysis of potential results, assuming a combination of litigation and
settlement strategies. The accuracy of these estimates is impacted by, among other things, the complexity of the issues and the
amount of due diligence we have been able to perform. We attempt to resolve these matters through settlements, mediation, and
arbitration proceedings when possible. If the actual settlement costs, final judgments, or fines, after appeals, differ from our
estimates, our future financial results may be adversely affected. We have in the past recorded significant adjustments to our
initial estimates of these types of contingencies.

Value of long-lived assets, including intangible assets and goodwill
We carry a variety of long-lived assets on our balance sheet including property, plant and equipment, goodwill, and

other intangibles. We conduct impairment tests on long-lived assets whenever events or changes in circumstances indicate that
the carrying value may not be recoverable. Impairment is the condition that exists when the carrying amount of a long-lived
asset exceeds its fair value, and any impairment charge that we record reduces our earnings. We review the carrying value of
these assets based upon estimated future cash flows while taking into consideration assumptions and estimates including the
future use of the asset, remaining useful life of the asset, and service potential of the asset.

Goodwill is the excess of the cost of an acquired entity over the net of the amounts assigned to assets acquired and
liabilities assumed. We test goodwill for impairment annually, during the third quarter, or if an event occurs or circumstances
change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. For purposes of
performing the goodwill impairment test our reporting units are the same as our reportable segments, the Completion and
Production division and the Drilling and Evaluation division. See Note 1 to the consolidated financial statements for our
accounting policies related to long-lived assets and intangible assets, as well as the results of our goodwill impairment
assessment.

The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted revenue
and costs assumptions. If the crude oil market continues to decline and remains at low levels for a sustained period of time, we
could record an impairment of the carrying value of our goodwill in the future. If crude oil prices decline further or remain at
low levels, to the extent appropriate we expect to perform our goodwill impairment assessment on a more frequent basis to
determine whether an impairment is required.

Acquisitions-purchase price allocation
We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair
values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill.
We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets,
and widely accepted valuation techniques such as discounted cash flows. We engage third-party appraisal firms to assist in fair
value determination of inventories, identifiable intangible assets, and any other significant assets or liabilities when appropriate.
The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as
well as asset lives, can materially impact our results of operations. Our acquisitions may also include contingent consideration,
or earn-out provisions, which provide for additional consideration to be paid to the seller if certain future conditions are met.
These earn-out provisions are estimated and recognized at fair value at the acquisition date based on projected earnings or other
financial metrics over specified periods after the acquisition date. These estimates are reviewed during the specified period and
adjusted based on actual results.

Pensions
Our pension benefit obligations and expenses are calculated using actuarial models and methods. Two of the more
critical assumptions and estimates used in the actuarial calculations are the discount rate for determining the current value of
benefit obligations and the expected long-term rate of return on plan assets used in determining net periodic benefit cost. Other

critical assumptions and estimates used in determining benefit obligations and cost, including demographic factors such as
retirement age, mortality, and turnover, are 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. These assumptions differ based on varying factors
specific to each particular country or economic environment.

The discount rate utilized in 2015 to determine the projected benefit obligation at the measurement date for our United

Kingdom pension plan, which constituted 81% of our international plans’ pension obligations, was 3.90%, compared to a
discount rate of 3.75% utilized in 2014. The expected long-term rate of return assumption used for our United Kingdom
pension plan expense was 6.0% in 2015 and 6.5% in 2014.

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
50-basis-point decrease in discount rate
50-basis-point increase in discount rate
50-basis-point decrease in expected long-term rate of return
50-basis-point increase in expected long-term rate of return

Effect on

Pretax Pension
Expense in 2015

Pension Benefit Obligation
at December 31, 2015

2 $
(2)
4
(4)

92
(80)
NA
NA

Our international defined benefit plans reduced pretax income by $42 million in 2015, $36 million in 2014, and $32

million in 2013. Included in these amounts was income from expected return on plan assets of $48 million in 2015, $52 million
in 2014, and $44 million in 2013. Actual returns on international plan assets totaled $34 million in 2015, compared to $69
million in 2014. Our net actuarial loss, net of tax, related to international pension plans was $205 million at December 31, 2015
and $298 million at December 31, 2014. In our international plans where employees earn additional benefits for continued
service, actuarial gains and losses will be recognized in operating income over a period of two to 20 years, which represents the
estimated average remaining service of the participant group expected to receive benefits. In our international plans where
benefits are not accrued for continued service, actuarial gains and losses will be recognized in operating income over a period
of 17 to 31 years, which represents the estimated average remaining lifetime of the benefit obligations. These ranges reflect
varying maturity levels among the plans.

During 2015, we made contributions of $18 million to our international defined benefit plans. We expect to make

contributions of approximately $14 million to our international defined benefit plans in 2016.

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 15 to the consolidated financial
statements for further information related to defined benefit and other postretirement benefit plans.

Allowance for bad debts
We evaluate our accounts receivable through a continuous process of assessing our portfolio on an individual customer

and overall basis. This process consists of a thorough review of historical collection experience, current aging status of the
customer accounts, financial condition of our customers, and whether the receivables involve retainages. We also consider the
economic environment of our customers, both from a marketplace and geographic perspective, in evaluating the need for an
allowance. Based on our review of these factors, we establish or adjust allowances for specific customers and the accounts
receivable portfolio as a whole. This process involves a high degree of judgment and estimation, and frequently involves
significant dollar amounts. Accordingly, our results of operations can be affected by adjustments to the allowance due to actual
write-offs that differ from estimated amounts. Our estimates of allowances for bad debts have historically been accurate. Over
the last five years, our estimates of allowances for bad debts, as a percentage of notes and accounts receivable before the
allowance, have ranged from 1.6% to 2.7%. At December 31, 2015, allowance for bad debts totaled $145 million, or 2.7% of
notes and accounts receivable before the allowance. At December 31, 2014, allowance for bad debts totaled $137 million, or
1.8% 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, 2015 would have resulted in a $53 million
adjustment to 2015 total operating costs and expenses. See Note 5 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. See Note 1 to the consolidated financial statements for further information.

OFF BALANCE SHEET ARRANGEMENTS

At December 31, 2015, we had no material off balance sheet arrangements, except for operating leases. For
information on our contractual obligations related to operating leases, see “Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Liquidity and Capital Resources – Contractual obligations.”

FINANCIAL INSTRUMENT MARKET RISK

We are exposed to market risk from changes in foreign currency exchange rates and interest rates. We selectively
manage these exposures through the use of derivative instruments, including forward foreign exchange contracts, foreign
exchange options, and interest rate swaps. The objective of our risk management strategy is to minimize the volatility from
fluctuations in foreign currency and interest rates. We do not use derivative instruments for trading purposes. The counterparties
to our forward contracts, options, and interest rate swaps are global commercial and investment banks.

We use a sensitivity analysis model to measure the impact of a 10% adverse movement of foreign currency exchange

rates against the United States dollar. A hypothetical 10% adverse change in the value of all our foreign currency positions
relative to the United States dollar as of December 31, 2015 would result in a $76 million, pre-tax, loss for our net monetary
assets denominated in currencies other than United States dollars.

With respect to interest rates sensitivity, after consideration of the impact from the interest rate swaps, a hypothetical
100 basis point increase in the LIBOR rate would result in approximately an additional $15 million of interest charges for the
year ended December 31, 2015.

There are certain limitations inherent in the sensitivity analyses presented, primarily due to the assumption that interest
rates and exchange rates change instantaneously in an equally adverse fashion. In addition, the analyses are unable to reflect the
complex market reactions that normally would arise from the market shifts modeled. While this is our best estimate of the
impact of the various scenarios, these estimates should not be viewed as forecasts.

For further information regarding foreign currency exchange risk, interest rate risk, and credit risk, see Note 14 to the

consolidated financial statements.

ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide.

For information related to environmental matters, see Note 9 to the consolidated financial statements and Part I, Item 1(a),
“Risk Factors.”

FORWARD-LOOKING INFORMATION

The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information.

Forward-looking information is based on projections and estimates, not historical information. Some statements in this Form
10-K are forward-looking and use words like “may,” “may not,” “believe,” “do not believe,” “plan,” “estimate,” “intend,”
“expect,” “do not expect,” “anticipate,” “do not anticipate,” “should,” “likely,” and other expressions. We may also provide oral
or written forward-looking information in other materials we release to the public. Forward-looking information involves risk
and uncertainties and reflects our best judgment based on current information. Our results of operations can be affected by
inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition, other factors may affect the
accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and
results of operations may vary materially.

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.

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, 2015 based upon criteria set forth in the Internal Control - Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of
December 31, 2015, our internal control over financial reporting is effective.

The effectiveness of Halliburton’s internal control over financial reporting as of December 31, 2015 has been audited

by KPMG LLP, an independent registered public accounting firm, as stated in their report that is included herein.

HALLIBURTON COMPANY

/s/ David J. Lesar
David J. Lesar
Chairman of the Board and
Chief Executive Officer

/s/ Christian A. Garcia
Christian A. Garcia
Senior Vice President, Finance and
Acting Chief Financial Officer

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,
2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and
their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally
accepted accounting principles.

As discussed in Note 16 to the financial statements, Halliburton Company changed its method of accounting for debt issuance costs
effective January 1, 2014 due to the adoption of FASB ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs.
Additionally, as discussed in Note 16 to the financial statements, Halliburton Company changed its method of accounting for
deferred income taxes effective January 1, 2014 due to the adoption of FASB ASU 2015-17, Balance Sheet Classification of
Deferred Taxes.

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, 2015, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated February 5, 2016 expressed an unqualified opinion on the effectiveness of
Halliburton Company’s internal control over financial reporting.

/s/ KPMG LLP
Houston, Texas
February 5, 2016

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, 2015, based on criteria
established in Internal Control - Integrated Framework (2013) 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) 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, 2015 and 2014, 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, 2015, and our report dated February 5, 2016 expressed an unqualified opinion on those
consolidated financial statements.

/s/ KPMG LLP
Houston, Texas
February 5, 2016

HALLIBURTON COMPANY
Consolidated Statements of Operations

Millions of dollars and shares except per share data

Revenue:
Services
Product sales
Total revenue

Operating costs and expenses:
Cost of services
Cost of sales
Impairment and other charges
Baker Hughes acquisition-related costs
General and administrative
Activity related to the Macondo well incident
Total operating costs and expenses

Operating income (loss)
Interest expense, net of interest income of $16, $13, and $8
Other, net

Income (loss) from continuing operations before income taxes
Income tax benefit (provision)

Income (loss) from continuing operations
Income (loss) from discontinued operations, net of income tax benefit (provision)
of $3, $(9), and $1

Net income (loss)

Net (income) attributable to noncontrolling interest
Net income (loss) attributable to company

Amounts attributable to company shareholders:
Income (loss) from continuing operations
Income (loss) from discontinued operations, net

Net income (loss) attributable to company

Basic income per share attributable to company shareholders:
Income (loss) from continuing operations
Income (loss) from discontinued operations, net

Net income (loss) per share

Diluted income per share attributable to company shareholders:
Income (loss) from continuing operations
Income (loss)from discontinued operations, net

Net income (loss) per share

Basic weighted average common shares outstanding
Diluted weighted average common shares outstanding

See notes to consolidated financial statements.

Year Ended December 31
2014

2013

2015

17,482 $
6,151
23,633

25,039 $
7,831
32,870

15,900
5,213
2,177
308
200
—
23,798

(165)
(447)
(324)
(936)
274
(662)

(5)
(667) $

(4)
(671) $

(666) $
(5)
(671) $

(0.78) $
(0.01)
(0.79) $

853
853

20,959
6,571
129
17
292
(195)
27,773
5,097
(383)
(2)
4,712
(1,275)
3,437

64
3,501 $

(1)
3,500 $

3,436 $
64
3,500 $

4.05 $
0.08
4.13 $

4.03 $
0.08
4.11 $

848
852

22,257
7,145
29,402

18,959
5,972
—
—
333
1,000
26,264
3,138
(331)
(43)
2,764
(648)
2,116

19
2,135

(10)
2,125

2,106
19
2,125

2.35
0.02
2.37

2.33
0.03
2.36

898
902

HALLIBURTON COMPANY
Consolidated Statements of Comprehensive Income

Year Ended December 31
2014

2013

2015

(667) $

3,501 $

2,135

105
(67)
(2)
36
(631) $

(4)
(635) $

(84)
—
(7)
(91)
3,410 $

(1)
3,409 $

—
—
2
2
2,137

(10)
2,127

Millions of dollars

Net income (loss)

Other comprehensive income, net of income taxes:
Defined benefit and other post retirement plans adjustment
Unrealized loss on cash flow hedges
Other
Other comprehensive income (loss), net of income taxes

Comprehensive income (loss)

Comprehensive income attributable to noncontrolling interest
Comprehensive income (loss) attributable to company shareholders

See notes to consolidated financial statements.

HALLIBURTON COMPANY
Consolidated Balance Sheets

Millions of dollars and shares except per share data

Assets

Current assets:
Cash and equivalents
Receivables (net of allowances for bad debts of $145 and $137)
Inventories
Assets held for sale
Prepaid expenses
Other current assets

Total current assets
Property, plant, and equipment (net of accumulated depreciation of $9,789 and $11,007)
Goodwill
Other assets

Total assets

Liabilities and Shareholders’ Equity

Current liabilities:
Accounts payable
Accrued employee compensation and benefits
Current maturities of long-term debt
Liabilities for Macondo well incident
Deferred revenue
Taxes other than income
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 1,071 and 1,071 shares)
Paid-in capital in excess of par value
Accumulated other comprehensive loss
Retained earnings
Treasury stock, at cost (215 and 223 shares)

Company shareholders’ equity
Noncontrolling interest in consolidated subsidiaries

Total shareholders’ equity
Total liabilities and shareholders’ equity

See notes to consolidated financial statements.

December 31

2015

2014

10,077 $
5,317
2,417
2,115
1,051
632
21,609
10,911
2,109
2,313
36,942 $

2,019 $
838
659
400
298
293
852
5,359
14,687
457
944
21,447

2,677
274
(363)
20,524
(7,650)
15,462
33
15,495
36,942 $

2,291
7,564
3,571
—
658
563
14,647
12,475
2,330
2,713
32,165

2,814
1,033
14
367
349
407
882
5,866
7,765
691
1,545
15,867

2,679
309
(399)
21,809
(8,131)
16,267
31
16,298
32,165

HALLIBURTON COMPANY
Consolidated Statements of Cash Flows

Millions of dollars

Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Impairments and other charges
Cash impact of impairments and other charges - severance payments
Depreciation, depletion, and amortization
Activity related to the Macondo well incident
Deferred income tax benefit, continuing operations
Other changes:
Receivables
Accounts payable
Inventories
Other

Total cash flows from operating activities
Cash flows from investing activities:
Capital expenditures
Sales of property, plant, and equipment
Purchases of investment securities
Sales of investment securities
Payments to acquire businesses, net of cash acquired
Other investing activities

Total cash flows from investing activities
Cash flows from financing activities:
Proceeds from issuance of long-term debt, net
Dividends to shareholders
Proceeds from exercises of stock options
Payments to reacquire common stock
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.

Year Ended December 31
2014

2015

2013

(667) $

3,501 $

2,135

2,177
(304)
1,835
(333)
(224)

1,468
(603)
153
(596)
2,906

(2,184)
168
(109)
106
(39)
(134)
(2,192)

7,440
(614)
167
—
88
7,081

(9)

7,786
2,291
10,077 $

129
(28)
2,126
(569)
(454)

(1,381)
489
(271)
520
4,062

(3,283)
338
(183)
444
(231)
(223)
(3,138)

—
(533)
332
(800)
(29)
(1,030)
41
(65)
2,356
2,291 $

—
—
1,900
1,000
(132)

(449)
327
(107)
(227)
4,447

(2,934)
241
(329)
356
(94)
(110)
(2,870)

2,968
(465)
277
(4,356)
(178)
(1,754)
49
(128)
2,484
2,356

380 $
370 $

384 $
1,269 $

293
913

$
$

HALLIBURTON COMPANY
Consolidated Statements of Shareholders' Equity

Company Shareholders’ Equity

Paid-in
Capital in
Excess of
Par Value

Common
Shares

Treasury
Stock

Retained
Earnings

Accumulated
Other
Comprehensive
Income (Loss)

Noncontrolling
interest in
Consolidated
Subsidiaries

Total

2,682 $

486 $

(4,276)$

17,182 $

(309) $

25 $ 15,790

—

(2)

—

(97)

—

(4,356)

583

—

2,125

—

(465)

—

2,135

— (4,356)

—

(1)

484

(465)

2,680 $

415 $

(8,049)$

18,842 $

(307) $

34 $ 13,615

—

(1)

—

(161)

—

(800)

718

—

3,500

—

(533)

—

(92)

—

(4)

3,501

(92)

(800)

556

(533)

2,679 $

309 $

(8,131)$

21,809 $

(399) $

31 $ 16,298

—

(2)

—

(39)

—

481

—

(671)

—

(614)

—

(2)

(667)

440

(614)

Millions of dollars

Balance at December 31, 2012

Comprehensive income (loss):

Net income

Other comprehensive income

Common shares repurchased

Stock plans

Cash dividends ($0.525 per share)

Other

Balance at December 31, 2013

Comprehensive income (loss):

Net income

Other comprehensive loss

Common shares repurchased

Stock plans

Cash dividends ($0.63 per share)

Other

Balance at December 31, 2014

Comprehensive income (loss):

Net income (loss)

Other comprehensive income

Stock plans

Cash dividends ($0.72 per share)

Other

Balance at December 31, 2015

2,677 $

274 $

(7,650)$

20,524 $

(363) $

33 $ 15,495

See notes to consolidated financial statements.

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
addition, certain reclassifications of prior period balances have been made to conform to the current period presentation.

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.

New Accounting Pronouncement. In May 2014, a new revenue recognition standard was issued that will supersede

existing revenue recognition guidance. See Note 16 for additional information.

Research and development
Research and development costs are expensed as incurred. Research and development costs were $487 million in

2015, $601 million in 2014, and $588 million in 2013.

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.

Allowance for bad debts
We establish an allowance for bad debts through a review of several factors, including historical collection experience,

current aging status of the customer accounts, and financial condition of our customers. Our policy is to write off bad debts
when the customer accounts are determined to be uncollectible.

Property, plant, and equipment
Other than those assets that have been written down to their fair values due to impairment, property, plant, and
equipment are reported at cost less accumulated depreciation, which is generally provided on the straight-line method over the
estimated useful lives of the assets. Accelerated depreciation methods are used for tax purposes, wherever permitted. Upon sale
or retirement of an asset, the related costs and accumulated depreciation are removed from the accounts and any gain or loss is
recognized. Planned major maintenance costs are generally expensed as incurred. Expenditures for additions, modifications,
and conversions are capitalized when they increase the value or extend the useful life of the asset.

Goodwill and other intangible assets
We record as goodwill the excess purchase price over the fair value of the tangible and identifiable intangible assets

acquired. Changes in the carrying amount of goodwill are detailed below by reportable segment.

Millions of dollars
Balance at December 31, 2013:

Completion
and Production
$

1,533 $

Current year acquisitions
Purchase price adjustments for previous acquisitions
Balance at December 31, 2014:

Current year acquisitions
Purchase price adjustments for previous acquisitions
Allocation to assets held for sale
Balance at December 31, 2015:

77
(4)
1,606 $

27
1
—
1,634 $

Drilling and
Evaluation

Total

635 $

79
10
724 $

26
1
(276)
475 $

2,168

156
6
2,330

53
2
(276)
2,109

As of December 31, 2015, we allocated $276 million of goodwill in the Drilling and Evaluation segment to assets held

for sale. See Note 2 for further information.

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 exist such as significant current or projected operating losses. In
2013, 2014, and 2015, we elected to bypass the qualitative assessment and perform a quantitative impairment test. This two-
step quantitative process, which consists of a discounted cash flow analysis based on management’s short-term and long-term
forecast of operating performance, compares 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 is performed to measure the amount of impairment loss
to be recorded, if any. As a result of our annual goodwill impairment assessments performed in 2015, 2014, and 2013, we
determined that the fair value of each reporting unit exceeded its net book value and, therefore, no goodwill impairments were
deemed necessary.

In 2015, the energy market continued to experience a considerable downturn as a result of a significant reduction in

crude oil prices, including the period subsequent to our annual goodwill impairment testing date. Due to this pricing decline and
its corresponding impact on our short-term business outlook, we determined that these recent events constituted a triggering
event that would require us to update our goodwill impairment assessment through December 31, 2015. As a result of our
analysis, we determined that the fair value of each reporting unit exceeded its net book value and therefore, no goodwill
impairment was necessary as of December 31, 2015. Should current market conditions worsen or persist for an extended period
of time, an impairment of the carrying value of our goodwill could occur, particularly in our Completion and Production
operating segment.

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 two to fifteen years. The components of these other intangible
assets generally consist of patents, license agreements, non-compete agreements, trademarks, and customer lists and contracts.

Evaluating impairment of long-lived assets
When events or changes in circumstances indicate that long-lived assets other than goodwill may be impaired, an

evaluation is performed. For an asset classified as held for use, the estimated future undiscounted cash flows associated with the
asset are compared to the asset’s carrying amount to determine if a write-down to fair value is required. When an asset is
classified as held for sale, the asset’s book value is evaluated and adjusted to the lower of its carrying amount or fair value less
cost to sell. In addition, depreciation and amortization is ceased while it is classified as held for sale.

Income taxes
We recognize the amount of taxes payable or refundable for the year. In addition, deferred tax assets and liabilities are

recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax
returns. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be
realized. As of December 31, 2015, we adopted a new accounting standard which requires that all deferred tax assets and
liabilities be classified as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent
amounts. See Note 16 for additional information.

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. Revenue and expense transactions are translated at
the average rates in effect during the year, except for those expenses associated with nonmonetary balance sheet accounts,
which are translated at historical rates. Gains or losses from remeasurement of monetary assets and liabilities due to changes in
exchange rates are recognized in our consolidated statements of operations in “Other, net” in the year of occurrence.

Stock-based compensation
Stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is

recognized as expense over the employee’s service period, which is generally the vesting period of the equity grant.
Additionally, compensation cost is recognized based on awards ultimately expected to vest, therefore, we have reduced the cost
for estimated forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant and revised in
subsequent periods to reflect actual forfeitures. See Note 12 for additional information related to stock-based compensation.

Note 2. Acquisitions and Dispositions

Pending acquisition of Baker Hughes
In November 2014, we and Baker Hughes entered into a merger agreement under which, subject to the conditions set

forth in the merger agreement, we will acquire all the outstanding shares of Baker Hughes in a stock and cash transaction.
Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas
industry. Under the terms of the merger agreement, at the effective time of the acquisition, each share of Baker Hughes
common stock will be converted into the right to receive 1.12 shares of our common stock and $19.00 in cash. The merger
agreement has been unanimously approved by both companies' Board of Directors, our stockholders have approved the
issuance of shares necessary to complete the acquisition of Baker Hughes, and Baker Hughes’ stockholders have adopted the
merger agreement and thereby approved the acquisition. The closing of the transaction is subject to receipt of certain regulatory
approvals and other conditions specified in the merger agreement.

Because the exchange ratio was fixed at the time of the merger agreement and the market value of our common stock

will continue to fluctuate, the total value of the consideration exchanged will not be determinable until the closing date. The
number of shares to be issued will not fluctuate based upon changes in the price of shares of our common stock or shares of
Baker Hughes common stock prior to the closing date, but the exact number of Halliburton shares to be issued with respect to
Baker Hughes stock awards will not be determinable until the closing of the transaction. We have estimated the total
consideration expected to be issued and paid to Baker Hughes stockholders in the acquisition to consist of approximately 492
million shares of our common stock and approximately $8.3 billion to be paid in cash.

In November 2015, we issued $7.5 billion aggregate principal amount of senior notes to be used for general corporate

purposes, including to finance a portion of the cash consideration for the acquisition. If the Baker Hughes acquisition is not
consummated, we are required to redeem $2.5 billion of the senior notes issued at a price of 101% of their principal amount.
See Note 8 for further information on the debt issuance and mandatory redemption features. We may finance the remainder of
the cash portion of the consideration for the acquisition with cash on hand, additional debt financing, or a combination thereof.
We have $1.1 billion remaining under the senior unsecured bridge facility commitment we obtained for the acquisition,
although we may obtain other debt financings in lieu of utilizing all or a portion of the bridge facility.

In December 2015, we announced that our timing agreement with the DOJ expired without reaching a settlement or

the DOJ initiating litigation. The DOJ informed us that they do not believe that our previously announced proposed divestitures
are sufficient to address their concerns, but acknowledged that they would assess further proposals. In January 2016, the EC
entered into Phase II of its investigation, and issued a report detailing initial concerns about the competition-related
implications of the acquisition.

Also, in January 2016, we presented to the DOJ an enhanced set of proposed divestitures in order to seek their
approval of the transaction. We also informally notified the EC and other jurisdictions about the enhanced divestitures package.
The sales process for the planned divestitures is continuing, but there is no agreement to date with any buyer or an agreement
with the DOJ or EC as to the adequacy of the proposed divestitures. Our conversations with the DOJ, the EC and other
enforcement authorities continue with the desire to resolve their competition-related concerns as soon as possible.

We remain committed to completing this transaction, despite the extended time required to obtain regulatory
approvals. We agreed with Baker Hughes to extend the period to obtain required regulatory approvals to no later than April 30,
2016, as permitted under the merger agreement, though we would proceed with closing prior to such date if all relevant
regulatory approvals have been obtained. If review by the relevant competition authorities extends beyond April 30, 2016, the
merger agreement does not terminate automatically; the parties may continue to seek relevant regulatory approvals or either of
the parties may terminate the merger agreement. Under the merger agreement, we could be required in certain circumstances,
where the termination of the merger agreement is related to failures to obtain regulatory clearances, to pay Baker Hughes a
termination fee of $3.5 billion. See "Assets Held for Sale" below for additional expenses we would recognize if the merger
agreement is terminated.

Assets Held for Sale
In April 2015, we announced our decision to market for sale our Fixed Cutter and Roller Cone Drill Bits, our
Directional Drilling, and our Logging-While-Drilling/Measurement-While-Drilling businesses in connection with the pending
Baker Hughes acquisition. The assets and liabilities for these businesses, which are included within our Drilling and Evaluation
operating segment, were classified as held for sale beginning in the second quarter of 2015 and, therefore, the corresponding
depreciation and amortization expense was ceased at that time. These anticipated divestitures are not presented as discontinued
operations in our consolidated statements of operations, because they do not represent a strategic shift in our business, as we
will continue operating similar businesses of Baker Hughes after the acquisition.

During the years ended December 31, 2015, 2014, and 2013, we generated revenue from these assets of $2.6 billion,

$3.6 billion, and $3.6 billion. Additionally, during the years ended December 31, 2015, 2014, and 2013, we recognized
operating income from these assets, consistent with our business segments presentation in Note 4, of $460 million, $391
million, and $422 million. These amounts reflect the impact of ceasing the recording of depreciation and amortization expense
for these businesses subsequent to their held for sale reclassification in 2015; the recording of such expenses would have
reduced operating income by $244 million during the year ended December 31, 2015. If the merger agreement for the pending

Baker Hughes acquisition is terminated, and therefore these businesses are no longer considered held for sale, we would
reclassify the assets as held and used at the lower of fair value or carrying value less ceased depreciation and amortization
expense as of that date. Additionally, we recorded $103 million of capitalized divestiture costs within "Other current assets" on
our consolidated balance sheets as of December 31, 2015, which we would record as an expense in our statement of operations
if the acquisition is not consummated.

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. As of December 31, 2015, we determined the fair value less cost to sell exceeded the
carrying amount of our assets held for sale.

A summary of the carrying amounts of assets and liabilities held for sale on our consolidated balance sheet as of

December 31, 2015 related to the anticipated divestitures discussed above is detailed below.

Millions of dollars

Property, plant, and equipment
Inventories
Goodwill
Patents and other intangibles

Total assets

Employee benefit liabilities (a)

Assets

Liabilities

December 31,
2015

1,206
576
276
57
2,115

$
$

46
46

Total liabilities
(a) Liabilities held for sale are classified within “Other current liabilities” on our consolidated
balance sheet as of December 31, 2015.

In the third quarter of 2015, we announced that we also intended to divest our expandable liner hangers business in

connection with the pending Baker Hughes acquisition, but the anticipated divestiture did not meet all of the requirements for
classification as assets held for sale. We have recently proposed a revised and enhanced divestiture package to the DOJ, which
no longer includes our expandable liner hangers business.

The final sale of each of the businesses described above, as well as any other businesses disposed of in connection

with the Baker Hughes acquisition, will be subject to the ability to negotiate acceptable terms and conditions, each company's
Board of Directors approval, as applicable, and final approval of the Baker Hughes acquisition by competition authorities. We
anticipate that each company would complete the sale of divested businesses concurrent with the closing of the Baker Hughes
acquisition.

Note 3. Impairments and Other Charges

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 at least annually, and more frequently whenever events or
changes in circumstances indicate that the carrying value may not be recoverable. We review the recoverability of the carrying
value of our 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. Additionally, inventories are
valued at the lower of cost or market.

During the year ended December 31, 2015, as a result of the downturn in the energy market and its corresponding

impact on our business outlook, we determined the carrying amount of a number of our long-lived assets exceeded their
respective fair values due to projected declines in asset utilization, and that the cost of some of our inventory exceeded its
market value; therefore, we recorded corresponding impairments and other charges. Additionally, we initiated a company-wide
reduction in workforce by approximately 25% during 2015 intended to reduce costs and better align our workforce with
anticipated activity levels in the near-term, which resulted in us recording severance costs relating to termination benefits. We
also recorded a write-off of our operations in both Libya and Yemen during the first quarter of 2015 due to our decision to exit
our operations in these countries. As part of the anticipated divestitures of certain businesses included in our Drilling and
Evaluation operating segment, we are incurring certain non-capitalizable costs, which we have included within "other matters"
in the table below.

Primarily as a result of the events described above, we recorded charges of approximately $2.2 billion and $129
million during the years ended December 31, 2015 and 2014, respectively, which consisted of equipment write-offs, asset
impairments, expenses and write-downs related to idle equipment, inventory write-downs, impairments of intangible assets,
severance costs, country and facility closures, and other items. We also recorded a $199 million foreign currency exchange loss
in Venezuela during the first quarter of 2015 as discussed in further detail below.

The following table presents various charges we recorded during the years ended December 31, 2015 and December

31, 2014 as a result of the downturn in the energy market and other matters:

Millions of dollars

Economic downturn:
Fixed asset impairments
Inventory write-downs
Severance costs
Intangible asset impairments
Other

Other matters:
Country closures
Other
Total impairments and other charges
Venezuela currency devaluation loss
Total charges

Year Ended
December 31,
2015

Year Ended
December 31,
2014

Income Statement Classification

760 $
484
352
212
201

80
88
2,177 $
199
2,376

47 Impairments and other charges
24 Impairments and other charges
28 Impairments and other charges
10 Impairments and other charges
20 Impairments and other charges

— Impairments and other charges
— Impairments and other charges
129
— Other, net
129

In February 2015, the Venezuelan government created a new foreign exchange rate mechanism, called the Marginal

Currency System, or SIMADI. The new mechanism, which is the third system in a three-tier exchange control mechanism, is a
floating market rate for the conversion of Bolívares to United States dollars based on supply and demand. Prior to 2015, we had
remeasured our net monetary assets denominated in Bolívares using the official exchange rate of 6.3 Bolívares per United
States dollar. During the first quarter of 2015, we began utilizing SIMADI to remeasure our net monetary assets denominated in
Bolívares with a market rate of 192 Bolívares per United States dollar as of March 31, 2015, which resulted in us recording a
foreign currency loss of $199 million during the first quarter of 2015.

Note 4. Business Segment and Geographic Information

We operate under two divisions, which form the basis for the two operating segments we report: the Completion and

Production segment and the Drilling and Evaluation segment.

Completion and Production delivers cementing, stimulation, intervention, pressure control, specialty chemicals,
artificial lift, and completion services. The segment consists of Production Enhancement, Cementing, Completion Tools,
Production Solutions, Pipeline & Process Services, Multi-Chem, and Artificial Lift.

Production Enhancement services include stimulation services and sand control services. Stimulation services
optimize oil and natural gas reservoir production through a variety of pressure pumping services, nitrogen services, and
chemical processes, commonly known as hydraulic fracturing and acidizing. Sand control services include fluid and chemical
systems and pumping services for the prevention of formation sand production.

Cementing services involve bonding the well and well casing while isolating fluid zones and maximizing wellbore

stability. Our cementing service line also provides casing equipment.

Completion Tools provides downhole solutions and services to our customers to complete their wells, including well
completion products and services, intelligent well completions, liner hanger systems, sand control systems, and service tools.

Production Solutions includes pressure control services such as coiled tubing, hydraulic workover units, and downhole

tools.

Pipeline & Process Services include pre-commissioning and maintenance services, subsea pipeline services,

conventional pipeline services, and process services.

Multi-Chem includes oilfield production and completion chemicals and services that address production, processing,

and transportation challenges.

Artificial Lift offers electrical submersible pumps and progressive cavity pumps, including the associated surface

package for power, control, and monitoring of the entire lift system, and provides installation, maintenance, repair, and testing
services. The objective of these services is to maximize reservoir and wellbore recovery by applying lifting technology and
intelligent field management solutions throughout the life of the well.

Drilling and Evaluation provides field and reservoir modeling, drilling, evaluation, and precise wellbore placement

solutions that enable customers to model, measure, drill, and optimize their well construction activities. The segment consists of
Baroid, Sperry Drilling, Wireline and Perforating, Drill Bits and Services, Landmark Software and Services, Testing and
Subsea, and Consulting and Project Management.

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.

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.

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.

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.

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.

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. In addition,
well control and prevention services are included.

Corporate and other includes expenses related to support functions and corporate executives and is primarily

composed of cash and equivalents, deferred tax assets, and investment securities. Also included are certain gains, losses and
costs not attributable to a particular business segment.

Intersegment revenue and revenue between geographic areas are immaterial. Our equity in earnings and losses of
unconsolidated affiliates that are accounted for under the equity method of accounting is included in revenue and operating
income of the applicable segment.

The following tables present information on our business segments.

Operations by business segment

Millions of dollars

Revenue:
Completion and Production
Drilling and Evaluation
Total revenue

Operating income (loss):
Completion and Production
Drilling and Evaluation
Total operations
Corporate and other
Impairments and other charges (a)
Total operating income (loss)

Interest expense, net of interest income
Other, net

Income (loss) 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

Year Ended December 31
2014

2013

2015

13,682 $
9,951
23,633 $

20,253 $
12,617
32,870 $

17,506
11,896
29,402

1,069 $
1,519
2,588
(576)
(2,177)

(165)$

(447)$
(324)

(936)$

1,526 $
650
8
2,184 $

1,160 $
638
37
1,835 $

3,670 $
1,740
5,410
(184)
(129)
5,097 $

(383) $
(2)

2,875
1,770
4,645
(1,507)
—
3,138

(331)
(43)

4,712 $

2,764

1,953 $
1,297
33
3,283 $

1,162 $
934
30
2,126 $

1,676
1,210
48
2,934

1,013
873
14
1,900

(a) Includes $1.1 billion attributable to Completion and Production, $1.0 billion attributable to Drilling and Evaluation, and $88 million
attributable to Corporate and other for the year ended December 31, 2015. Includes $60 million attributable to Completion and Production and
$69 million attributable to Drilling and Evaluation for the year ended December 31, 2014.

Millions of dollars
Total assets:
Completion and Production
Drilling and Evaluation
Shared assets
Corporate and other
Total

December 31

2015

2014

13,628 $
10,531
1,785
10,998
36,942 $

16,033
11,237
1,930
2,965
32,165

Not all assets are associated with specific segments. Those assets specific to segments include receivables, inventories,

certain identified property, plant, and equipment (including field service equipment), equity in and advances to related
companies, and goodwill. The remaining assets, such as cash and equivalents, are considered to be shared among the segments.

The following tables present information by geographic area. In 2015, 2014, and 2013, based on the location of
services provided and products sold, 44%, 51%, and 49% of our consolidated revenue was from the United States. As of
December 31, 2015 and December 31, 2014, 51% and 46% of our property, plant, and equipment was from the United States.
No other country accounted for more than 10% of our revenue or property, plant, and equipment during the periods presented.

Operations by geographic region

Millions of dollars
Revenue:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total

Millions of dollars
Net property, plant, and equipment:
North America
Latin America
Europe/Africa/CIS
Middle East/Asia
Total

Year Ended December 31
2014

2015

2013

10,856 $
3,149
4,175
5,453
23,633 $

17,698 $
3,875
5,490
5,807
32,870 $

15,212
3,909
5,225
5,056
29,402

December 31

2015

2014

6,057
5,745 $
1,406
1,450
1,832
1,594
3,180
2,122
10,911 $ 12,475

Note 5. Receivables

Our trade receivables are generally not collateralized. At December 31, 2015 and December 31, 2014, 26% and 39%

of our gross trade receivables were from customers in the United States, respectively. Other than Venezuela, as further
discussed below, no other country or single customer accounted for more than 10% of our gross trade receivables at these dates.
Venezuela. During the first quarter of 2015, we began utilizing the new SIMADI exchange rate mechanism to

remeasure our net monetary assets denominated in Bolívares, at a market rate of 192 Bolívares per United States dollar as
compared to the official exchange rate of 6.3 Bolívares per United States dollar we had previously utilized, resulting in a
foreign currency devaluation loss of $199 million. See Note 3 and “Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Business Environment and Results of Operations” for further information.

Our total outstanding trade receivables in Venezuela were $704 million, which is more than 10% of our gross trade
receivables, as of December 31, 2015, compared to $670 million, or approximately 9% of our gross trade receivables, as of
December 31, 2014. We have experienced delays in collecting payment on our receivables from our primary customer in
Venezuela, which contributed to the increase in those receivables during the period. This was partially offset by a decline due to
the currency devaluation in the first quarter of 2015. These receivables are not disputed, and we have not historically had
material write-offs relating to this customer. Additionally, we routinely monitor the financial stability of our customers. Of the
$704 million of receivables in Venezuela as of December 31, 2015, the majority of which are United States dollar-denominated
receivables, $175 million has been classified as long-term and included within “Other assets” on our consolidated balance
sheets. Of the $670 million receivables in Venezuela as of December 31, 2014, $256 million has been classified as long-term
and included within “Other assets” on our consolidated balance sheets.

The following table presents a rollforward of our allowance for bad debts for 2013, 2014, and 2015.

Millions of dollars
Year ended December 31, 2013
Year ended December 31, 2014
Year ended December 31, 2015

Balance at
Beginning of
Period

Charged to
Costs and
Expenses Write-Offs

Balance at
End of
Period

92 $
117
137

39 $
26
44

(14) $
(6)
(36)

117
137
145

Note 6. Inventories

Inventories are stated at the lower of cost or market. In the United States, we manufacture certain finished products

and parts inventories for drill bits, completion products, bulk materials, and other tools that are recorded using the last-in, first-
out method and totaled $120 million at December 31, 2015 and $227 million at December 31, 2014. If the average cost method
had been used, there would have been no difference reported at December 31, 2015 and total inventories would have been $38
million higher than reported at December 31, 2014. 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

2015

2014

1,747 $
548
122
2,417 $

2,606
754
211
3,571

We reclassified $576 million of our inventory to assets held for sale as of December 31, 2015. See Note 2 for further

information. Additionally, as a result of the downturn in the energy market and its corresponding impact on our business
outlook, we recorded inventory write-downs as the cost of some of our inventory exceeded its market value. See Note 3 for
further information about impairments and other charges.

Finished products and parts are reported net of obsolescence reserves of $218 million at December 31, 2015 and $161

million at December 31, 2014.

Note 7. 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

2015

2014

232 $

3,359
17,109
20,700
9,789
10,911 $

217
3,311
19,954
23,482
11,007
12,475

Classes of assets, excluding oil and natural gas investments, are depreciated over the following useful lives:

Buildings and Property
Improvements

2015
12%
41%
22%
25%

2014
12%
42%
21%
25%

Machinery, Equipment,
and Other

2015
23%
69%
8%

2014
23%
70%
7%

1 - 10 years
11 - 20 years
21 - 30 years
31 - 40 years

1 - 5 years
6 - 10 years
11 - 20 years

Note 8. Debt

Our long-term debt, including current maturities, consisted of the following:

Millions of dollars
5.0% senior notes due November 2045
3.8% senior notes due November 2025
3.375% senior notes due November 2022
2.7% senior notes due November 2020
3.5% senior notes due August 2023
4.85% senior notes due November 2035
6.15% senior notes due September 2019
7.45% senior notes due September 2039
4.75% senior notes due August 2043
6.7% senior notes due September 2038
1.0% senior notes due August 2016
3.25% senior notes due November 2021
4.5% senior notes due November 2041
2.0% senior notes due August 2018
5.9% senior notes due September 2018
7.6% senior debentures due August 2096
8.75% senior debentures due February 2021
6.75% notes due February 2027
7.53% notes due May 2017
Other
Unamortized debt issuance costs and discounts
Total
Current maturities
Total long-term debt

December 31

2015

2014

2,000 $
2,000
1,250
1,250
1,100
1,000
1,000
1,000
900
800
600
500
500
400
400
300
185
104
45
144
(132)

15,346

(659)
14,687 $

—
—
—
—
1,100
—
1,000
1,000
900
800
600
500
500
400
400
300
185
104
45
37
(92)
7,779
(14)
7,765

$7.5 billion issuance
In November 2015, we issued $7.5 billion aggregate principal amount of senior notes in five tranches: $1.25 billion of

2.7% senior notes due 2020, $1.25 billion of 3.375% senior notes due 2022, $2.0 billion of 3.8% senior notes due 2025, $1.0
billion of 4.85% senior notes due 2035, and $2.0 billion of 5.0% senior notes due 2045. We intend to use the net proceeds of the
offering for general corporate purposes, including financing a portion of the cash consideration component of our pending
acquisition of Baker Hughes. The 2020 notes and the 2022 notes, which aggregate $2.5 billion in principal amount, are subject
to a special mandatory redemption. In the event the Baker Hughes acquisition is not consummated on or prior to November 13,
2016, or, if prior to such date, the merger agreement is terminated for any reason, we will be required to redeem the 2020 notes
and the 2022 notes at a redemption price equal to 101% of the principal amount, plus accrued and unpaid interest. Based on
management's assessment, we believe the 2020 notes and the 2022 notes are appropriately classified as long-term debt on our
consolidated balance sheets as of December 31, 2015.

In conjunction with the November 2015 debt issuance, we adopted a new accounting standards update requiring debt
issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent
with debt discounts. We applied the change retrospectively for prior period balances of unamortized debt issuance costs. As
such, the table above now presents unamortized debt issuance costs and discounts in the aggregate for both periods. See Note
16 for further information.

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
In July 2015, we entered into a new five-year revolving credit agreement, with an initial capacity of $3.0 billion,

increasing to $4.5 billion upon closing of the Baker Hughes acquisition and satisfaction of the conditions provided in the credit
agreement. The credit agreement is for working capital or general corporate purposes and expires on July 21, 2020. The full
amount of the revolving credit facility was available as of December 31, 2015.

Debt maturities
Our long-term debt matures as follows: $659 million in 2016, $79 million in 2017, $823 million in 2018, $1.0 billion

in 2019, $1.3 billion in 2020, and the remainder in 2021 and thereafter.

Bridge facility commitment
In November 2014, we obtained a commitment letter for an $8.6 billion senior unsecured bridge facility in connection
with the pending acquisition of Baker Hughes. Upon issuance of the $7.5 billion principal amount of senior notes in November
2015, the commitment was reduced by that amount to $1.1 billion, and the facility expires on April 30, 2016. We have not
drawn any amounts under this commitment as of December 31, 2015. We may use cash on hand, obtain additional debt
financings or a combination thereof, in lieu of utilizing all or a portion of the bridge facility for the remaining portion of the
cash consideration for the acquisition. See Note 2 for further information about the pending acquisition.

Note 9. Commitments and Contingencies

Macondo well incident
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 an affiliate of Transocean Ltd. and had been drilling
the Macondo exploration well in the Gulf of Mexico for the lease operator, BP Exploration & Production, Inc. (BP). We
performed a variety of services on that well for BP. There were eleven fatalities and a number of injuries as a result of the
Macondo well incident.

Litigation and settlements. Numerous lawsuits relating to the Macondo well incident and alleging damages arising

from the blowout were filed against various parties, including BP, Transocean and us, in federal and state courts throughout the
United States, most of which were consolidated in a Multi District Litigation proceeding (MDL) in the United States Eastern
District of Louisiana. The defendants in the MDL proceeding filed a variety of cross claims against each other.

In 2012, BP reached a settlement to resolve the substantial majority of eligible private economic loss and medical

claims stemming from the Macondo well incident (BP MDL Settlements). The MDL court has since certified the classes and
granted final approval for the BP MDL Settlements, which also provided for the release by participating plaintiffs of
compensatory damage claims against us.

The trial for the first phase of the MDL proceeding occurred in February 2013 through April 2013 and covered issues
arising out of the conduct and degree of culpability of various parties allegedly relevant to the loss of well control, the ensuing
fire and explosion on and sinking of the Deepwater Horizon, and the initiation of the release of hydrocarbons from the
Macondo well. In September 2014, the MDL court ruled (Phase One Ruling) that, among other things, (1) in relation to the
Macondo well incident, BP’s conduct was reckless, Transocean’s conduct was negligent, and our conduct was negligent, (2)
fault for the Macondo blowout, explosion, and spill was apportioned 67% to BP, 30% to Transocean and 3% to us, and (3) the
indemnity and release clauses in our contract with BP are valid and enforceable against BP. The MDL court did not find that
our conduct was grossly negligent, thereby, subject to any appeals, eliminating our exposure in the MDL for punitive damages.
The appeal process for the Phase One Ruling is underway, with various parties filing briefs according to a court-ordered
schedule.

In September 2014, prior to the Phase One Ruling, we reached an agreement, subject to court approval, to settle a
substantial portion of the plaintiffs’ claims asserted against us relating to the Macondo well incident (our MDL Settlement).
Pursuant to our MDL Settlement, we agreed to pay an aggregate of $1.1 billion, which includes legal fees and costs, into a
settlement fund in three installments over two years, except that one installment of legal fees will not be paid until all of the
conditions to the settlement have been satisfied or waived. Certain conditions must be satisfied before our MDL Settlement
becomes effective and the funds are released from the settlement fund. These conditions include, among others, the issuance of
a final order of the MDL court, including the resolution of certain appeals. In addition, we have the right to terminate our MDL
Settlement if more than an agreed number of plaintiffs elect to opt out of the settlement prior to the expiration of the opt out
deadline to be established by the MDL court. Before approving our MDL Settlement, the MDL court must certify the
settlement class, the numerous class members must be notified of the proposed settlement, and the court must hold a fairness
hearing. We are unable to predict when the MDL court will approve our MDL Settlement.

Our MDL Settlement does not cover claims against us by the state governments of Alabama, Florida, Mississippi,

Louisiana, or Texas, claims by our own employees, compensatory damages claims by plaintiffs in the MDL that opted out of or
were excluded from the settlement class in the BP MDL Settlements, or claims by other defendants in the MDL or their
respective employees. However, these claims have either been dismissed, are subject to dismissal, are subject to
indemnification by BP, or are not believed to be material.

On May 20, 2015, we and BP entered into an agreement to resolve all remaining claims against each other, and

pursuant to which BP will defend and indemnify us in future trials for compensatory damages. We have also reached a similar
agreement with Transocean, each agreeing to drop all remaining claims against the other. On July 2, 2015, BP announced that it
had reached agreements in principle to settle all remaining federal, state and local government claims arising from the Macondo
well incident.

Regulatory action. 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. We have appealed the INCs, but the appeal has been suspended pending certain proceedings in
the MDL and potential appeals. The BSEE has announced that the INCs will be reviewed for possible imposition of civil
penalties once the appeal has ended. 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.

Loss contingency. During 2015, we made the second installment payment under our MDL Settlement in the amount of

$333 million. Accordingly, as of December 31, 2015, our remaining liability related to the Macondo well incident was $472
million, consisting of a current portion of $400 million related to our MDL Settlement and a non-current portion of $72 million
representing a loss contingency unrelated to that settlement, included within "Other liabilities" on our consolidated balance
sheets. Our loss contingency liability has not been reduced for potential recoveries from our insurers. See below for information
regarding amounts that we could potentially recover from insurance.

Subject to the satisfaction of the conditions of our MDL Settlement and to the resolution of the appeal of the Phase

One Ruling, we believe that the BP MDL Settlement, our MDL Settlement, the Phase One Ruling and our settlement with BP
have eliminated any additional material financial exposure to us in relation to the Macondo well incident.

Insurance coverage. We had a general liability insurance program of $600 million at the time of the Macondo well
incident. Our insurance was 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. Through December 31, 2015, we have incurred approximately $1.5 billion of expenses related
to the MDL Settlement, legal fees, and other settlement-related costs, of which $403 million has been reimbursed under our
insurance program. Most of the insurance carriers that issued policies in the final $200 million layer of insurance coverage
relating to the Macondo well incident notified us that they would not reimburse us with respect to our MDL Settlement. During
the first and third quarters of 2015, we settled with two of the remaining insurance carriers. We have initiated arbitration
proceedings to pursue recovery of the remaining balance of approximately $118 million. Due to the uncertainty surrounding
such recovery, no related amounts have been recognized in the consolidated financial statements as of December 31, 2015.

Fair Labor Standards Act (FLSA) Claim
In 2014, the U.S. Department of Labor Wage and Hour Division (DOL) commenced an audit to determine whether

certain workers have been properly classified by us as exempt under the FLSA. In addition, litigation was commenced against
us alleging that certain field professionals were not properly classified. During 2015, upon completion of a detailed analysis of
the potential exposure involved and settlement with the DOL and of the pending litigation, we recorded corresponding loss
contingency liabilities.

Securities litigation
In June 2002, a class action lawsuit was filed against us in federal court alleging violations of the federal securities

laws after the Securities and Exchange Commission (SEC) initiated an investigation in connection with our change in
accounting for revenue on long-term construction projects and related disclosures. In the weeks that followed, approximately
twenty similar class actions were filed against us. Several of those lawsuits also named as defendants several of our present or
former officers and directors. The class action cases were later consolidated, and the amended consolidated class action
complaint, styled Richard Moore, et al. v. Halliburton Company, et al., was filed and served upon us in April 2003. As a result
of a substitution of lead plaintiffs, the case was styled Archdiocese of Milwaukee Supporting Fund (AMSF) v. Halliburton
Company, et al. AMSF has changed its name to Erica P. John Fund, Inc. (the Fund). We settled with the SEC in the second
quarter of 2004.

In June 2003, the lead plaintiffs filed a motion for leave to file a second amended consolidated complaint, which was

granted by the court. In addition to restating the original accounting and disclosure claims, the second amended consolidated
complaint included claims arising out of our 1998 acquisition of Dresser Industries, Inc., including that we failed to timely
disclose the resulting asbestos liability exposure.

In April 2005, the court appointed new co-lead counsel and named the Fund the new lead plaintiff, directing that it file
a third consolidated amended complaint and that we file our motion to dismiss. The court held oral arguments on that motion in
August 2005. In March 2006, the court entered an order in which it granted the motion to dismiss with respect to claims arising
prior to June 1999 and granted the motion with respect to certain other claims while permitting the Fund to re-plead some of
those claims to correct deficiencies in its earlier complaint. In April 2006, the Fund filed its fourth amended consolidated
complaint. We filed a motion to dismiss those portions of the complaint that had been re-pled. A hearing was held on that
motion in July 2006, and in March 2007 the court ordered dismissal of the claims against all individual defendants other than
our Chief Executive Officer (CEO). The court ordered that the case proceed against our CEO and us.

In September 2007, the Fund filed a motion for class certification, and our response was filed in November 2007. The

district court issued an order in November 2008 denying the motion for class certification. The Fifth Circuit Court of Appeals
affirmed the district court’s order denying class certification. In June 2011, the United States Supreme Court reversed the Fifth
Circuit ruling that the Fund needed to prove loss causation in order to obtain class certification and the case was returned to the
lower courts for further consideration.

In January 2012, the district court issued an order certifying the class. In April 2013, the Fifth Circuit issued an order

affirming the district court's order.

Our writ of certiorari with the United States Supreme Court was granted and in June 2014 the Supreme Court issued
its decision, maintaining the presumption of class member reliance through the “fraud on the market” theory, but holding that
we are entitled to rebut that presumption by presenting evidence that there was no impact on our stock price from the alleged
misrepresentation. Because the district court and the Fifth Circuit denied us that opportunity, the Supreme Court vacated the
Fifth Circuit’s decision and remanded for further proceedings consistent with the Supreme Court decision.

In December 2014, the district court held a hearing to consider whether there was an impact on our stock price from

the alleged misrepresentations. On July 27, 2015, the district court denied certification for the plaintiff class with respect to five
of the six dates upon which the plaintiffs claimed that disclosures correcting previously misleading statements had been made
that resulted in an impact to the stock price. However, the district court certified the class with respect to a disclosure made on
December 7, 2001 regarding an adverse jury verdict in an asbestos case that plaintiffs alleged was corrective, leaving the
allegation relating to disclosure of the asbestos liability exposure as the only remaining punitive class action claim. The ruling
was based on the district court's conclusion that the court was required to assume at class certification that a disclosure was
actually corrective. We do not agree with that conclusion and filed a petition with the Fifth Circuit seeking to appeal the ruling.
On November 4, 2015, the Fifth Circuit granted our petition to appeal the district court's ruling. The case will now be fully
briefed and argued before the Fifth Circuit. We cannot predict the outcome or consequences of this case, which we intend to
vigorously defend.

Investigations
We are conducting internal investigations of certain areas of our operations in Angola and Iraq, focusing on

compliance with certain company policies, including our Code of Business Conduct (COBC), and the FCPA and other
applicable laws.

In December 2010, we received an anonymous e-mail alleging that certain current and former personnel violated our

COBC and the FCPA, principally through the use of an Angolan vendor. The e-mail also alleges conflicts of interest, self-
dealing, and the failure to act on alleged violations of our COBC and the FCPA. We contacted the DOJ to advise them that we
were initiating an internal investigation.

During the second quarter of 2012, in connection with a meeting with the DOJ and the SEC regarding the above

investigation, we advised the DOJ and the SEC that we were initiating unrelated, internal investigations into payments made to
a third-party agent relating to certain customs matters in Angola and to third-party agents relating to certain customs and visa
matters in Iraq.

Since the initiation of the investigations described above, we have participated in meetings with the DOJ and the SEC

to brief them on the status of the investigations and produced documents to them both voluntarily and as a result of SEC
subpoenas to us and certain of our current and former officers and employees.

We expect to continue to have discussions with the DOJ and the SEC regarding issues relevant to the Angola and Iraq

matters described above. We have engaged outside counsel and independent forensic accountants to assist us with these
investigations.

Because these investigations are ongoing, we cannot predict their outcome or the consequences thereof.
Environmental
We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In

the United States, these laws and regulations include, among others:

- the Comprehensive Environmental Response, Compensation, and Liability Act;
- the Resource Conservation and Recovery Act;
- the Clean Air Act;
- the Federal Water Pollution Control Act;
- the Toxic Substances Control Act; and
- the Oil Pollution Act.
In addition to the federal laws and regulations, states and other countries where we do business often have numerous

environmental, legal, and regulatory requirements by which we must abide. We evaluate and address the environmental impact
of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with
environmental, legal, and regulatory requirements. Our Health, Safety, and Environment group has several programs in place to
maintain environmental leadership and to help prevent the occurrence of environmental contamination. On occasion, in
addition to the matters relating to the Macondo well incident described above, we are involved in other environmental litigation
and claims, including the remediation of properties we own or have operated, as well as efforts to meet or correct compliance-

related matters. We do not expect costs related to those claims and remediation requirements to have a material adverse effect
on our liquidity, consolidated results of operations, or consolidated financial position. Our accrued liabilities for environmental
matters were $50 million as of December 31, 2015 and $57 million as of December 31, 2014. Because our estimated liability is
typically within a range and our accrued liability may be the amount on the low end of that range, our actual liability could
eventually be well in excess of the amount accrued. Our total liability related to environmental matters covers numerous
properties.

Additionally, we have subsidiaries that have been named as potentially responsible parties along with other third

parties for eight federal and state Superfund sites for which we have established reserves. As of December 31, 2015, those eight
sites accounted for approximately $3 million of our $50 million total environmental reserve. Despite attempts to resolve these
Superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount
accrued. With respect to some Superfund sites, we have been named a potentially responsible party by a regulatory agency;
however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims
with respect to environmental matters for which we have been named as a potentially responsible party.

Guarantee arrangements
In the normal course of business, we have agreements with financial institutions under which approximately $2.0

billion of letters of credit, bank guarantees, or surety bonds were outstanding as of December 31, 2015. 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 $875 million in 2015, $1.0 billion
in 2014, and $958 million in 2013.

Future total rentals on our noncancellable operating leases are $944 million in the aggregate, which includes the

following: $257 million in 2016; $171 million in 2017; $132 million in 2018; $96 million in 2019; $60 million in 2020; and
$228 million thereafter.

Note 10. Income Taxes

The components of the benefit (provision) for income taxes on continuing operations were:

Millions of dollars
Current income taxes:
Federal
Foreign
State
Total current
Deferred income taxes:
Federal
Foreign
State
Total deferred
Income tax benefit (provision)

Year Ended December 31
2014

2013

2015

635 $
(636)
51
50

(18)
262
(20)
224
274 $

(959) $
(734)
(36)
(1,729)

83
357
14
454
(1,275) $

(245)
(485)
(49)
(779)

4
125
2
131
(648)

The United States and foreign components of income (loss) from continuing operations before income taxes were as

follows:

Millions of dollars
United States
Foreign
Total

Year Ended December 31
2014

2015

2013

(1,560)$
624
(936)$

3,020 $
1,692
4,712 $

1,070
1,694
2,764

Reconciliations between the actual provision for income taxes on continuing operations and that computed by

applying the United States statutory rate to income (loss) from continuing operations before income taxes were as follows:

Year Ended December 31
2014

2015

2013

United States statutory rate

Impact of foreign income taxed at different rates
Venezuela devaluation
Valuation allowance against tax assets
Impact of impairments and other charges
Non-deductible acquisition costs
Adjustments of prior year taxes
Other impact of foreign operations
State income taxes
Domestic manufacturing deduction
Other items, net

Total effective tax rate on continuing operations

35.0%
(15.6)
4.3
3.5
(3.0)
2.6
(0.7)
(0.5)
0.3
—
3.4
29.3%

35.0%
(5.7)
—
(3.6)
—
—
0.3
(0.1)
0.8
(1.9)
2.3
27.1%

35.0%
(9.3)
—
(0.1)
—
—
(0.6)
(0.7)
1.7
(2.0)
(0.5)
23.5%

Our effective tax rate on continuing operations was 29.3% for 2015, 27.1% for 2014 and 23.5% for 2013. The
effective tax rate in all periods were positively impacted by lower tax rates in certain foreign jurisdictions. The effective tax rate
for 2015 was also impacted by the tax effects of the $2.2 billion of impairments and other charges, a change in mix of
geographic earnings in which we experienced low levels of United States income during the year, additional valuation
allowances booked on foreign deferred tax assets, a $199 million foreign currency exchange loss in Venezuela, and non-
deductible costs related to the pending Baker Hughes acquisition. The effective tax rate for 2014 was positively impacted by a
$201 million net operating loss valuation allowance released as a result of a reorganization of our legal structure in
Brazil. Partially offsetting these items were total charges of approximately $150 million for a write-off of certain prepaid tax
assets recorded in Iraq, additional tax expenses related to the settlement of a research and development credit with the United
States authorities, and tax expenses related to other unrecognized tax benefits, which are mostly included in "Other items, net"
in the table above.

We have not provided United States income taxes and foreign withholding taxes on the undistributed earnings of
foreign subsidiaries as of December 31, 2015 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, 2015, the cumulative amount of earnings upon
which United States income taxes have not been provided is approximately $6.9 billion. It is not practicable to estimate the
amount of unrecognized deferred tax liability related to these earnings at this time.

The primary components of our deferred tax assets and liabilities were as follows:

Millions of dollars
Gross deferred tax assets:
Accrued liabilities
Net operating loss carryforwards
Employee compensation and benefits
Foreign tax credit carry forward
Other

Total gross deferred tax assets
Gross deferred tax liabilities:

Depreciation and amortization
Other

Total gross deferred tax liabilities
Valuation allowances
Net deferred income tax asset

December 31

2015

2014

392 $
540
403
365
354
2,054

1,334
109
1,443
213
398 $

494
462
395
79
236
1,666

1,005
111
1,116
184
366

At December 31, 2015, we had $2.0 billion of net operating loss carryforwards, of which $375 million will expire

from 2016 through 2019, $367 million will expire from 2020 through 2024, and $285 million will expire from 2025 through
2035. The remaining balance will not expire.

The following table presents a rollforward of our unrecognized tax benefits and associated interest and penalties.

Unrecognized
Tax Benefits

Interest
and Penalties

Millions of dollars
Balance at January 1, 2013
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, 2013
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, 2014
Change in prior year tax positions
Change in current year tax positions
Cash settlements with taxing authorities
Lapse of statute of limitations
Balance at December 31, 2015

68
(9)
1
(17)
(9)
34
24
—
(1)
(1)
56
7
1
(15)
(2)
47
(a) Includes $67 million as of December 31, 2015 and $46 million as of December 31, 2014 in foreign unrecognized tax

228
(53)
30
(21)
(9)
175
83
84
(27)
(1)
314 (a)
(33)
62
(16)
(5)

322 (a)(b) $

benefits that would give rise to a United States tax credit. Approximately $176 million, which excludes $10 million of
unrecognized tax benefits covered by an indemnification asset, as of December 31, 2015 and $194 million as of
December 31, 2014, 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 $37 million that could be resolved within the next 12 months.

We file income tax returns in the United States federal jurisdiction and in various states and foreign jurisdictions. In
most cases, we are no longer subject to state, local, or non-United States income tax examination by tax authorities for years
before 2005. Tax filings of our subsidiaries, unconsolidated affiliates, and related entities are routinely examined in the normal
course of business by tax authorities. Currently, our United States federal tax filings for the tax years 2012 through 2013 are
under review, 2003 through 2009 are under appeal pending final calculation of certain tax attribute carryforwards, and 2010
through 2011 are also under appeals by the Internal Revenue Service.

Note 11. 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

2015

2014

1,071
(215)
856

1,071
(223)
848

Our Board of Directors has authorized a program to repurchase our common stock from time to time. The program

does not require a specific number of shares to be purchased and the program may be effected through solicited or unsolicited
transactions in the market or in privately negotiated transactions. The program may be terminated or suspended at any time.
There were no repurchases made under the program during the year ended December 31, 2015. Approximately $5.7 billion
remains authorized for repurchases as of December 31, 2015. From the inception of this program in February 2006 through
December 31, 2015, we repurchased approximately 201 million shares of our common stock for a total cost of approximately
$8.4 billion.

Preferred stock
Our preferred stock consists of five million total authorized shares at December 31, 2015, 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
Unrealized loss on cash flow hedge
Other
Total accumulated other comprehensive loss

December 31

2015

2014

(221 ) $
(78)
(67)
3
(363 ) $

(326)
(70)
—
(3)
(399)

(a) Included net actuarial losses for our international pension plans of $205 million at
December 31, 2015 and $298 million at December 31, 2014.

Note 12. Stock-based Compensation

The following table summarizes stock-based compensation costs for the years ended December 31, 2015, 2014, and

2013.

Millions of dollars
Stock-based compensation cost
Tax benefit
Stock-based compensation cost, net of tax

Year Ended December 31
2014

2015

2013

294 $
(99)
195 $

298 $
(90)
208 $

264
(81)
183

Our Stock and Incentive Plan, as amended (Stock Plan), provides for the grant of any or all of the following types of

stock-based awards:

- stock options, including incentive stock options and nonqualified stock options;
- restricted stock awards;
- restricted stock unit awards;
- stock appreciation rights; and
- stock value equivalent awards.
There are currently no stock appreciation rights, stock value equivalent awards, or incentive stock options outstanding.
Under the terms of the Stock Plan, approximately 187 million shares of common stock have been reserved for issuance

to employees and non-employee directors. At December 31, 2015, approximately 19 million shares were available for future
grants under the Stock Plan. The stock to be offered pursuant to the grant of an award under the Stock Plan may be authorized
but unissued common shares or treasury shares.

In addition to the provisions of the Stock Plan, we also have stock-based compensation provisions under our Restricted

Stock Plan for Non-Employee Directors and our Employee Stock Purchase Plan (ESPP).
Each of the active stock-based compensation arrangements is discussed below.
Stock options
The majority of our options are generally issued during the second quarter of the year. All stock options under the

Stock Plan are granted at the fair market value of our common stock at the grant date. Employee stock options vest ratably over
a three-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 2015.

Outstanding at January 1, 2015

Granted
Exercised
Forfeited/expired

Outstanding at December 31, 2015

Exercisable at December 31, 2015

Number
of Shares
(in millions)

Weighted
Average
Exercise
Price
per Share

Weighted
Average
Remaining
Contractual
Term (years)

Aggregate
Intrinsic
Value
(in millions)

17.4 $
4.3
(0.8)
(0.9)
20.0 $

11.2 $

43.73
43.49
30.81
49.88
43.90

39.95

7.1 $

5.8 $

The total intrinsic value of options exercised was $9 million in 2015, $151 million in 2014, and $93 million in 2013.

As of December 31, 2015, there was $88 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 $167 million during 2015, $332 million during 2014, and $277 million

during 2013.

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
Weighted average grant-date fair value per share

2015
5.16
39%

Year Ended December 31
2014
5.23
37%
1.51 - 1.85% 0.94 - 1.77% 0.94 - 1.33%
1.43 - 1.72% 1.57 - 1.86% 0.77 - 1.73%
$19.26

2013
5.27
40%

$14.34

$13.47

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.

The following table represents our restricted stock awards and restricted stock units granted, vested, and forfeited

during 2015.

Nonvested shares at January 1, 2015

Granted
Vested
Forfeited

Nonvested shares at December 31, 2015

Number of
Shares
(in millions)

Weighted
Average
Grant-Date Fair
Value per Share
45.88
43.24
42.86
47.57
45.59

16.1 $
6.5
(4.8)
(1.3)
16.5 $

The weighted average grant-date fair value of shares granted during 2014 was $58.21 and during 2013 was $42.93.

The total fair value of shares vested during 2015 was $211 million, during 2014 was $278 million, and during 2013 was $208
million. As of December 31, 2015, there was $507 million of unrecognized compensation cost, net of estimated forfeitures,
related to nonvested restricted stock, which is expected to be recognized over a weighted average period of three years.

Employee Stock Purchase Plan
Under the ESPP, eligible employees may have up to 10% of their earnings withheld, subject to some limitations, to be
used to purchase shares of our common stock. The ESPP contains four three-month offering periods commencing on January 1,
April 1, July 1, and October 1 of each year. The price at which common stock may be purchased under the ESPP is equal to
85% of the lower of the fair market value of the common stock on the commencement date or last trading day of each offering
period. Under this plan, 74 million shares of common stock have been reserved for issuance. The stock to be offered may be
authorized but unissued common shares or treasury shares. As of December 31, 2015, 40 million shares have been sold through
the ESPP since the inception of the plan and 34 million shares are available for future issuance.

The fair value of ESPP shares was estimated using the Black-Scholes option pricing model. The expected volatility

was a one-year historical volatility of our common stock. The assumptions and resulting fair values were as follows:

Expected volatility
Expected dividend yield
Risk-free interest rate
Weighted average grant-date fair value per share

Year Ended December 31
2014

2015

2013

35%
1.82%
0.01%
8.62 $

23%
1.07%
0.04%
11.80 $

27%
1.12%
0.06%
8.40

Note 13. Income per Share

Basic income or loss per share is based on the weighted average number of common shares outstanding during the
period. Diluted income per share includes additional common shares that would have been outstanding if potential common
shares with a dilutive effect had been issued. Antidilutive securities represent potentially dilutive securities which are excluded
from the computation of diluted income or loss per share as their impact was antidilutive.

A reconciliation of the number of shares used for the basic and diluted income per share computations is as follows:

Millions of shares
Basic weighted average common shares outstanding
Dilutive effect of awards granted under our stock incentive plans
Diluted weighted average common shares outstanding

Antidilutive shares:

Options with exercise price greater than the average market price
Options which ordinarily would be considered dilutive if not for
being in net loss position
Total antidilutive shares

Year Ended December 31
2014

2013

2015

853
—
853

2
12

848
4
852

—
2

898
4
902

—
3

Note 14. Financial Instruments and Risk Management

At December 31, 2015, we held $96 million of investments in fixed income securities with maturities ranging from
less than one year to January 2018, of which $63 million are classified as “Other current assets” and $33 million are classified
as “Other assets” on our consolidated balance sheets. At December 31, 2014, we held $103 million of investments in fixed
income securities, of which $56 million are classified as "Other current assets" and $47 million are classified as "Other assets"
on our consolidated balance sheets.

These securities consist primarily of corporate bonds and other debt instruments, are accounted for as available-for-

sale and recorded at fair value, and are classified as Level 2 assets. Level 2 asset fair values are based on quoted prices for
identical assets in less active markets. We have no financial instruments measured at fair value based on quoted prices in active
markets (Level 1) or unobservable inputs (Level 3). The carrying amount of cash and equivalents, receivables, and accounts
payable, as reflected in the consolidated balance sheets, approximates fair value due to the short maturities of these instruments.

The carrying amount and fair value of our long-term debt is as follows:

Millions of dollars
Long-term debt

Level 1

1,009 $

December 31, 2015
Total fair
value
15,956 $

14,947 $

Level 2

Carrying
value
15,346 $

December 31, 2014
Total fair
value

Level 2

Carrying
value

Level 1

4,822 $

4,257 $

9,079 $

7,779

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. Our total fair value and carrying value of debt increased in 2015 compared to 2014
associated with the $7.5 billion debt issuance in November 2015. Additionally, differences between the periods presented in our
Level 1 and Level 2 classification of our long-term debt relate to the timing of when transactions are executed. We have no debt
measured at fair value using unobservable inputs (Level 3).

We are exposed to market risk from changes in foreign currency exchange rates and interest rates. We selectively
manage these exposures through the use of derivative instruments, including forward foreign exchange contracts, foreign
exchange options, and interest rate swaps. The objective of our risk management strategy is to minimize the volatility from
fluctuations in foreign currency and interest rates. We do not use derivative instruments for trading purposes. The fair value of
our forward contracts, options, and interest rate swaps was not material as of December 31, 2015 or December 31, 2014. The
counterparties to our derivatives are primarily global commercial and investment banks.

Foreign currency exchange risk
We have operations in many international locations and are involved in transactions denominated in currencies other
than the United States dollar, our functional currency, which exposes us to foreign currency exchange rate risk. Techniques in
managing foreign currency exchange risk include, but are not limited to, foreign currency borrowing and investing and the use
of currency exchange instruments. We attempt to selectively manage significant exposures to potential foreign currency
exchange losses based on current market conditions, future operating activities, and the associated cost in relation to the
perceived risk of loss. The purpose of our foreign currency risk management activities is to minimize the risk that our cash
flows from the sale and purchase of services and products in foreign currencies will be adversely affected by changes in
exchange rates.

We use forward contracts and options to manage our exposure to fluctuations in the currencies of certain countries in
which we do business internationally. These instruments are not treated as hedges for accounting purposes, generally have an
expiration date of one year or less, and are not exchange traded. While these instruments are subject to fluctuations in value, the
fluctuations are generally offset by the value of the underlying exposures being managed. The use of some of these instruments
may limit our ability to benefit from favorable fluctuations in foreign currency exchange rates.

Derivatives are not utilized to manage exposures in some currencies due primarily to the lack of available markets or
cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency
exposure in non-traded currencies and recognize that pricing for the services and products offered in these countries should
account for the cost of exchange rate devaluations. We have historically incurred transaction losses in non-traded currencies.

The notional amounts of open foreign exchange derivatives were $619 million at December 31, 2015 and $662 million
at December 31, 2014. The notional amounts of these instruments do not generally represent amounts exchanged by the parties,
and thus are not a measure of our exposure or of the cash requirements related to these contracts. As such, cash flows related to
these contracts are typically not material. The amounts exchanged are calculated by reference to the notional amounts and by
other terms of the contracts, such as exchange rates.

Interest rate risk
We are subject to interest rate risk on our existing long-term debt, debt potentially issued in the future, and some of our

long-term investments in fixed income securities. Our short-term borrowings and short-term investments in fixed income
securities do not give rise to significant interest rate risk due to their short-term nature. We had fixed rate long-term debt
totaling $15.3 billion at December 31, 2015 and $7.8 billion at December 31, 2014, with $659 million maturing during 2016.
We also had $33 million of long-term investments in fixed income securities at December 31, 2015 with maturities that extend
through January 2018.

We maintain an interest rate management strategy that is intended to mitigate the exposure to changes in interest rates

in the aggregate for our debt portfolio. We hold a series of interest rate swaps relating to three of our debt instruments with a
total notional amount of $1.5 billion at a weighted-average, LIBOR-based, floating rate of 4.0% as of December 31, 2015. 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, 2015 and December 31, 2014. 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, 2015, we had fixed rate debt aggregating $13.8 billion and variable rate
debt aggregating $1.5 billion, after taking into account the effects of the interest rate swaps.

Credit risk
Financial instruments that potentially subject us to concentrations of credit risk are primarily cash equivalents,
investments in fixed income securities, and trade receivables. It is our practice to place our cash equivalents and investments in
fixed income securities in high quality investments with various institutions. We derive the majority of our revenue from selling
products and providing services to the energy industry. Within the energy industry, our trade receivables are generated from a
broad and diverse group of customers. As of December 31, 2015, 26% of our gross trade receivables were in the United States
and more than 10% were in Venezuela, compared to 39% in the United States and 9% in Venezuela at December 31, 2014. 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 15. 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 $288 million in 2015, $347 million in 2014, and $313
million in 2013;

- 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, 2015, the projected benefit obligation was $1.0 billion and the
fair value of plan assets was $872 million, which resulted in an unfunded obligation of $174 million. At December 31, 2014,
the projected benefit obligation was $1.2 billion and the fair value of plan assets was $891 million, which resulted in an
unfunded obligation of $347 million. The accumulated benefit obligation for our international plans was $990 million at
December 31, 2015 and $1.2 billion at December 31, 2014.

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

2015

2014

20 $
155

1,042 $
867

964 $
846

22
325

1,232
884

1,120
860

Fair value measurements of plan assets
Our Level 1 plan asset fair values are based on quoted prices in active markets for identical assets, our Level 2 plan

asset fair values are based on significant observable inputs for similar assets, and our Level 3 plan asset fair values are based on
significant unobservable inputs.

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
Cash and equivalents
Common/collective trust funds

Equity funds (a)
Bond funds (b)
Alternatives funds (c)
Real estate funds (d)

Other assets
Fair value of plan assets at December 31, 2015

Common/collective trust funds

Equity funds (a)
Bond funds (b)
Alternatives fund (c)
Real estate funds (d)

Other assets
Fair value of plan assets at December 31, 2014

Level 1

Level 2

Level 3

Total

— $

—
—
—
—
2
2 $

— $
—
—
—
6
6 $

46 $

209
212
42
231
19
759 $

320 $
197
148
86
33
784 $

— $

—
38
46
—
27
111 $

— $
70
—
—
31
101 $

209
250
88
231
48
872

320
267
148
86
70
891

(a) Strategy is to invest in diversified funds of global common stocks.
(b) Strategy is to invest in diversified funds of fixed income securities of varying geographies and credit quality and

whose cash flows approximate the maturities of the benefit obligation.

(c) Strategy is to invest in a fund of diversifying investments, including but not limited to reinsurance, commodities, and

currencies.

(d) Strategy is to invest in diversified funds of real estate investment trusts and private real estate.

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. Risk management practices include
diversification by issuer, industry, and geography, as well as the use of multiple asset classes and investment managers within
each asset class. For our United Kingdom pension plan, which constituted 81% of our international pension plans’ projected
benefit obligation at December 31, 2015 and is no longer accruing service benefits, we implemented an investment strategy in
2014 that aims to achieve full funding of the benefit obligation, with the plan's assets increasingly composed of investments
whose cash flows match the maturities of the obligation.

Net periodic benefit cost
Net periodic benefit cost for our international pension plans was $42 million in 2015, which included $9 million of net

curtailment and settlement cost arising from reductions in workforce during the year. Net periodic benefit cost for our
international pension plans was $36 million in 2014, and $32 million in 2013.

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

2015
4.2%
5.4%

2014
4.1%
5.3%

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

2015
4.1%
5.9%
5.3%

2014
4.8%
6.4%
5.4%

2013
4.8%
6.4%
5.5%

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 $14 million to our international pension plans in 2016.

Benefit payments. The following table presents expected benefit payments over the next 10 years for our international

pension plans.

Millions of dollars
2016
2017
2018
2019
2020
Years 2021 - 2025

51
37
39
44
44
280

Note 16. New Accounting Pronouncements

Standards adopted in 2015
Discontinued Operations
On January 1, 2015, we adopted an accounting standards update issued by the FASB related to discontinued
operations, which added criteria providing that only those disposals of a component of an entity or a group of components of an
entity that represent a strategic shift in operations should be presented as discontinued operations. The update allows an entity
to present a disposal as discontinued operations even when it has continuing cash flows and significant continuing involvement
with the disposed component. The update also requires expanded disclosures for discontinued operations and individually
significant components of an entity that does not qualify for discontinued operations reporting. The adoption of this update did
not impact our consolidated financial statements. This update may have a material impact on our consolidated financial
statements in connection with the anticipated divestitures related to the pending acquisition of Baker Hughes. Because we will
continue operating similar businesses of Baker Hughes after the acquisition, the disposition of the Halliburton businesses
discussed in Note 2 does not represent a strategic shift in our business. Accordingly, these businesses anticipated to be divested
will not be presented as discontinued operations.

Debt Issuance Costs
In April 2015, the FASB issued an accounting standards update to simplify the presentation of debt issuance costs. The

update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct
deduction from the carrying amount of that debt liability, consistent with debt discounts, as opposed to current presentation of
an asset on the balance sheet. This update is effective for fiscal years beginning after December 15, 2015, and interim periods
within those fiscal years, and may be adopted earlier on a voluntary basis. We adopted this update in the fourth quarter of 2015
upon execution of our debt financing for the pending Baker Hughes acquisition. We applied the change retrospectively to
January 1, 2014 for prior period balances of unamortized debt issuance costs, resulting in a $75 million reduction in other assets
and long-term debt on our consolidated balance sheet as of December 31, 2014. See Note 2 for further information about the
pending acquisition and Note 8 for information about our debt issuance in the fourth quarter of 2015.

Deferred Income Taxes
In November 2015, the FASB issued an accounting standards update to simplify income tax accounting. The update

requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet instead of separating deferred
taxes into current and noncurrent amounts. This update is effective for fiscal years beginning after December 15, 2016, and
interim periods within those fiscal years, and may be adopted earlier on a voluntary basis. We adopted this update as of
December 31, 2015 and applied the change retrospectively to January 1, 2014 for prior period balances of deferred tax assets
and liabilities, resulting in a $421 million reduction in total current assets and corresponding increase in other assets, along with
a $17 million reduction in total current liabilities and corresponding increase in other liabilities on our consolidated balance
sheet as of December 31, 2014.

Standards not yet adopted
Revenue Recognition
In May 2014, the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board
(IASB) issued a comprehensive new revenue recognition standard that will supersede existing revenue recognition guidance
under United States generally accepted accounting principles (U.S. GAAP) and International Financial Reporting Standards
(IFRS). The issuance of this guidance completes the joint effort by the FASB and the IASB to improve financial reporting by
creating common revenue recognition guidance for U.S. GAAP and IFRS.

The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised

goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in
exchange for those goods or services. The standard creates a five-step model that requires companies to exercise judgment
when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition
methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified
retrospective adoption in which the standard is applied only to the most current period presented in the financial statements,
including additional disclosures of the standard’s application impact to individual financial statement line items.

In August 2015, the FASB issued an accounting standards update for a one-year deferral of the revenue recognition

standard's effective date for all entities, which changed the effectiveness to annual reporting periods beginning after December
15, 2017, including interim periods within that reporting period. We are currently evaluating this standard and our existing
revenue recognition policies to determine which contracts in the scope of the guidance will be affected by the new requirements
and what impact they would have on our consolidated financial statements upon adoption. We have not yet determined which
transition method we will utilize upon adoption on the effective date.

Consolidation
In February 2015, the FASB issued an accounting standards update related to the consolidation analysis, which
amends the guidelines for determining whether certain legal entities should be consolidated. This update eliminates the

presumption that a general partner should consolidate a limited partnership and modifies the evaluation of whether limited
partnerships are variable interest entities or voting interest entities. This update is effective for fiscal years beginning after
December 15, 2015, and interim periods within those fiscal years. We do not expect the adoption of this update to have a
material impact on our consolidated financial statements.

Inventory
In July 2015, the FASB issued an accounting standards update to simplify the measurement of inventory, which

requires inventory measured using the first in, first out (FIFO) or average cost methods to be subsequently measured at the
lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less
reasonably predictable cost of completion, disposal, and transportation. Currently, these inventory methods are required to be
subsequently measured at the lower of cost or market. Market could be replacement cost, net realizable value, or net realizable
value less an approximately normal profit margin. This update will be effective for fiscal years beginning after December 15,
2016, including interim periods within those fiscal years, and will be applied prospectively. Early adoption is permitted. We are
currently evaluating the impact that this update will have on our consolidated financial statements.

Business Combinations
In September 2015, the FASB issued an accounting standards update to simplify the accounting for measurement-

period adjustments for an acquirer in a business combination. The update will require an acquirer to recognize any adjustments
to provisional amounts of the initial accounting for a business combination with a corresponding adjustment to goodwill in the
reporting period in which the adjustments are determined in the measurement period, as opposed to revising prior periods
presented in financial statements. Thus, an acquirer shall adjust its financial statements as needed, including recognizing in its
current-period earnings the full effect of changes in depreciation, amortization, or other income effects, by line item, if any, as a
result of the change to the provisional amounts calculated as if the accounting had been completed at the acquisition date. This
update is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. This
update may have a material impact on our consolidated financial statements subsequent to the pending acquisition of Baker
Hughes for any measurement-period adjustments after the initial accounting period. See Note 2 for further information about
the pending acquisition.

Year ended December 31
2013
29,402 $
3,138
2,116
2.35
2.33
0.525
8,678
29,223
7,816
13,615
2,934

2014
32,870 $
5,097
3,437
4.05
4.03
0.63
8,781
32,165
7,779
16,298
3,283

2012
28,503 $
4,159
2,587
2.78
2.78
0.36
8,334
27,410
4,820
15,790
3,566

2011
24,829
4,737
3,010
3.27
3.26
0.36
7,456
23,677
4,820
13,216
2,953

HALLIBURTON COMPANY
Selected Financial Data
(Unaudited)

Millions of dollars except per share
Revenue
Operating income (loss)
Income (loss) from continuing operations
Basic income (loss) per share from continuing operations
Diluted income (loss) per share from continuing operations
Cash dividends per share
Net working capital
Total assets
Long-term debt (including current maturities)
Total shareholders’ equity
Capital expenditures

2015
23,633 $
(165)
(662)
(0.78)
(0.78)
0.72
16,250
36,942
15,346
15,495
2,184

HALLIBURTON COMPANY
Quarterly Data and Market Price Information
(Unaudited)

Quarter

Millions of dollars except per share data

First

Second

Third

Fourth

Year

2015
Revenue
Operating income (loss)
Net income (loss)
Amounts attributable to company shareholders:

Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss) attributable to company

Basic income per share attributable to company shareholders:

Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)

Diluted income per share attributable to company shareholders:

Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)

Cash dividends paid per share
Common stock prices (1)

High
Low

2014
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 from discontinued operations
Net income

Diluted income per share attributable to company shareholders:

Income from continuing operations
Income from discontinued operations
Net income

Cash dividends paid per share
Common stock prices (1)

High
Low

7,050 $
(548)
(641)

5,919 $
254
53

5,582 $
43
(53)

5,082 $
86
(26)

23,633
(165)
(667)

(639)
(4)
(643)

(0.75)
(0.01)
(0.76)

(0.75)
(0.01)
(0.76)
0.18

55
(1)
54

0.06
—
0.06

0.06
—
0.06
0.18

(54)
—
(54)

(0.06)
—
(0.06)

(0.06)
—
(0.06)
0.18

(28)
—
(28)

(0.03)
—
(0.03)

(0.03)
—
(0.03)
0.18

(666)
(5)
(671)

(0.78)
(0.01)
(0.79)

(0.78)
(0.01)
(0.79)
0.72

44.92
37.27

50.20
42.46

43.71
30.93

41.28
32.13

50.20
30.93

7,348 $
970
616

8,051 $
1,194
775

8,701 $
1,634
1,205

8,770 $
1,299
905

32,870
5,097
3,501

623
(1)
622

0.73
—
0.73

0.73
—
0.73
0.15

776
(2)
774

0.92
—
0.92

0.91
—
0.91
0.15

1,137
66
1,203

1.34
0.08
1.42

1.33
0.08
1.41
0.15

900
1
901

1.06
—
1.06

1.06
—
1.06
0.18

3,436
64
3,500

4.05
0.08
4.13

4.03
0.08
4.11
0.63

59.99
47.60

71.26
57.13

74.33
63.06

64.88
37.21

74.33
37.21

Note: Results include an aggregate of $2.2 billion in impairments and other charges during 2015. See Note 3 for further information.

(1) New York Stock Exchange – composite transactions high and low intraday price.

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 2016 Annual Meeting of Stockholders (File No. 001-03492) under the captions “Election of Directors”
and “Involvement in Certain Legal Proceedings.” The information required for the executive officers of the Registrant is
included under Part I on pages 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 2016 Annual Meeting of Stockholders (File No. 001-03492) under the caption “Section 16(a) Beneficial Ownership
Reporting Compliance,” to the extent any disclosure is required. The information for our code of ethics is incorporated by
reference to the Halliburton Company Proxy Statement for our 2016 Annual Meeting of Stockholders (File No. 001-03492)
under the caption “Corporate Governance.” The information regarding our Audit Committee and the independence of its
members, along with information about the audit committee financial expert(s) serving on the Audit Committee, is incorporated
by reference to the Halliburton Company Proxy Statement for our 2016 Annual Meeting of Stockholders (File No. 001-03492)
under the caption “The Board of Directors and Standing Committees of Directors.”

Item 11. Executive Compensation.