2016
ANNUAL REPORT
FINANCIAL HIGHLIGHTS
(In millions, except per share amounts)
2016
2015
2014
2013
2012
YEAR ENDED DECEMBER 31
As Reported:
Revenue
Operating income (loss)
Net income (loss)
Net income (loss) attributable to Baker Hughes
Per share of common stock:
Net income (loss) attributable to Baker Hughes:
Basic
Diluted
Dividends
Number of shares:
$ 9,841
$ 15,742
$ 24,551
$ 22,364
$ 21,361
(1,623)
(2,736)
(2,738)
(2,396)
(1,974)
(1,967)
2,859
1,731
1,719
1,949
1,103
1,096
2,192
1,317
1,311
$ (6.31)
$ (4.49)
$ 3.93
$ 2.47
$ 2.98
(6.31)
0.68
(4.49)
0.68
3.92
0.64
2.47
0.60
2.97
0.60
Weighted average common shares diluted
434
438
439
444
441
Reconciliation from As Reported to Adjusted Net Income (Loss):
Net income (loss) attributable to Baker Hughes
$ (2,738)
$ (1,967)
$ 1,719
$ 1,096
$ 1,311
Adjustments(1)
Adjusted net income (loss)(2)
Per share of common stock:
Adjusted net income (loss)(2):
Basic
Diluted
Cash, cash equivalents and short-term investments
Working capital
Total assets
Total debt
Equity
Total debt/capitalization
Number of employees (thousands)
1,455
1,758
130
69
43
$ (1,283)
$ (209)
$ 1,849
$ 1,165
$ 1,354
$ (2.96)
$ (0.48)
$ 4.23
$ 2.62
$ 3.08
(2.96)
4,572
6,863
(0.48)
2,324
6,493
4.22
1,740
7,408
2.62
1,399
6,717
3.07
1,015
6,293
19,034
24,080
28,827
27,934
26,689
3,018
4,041
4,133
4,381
4,916
12,737
16,382
18,730
17,912
17,268
19%
33.0
20%
43.0
18%
62.0
20%
59.4
22%
58.8
(1) 2016 after-tax adjustments: cost of $1,735 million associated with asset impairments, workforce reductions, facility closures and contract terminations; goodwill impairment charge of $1,858 million,
cost of $617 million to adjust the carrying value of certain inventory; cost of $199 million for merger and related expenses; a $97 million loss on sale of business interest; a $142 million loss on early
extinguishment of debt; $41 million in litigation settlements; and a receipt of a $3,500 million merger termination fee.
2015 after-tax adjustments: cost of $1,415 million associated with asset impairments, workforce reductions, facility closures and contract terminations; cost of $214 million for merger and related
expenses; cost of $138 million to adjust the carrying value of certain inventory; and a $9 million reduction in the accrual for litigation settlements for labor claims.
2014 after-tax adjustments: cost of $58 million related to restructuring our North Africa business; cost of $39 million for litigation settlements for labor claims; severance charges of $21 million in
North America; cost of $20 million related to a technology royalty agreement; cost of $14 million related to an impairment of a technology investment; foreign exchange loss of $12 million from
the devaluation of the Venezuelan currency; $34 million gain from the deconsolidation of a joint venture.
2013 after-tax adjustments: severance charges of $29 million; foreign exchange loss of $23 million from the devaluation of the Venezuelan currency; $17 million of restructuring charges related
to Latin America.
2012 after-tax adjustments: expenses of $15 million from the closure of a chemical manufacturing facility in the United Kingdom; expenses of $28 million for internally developed software and
other information technology assets.
(2) Adjusted net loss is a non-GAAP measure comprised of net loss attributable to Baker Hughes excluding the impact of certain identified items. The company believes that adjusted net loss is
useful to investors because it is a consistent measure of the underlying results of the company’s business. Furthermore, management uses adjusted net loss as a measure of the performance
of the company’s operations.
Martin Craighead
CHAIRMAN AND CHIEF EXECUTIVE OFFICER
TO OUR SHAREHOLDERS
Against the backdrop of
continued challenges for the
entire industry, 2016 was a year
of significant accomplishments
for Baker Hughes.
Facing a global supply-demand imbalance
that continued to dampen hydrocarbon pricing
and, by extension, demand and pricing for
oilfield services, Baker Hughes took decisive
steps to strengthen the company’s financial
and competitive position, accelerate product
innovation, and optimize its capital structure.
In addition to delivering on those objectives,
I believe our most transformative achievement
of 2016 will prove to be our agreement with
GE to combine Baker Hughes with GE Oil & Gas
in a transaction that will create value for
our shareholders, benefits for customers
industrywide and opportunities for employees
of both companies.
As we move through the early part of 2017
the company remains focused on building on
our momentum from last year to be successful
regardless of the industry conditions. Contrary
to this time a year ago, or even six months
ago, it is clear that some indicators of a broader
market recovery have fallen into place, but
lingering questions remain that could affect
the outlook.
Looking back on the past year, I am extremely
proud of the efforts of our employees who,
even as they faced difficult industry conditions
and navigated many changes at our own
company, stayed focused on safety, compliance,
controls and delivering for customers.
I want to thank all of our employees for their
commitment to the company and its stakeholders,
which is evident when looking at our overall
performance in the area of Health, Safety and
Environment (HSE). We ended 2016 with 208
“Perfect HSE Days” during which we had no
injuries, environmental releases or vehicle
accidents, eclipsing the 146 perfect days we
achieved in 2015. While this performance is
encouraging, especially in the face of so many
potential distractions, we won’t be satisfied
until every day is a Perfect HSE Day.
OBJECTIVES FOR THE
SECOND HALF OF 2016
I’m particularly proud of our achievements in
delivering on the objectives for the second half
of 2016 that we outlined starting in May, after
the operating restrictions associated with the
merger agreement were terminated. What we
called our “Path Forward” for Baker Hughes
was designed to strengthen our financial
performance, enhance our commercial strategy
and optimize our capital structure. It was an
ambitious plan with four primary components.
First, we said we would simplify the company’s
organizational structure and operational footprint
to improve profitability and return on invested
capital. Our initial goal was to reduce annualized
costs by $500 million by the end of 2016.
Second, we said we would optimize our capital
structure by reducing debt and buying back
shares while maintaining financial flexibility.
Third, we said we would focus on our core strength
of product innovation in our full-service business
while building broader sales channels for our products
and technology, and do so with an asset-light
approach that maximizes returns on invested capital.
And fourth, in line with this asset-light strategy,
we said we intended to maximize shareholder value
for our North American onshore pressure pumping
business while continuing to participate in this
market segment.
On every objective, we achieved or exceeded our goals.
COST AND CAPITAL STRUCTURE
IMPROVEMENTS
On the first objective, reducing costs, we achieved
the $500 million savings target by the end of the third
quarter, three months ahead of schedule. Ultimately,
we achieved nearly $700 million in annualized cost
savings by the end of 2016. More than just an exercise
in removing costs, we accomplished a complete
restructuring of the company to improve efficiency,
foster more accountability and enhance performance.
Regarding our second objective, optimizing our capital
structure, we reduced debt by $1 billion and executed
on our share buyback plan. During the course of
2016, we purchased 16.2 million shares of common
stock totaling $763 million. In addition, we exited
2016 with $4.6 billion in cash, nearly double the $2.3
billion we had at the end of 2015, primarily due to the
receipt of the $3.5 billion merger termination fee.
INNOVATION PIPELINE
STRONG AND GROWING
increasing performance by more than
35% over competitive products.
Turning to our third objective, to ensure
we are best positioned to capitalize on
opportunities in the market, we created
a flatter, simpler and more responsive
organizational structure that has allowed us
to operate more efficiently and effectively.
We gained traction in the market with
key customer contract awards during
the second half of 2016, as we further
strengthened our Sales organization and
accelerated new product launches.
In fact, we exceeded our objective with
nearly 70 new products launched during
the last six months of 2016. That was an
increase of more than 50% over the first
half of the year, as we continue to focus
on developing products that achieve more
efficient wells, production maximization
and improved ultimate recoveries for
customers who are seeking better project
economics amid challenging conditions.
Technology highlights include:
In the category of building more efficient
wells, we launched the Kymera™ XTreme
hybrid drill bit in September, and it had
an immediate impact with drilling
performance records achieved in Norway,
the Netherlands, the Gulf of Mexico, the
Permian Basin, Saudi Arabia, Oman and
Australia. On a number of run evaluations
performed across the globe, this bit is
An example aimed at improving production
was the launch of our TRETOLITE™ SNAP
water clarifier product. Designed for wells
that require oil and water separation,
which can result in higher costs and
operational challenges, this product has
been shown to minimize oil-in-water levels
to improve water quality and lower basic
sediment and water content in the oil to
decrease the amount of recycling required.
In trials prior to commercial launch, this
significantly reduced recycling, costly
equipment clean-outs and slop production,
all while increasing throughput capacity.
And, finally, to increase ultimate recovery
in a meaningful way will require not only
the aforementioned well construction and
production improvements, but also the
development of a new range of sensing
and intelligent products integrated into
a broader digital framework. For several
years now, we've been investing in
next-generation electronics to deploy
in the extreme environments that we
face in drilling and completions.
Our launch of the SureSENS™ QPT
ELITE product is a great example of this
in our completions business, designed
to provide 20 years of downhole data in
high-pressure, high-temperature wells. This
design incorporates integrated circuits that
do not break down in high temperatures
and deliver next-generation reliability
and accuracy for downhole gauges.
This gauge delivers static and dynamic
pressure and temperature data which are
used to calculate estimated returns and
optimize intelligent production systems.
We also launched Integrity eXplorer™, a
unique wireline service that is fast becoming
the industry standard for accurate and
reliable cement evaluation. This technology is
enabled by electromagnetic acoustic sensors
that deliver precise evaluation of any cement
mixture in all borehole environments. When
conventional technologies can’t reliably
confirm cement quality, operators are
required to perform unnecessary remedial
operations that cost them days of rig time
and unplanned expenditures. Integrity
eXplorer is the only product in the market
that deploys this technology and customer
reaction thus far has been exceptional.
The commercial outcomes of our innovation
efforts are not only being recognized by
customers but by the broader industry.
Baker Hughes was honored in October
to receive six World Oil awards, which
recognize the upstream oil and gas industry’s
top innovations and innovators, more
than any other company. I'm confident
that as we focus on what we do best,
differentiate ourselves in the marketplace
through our technology, we will continue
to build on our long legacy of innovation.
Hybrid drill bit
NEW SALES CHANNELS FOR
PRODUCTS AND TECHNOLOGY
Moving to our efforts to build new sales
channels for our products and technology,
we've embarked on a concerted sales
effort globally targeting local service
providers, a segment which has grown
considerably in recent years. These service
providers need a trusted partner who can
provide industry-leading products and
expertise to facilitate their local projects.
Baker Hughes is well positioned to be a
partner of choice for this customer group,
and this effort is already producing results.
During the fourth quarter of 2016, we
entered into agreements with three local
service providers in the United States,
Mexico and Malaysia. The interest among
this customer segment is growing and we
are confident this effort will differentiate
Baker Hughes and become a source
of consistent growth as it matures.
MAXIMIZING VALUE FOR
NORTH AMERICAN LAND
PRESSURE PUMPING BUSINESS
Finishing with our fourth objective, which
was to maximize shareholder value for our
North American onshore pressure pumping
business, we also delivered. In November,
we announced an agreement to contribute
our North American onshore hydraulic
fracturing and cementing business into
a new company that is now the largest
pure-play pressure pumping provider
throughout the North American market.
In addition to receiving cash from our
partners in the transaction, which
closed in late December, we own nearly
47% of a company with outstanding
technology, assets and people, and
a seasoned-leadership team with a
successful track record of execution.
The new company has a strong balance
sheet, more cost-efficient structure, and
even stronger prospects for growth.
Importantly, this transaction allows
Baker Hughes to more efficiently benefit
from the improvement we've already
seen in this market while also allowing
us to reduce our company’s capital
intensity and resource requirements.
FINANCIAL PERFORMANCE
Clearly, 2016 was another incredibly
difficult year overall for the broader
industry. Those challenges were
reflected in our full-year financial
results, as well as those of our peers.
Full-year 2016 revenue was $9.8 billion,
down 37% from 2015. The difficulties
impacting the oilfield services market
could be seen in global rig counts
dropping another 32% compared
to the 2015 average and pricing
pressures worsening as oil prices
bottomed at $26/Bbl early in 2016.
On a GAAP basis, the net loss attributable
to Baker Hughes was $2.7 billion
($6.31 per diluted share) for 2016,
compared to a net loss of $2.0 billion
($4.49 per diluted share) for 2015.
For 2016, adjusted net loss (a
non-GAAP measure), which excludes
the impact of $1.4 billion in adjusting
items, was $1.3 billion ($2.96 per
diluted share), compared to an adjusted
net loss of $209 million ($0.48 per
diluted share) for the prior year.
However, while the industry environment
remained challenging throughout the
year, we achieved an improvement in
our own performance during the second
half of the year as a result of the cost
reductions, organizational changes
and commercial enhancements that
we implemented starting in May.
During the second half of 2016, in
spite of a 6% revenue decline reflecting
broader industry conditions, we
significantly improved our profitability
compared to the first half of the year.
In the fourth quarter specifically, we
were able to achieve revenue growth of
2% sequentially from the third quarter,
to $2.4 billion, our first sequential
quarterly growth in the two years
since the industry downturn began.
While those accomplishments are
indeed meaningful, they are squarely
in our rear-view mirror as we continue
to focus on seeking growth opportunities
while staying disciplined on costs and
working capital.
TRANSFORMATIVE OPPORTUNITY
FOR THE FUTURE
Beyond all that we accomplished last
year, I believe the agreement with GE to
combine Baker Hughes and GE Oil & Gas
will be a transformational combination
for Baker Hughes, our shareholders, and
our customers throughout the industry.
This combination will not only accelerate
our own momentum, but provide needed
productivity and efficiency benefits to our
respective customers, significant value for
our shareholders, and greater opportunities
for employees of both companies.
Together, Baker Hughes and GE Oil & Gas
will create a fullstream equipment, technology,
services and solutions provider that can deliver
step changes in economics and productivity
gains for the benefit of our customers.
The new company also will benefit from
having access to the advanced manufacturing
and innovation capabilities of the broader
GE company, and we will leverage the
immense potential of GE's Predix industrial
operating system to finally deliver on the
long-anticipated promise of data and
analytics in the oil and gas industry.
At a time when investment in technology is
critical to the future of oil and gas, the new
company will be able to provide best-in-class
physical and digital technology solutions.
The combination also will create significant
value for Baker Hughes shareholders. They
will benefit from $1.6 billion in expected cost
and revenue synergies by 2020, receipt of a
$17.50 per share dividend upon closing, and
approximately 37.5% ownership in a company
with more revenue diversity, deeper customer
relationships and stronger cycle resiliency.
Our respective teams are working very
effectively together on the integration
planning efforts, and we continue to expect
a mid-2017 closing. There is great chemistry
between our people, and the two companies
have very similar cultures and values.
In short, I have never been more confident
that this combination is the right and
the best outcome for Baker Hughes, our
customers, shareholders, and employees.
MARKET OUTLOOK
IN CLOSING
In summary, 2016 was a year of significant
progress for Baker Hughes, marked by many
accomplishments. At this point in 2017,
we foresee a more optimistic industry
outlook but one that is not without
challenges and unanswered questions.
Looking ahead, we are excited to build
on our progress and we are confident
that Baker Hughes is well positioned
for success in any market scenario.
Before I close out this letter, I wanted to say
a few words about a special person who
played a huge role in our company’s growth
and success and who, sadly, is no longer
with us. I’m talking about our longtime
director Larry D. Brady, who passed away
in January. The entire Baker Hughes family
was saddened to learn of Larry’s passing.
Larry was a respected leader, dedicated
family man and an outstanding director who
provided invaluable support and guidance
throughout his 13 years on the board. He
was a great advocate for the company
and its shareholders, and I will miss his
friendship, wisdom and counsel a great deal.
In closing, and on behalf of the team at
Baker Hughes, thank you for your loyalty and
for investing in our company. I look forward to
keeping you updated on developments in 2017.
Martin Craighead
CHAIRMAN AND CHIEF EXECUTIVE OFFICER
As we look ahead to the remainder of
2017, it is clear that the market is in a
healthier place today as a result of several
significant industry changes that have
developed since the fall of 2016. However,
while there are reasons to be optimistic, a
number of factors could impact the timing
and breadth of the expected recovery.
OPEC’s decision last fall to scale back
production, along with an increase of
1.6 million barrels per day in forecasted
global demand for 2017, would appear to
point towards a rebalancing of supply and
demand in the second half of this year.
Yet, the impact that the North American
shale segment might have on a potential
recovery remains an open question.
For example, since details of OPEC's plan
surfaced, U.S. rig counts increased by 23%
during the fourth quarter of 2016 alone,
along with a corresponding increase in U.S.
shale production. The North American shale
operators' ability to bring production online
quickly has resulted in the commodity price
recovery being more muted than expected,
bringing some uncertainty to the sustainability
of recent commodity price increases.
In addition, from the oilfield services
perspective, we continue to believe that
activity needs to increase meaningfully before
excess service capacity can be absorbed
and a recovery in service pricing can take
place. We have seen early signs of this in
select product lines in some North American
basins, but a fair amount of capacity must
be absorbed before service pricing will
become more tightly correlated with higher
commodity prices and increased activity.
As we look at the landscape of geographic
markets globally, while we expect the gradual
recovery in North America to continue in
2017, we expect the outlook in international
markets to be roughly flat overall, with pockets
of growth in specific geographic markets, for
the first half of this year. In offshore markets,
we expect continued softness throughout
the year, although we are well positioned
geographically and with our capabilities
to capture opportunities that arise.
FORM 10-K
FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2016
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-9397
Baker Hughes Incorporated
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
76-0207995
(I.R.S. Employer Identification No.)
17021 Aldine Westfield Road, Houston, Texas
(Address of principal executive offices)
77073-5101
(Zip Code)
Registrant's telephone number, including area code: (713) 439-8600
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock, $1 Par Value per Share
New York Stock Exchange
SIX Swiss 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] NO [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES [ ] NO [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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] NO [ ]
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.
(Check one):
Large accelerated filer [X]
Accelerated filer [ ]
Non-accelerated filer [ ]
Smaller reporting company [ ]
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES [ ] NO [X]
The aggregate market value of the voting and non-voting common stock held by non-affiliates as of the last business day of the registrant's most
recently completed second fiscal quarter (based on the closing price on June 30, 2016 reported by the New York Stock Exchange) was
approximately $19,263,511,000.
As of January 31, 2017, the registrant has outstanding 425,325,600 shares of common stock, $1 par value per share.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant's Definitive Proxy Statement for the 2017 Annual Meeting of Stockholders are incorporated by reference into Part III of this
Form 10-K.
Baker Hughes Incorporated
Table of Contents
Part I
Part II
Business
Item 1.
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Item 3.
Item 4. Mine Safety Disclosures
Legal Proceedings
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Item 6.
Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Management's Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income (Loss)
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Balance Sheets
Consolidated Statements of Changes in Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Item 15. Exhibits and Financial Statement Schedules
Signatures
Part IV
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Page
2
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22
24
25
46
48
48
49
50
51
52
53
54
55
93
93
93
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94
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95
95
96
102
ITEM 1. BUSINESS
PART I
Baker Hughes Incorporated is a Delaware corporation engaged in the oilfield services industry. As used herein,
phrases such as "Baker Hughes," "Company," "we," "our" and "us" intend to refer to Baker Hughes Incorporated
and/or its subsidiaries. The use of these terms is not intended to connote any particular corporate status or
relationships.
AVAILABILITY OF INFORMATION FOR STOCKHOLDERS
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 Securities Exchange Act of
1934, as amended (the "Exchange Act"), are made available free of charge on our Internet website at
www.bakerhughes.com as soon as reasonably practicable after these reports have been electronically filed with, or
furnished to, the Securities and Exchange Commission (the "SEC"). Information contained on or connected to our
website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of
this annual report or any other filing we make with the SEC.
We have a Business Code of Conduct to provide guidance to our directors, officers and employees on matters
of business conduct and ethics, including compliance standards and procedures. We have also required our
principal executive officer, principal financial officer and principal accounting officer to sign a Code of Ethical
Conduct Certification.
Our Business Code of Conduct and Code of Ethical Conduct Certifications are available on the Investor
Relations section of our website at www.bakerhughes.com. We will disclose on a current report on Form 8-K or on
our website information about any amendment or waiver of these codes for our executive officers and directors.
Waiver information disclosed on our website will remain on the website for at least 12 months after the initial
disclosure of a waiver. Our Corporate Governance Guidelines and the charters of our Audit/Ethics Committee,
Compensation Committee, Executive Committee, Finance Committee and Governance and HS&E Committee are
also available on the Investor Relations section of our website at www.bakerhughes.com. In addition, a copy of our
Business Code of Conduct, Code of Ethical Conduct Certifications, Corporate Governance Guidelines and the
charters of the committees referenced above are available in print at no cost to any stockholder who requests them
by writing or telephoning us at the following address or telephone number:
Baker Hughes Incorporated
17021 Aldine Westfield Road
Houston, TX 77073
Attention: Investor Relations
Telephone: (713) 439-8600
ABOUT BAKER HUGHES
Baker Hughes is a leading supplier of oilfield services, products, technology and systems used in the worldwide
oil and natural gas industry. We also provide products and services for other businesses including downstream
chemicals, and process and pipeline services. Baker Hughes was formed as a corporation in April 1987 in
connection with the combination of Baker International Corporation and Hughes Tool Company. We conduct our
operations through subsidiaries, affiliates, ventures and alliances. We conduct business in more than 80 countries
around the world and our corporate headquarters is in Houston, Texas. As of December 31, 2016, we had
approximately 33,000 employees, of which approximately 64% work outside the United States (the "U.S.").
Our global oilfield operations are organized into a number of geomarket organizations, which are combined into
four regions for assessing performance and allocating resources. The President of Global Operations manages our
oilfield organization and reports to our chief executive officer. These regions form the basis of our four geographical
operating segments as follows: North America; Latin America; Europe/Africa/Russia Caspian; and Middle East/Asia
Pacific.
2
Through the geographic organization, our management is located close to our customers, facilitating strong
customer relationships and allowing us to react quickly to local market conditions and customer needs. The
geographic organization supports our oilfield operations and is responsible for sales, field operations and well site
execution. In addition to the above, we have an Industrial Services segment, which includes the downstream
chemicals business and the process and pipeline services business.
Certain support operations are organized at the enterprise level and include the supply chain and product line
technology organizations. The supply chain organization is responsible for the cost-effective procurement and
manufacturing of our products as well as product quality and reliability. The product line technology organization is
responsible for innovating, developing, commercializing, and marketing reliable products designed to advance the
performance of reservoirs for our customers. The product line technology organization also facilitates the
development of cross-product line solutions, sales processes and integrated operations capabilities.
Further information about our segments is set forth in Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations and Note 6. "Segment Information" of the Notes to Consolidated
Financial Statements in Item 8 herein.
HALLIBURTON TERMINATED MERGER AGREEMENT
On November 16, 2014, Baker Hughes and Halliburton Company ("Halliburton") entered into a definitive
agreement and plan of merger (the "Merger Agreement") under which Halliburton would acquire all outstanding
shares of Baker Hughes in a stock and cash transaction (the "Merger"). In accordance with the provisions of
Section 9.1 of the Merger Agreement, Baker Hughes and Halliburton agreed to terminate the Merger Agreement on
April 30, 2016, as a result of the failure of the Merger to occur on or before April 30, 2016 due to the inability to
obtain certain specified antitrust related approvals. Halliburton paid $3.5 billion to Baker Hughes on May 4, 2016,
representing the antitrust termination fee required to be paid pursuant to the Merger Agreement. For further
information about the Merger, see Note 2. "Halliburton Terminated Merger Agreement" of the Notes to Consolidated
Financial Statements in Item 8 herein.
GENERAL ELECTRIC TRANSACTION AGREEMENT
On October 30, 2016, Baker Hughes, General Electric Company ("GE"), Bear Newco, Inc. ("Newco"), a direct
wholly owned subsidiary of Baker Hughes, and Bear MergerSub, Inc. ("Merger Sub"), a direct wholly owned
subsidiary of Newco, entered into a Transaction Agreement and Plan of Merger (the "Transaction Agreement").
Pursuant to the terms of the Transaction Agreement, Merger Sub will merge with and into Baker Hughes, with Baker
Hughes as the surviving corporation (the "Surviving Entity") and a direct wholly owned subsidiary of Newco. As a
result of the merger, each outstanding share of the Baker Hughes' common stock will be converted into the right to
receive one share of Class A common stock of Newco ("Newco Class A Common Stock"). Immediately following
the merger, Newco will cause the Surviving Entity to be converted into a Delaware limited liability company ("Newco
LLC") and Newco will become the sole managing member of Newco LLC. Following this conversion, GE will
receive an approximate 62.5% membership interest in Newco LLC in exchange for contributing $7.4 billion (less the
Class B Purchase Price, as defined below) in cash and GE's oil and gas business ("GE O&G") to Newco LLC, and
will also receive Class B common stock of Newco (the "Newco Class B Common Stock"), representing
approximately 62.5% of the voting power of the outstanding shares of common stock of Newco, in exchange for
contributing the par value thereof (the "Class B Purchase Price") to Newco. Newco will distribute as a special
dividend an amount equal to $17.50 per share to the holders of record of the Newco Class A Common Stock, which
are the former Baker Hughes stockholders. Newco will operate as a public company.
Immediately following the closing (the "Closing") of the transactions contemplated by the Transaction
Agreement (collectively the "GE Transaction"), GE will hold 100% of the Newco Class B Common Stock, which will
represent approximately 62.5% of the voting power of the outstanding shares of common stock of Newco, and
Baker Hughes' stockholders immediately prior to the Closing will hold 100% of the Newco Class A Common Stock,
which will represent approximately 37.5% of the voting power of the outstanding shares of common stock of Newco.
In addition, GE will hold an approximate 62.5% membership interest in Newco LLC and Newco will hold an
approximate 37.5% membership interest in Newco LLC. The membership interests in Newco LLC, together with the
Newco Class B Common Stock, will be exchangeable on a 1:1 basis for Newco Class A Common Stock, subject to
certain adjustments. The rights (including voting rights) of Newco Class A Common Stock and Newco Class B
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Common Stock are identical; provided that Newco Class B Common Stock has no economic rights. Effective from
and following the Closing, Newco and its subsidiaries will operate under the name "Baker Hughes, a GE Company."
The GE Transaction is subject to the approval of Baker Hughes' stockholders, regulatory approvals and
customary closing conditions. Baker Hughes and GE expect the GE Transaction to close in mid-2017. However,
Baker Hughes cannot predict with certainty when, or if, the GE Transaction will be completed because completion of
the GE Transaction is subject to conditions beyond the control of Baker Hughes. For further information about the
GE Transaction, see Note 3. "General Electric Transaction Agreement" of the Notes to Consolidated Financial
Statements in Item 8 herein.
PRODUCTS AND SERVICES
Oilfield Operations
We offer a full suite of products and services to our customers around the world. Our oilfield products and
services fall into one of two categories, Drilling and Evaluation or Completion and Production. This classification is
based on the two major phases of constructing an oil and/or natural gas well, the drilling phase and the completion
phase, and how our products and services are utilized for each phase.
Drilling and Evaluation products and services consist of the following:
• Drill Bits - Includes Tricone™ roller cone drill bits, polycrystalline diamond composite (PDC or
"diamond" drill bits, Kymera™ hybrid drill bits and related cutter technology used for performance drilling,
hole enlargement and coring.
• Drilling Services - Includes directional drilling systems and services (rotary steerables, drilling motors,
measurement-while-drilling (MWD) systems, etc.), logging-while-drilling (LWD) systems and services
(resistivity, imaging, pressure testing and sampling, etc.), surface logging and coring systems and
services, and geoscience services.
• Wireline Services - Includes both open hole (imaging, fluids sampling, etc.) and cased hole
(production logging, wellbore integrity, pipe recovery, etc.) well logging services.
• Drilling and Completion Fluids - Includes emulsion (oil-based) and water-based drilling fluids
systems; reservoir drill-in fluids; completion fluids, and fluids environmental services.
Completion and Production products and services consist of the following:
• Completion Systems - Includes products and services used to control the flow of hydrocarbons within
•
a wellbore including upper completions (packers, liner hangers, safety systems, etc.), lower
completions (sand screens, tubing conveyed perforating, etc.) and unconventional multistage
completion systems (frac plugs, frac balls, etc.).
Intelligent Production Systems - Includes products, services, and software used to monitor, analyze,
and dynamically control production to optimize returns and ultimate recovery (production decisions
services, chemical injection service, well monitoring services, intelligent well systems, and artificial lift
monitoring).
• Wellbore Intervention - Includes products and services used to intervene in existing wellbores to
improve production and solve problems within the well (fishing services, wellbore cleanup, casing exit
systems, workover systems, smart interventional technologies, and through-tubing intervention tools).
• Artificial Lift - Includes products and services used to maintain production, improve recovery rates,
and lower operating costs in wells in which a reservoir can no longer flow naturally (in-well electric
submersible pumping systems; progressing cavity pump systems; gas lift systems); and horizontal
surface pumping systems that move fluids on the surface for applications such as injection, disposal,
transfer, and pipeline boosting.
• Upstream Chemicals - Includes chemical technologies and services that solve production challenges
related to flow assurance, production optimization, asset integrity, and water management.
• Pressure Pumping - Includes onshore and offshore cementing, stimulation services (hydraulic
fracturing, acidizing, stimulation vessels, etc.) and coiled tubing services used in the completion of new
oil and natural gas wells and in remedial work on existing wells. Hydraulic fracturing is the practice of
pumping fluid through a wellbore at pressures and rates sufficient to crack rock in the target formation,
extend the cracks, and leave behind a propping agent to keep the cracks open after pumping ceases.
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The purpose of the cracks is to provide a pathway that allows for the passage of hydrocarbons from the
rock to the wellbore, thus improving the production of hydrocarbons to the surface. On December 30,
2016, we contributed our North American onshore pressure pumping business to a newly formed
venture ("BJ Services, LLC"), of which we retained a 46.7% interest and accounted for as an equity
method investment.
We also provide dedicated project solutions to our customers through our Integrated Operations group.
Integrated Operations is focused on the execution of projects that have one or more of the following attributes:
project management, well site supervision, well construction, intervention, third-party contractor management,
procurement and rig management. Contracts for this business unit tend to be longer in duration, often spanning
multiple years, and may include significant third-party components to supplement the core products and services
provided by us. By partnering with Integrated Operations, our customers have access to a comprehensive business
solution that leverages our technical expertise, relationships with third-party and rig providers, and our industry
leading technologies.
Additional information regarding our oilfield products and services can be found on the Company's website at
www.bakerhughes.com. Our website also includes details of our hydraulic fracturing operations, including our
hydraulic fracturing chemical disclosure policy and support of the online national hydraulic fracturing chemical
registry at www.fracfocus.org, and information on our SmartCare™ qualified systems and products, which are
intended to maximize performance while minimizing our impact on the community and environment.
Industrial Services
Industrial Services consists primarily of our downstream chemicals, and process and pipeline services
businesses and provides chemical technologies, equipment, and services that optimize operations throughout the
industrial lifecycle (midstream and transportation, processing and refining, water treatment, petrochemical
processing). Specifically, downstream chemicals provides products and services that help to increase refinery
production, as well as improve plant safety and equipment. Process and pipeline services work to improve
efficiency and reduce downtime with inspection, pre-commissioning and commissioning of new and existing pipeline
systems and process plants.
MARKETING, COMPETITION AND CONTRACTING
We market our products and services within our four geographic regions on a product line basis primarily
through our own sales organizations. We provide technical and advisory services to assist in our customers' use of
our products and services. Stock points and service centers for our products and services are located in areas of
drilling and production activity throughout the world.
Our primary competitors include the major diversified oilfield service companies such as Schlumberger,
Halliburton and Weatherford International, where the breadth of service capabilities as well as competitive position
of each product line are the keys to differentiation in the market. We also compete with other companies who may
participate in only a few of the same product lines as us, such as National Oilwell Varco, Ecolab, Newpark
Resources and FTS International. Our products and services are sold in highly competitive markets and revenue
and earnings are affected by changes in commodity prices, fluctuations in the level of drilling, workover and
completion activity in major markets, general economic conditions, foreign currency exchange fluctuations and
governmental regulations. We believe that the principal competitive factors in our industries are product and service
quality, reliability and availability, health, safety and environmental standards, technical proficiency and price.
Our customers include the large integrated major and super-major oil and natural gas companies, U.S. and
international independent oil and natural gas companies and the national or state-owned oil companies. No single
customer accounts for more than 10% of our business. While we may have contracts with customers that include
multiple well projects and that may extend over a period of time ranging from two to four years, our services and
products are generally provided on a well-by-well basis. Most contracts cover our pricing of the products and
services, but do not necessarily establish an obligation to use our products and services.
We strive to negotiate the terms of our customer contracts consistent with what we consider to be best
practices. The general industry practice is for oilfield service providers, like us, to be responsible for their own
products and services and for our customers to retain liability for drilling and related operations. Consistent with this
5
practice, we generally take responsibility for our own people and property while our customers, such as the operator
of a well, take responsibility for their own people, property and all liabilities related to the well and subsurface
operations, regardless of either party's negligence. In general, any material limitations on indemnifications to us
from our customers in support of this allocation of responsibility arise only by applicable statutes.
Certain states such as Texas, Louisiana, Wyoming, and New Mexico have enacted oil and natural gas specific
statutes that void any indemnity agreement that attempts to relieve a party from liability resulting from its own
negligence ("anti-indemnity statutes"). These statutes can void the allocation of liability agreed to in a contract;
however, both the Texas and Louisiana anti-indemnity statutes include important exclusions. The Louisiana statute
does not apply to property damage, and the Texas statute allows mutual indemnity agreements that are supported
by insurance and has exclusions, which include, among other things, loss or liability for property damage that
results from pollution and the cost of well control events. We negotiate with our customers in the U.S. to include a
choice of law provision adopting the law of a state that does not have an anti-indemnity statute because both Baker
Hughes and our customers generally prefer to contract on the basis as we mutually agree. When this does not
occur, we will generally use Texas law. With the exclusions contained in the Texas anti-indemnity statute, we are
usually able to structure the contract such that the limitation on the indemnification obligations of the customer is
limited and should not have a material impact on the terms of the contract. State law, laws or public policy in
countries outside the U.S., or the negotiated terms of our agreement with the customer may also limit the
customer's indemnity obligations in the event of the gross negligence or willful misconduct of a Company employee.
The Company and the customer may also agree to other limitations on the customer's indemnity obligations in the
contract.
The Company maintains a commercial general liability insurance policy program that covers against certain
operating hazards, including product liability claims and personal injury claims, as well as certain limited
environmental pollution claims for damage to a third party or its property arising out of contact with pollution for
which the Company is liable; however, clean up and well control costs are not covered by such program. All of the
insurance policies purchased by the Company are subject to deductible and/or self-insured retention amounts for
which we are responsible for payment, specific terms, conditions, limitations and exclusions. There can be no
assurance that the nature and amount of Company insurance will be sufficient to fully indemnify us against liabilities
related to our business.
RESEARCH AND DEVELOPMENT AND PATENTS
Our products and technology organization engages in research and development activities directed primarily
toward the development of new products, processes and services, the improvement of existing products and
services and the design of specialized products to meet specific customer needs. We have technology centers
located in the U.S. (several in Houston, Texas and surrounding areas and one in Claremore, Oklahoma), Germany
(Celle), Russia (Novosibirsk), and Saudi Arabia (Dhahran). For information regarding the total amount of research
and development expense in each of the three years in the period ended December 31, 2016, see Note 1.
"Summary of Significant Accounting Policies" of the Notes to Consolidated Financial Statements in Item 8 herein.
We have followed a policy of seeking patent and trademark protection in numerous countries and regions
throughout the world for products and methods that appear to have commercial significance. We believe our
patents, trademarks, and related intellectual property rights are adequate for the conduct of our business, and
aggressively pursue protection of our intellectual property rights against infringement worldwide. Additionally, we
consider the quality and timely delivery of our products, the service we provide to our customers and the technical
knowledge and skills of our personnel to be other important components of the portfolio of capabilities and assets
supporting our ability to compete. No single patent or trademark is considered to be critical to our business.
SEASONALITY
Our operations can be affected by seasonal weather, which can temporarily affect the delivery and performance
of our products and services, and our customers' budgetary cycles. Examples of seasonal events that can impact
our business are set forth below:
• The severity and duration of both the summer and the winter in North America can have a significant impact
on activity levels. In Canada, the timing and duration of the spring thaw directly affects activity levels, which
6
reach seasonal lows during the second quarter and build through the third and fourth quarters to a seasonal
high in the first quarter.
• Adverse weather conditions such as hurricanes and typhoons can disrupt coastal and offshore drilling and
production operations.
• Severe weather during the winter months normally results in reduced activity levels in the North Sea and
Russia generally in the first quarter.
• Scheduled repair and maintenance of offshore facilities in the North Sea can reduce activity in the second
and third quarters.
• Many of our international oilfield customers increase orders for certain products and services in the fourth
quarter.
• Our Industrial Services segment typically experiences lower sales during the first and fourth quarters of the
year due to the Northern Hemisphere winter.
RAW MATERIALS
We purchase various raw materials and component parts for use in manufacturing our products and delivering
our services. The principal materials we purchase include, but are not limited to, steel alloys (including chromium
and nickel), titanium, barite, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, gels, sand
and other proppants, printed circuit boards and other electronic components and hydrocarbon-based chemical feed
stocks. These materials are generally available from multiple sources and may be subject to price volatility. While
we generally do not experience significant or long-term shortages of these materials, we have from time to time
experienced temporary shortages of particular raw materials. We do not expect significant interruptions in the
supply of raw materials, but there can be no assurance that there will be no price or supply issues over the long-
term.
EMPLOYEES
As of December 31, 2016, we had approximately 33,000 employees, of which the majority are outside the U.S.
Approximately 10% of these employees are represented under collective bargaining agreements or similar-type
labor arrangements.
EXECUTIVE OFFICERS OF BAKER HUGHES INCORPORATED
The following table shows, as of February 7, 2017, the name of each of our executive officers, together with his
or her age and all offices presently or previously held. There are no family relationships among our executive
officers.
Name
Martin S. Craighead
Age
57
Kimberly A. Ross
51
Belgacem Chariag
54
Background
Chairman of the Board of Directors of the Company since April 2013 and Director
since 2011. Chief Executive Officer of the Company since January 2012 and
President since 2010. Chief Operating Officer from 2009 to 2012. Group President
of Drilling and Evaluation from 2007 to 2009. President of INTEQ from 2005 to 2007
and President of Baker Atlas from February 2005 to August 2005. Employed by the
Company in 1986.
Senior Vice President and Chief Financial Officer of the Company since October
2014. Executive Vice President and Chief Financial Officer of Avon Products
Incorporated from 2011 to 2014. Executive Vice President and Chief Financial
Officer of Royal Ahold N.V. from 2007 to 2011 and various other finance positions
with Royal Ahold from 2001 to 2007. Ms. Ross serves on the board of directors and
the audit committee of Chubb Limited. Employed by the Company in October 2014.
President, Global Operations since May 2016. Chief Integration Officer from
December 2014 to May 2016. President, Global Products and Services of the
Company from October 2013 to December 2014. President, Eastern Hemisphere
Operations from 2009 to 2013. Vice President/Director HSE of Schlumberger
Limited from May 2008 to May 2009. Various other executive positions at
Schlumberger from 1989 to 2008. Employed by the Company in 2009.
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Archana Deskus
51
Jack Hinton
63
Kelly C. Janzen
44
Murali
Kuppuswamy
55
William D. Marsh
54
Jay G. Martin
Derek Mathieson
65
46
Arthur L. Soucy
54
Vice President and Chief Information Officer of the Company since 2013. Vice
President and Chief Information Officer for Ingersoll-Rand from 2011 to 2012.
Senior Vice President and Chief Information Officer for Timex Group from 2006 to
2011. Various positions at United Technologies from 1987 to 2006, including Vice
President and Chief Information Officer for Carrier North America. Employed by the
Company in 2013.
Vice President, Health, Safety and Environment since 2015. Vice President,
Enterprise Solutions at the Company from 2011 to 2014 and Director Health, Safety
and Environment at the Company from 2005 to 2010. Dean and professor at the
Kazakhstan Institute of Management, Economics and Strategic Research from 2004
to 2005. He previously spent 26 years at Texaco in various Health, Safety and
Environment leadership roles. Employed by the Company in 2005.
Vice President, Controller and Chief Accounting Officer since September 2016. Vice
President, Finance and Chief Accounting Officer for McDermott International from
December 2014 to August 2016. Distributed Power Global Controller at General
Electric Company ("GE") from April 2013 to November 2014 and Operational
Controller, Global Growth and Operations at GE from August 2011 to April 2013.
Various corporate roles at GE from 2007 to 2011. Employed by the Company in
2016.
Chief Human Resources Officer since May 2016. Vice President, Human Resources
for Europe, Africa and Russia Caspian from December 2013 through May 2016.
Vice President, Human Resources for Global Products and Technology from
September 2011 through December 2013. Various human resources leadership
roles at GE from 1993 to 2011. Employed by the Company in 2011.
Vice President and General Counsel of the Company since February 2013. Vice
President-Legal for Western Hemisphere from May 2009 to February 2013. Various
executive, legal and corporate roles within the Company from 1998 to 2009. Partner
at Ballard Spahr LLP from 1997 to 1998. Mr. Marsh serves on the Board of
Directors of People's Utah Bancorp (bank holding company). Employed by the
Company in 1998.
Vice President, Chief Compliance Officer and Senior Deputy General Counsel of the
Company since 2004. Shareholder at Winstead Sechrest & Minick P.C. from 2001
to 2004. Employed by the Company in 2004.
Chief Commercial Officer since May 2016. Chief Technology and Marketing Officer
of the Company from September 2015 to May 2016 and Chief Strategy Officer from
October 2013 to September 2015. President Western Hemisphere Operations from
2012 to 2013. President, Products and Technology from May 2009 to January 2012.
Chief Technology and Marketing Officer of the Company from December 2008 to
May 2009. Employed by the Company in 2008.
President, Products and Technology from May 2016. President, Europe, Africa and
Russia Caspian Region of the Company from 2013 to May 2016. President, Global
Products and Services from 2012 to 2013. Vice President Supply Chain of the
Company from April 2009 to January 2012. Vice President, Global Supply Chain for
Pratt and Whitney from 2007 to 2009. Employed by the Company in 2009.
ENVIRONMENTAL MATTERS
We are committed to the health and safety of people, protection of the environment and compliance with laws,
regulations and our policies. Our past and present operations include activities that are subject to extensive
domestic (including U.S. federal, state and local) and international regulations with regard to air, land and water
quality and other environmental matters. We believe we are in substantial compliance with these regulations.
Regulation in this area continues to evolve, and changes in standards of enforcement of existing regulations, as
well as the enactment and enforcement of new legislation, may require us and our customers to modify, supplement
or replace equipment or facilities or to change or discontinue present methods of operation. Our environmental
compliance expenditures and our capital costs for environmental control equipment may change accordingly.
We are involved in voluntary remediation projects at certain of our facilities. On rare occasions, remediation
activities are conducted as specified by a government agency-issued consent decree or agreed order. Estimated
remediation costs are accrued using currently available facts, existing environmental permits, technology and
presently enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost
estimates are developed based on internal evaluations and are not discounted. We record accruals when it is
probable that we will be obligated to pay amounts for environmental site evaluation, remediation or related activities,
8
and such amounts can be reasonably estimated. Accruals are recorded even if significant uncertainties exist over
the ultimate cost of the remediation. Ongoing environmental compliance costs, such as obtaining environmental
permits, installation of pollution control equipment and waste disposal, are expensed as incurred.
The Comprehensive Environmental Response, Compensation and Liability Act (known as "Superfund") imposes
liability for the release of a "hazardous substance" into the environment. Superfund liability is imposed without
regard to fault, even if the waste disposal was in compliance with laws and regulations. The U.S. Environmental
Protection Agency (the "EPA") and appropriate state agencies supervise investigative and cleanup activities at
Superfund sites. We have been identified as a potentially responsible party ("PRP") in remedial activities related to
various Superfund sites, and we accrue our share of the estimated remediation costs of the site based on the ratio
of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site. PRPs
in Superfund actions have joint and several liability for all costs of remediation. Accordingly, a PRP may be required
to pay more than its proportional share of such costs. For some projects, it is not possible to quantify our ultimate
exposure because the projects are either in the investigative or early remediation stage, or allocation information is
not yet available. However, based upon current information, we do not believe that probable or reasonably possible
expenditures in connection with the sites are likely to have a material adverse effect on our consolidated financial
statements because we have recorded adequate reserves to cover the estimate we presently believe will be our
ultimate liability in the matter. Further, other PRPs involved in the sites have substantial assets and may reasonably
be expected to pay their share of the cost of remediation, and, in some circumstances, we have insurance coverage
or contractual indemnities from third parties to cover a portion of the ultimate liability.
Based upon current information, we believe that our overall compliance with environmental regulations,
including routine environmental compliance costs and capital expenditures for environmental control equipment, will
not have a material adverse effect on our capital expenditures, earnings or competitive position because we have
either established adequate reserves or our cost for that compliance is not expected to be material to our
consolidated financial statements. Our total accrual for environmental remediation was $31 million and $35 million
at December 31, 2016 and 2015, respectively, which included accruals of $2 million in each year for the various
Superfund sites.
We are subject to various other governmental proceedings and regulations, including foreign regulations,
relating to environmental matters, but we do not believe that any of these matters are likely to have a material
adverse effect on our consolidated financial statements. We continue to focus on reducing future environmental
liabilities by maintaining appropriate Company standards and by improving our assurance programs.
ITEM 1A. RISK FACTORS
An investment in our common stock involves various risks. When considering an investment in Baker Hughes,
one should carefully consider all of the risk factors described below, as well as other information included and
incorporated by reference in this annual report. There may be additional risks, uncertainties and matters not listed
below, that we are unaware of, or that we currently consider immaterial. Any of these may adversely affect our
business, financial condition, results of operations and cash flows and, thus, the value of an investment in Baker
Hughes.
Risk Factors Related to the Worldwide Oil and Natural Gas Industry
Our business is focused on providing products and services to the worldwide oil and natural gas industry;
therefore, our risk factors include those factors that impact, either positively or negatively, the markets for oil and
natural gas. Expenditures by our customers for exploration, development and production of oil and natural gas are
based on their expectations of future hydrocarbon demand, their expectations for future energy prices, the risks
associated with developing the reserves, their ability to finance exploration for and development of reserves, and
the future value of the reserves. Their evaluation of the future value is based, in part, on their expectations for
global demand, global supply, spare productive capacity, inventory levels and other factors that influence oil and
natural gas prices. The key risk factors we believe are currently influencing the worldwide oil and natural gas
markets are discussed below.
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Demand for oil and natural gas is subject to factors beyond our control, which may adversely affect our operating
results. Changes in the global economy could impact our customers' spending levels and our revenue and
operating results.
Demand for oil and natural gas, as well as the demand for our services, is highly correlated with global
economic growth, and in particular by the economic growth of countries such as the U.S., India, China, and
developing countries in Asia and the Middle East who are either significant users of oil and natural gas or whose
economies are experiencing the most rapid economic growth compared to the global average. Weakness or
deterioration of the global economy or credit markets could reduce our customers' spending levels and reduce our
revenue and operating results. Events such as Britain's vote in late June 2016 to leave the European Union and
incremental weakness in global economic activity, particularly in China, India, Europe, the Middle East and
developing countries in Asia, could reduce demand for oil and natural gas and result in lower oil and natural gas
prices. Incremental strength in global economic activity in such areas will create more demand for oil and natural
gas and support higher oil and natural gas prices. In addition, demand for oil and natural gas could be impacted by
environmental regulation, including cap and trade legislation, regulation of hydraulic fracturing, carbon taxes and the
cost for carbon capture and sequestration related regulations.
Supply of oil and natural gas is subject to factors beyond our control, which may adversely affect our operating
results.
Productive capacity for oil and natural gas is dependent on our customers' decisions to develop and produce oil
and natural gas reserves and on the regulatory environment in which our customers and we operate. The ability to
produce oil and natural gas can be affected by the number and productivity of new wells drilled and completed, as
well as the rate of production and resulting depletion of existing wells. Advanced technologies, such as horizontal
drilling and hydraulic fracturing, improve total recovery but also result in a more rapid production decline and may
become subject to more stringent regulation in the future.
Productive capacity in excess of demand ("spare productive capacity") is also an important factor influencing
energy prices and spending by oil and natural gas exploration companies. Spare productive capacity and oil and
natural gas storage inventory levels are an indicator of the relative balance between supply and demand. High or
increasing storage, inventories, or spare productive capacity generally indicate that supply is exceeding demand
and that energy prices are likely to soften. Low or decreasing storage, inventories, or spare productive capacity are
generally an indicator that demand is growing faster than supply and that energy prices are likely to rise.
Access to prospects is also important to our customers and such access may be limited because host
governments do not allow access to the reserves. Government regulations and the costs incurred by oil and natural
gas exploration companies to conform to and comply with government regulations may also limit the quantity of oil
and natural gas that may be economically produced.
Supply can also be impacted by the degree to which individual Organization of Petroleum Exporting Countries
("OPEC") nations and other large oil and natural gas producing countries, including, but not limited to, Norway and
Russia, are willing and able to control production and exports of oil, to decrease or increase supply and to support
their targeted oil price while meeting their market share objectives. Any of these factors could affect the supply of oil
and natural gas and could have a material effect on our results of operations.
Volatility of oil and natural gas prices can adversely affect demand for our products and services.
Volatility in oil and natural gas prices can also impact our customers' activity levels and spending for our
products and services. Current energy prices are important contributors to cash flow for our customers and their
ability to fund exploration and development activities. Since 2014, oil prices have declined significantly due in large
part to increasing supplies, weakening demand growth and OPEC's position to not cut production until the fourth
quarter of 2016. Expectations about future prices and price volatility are important for determining future spending
levels.
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Lower oil and natural gas prices generally lead to decreased spending by our customers. While higher oil and
natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an
impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers
also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual
projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and
could have a material effect on our results of operations.
Our customers' activity levels and spending for our products and services and ability to pay amounts owed us could
be impacted by the reduction of their cash flow and the ability of our customers to access equity or credit markets.
Our customers' access to capital is dependent on their ability to access the funds necessary to develop projects
based upon their expectations of future energy prices, required investments and resulting returns. Limited access
to external sources of funding has and may continue to cause customers to reduce their capital spending plans to
levels supported by internally-generated cash flow. In addition, a reduction of cash flow resulting from declines in
commodity prices, a reduction in borrowing bases under reserve-based credit facilities or the lack of available debt
or equity financing may impact the ability of our customers to pay amounts owed to us and could cause us to
increase our reserve for doubtful accounts.
Seasonal and weather conditions could adversely affect demand for our services and operations.
Variation from normal weather patterns, such as cooler or warmer summers and winters, can have a significant
impact on demand. Adverse weather conditions, such as hurricanes in the Gulf of Mexico, may interrupt or curtail
our operations, or our customers' operations, cause supply disruptions and result in a loss of revenue and damage
to our equipment and facilities, which may or may not be insured. Extreme winter conditions in Canada, Russia or
the North Sea may interrupt or curtail our operations, or our customers' operations, in those areas and result in a
loss of revenue.
Risk Factors Related to Our Business
Our expectations regarding our business are affected by the following risk factors and the timing of any of these
risk factors:
We operate in a highly competitive environment, which may adversely affect our ability to succeed.
We operate in a highly competitive environment for marketing oilfield services and securing equipment and
trained personnel. Our ability to continually provide competitive products and services can impact our ability to
defend, maintain or increase prices for our products and services, maintain market share, and negotiate acceptable
contract terms with our customers. In order to be competitive, we must provide new technologies, reliable products
and services that perform as expected and that create value for our customers, and successfully recruit, train and
retain competent personnel. Our investments in new technologies and property, plant and equipment may not
provide competitive returns. Our ability to defend, maintain or increase prices for our products and services is in
part dependent on the industry's capacity relative to customer demand, and on our ability to differentiate the value
delivered by our products and services from our competitors' products and services.
Managing development of competitive technology and new product introductions on a forecasted schedule and
at forecasted costs can impact our financial results. Development of competing technology that accelerates the
obsolescence of any of our products or services can have a detrimental impact on our financial results.
We may be disadvantaged competitively and financially by a significant movement of exploration and
production operations to areas of the world in which we are not currently active.
The high cost or unavailability of infrastructure, materials, equipment, supplies and personnel, particularly in periods
of rapid growth, could adversely affect our ability to execute our operations on a timely basis.
Our manufacturing operations are dependent on having sufficient raw materials, component parts and
manufacturing capacity available to meet our manufacturing plans at a reasonable cost while minimizing
inventories. Our ability to effectively manage our manufacturing operations and meet these goals can have an
11
impact on our business, including our ability to meet our manufacturing plans and revenue goals, control costs, and
avoid shortages or over supply of raw materials and component parts. Raw materials and components of particular
concern include steel alloys (including chromium and nickel), titanium, barite, beryllium, copper, lead, tungsten
carbide, synthetic and natural diamonds, gels, sand and other proppants, printed circuit boards and other electronic
components and hydrocarbon-based chemical feed stocks. Our ability to repair or replace equipment damaged or
lost in the well can also impact our ability to service our customers. A lack of manufacturing capacity could result in
increased backlog, which may limit our ability to respond to orders with short lead times.
People are a key resource to developing, manufacturing and delivering our products and services to our
customers around the world. Our ability to manage the recruiting, training, retention and efficient usage of the
highly skilled workforce required by our plans and to manage the associated costs could impact our business. A
well-trained, motivated workforce has a positive impact on our ability to attract and retain business. Periods of rapid
growth present a challenge to us and our industry to recruit, train and retain our employees, while managing the
impact of wage inflation and potential lack of available qualified labor in the markets where we operate.
Likewise, if the downturn in the economy or our markets continues, we may have to adjust our workforce to
control costs and may lose our skilled and diverse workforce. Labor-related actions, including strikes, slowdowns
and facility occupations can also have a negative impact on our business.
Our business could be impacted by geopolitical and terrorism threats.
Geopolitical and terrorism risks continue to grow in a number of key countries where we do business.
Geopolitical and terrorism risks could lead to, among other things, a loss of our investment in the country,
impairment of the safety of our employees and impairment of our ability to conduct our operations.
Our business operations may be impacted by civil unrest, government expropriations and/or epidemic outbreaks.
In addition to other geopolitical and terrorism risks, civil unrest continues to grow in a number of key countries
where we do business. Our ability to conduct business operations may be impacted by that civil unrest and our
assets in these countries may also be subject to expropriation by governments or other parties involved in civil
unrest. Epidemic outbreaks may also impact our business operations by, among other things, restricting travel to
protect the health and welfare of our employees and decisions by our customers to curtail or stop operations in
impacted areas.
Our business could be impacted by cybersecurity risks and threats.
Threats to our information technology systems associated with cybersecurity risks and cyber incidents or
attacks continue to grow and it is possible that breaches to our systems could go unnoticed for some period of time.
Risks associated with these threats include, among other things, loss of intellectual property, impairment of our
ability to conduct our operations, disruption of our customers' operations, loss or damage to our customer data
delivery systems, and increased costs to prevent, respond to or mitigate cybersecurity events.
Our failure to comply with the Foreign Corrupt Practices Act ("FCPA") and other laws could have a negative impact
on our ongoing operations.
Our ability to comply with the FCPA, the U.K. Bribery Act and various other anti-bribery and anti-corruption laws
is dependent on the success of our ongoing compliance program, including our ability to continue to manage our
agents and business partners, and supervise, train and retain competent employees. Our compliance program is
also dependent on the efforts of our employees to comply with applicable law and the Baker Hughes Business Code
of Conduct. We could be subject to sanctions and civil and criminal prosecution as well as fines and penalties in the
event of a finding of a violation of any of these laws by us or any of our employees.
Compliance with and changes in laws could be costly and could affect operating results. In addition, government
disruptions could negatively impact our ability to conduct our business.
We conduct business in the U.S. and in more than 80 countries that can be impacted by expected and
unexpected changes in the legal and business environments in which we operate. Compliance related issues could
12
also limit our ability to do business in certain countries and impact our earnings. Changes that could impact the
legal environment include new legislation, new regulations, new policies, investigations and legal proceedings and
new interpretations of existing legal rules and regulations, in particular, changes in export control laws or exchange
control laws, additional restrictions on doing business in countries subject to sanctions, and changes in laws in
countries where we operate or intend to operate. In addition, government disruptions, such as a U.S. government
shutdown, may delay or halt the granting and renewal of permits, licenses and other items required by us and our
customers to conduct our business.
Changes in tax laws or tax rates, adverse positions taken by taxing authorities and tax audits could impact
operating results.
The U.S. and global tax environment today is evolving rapidly with a number of countries in which we operate
enacting, or planning to enact, legislative changes that conform to the Organization for Economic Cooperation and
Development's ("OECD") Base Erosion and Profit Shifting ("BEPS") project or otherwise make fundamental
modifications to their tax regimes. These changes in tax laws or tax rates, the resolution of tax assessments or
audits by various tax authorities, and the ability to fully utilize our tax loss carryforwards and tax credits could impact
operating results, including additional valuation allowances for deferred tax assets. In addition, we may periodically
restructure our legal entity organization. If taxing authorities were to disagree with our tax positions in connection
with any such restructurings, our effective tax rate could be materially impacted.
Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we
conduct business. We have received tax assessments from various taxing authorities and are currently at varying
stages of appeals and/or litigation regarding these matters. These audits may result in assessment of additional
taxes that are resolved with the authorities or through the courts. We believe these assessments may occasionally
be based on erroneous and even arbitrary interpretations of local tax law. Resolution of any tax matter involves
uncertainties and there are no assurances that the outcomes will be favorable.
Changes in and compliance with restrictions or regulations on offshore drilling may adversely affect our business
and operating results and reduce the need for our services in those areas.
Legislation and regulation in the U.S. and other parts of the world of the offshore oil and natural gas industry
may result in substantial increases in costs or delays in drilling or other operations in the Gulf of Mexico and other
parts of the world, oil and natural gas projects becoming potentially non-economic, and a corresponding reduced
demand for our services. If the U.S. or other countries where we operate, enact stricter restrictions on offshore
drilling or further regulate offshore drilling or contracting services operations, higher operating costs could result and
adversely affect our business and operating results.
If the Company were to be involved in a future incident similar to the 2010 Deepwater Horizon accident, the
Company could suffer significant financial losses that could severely impair the Company. Protections available to
the Company through contractual terms and insurance coverage may not be sufficient to protect the Company in
the event we were involved in that type of an incident.
Compliance with, and rulings and litigation in connection with, environmental regulations and the environmental
impacts of our or our customers' operations may adversely affect our business and operating results.
Our business is impacted by material changes in environmental laws, rulings and litigation. Our expectations
regarding our compliance with environmental laws and our expenditures to comply with environmental laws,
including (without limitation) our capital expenditures for environmental control equipment, are only our forecasts
regarding these matters. These forecasts may be substantially different from actual results, which may be affected
by factors such as: changes in law that impose new restrictions on air emissions, wastewater management, waste
disposal, hydraulic fracturing, or wetland and land use practices; more stringent enforcement of existing
environmental regulations; a change in our allocation or other unexpected, adverse outcomes with respect to sites
where we have been named as a PRP, including (without limitation) Superfund sites; the discovery of other sites
where additional expenditures may be required to comply with environmental legal obligations; and the accidental
discharge of hazardous materials.
13
International, national, and state governments and agencies continue to evaluate and promulgate legislation
and regulations that are focused on restricting emissions commonly referred to as greenhouse gas ("GHG")
emissions. In the U.S., the EPA has taken steps to regulate GHG emissions as air pollutants under the Clean Air
Act. The EPA's Greenhouse Gas Reporting Rule requires monitoring and reporting of GHG emissions from, among
others, certain mobile and stationary GHG emission sources in the oil and natural gas industry, which in turn may
include data from some of our wellsite equipment and operations. The EPA has also proposed other related GHG
emission standards that are applicable to the oil and natural gas industry, including several targeting methane,
some of which have been adopted. The impact of these standards on our business, both proposed and adopted,
remains unclear given recent actions taken by Congress and the current U.S. Administration. Other developments
focused on restricting GHG emissions include the United Nations Framework Convention on Climate Change,
which includes the Paris Agreement and the Kyoto Protocol; the European Union Emission Trading System; and,
the United Kingdom's Carbon Reduction Commitment which affects more than 40 Baker Hughes facilities. Other
regulatory changes have been proposed related to climate change including emissions trading schemes, carbon
taxes and emissions reduction targets in various areas across the globe.
We are unable to predict whether proposed changes in laws or regulations will ultimately occur or what the
adopted and proposed changes will ultimately require, and accordingly, we are unable to assess the potential
financial or operational impact they may have on our business. In addition, current or future legislation, regulations
and developments may curtail production and demand for hydrocarbons such as oil and natural gas in areas of the
world where our customers operate and thus adversely affect future demand for our services, which may in turn
adversely affect future results of operations.
We may be subject to litigation if another party claims that we have infringed upon its intellectual property rights.
The tools, techniques, methodologies, programs and components we use to provide our services may infringe
upon the intellectual property rights of others. Infringement claims generally result in significant legal and other
costs and may distract management from running our core business. Royalty payments under licenses from third
parties, if available, would increase our costs. Additionally, developing non-infringing technologies would increase
our costs. If a license were not available, we might not be able to continue providing a particular service or product,
which could adversely affect our financial condition, results of operations and cash flows.
Uninsured claims and litigation against us could adversely impact our operating results.
We could be impacted by the outcome of pending litigation as well as unexpected litigation or proceedings. We
have insurance coverage against operating hazards, including product liability claims and personal injury claims
related to our products, to the extent deemed prudent by our management and to the extent insurance is available;
however, no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify
us against liabilities arising out of pending and future claims and litigation. This insurance has deductibles or self-
insured retentions and contains certain coverage exclusions. The insurance does not cover damages from breach
of contract by us or based on alleged fraud or deceptive trade practices. In addition, the following risks apply with
respect to our insurance coverage:
• we may not be able to continue to obtain insurance on commercially reasonable terms;
• we may be faced with types of liabilities that will not be covered by our insurance;
•
•
our insurance carriers may not be able to meet their obligations under the policies; or
the dollar amount of any liabilities may exceed our policy limits.
Whenever possible, we obtain agreements from customers that limit our liability. However, state law, laws or
public policy in countries outside the U.S., or the negotiated terms of the agreement with the customer may not
recognize those limitations of liability and/or limit the customer's indemnity obligations to the Company. In addition,
insurance and customer agreements do not provide complete protection against losses and risks from an event like
a well control failure that can lead to property damage, personal injury, death or the discharge of hazardous
materials into the environment. Our results of operations could be adversely affected by unexpected claims not
covered by insurance.
14
Control of oil and natural gas reserves by state-owned oil companies may impact the demand for our services and
create additional risks in our operations.
Much of the world's oil and natural gas reserves are controlled by state-owned oil companies. State-owned oil
companies may require their contractors to meet local content requirements or other local standards, such as joint
ventures, that could be difficult or undesirable for the Company to meet. The failure to meet the local content
requirements and other local standards may adversely impact the Company's operations in those countries. In
addition, our ability to work with state-owned oil companies is subject to our ability to negotiate and agree upon
acceptable contract terms.
Providing services on an integrated or turnkey basis could require the Company to assume additional risks.
Many state-owned oil companies and other operators may require integrated contracts or turnkey contracts and
the Company may choose to provide services outside its core business. Providing services on an integrated or
turnkey basis generally subjects the Company to additional risks, such as costs associated with unexpected delays
or difficulties in drilling or completion operations and risks associated with subcontracting arrangements.
Currency fluctuations or devaluations may impact our operating results.
Fluctuations or devaluations in foreign currencies relative to the U.S. Dollar can impact our revenue and our
costs of doing business. Most of our products and services are sold through contracts denominated in U.S. Dollars
or local currency indexed to U.S. Dollars; however, some of our revenue, local expenses and manufacturing costs
are incurred in local currencies and therefore changes in the exchange rates between the U.S. Dollar and foreign
currencies can increase or decrease our revenue and expenses reported in U.S. Dollars and may impact our results
of operations.
Changes in economic and/or market conditions may impact our ability to borrow and/or cost of borrowing.
The condition of the capital markets and equity markets in general can affect the price of our common stock and
our ability to obtain financing, if necessary. If the Company's credit rating is downgraded, this could increase
borrowing costs under our credit facility and commercial paper program, as well as the cost of renewing or
obtaining, or make it more difficult to renew or obtain or issue new debt financing.
Our restructuring activities may not achieve the results we expect and could increase, which could materially and
adversely affect our results of operations and financial condition.
During 2015 and 2016, we implemented a number of restructuring activities to reduce expenses, which included
a reduction in our workforce, the termination of various contracts, the closing or abandoning of certain facilities, the
downsizing of our presence in select markets and the contribution of our North American onshore pressure pumping
business to BJ Services, LLC. There can be no assurance that our restructuring activities will produce the cost
savings we anticipate in the expected timeframe or that the cumulative restructuring activities and charge will not
have to increase in order to achieve our cost savings targets. Any delay or failure to achieve the expected cost
savings and any increase in our anticipated cumulative restructuring activities and charge would likely cause our
future earnings to be lower than anticipated.
The BJ Services, LLC venture may not achieve the results we expect and could result in a loss of our investment in
the North America onshore pressure pumping business.
The Company will no longer control its North America onshore pressure pumping business and must rely on the
management of BJ Services, LLC to operate that business. Poor performance or additional government regulation
of that business could result in lower profitability than expected and could ultimately result in a loss of the
investment the Company has in the business through its ownership of the LLC. This investment, and the related
earnings, will be excluded from our North America segment.
15
Risk Factors Related to the GE Transaction
Our expectations regarding our business may be impacted by the following risk factors related to the pending
GE Transaction:
The pendency of the GE Transaction could adversely affect our business.
In connection with the GE Transaction, 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
GE Transaction is completed. We have agreed in the Transaction Agreement to refrain from taking certain actions
with respect to our business and financial affairs during the pendency of the GE Transaction, which restrictions
could be in place for an extended period of time if completion of the GE Transaction is delayed and could adversely
impact our financial condition, results of operations or cash flows. These restrictions may prevent us from pursuing
otherwise attractive business opportunities and making other changes to our business before completion of the GE
Transaction or termination of the Transaction Agreement. The process of seeking to accomplish the GE
Transaction could also divert the focus of our management from pursuing other opportunities that could be
beneficial to us.
The pursuit of the GE Transaction and the preparation for the integration of Baker Hughes and GE O&G have
placed, and will continue to place, a significant burden on our management and internal resources. There is a
significant degree of difficulty and management distraction inherent in the process of seeking to close the GE
Transaction and integrate Baker Hughes and GE O&G, which could cause an interruption of, or loss of momentum
in, the activities of our existing business, regardless of whether the GE Transaction is eventually completed. Our
management team will be required to devote considerable amounts of time to this integration process, which will
decrease the time they will have to manage our existing businesses, service existing customers, attract new
customers and develop new products, services or strategies. One potential consequence of such distractions could
be the failure of management to realize other opportunities that could be beneficial to us. If our senior management
is not able to effectively manage the process leading up to and immediately following Closing, or if any significant
business activities are interrupted as a result of the integration process, the business of Baker Hughes could suffer.
We may be unable to attract and retain key employees during the pendency of the GE Transaction.
In connection with the GE Transaction, current and prospective employees of Baker Hughes may experience
uncertainty about their future roles with Baker Hughes, a GE Company following the GE Transaction ("New Baker
Hughes"), which may materially adversely affect our ability to attract and retain key personnel during the pendency
of the GE Transaction. Key employees may depart because of issues relating to the uncertainty and difficulty of
integration or a desire not to remain with New Baker Hughes following the Transaction. The departure of existing
key employees or the failure of potential key employees to accept employment with New Baker Hughes, despite our
recruiting efforts, could have a material adverse impact on our business, financial condition and operating results,
regardless of whether the GE Transaction is eventually completed.
The GE Transaction may not be completed on the terms or timeline currently contemplated, or at all, and failure to
complete the GE Transaction may result in material adverse consequences to our business and operations.
The GE Transaction is subject to several closing conditions, including the adoption of the Transaction
Agreement by our stockholders, the expiration or termination of any applicable waiting period under the U.S. Hart-
Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act") and the receipt of regulatory
approvals in certain other jurisdictions. The closing conditions also include the delivery by GE to us of the audited
financial statements of GE O&G and the absence of differences between such audited financial statements and the
unaudited financial statements of GE O&G that were delivered by GE to us prior to the date of the Transaction
Agreement that are material to the intrinsic value of GE O&G (as determined in a manner consistent with
appropriate valuation methodologies), excluding changes in goodwill and certain other exclusions. If any one of
these conditions is not satisfied or waived, the GE Transaction may not be completed. There is no assurance that
the GE Transaction will be completed on the terms or timeline currently contemplated, or at all.
The parties have not yet obtained all regulatory clearances, consents and approvals required to complete the
GE Transaction. Governmental or regulatory agencies could still seek to block or challenge the GE Transaction or
16
could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the GE
Transaction. These restrictions could include a requirement to sell certain specified businesses that GE is obligated
under the terms of the Transaction Agreement to divest if necessary to obtain such regulatory approvals. If these
approvals are not received, then neither we nor GE will be obligated to complete the GE Transaction. If the
approvals could be received, but the applicable regulatory agency is not satisfied that a qualified buyer has been
found or imposes on a party any antitrust action that would have an effect exceeding $200 million in revenue for the
twelve months ended December 31, 2015 (other than with respect to the divestiture of certain specified businesses,
which are not subject to the preceding limitations), GE would not be required to agree to undertake such actions
and neither we nor GE would be obligated to complete the GE Transaction.
If our stockholders do not approve and adopt the Transaction Agreement or if the GE Transaction is not
completed for any other reason, we would be subject to a number of risks, including the following:
•
•
the attention of our management may have been diverted to the GE Transaction instead of on our
operations and pursuit of other opportunities that may have been beneficial to us;
resulting negative customer perception could adversely affect our ability to compete for, or to win, new and
renewal business in the marketplace;
• we and our stockholders would not realize the anticipated benefits of the GE Transaction, including a
special one-time cash dividend of $17.50 per share of Newco Class A Common Stock and any anticipated
synergies from combining our business with GE O&G;
• we may be required to pay a termination fee of $750 million if the Transaction Agreement is terminated in
the case of certain events described in the Transaction Agreement, including due to an adverse change in
our board of directors' recommendation to our stockholders to approve the GE Transaction;
•
the trading price of our common stock may experience increased volatility to the extent that the current
market prices reflect a market assumption that the GE Transaction will be completed; or
•
the Company could be subject to litigation from shareholders related to the Transaction Agreement.
The occurrence of any of these events individually or in combination could have a material adverse effect on
our results of operations or the trading price of our common stock.
Even if the GE Transaction is closed, the integration of Baker Hughes and GE O&G following the Closing will
present significant challenges that may result in a decline in the anticipated benefits of the GE Transaction.
The GE Transaction involves the combination of two businesses that currently operate as independent
businesses. New Baker Hughes will be required to devote management attention and resources to integrating its
business practices and operations, and prior to the GE Transaction, management attention and resources will be
required to plan for such integration. Potential difficulties New Baker Hughes may encounter in the integration
process include the following:
•
•
•
•
the inability to successfully integrate the two businesses, including operations, technologies, products and
services, in a manner that permits New Baker Hughes to achieve the cost savings and operating synergies
anticipated to result from the GE Transaction, which could result in the anticipated benefits of the GE
Transaction 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 businesses deciding
not to do business with New Baker Hughes, or deciding to decrease their amount of business in order to
reduce their reliance on a single company;
the necessity of coordinating geographically separated organizations, systems and facilities;
potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated
with the GE Transaction;
17
•
•
•
•
integrating personnel with diverse business backgrounds and business cultures, while maintaining focus on
providing consistent, high-quality products and services;
consolidating and rationalizing information technology platforms and administrative infrastructures as well
as accounting systems and related financial reporting activities;
preserving important relationships of both Baker Hughes and GE O&G and resolving potential conflicts that
may arise; and
performance shortfalls at one or both of Baker Hughes and GE O&G as a result of the diversion of
management's attention caused by completing the GE Transaction and integrating the two businesses'
operations.
The Transaction Agreement contains provisions that may discourage other companies from trying to acquire us.
The Transaction Agreement contains provisions that may discourage third parties from submitting business
combination proposals to us that might result in greater value to our stockholders than the GE Transaction. The
Transaction Agreement generally prohibits us from soliciting any competing acquisition proposal. In addition, if the
Transaction Agreement is terminated by us or GE in circumstances that obligates us to pay a termination fee and to
reimburse transaction expenses to GE, our financial condition may be adversely affected as a result of the payment
of the termination fee and transaction expenses, which might deter third parties from proposing alternative business
combination proposals.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We own or lease numerous properties throughout the world. We consider our manufacturing plants, equipment
assembly, maintenance and overhaul facilities, grinding plants, drilling fluids and chemical processing centers, and
primary research and technology centers to be our principal properties. The following sets forth the location of our
principal owned or leased facilities for our oilfield operations and Industrial Services segments as of December 31,
2016:
North America:
Houston, Pasadena, and The Woodlands, Texas; Broken Arrow, Claremore,
Tulsa and Sand Springs, Oklahoma; Bossier City, Broussard, and Lafayette,
Louisiana - all located in the United States; and Leduc, Canada
Europe/Africa/Russia Caspian: Aberdeen, Scotland; Liverpool, England; Celle, Germany; Tananger, Norway;
Middle East/Asia Pacific:
Industrial Services:
Port Harcourt, Nigeria; Luanda, Angola; Tyumen and Novosibirsk, Russia
Dubai, United Arab Emirates; Dhahran, Saudi Arabia; Singapore, Singapore;
Chonburi, Thailand; and Hsinchu, Taiwan
Pasadena, Texas; Sand Springs and Barnsdall, Oklahoma; Taft, California; and
Liverpool, England
We own or lease numerous other facilities such as service centers, blend plants, workshops and sales and
administrative offices throughout the geographic regions in which we operate. We also have a significant
investment in service vehicles, tools and manufacturing and other equipment. All of our owned properties are
unencumbered. We believe that our facilities are well maintained and suitable for their intended purposes.
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ITEM 3. LEGAL PROCEEDINGS
We are subject to a number of lawsuits and claims arising out of the conduct of our business. The ability to
predict the ultimate outcome of such matters involves judgments, estimates and inherent uncertainties. We record
a liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably
estimated, including accruals for self-insured losses which are calculated based on historical claim data, specific
loss development factors and other information. A range of total possible losses for all litigation matters cannot be
reasonably estimated. Based on a consideration of all relevant facts and circumstances, we do not expect the
ultimate outcome of any currently pending lawsuits or claims against us will have a material adverse effect on our
financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate
outcome of these matters.
We insure against risks arising from our business to the extent deemed prudent by our management and to the
extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be
sufficient to fully indemnify us against liabilities arising out of pending or future legal proceedings or other claims.
Most of our insurance policies contain deductibles or self-insured retentions in amounts we deem prudent and for
which we are responsible for payment. In determining the amount of self-insurance, it is our policy to self-insure
those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability,
general liability and workers compensation.
The following lawsuits were filed in Delaware in connection with our Merger with Halliburton. Subsequent to the
filing of the lawsuits, on April 30, 2016, the Merger Agreement with Halliburton was terminated as described in Note
2. "Halliburton Terminated Merger Agreement."
• On November 24, 2014, Gary Molenda, a purported shareholder of the Company, filed a class action
lawsuit in the Court of Chancery of the State of Delaware ("Delaware Chancery Court") against Baker
Hughes, the Company's Board of Directors, Halliburton, and Red Tiger LLC, a wholly owned subsidiary of
Halliburton ("Red Tiger" and together with all defendants, "Defendants") styled Gary R. Molenda v. Baker
Hughes, Inc., et al., Case No. 10390-CB.
• On November 26, 2014, a second purported shareholder of the Company, Booth Family Trust, filed a
substantially similar class action lawsuit in Delaware Chancery Court.
• On December 1, 2014, New Jersey Building Laborers Annuity Fund and James Rice, two additional
purported shareholders of the Company, filed substantially similar class action lawsuits in Delaware
Chancery Court.
• On December 10, 2014, a fifth purported shareholder of the Company, Iron Workers Mid-South Pension
Fund, filed another substantially similar class action lawsuit in the Delaware Chancery Court.
• On December 24, 2014, a sixth purported shareholder of the Company, Annette Shipp, filed another
substantially similar class action lawsuit in the Delaware Chancery Court.
All of the lawsuits make substantially similar claims. The plaintiffs generally allege that the members of the
Company's Board of Directors breached their fiduciary duties to our shareholders in connection with the Merger
negotiations by entering into the Merger Agreement and by approving the Merger, and that the Company,
Halliburton, and Red Tiger aided and abetted the purported breaches of fiduciary duties. More specifically, the
lawsuits allege that the Merger Agreement provides inadequate consideration to our shareholders, that the process
resulting in the Merger Agreement was flawed, that the Company's directors engaged in self-dealing, and that
certain provisions of the Merger Agreement improperly favor Halliburton and Red Tiger, precluding or impeding third
parties from submitting potentially superior proposals, among other things. The lawsuit filed by Annette Shipp also
alleges that our Board of Directors failed to disclose material information concerning the proposed Merger in the
preliminary registration statement on Form S-4. On January 7, 2015, James Rice amended his complaint, adding
similar allegations regarding the disclosures in the preliminary registration statement on Form S-4. The lawsuits
seek unspecified damages, injunctive relief enjoining the Merger, and rescission of the Merger Agreement, among
other relief. On January 23, 2015, the Delaware lawsuits were consolidated under the caption In re Baker Hughes
Inc. Stockholders Litigation, Consolidated C.A. No. 10390-CB (the "Consolidated Case"). Pursuant to the Court's
consolidation order, plaintiffs filed a consolidated complaint on February 4, 2015, which alleges substantially similar
claims and seeks substantially similar relief to that raised in the six individual complaints, except that while Baker
Hughes is named as a defendant, no claims are asserted against the Company.
19
On March 18, 2015, the parties reached an agreement in principle to settle the Consolidated Case in exchange
for the Company making certain additional disclosures. Those disclosures were contained in a Form 8-K filed with
the SEC on March 18, 2015. The settlement was made subject to certain conditions, including consummation of
the Merger, final documentation, and court approval. With the termination of the Merger Agreement with
Halliburton, the March 18, 2015 settlement agreement is rendered null and void. On May 31, 2016, the
Consolidated Case and the claims asserted therein were dismissed, save and except for plaintiffs counsel's Fee
and Expense Application to the Delaware Chancery Court. On October 13, 2016, the Delaware Chancery Court
ruled on plaintiffs counsel's Fee and Expense Application. The amount awarded does not have a material impact
on our financial position, results of operations or cash flows.
On October 9, 2014, one of our subsidiaries filed a Request for Arbitration against a customer before the
London Court of International Arbitration, pursuing claims for the non-payment of invoices for goods and services
provided in an amount provisionally quantified to exceed $67.9 million. In our Request for Arbitration, we also noted
that invoices in an amount exceeding $57 million had been issued to the customer, and would be added to the claim
in the event that they became overdue. On November 6, 2014, the customer filed its Response and Counterclaim,
denying liability and counterclaiming damages for breach of contract of approximately $182 million. On March 31,
2016, the parties agreed to a settlement principally involving the purchase by the customer of certain inventory held
by our subsidiary, with all other claims and counterclaims being released and discharged by each party, and the
arbitral proceedings being discontinued. On April 18, 2016, all claims and counterclaims filed in the London Court
of International Arbitration were released and discontinued. The settlement did not have a material impact on our
financial position, results of operations or cash flows.
During 2014, we received customer notifications related to a possible equipment failure in a natural gas storage
system in Northern Germany, which includes certain of our products. We are currently investigating the cause of
the possible failure and, if necessary, possible repair and replacement options for our products. Similar products
were utilized in other natural gas storage systems for this and other customers. The customer initiated arbitral
proceedings against us on June 19, 2015, under the rules of the German Institute of Arbitration e.V. (DIS). On
August 3, 2016, the customer amended its claims and now alleges damages of approximately $224 million plus
interest at an annual rate of prime + 5%. A hearing before the arbitration panel was held January 16, 2017 through
January 23, 2017, and an additional hearing is scheduled for March 20, 2017 and March 21, 2017. In addition, on
September 21, 2015, TRIUVA Kapitalverwaltungsgesellschaft mbH filed a lawsuit in the United States District Court
for the Southern District of Texas Houston Division against the Company and Baker Hughes Oilfield Operations, Inc.
alleging that the plaintiff is the owner of gas storage caverns in Etzel, Germany in which the Company provided
certain equipment in connection with the development of the gas storage caverns. The plaintiff further alleges that
the Company supplied equipment that was either defectively designed or failed to warn of risks that the equipment
posed, and that these alleged defects caused damage to the plaintiff's property. The plaintiff seeks recovery of
alleged compensatory and punitive damages of an unspecified amount, in addition to reasonable attorneys' fees,
court costs and pre-judgment and post-judgment interest. The allegations in this lawsuit are related to the claims
made in the June 19, 2015 German arbitration referenced above. At this time, we are not able to predict the
outcome of these claims or whether either will have any material impact on our financial position, results of
operations or cash flows.
On August 31, 2015, a customer of one of the Company's subsidiaries issued a Letter of Claim pursuant to a
Construction and Engineering Contract. The customer had claimed $369 million plus loss of production resulting
from a breach of contract related to five electric submersible pumps installed by the subsidiary in Europe. On
January 29, 2016, the Customer served its Statement of Claim, Case No. CL-2015-00584, in the Commercial Court
Queen's Bench Division of the High Court of Justice. On September 20, 2016, the parties entered a settlement
agreement by which all claims were released and discharged by each party. On October 6, 2016, the Commercial
Court entered a Consent Order dismissing all claims in the litigation. The settlement did not have a material impact
on our financial position, results of operations or cash flows.
On October 30, 2015, Chieftain Sand and Proppant Barron, LLC initiated arbitration against our subsidiary,
Baker Hughes Oilfield Operations, Inc., in the American Arbitration Association. The Claimant alleged that the
Company failed to purchase the required sand tonnage for the contract year 2014-2015 and further alleged that the
Company repudiated its yearly purchase obligations over the remaining contract term. The Claimant alleged
damages of approximately $110 million plus interest, attorneys' fees and costs. On June 2, 2016, the parties
agreed to a settlement of all claims and counterclaims asserted in the Arbitration. The settlement did not have a
material impact on our financial position, results of operations or cash flows.
20
On April 30, 2015, a class and collective action lawsuit alleging that we failed to pay a nationwide class of
workers overtime in compliance with the Fair Labor Standards Act and North Dakota law was filed titled Williams et
al. v. Baker Hughes Oilfield Operations, Inc. in the U.S. District Court for the District of North Dakota. On February
8, 2016, the Court conditionally certified certain subclasses of employees for collective action treatment. We are
evaluating the background facts and at this time cannot predict the outcome of this lawsuit and are not able to
reasonably estimate the potential impact, if any, such outcome would have on our financial position, results of
operations or cash flows.
On July 31, 2015, Rapid Completions LLC filed a lawsuit in federal court in the Eastern District of Texas against
Baker Hughes Incorporated, Baker Hughes Oilfield Operations, Inc., and others claiming infringement of U.S.
Patent Nos. 6,907,936; 7,134,505; 7,543,634; 7,861,774; and 8,657,009. On August 6, 2015, Rapid Completions
amended its complaint to allege infringement of U.S. Patent No. 9,074,451. On September 17, 2015, Rapid
Completions and Packers Plus Energy Services Inc., sued Baker Hughes Canada Company in the Canada Federal
Court on related Canadian patent 2,412,072. On April 1, 2016, Rapid Completions removed U.S. Patent No.
6,907,936 from its claims in the lawsuit. On April 5, 2016, Rapid Completions filed a second lawsuit in federal court
in the Eastern District of Texas against Baker Hughes Incorporated, Baker Hughes Oilfield Operations, Inc. and
others claiming infringement of U.S. Patent No. 9,303,501. These patents relate primarily to certain specific
downhole completions equipment. The plaintiff has requested a permanent injunction against further alleged
infringement, damages in an unspecified amount, supplemental and enhanced damages, and additional relief such
as attorney's fees and costs. During August and September 2016, the United States Patent and Trademark office
agreed to institute an inter-partes review of U.S. Patent Nos 7,861,774; 7,134,505; 7,534,634; 6,907,936;
8,657,009; and 9,074,451. At this time, we are not able to predict the outcome of these claims or whether they will
have a material impact on our financial position, results of operations or cash flows.
On April 6, 2016, a civil Complaint against Baker Hughes Incorporated and Halliburton Company was filed by
the United States of America seeking a permanent injunction restraining Baker Hughes and Halliburton from
carrying out the planned acquisition of Baker Hughes by Halliburton or any other transaction that would combine the
two companies. The lawsuit is styled United States of America v. Halliburton Co. and Baker Hughes Inc., in the
U.S. District Court for the District of Delaware, Case No. 1:16-cv-00233-UNA. The Complaint alleges that the
proposed transaction between Halliburton and Baker Hughes would violate Section 7 of the Clayton Act.
Subsequent to the filing of the Complaint, on April 30, 2016, the Merger Agreement with Halliburton was terminated
as described in Note 2. "Halliburton Terminated Merger Agreement." On May 4, 2016, the United States filed a
Notice of Voluntary Dismissal of the Complaint.
On May 30, 2013, we received a Civil Investigative Demand ("CID") from the U.S. Department of Justice
("DOJ") pursuant to the Antitrust Civil Process Act. The CID sought documents and information from us for the
period from May 29, 2011 through the date of the CID in connection with a DOJ investigation related to pressure
pumping services in the U.S. On May 18, 2016, we received notice from the DOJ that they have closed the
investigation with no further action requested of the Company.
ITEM 4. MINE SAFETY DISCLOSURES
Our barite mining operations, in support of our drilling fluids products and 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 is included in Exhibit
95 to this annual report.
21
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock, $1.00 par value per share, is principally traded on the New York Stock Exchange. Our
common stock is also traded on the SIX Swiss Exchange. As of January 31, 2017, there were approximately 8,847
stockholders of record.
For information regarding quarterly high and low sales prices on the New York Stock Exchange for our common
stock during the two years ended December 31, 2016, and information regarding dividends declared on our
common stock during the two years ended December 31, 2016, see Note 17. "Quarterly Data (Unaudited)" of the
Notes to Consolidated Financial Statements in Item 8 herein.
The following table contains information about our purchases of equity securities during the fourth quarter of
2016.
Issuer Purchases of Equity Securities
Period
October 1-31, 2016
November 1-30, 2016
December 1-31, 2016
Total
Total Number
of Shares
Purchased (1)
9,640
Average
Price Paid
Per Share (1)
52.35
$
—
69,214
78,854
$
—
64.71
63.20
Total Number of
Shares Purchased as
Part of a Publicly
Announced Program (2)
—
—
—
—
Maximum Dollar Value
of Shares that May Yet Be
Purchased Under the
Program (3)
$
$
$
1,237,161,230
1,237,161,230
1,237,161,230
(1) Represents shares purchased from employees to satisfy the tax withholding obligations in connection with
the vesting of restricted stock awards and restricted stock units.
(2) There were no repurchases during the fourth quarter of 2016 under our previously announced purchase
program.
(3) Under the transaction agreement with General Electric, as described in Note 3. "General Electric
Transaction Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein, we have
agreed not to repurchase any shares of our common stock other than in connection with shares
repurchased from employees to satisfy the tax withholding obligations in connection with the vesting of
equity awards.
22
Corporate Performance Graph
The following graph compares the yearly change in our cumulative total stockholder return on our common
stock (assuming reinvestment of dividends into common stock at the date of payment) with the cumulative total
return on the published Standard & Poor's ("S&P") 500 Stock Index and the cumulative total return on the S&P 500
Oil and Gas Equipment and Services Index over the preceding five-year period.
Comparison of Five-Year Cumulative Total Return *
Baker Hughes Incorporated; S&P 500 Index and S&P 500 Oil and Gas Equipment and Services Index
2011
2012
2013
2014
2015
2016
Baker Hughes
S&P 500 Index
$100.00 $ 85.18 $116.65 $119.55 $ 99.62 $142.17
197.75
176.75
153.39
100.00
115.93
174.29
S&P 500 Oil and Gas Equipment and Services Index
100.00
100.00
130.65
120.46
97.87
129.12
* Total return assumes reinvestment of dividends on a quarterly basis.
The comparison of total return on investment (change in year-end stock price plus reinvested dividends)
assumes that $100 was invested on December 31, 2011 in Baker Hughes common stock, the S&P 500 Index and
the S&P 500 Oil and Gas Equipment and Services Index.
The corporate performance graph and related information shall not be deemed "soliciting material" or to be
"filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the
Securities Act or the Exchange Act, except to the extent that Baker Hughes specifically incorporates it by reference
into such filing.
23
ITEM 6. SELECTED FINANCIAL DATA
The Selected Financial Data should be read in conjunction with Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data, both
contained herein.
(In millions, except per share amounts)
Revenue
Gross Profit
Marketing, general and administrative
Impairment and restructuring charges (1)
Goodwill impairment (2)
Merger and related costs
Merger termination fee (3)
Operating (loss) income
Non-operating expense, net
(Loss) income before income taxes
Income tax (provision) benefit
Net (loss) income
Year Ended December 31,
2016
$ 9,841
2015
$ 15,742
2014
$ 24,551
2013
$ 22,364
2012
$ 21,361
(516)
815
1,735
1,858
199
(3,500)
(1,623)
(417)
(2,040)
(696)
861
969
1,993
—
295
—
(2,396)
(217)
(2,613)
639
(2,736)
(1,974)
4,192
1,333
3,255
1,306
3,508
1,316
—
—
—
—
2,859
(232)
2,627
(896)
1,731
(12)
—
—
—
—
1,949
(234)
1,715
(612)
1,103
(7)
—
—
—
—
2,192
(210)
1,982
(665)
1,317
(6)
Net (income) loss attributable to noncontrolling interests
(2)
7
Net (loss) income attributable to Baker Hughes
$ (2,738) $ (1,967) $ 1,719
$ 1,096
$ 1,311
Per share of common stock:
Net (loss) income attributable to Baker Hughes:
Basic
Diluted
Dividends
Balance Sheet Data:
$ (6.31) $ (4.49) $
(6.31)
0.68
(4.49)
0.68
3.93
3.92
0.64
$
2.47
2.47
0.60
$
2.98
2.97
0.60
Cash, cash equivalents and short-term investments
$ 4,572
$ 2,324
$ 1,740
$ 1,399
$ 1,015
Working capital (current assets minus current liabilities)
Total assets
Long-term debt
Total equity
Notes To Selected Financial Data
6,863
19,034
2,886
12,737
6,493
24,080
3,890
16,382
7,408
28,827
3,913
18,730
6,717
27,934
3,882
17,912
6,293
26,689
3,837
17,268
(1)
Impairment and restructuring charges associated with asset impairments, workforce reductions, facility
closures and contract terminations recorded during 2015 and 2016. See Note 4. "Impairment and
Restructuring Charges" of the Notes to Consolidated Financial Statements in Item 8 herein for further
discussion.
(2) Goodwill impairment recognized in the second and third quarters of 2016. See Note 12. "Goodwill and
Intangible Assets" of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion.
(3) Merger termination fee received from Halliburton. See Note 2. "Halliburton Terminated Merger Agreement"
of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion.
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") should be
read in conjunction with the consolidated financial statements included in Item 8. Financial Statements and
Supplementary Data contained herein.
EXECUTIVE SUMMARY
Baker Hughes is a leading supplier of oilfield services, products, technology and systems used in the worldwide
oil and natural gas industry, referred to as our oilfield operations. We manage our oilfield operations through four
geographic segments consisting of North America, Latin America, Europe/Africa/Russia Caspian, and Middle East/
Asia Pacific. Our Industrial Services businesses are reported in a fifth segment. As of December 31, 2016, Baker
Hughes had approximately 33,000 employees compared to approximately 43,000 employees as of December 31,
2015.
Within our oilfield operations, the primary driver of our businesses is our customers' capital and operating
expenditures dedicated to oil and natural gas exploration, field development and production. The main products
and services provided by oilfield operations fall into one of two categories, Drilling and Evaluation or Completion
and Production. This classification is based on the two major phases of constructing an oil and/or natural gas well,
the drilling phase and the completion phase, and how our products and services are utilized in each phase. We
also provide products and services to the downstream chemicals, and process and pipeline services, referred to as
Industrial Services.
During 2016, we continued to face difficult industry conditions as commodity prices deteriorated to levels not
seen in more than a decade. Activity declined across the globe as reflected by the worldwide rig count, which
decreased 32% as compared to the 2015 average. Customers continued to reduce spending to cope with this
challenging low-commodity price environment, resulting in further price deterioration for our products and services.
The steady decline in U.S. oil production along with the production cuts announced during the fourth quarter of
2016 by OPEC and certain non-OPEC countries drove oil prices higher resulting in an 11% increase when
comparing the fourth quarter closing price for West Texas Intermediate Cushing Crude of $53.72/Bbl to the third
quarter closing price of $48.24/Bbl. This increase stimulated improvement in activity in the North America market
as evidenced by the 29% growth in the rig count in the fourth quarter of 2016 as compared to the third quarter of
2016. Despite this improvement, there has yet to be any meaningful increase in the prices we are able to charge
for our products and services, and thus the impact on our profitability has been minimal. International and deep
water activity continued to decline in the fourth quarter, as most operators are awaiting for a sustainable rebalancing
of the oil market before increasing activity.
Against the back-drop of another difficult year for the industry, we achieved significant progress on our
commitment to improve financial performance by reducing costs and simplifying our operational structure,
optimizing our capital structure, and strengthening our commercial strategy. More specifically, we generated $4.23
billion of cash flows from operations, which includes the $3.5 billion Halliburton merger termination fee, paid down
$1.0 billion in debt, repurchased $763 million in shares, accelerated innovation with over 100 new product
introductions, and built new sales channels to take our products and technology to market faster and more
efficiently. As we executed on our strategy to strengthen profitability and return on invested capital, we rationalized
under-performing product lines in select markets based on our objectives of profitable growth. While these
reductions have had minimal impact on our revenue they have had a positive impact on operating profitability. In
addition, we contributed our North American onshore pressure pumping business into a new venture that is better
positioned to participate efficiently and cost-effectively in the anticipated growth of this market segment.
For 2016, we generated revenue of $9.84 billion, a decrease of $5.90 billion, or 37%, compared to 2015. Net
loss attributable to Baker Hughes was $2.74 billion for 2016 compared to $1.97 billion for 2015. The steep decline
in activity, as evidenced by the 32% decline in the average global rig count year-over-year, and price deterioration
experienced across all our segments are the main drivers for the decline in revenue and profitability. We have
continued to restructure and adjust our operations and cost structure to reflect reduced activity levels. As a result of
these restructuring activities, we recorded charges totaling $1.17 billion in 2016, which included workforce
reductions, contract terminations, facility closures and the write-down of excess machinery and equipment. In
25
addition to our restructuring activities, as a result of the downturn in the energy market and its impact on our
business outlook, we determined that the carrying amount of certain assets exceeded their respective fair values;
therefore, we recorded an impairment charge of $567 million. Further, we recorded goodwill impairment charges
primarily related to our North America reporting unit totaling $1.86 billion. These charges have been excluded from
the results of our operating segments.
OUTLOOK
Oil prices started to rebound in the fourth quarter of 2016 as a result of the announced supply cut agreements
by OPEC and 11 non-OPEC producers, and a modest increase in the forecasted demand for oil. However, North
American production remains uncertain due to the unpredictable actions of North American shale operators who
can bring on production and impact commodity prices much more quickly than their peers in other operating
environments. Since details of OPEC’s plans surfaced in October, rig counts for the fourth quarter of 2016
increased by 23% in the U.S. compared to the third quarter of 2016, with a corresponding increase in U.S. shale
production already materializing. Therefore, the operators' ability to quickly get resources from the ground into
production could limit near-term commodity price gains. This North America dynamic, combined with questions
about OPEC's ability to implement and sustain these cuts, leave room for skepticism that these agreed-upon
production cuts could lead to a more sustainable improvement in oil prices, and in turn, to a more material increase
in spending by exploration and production companies.
While some are more optimistic about the prospects for the near-term recovery, we continue to believe that oil
prices sustained in the mid-to-high $50s are required for confidence in the customer community to improve and
investment to accelerate. Also, activity needs to increase meaningfully before excess service capacity can be
substantially absorbed and meaningful pricing recovery takes place. We are seeing the first signs of this in select
product lines in a few of the North American basins, but we still believe there remains a fair amount of capacity that
must be absorbed before service pricing will become more tightly correlated with higher commodity prices and
increased activity.
Further, we believe recovery paths will vary depending on the location and operating environment. In the North
American market, onshore activity continues to climb upward, and we expect that trend to continue through 2017.
Conversely, in offshore markets around the world, where full cycle lifting costs are higher, particularly deepwater, we
expect activity to remain challenging with more declines expected in 2017. Overall, internationally we expect the
market to be flat to down slightly in the first half of 2017, with continued activity declines and pricing pressure near-
term, partially offset by pockets of moderate growth onshore. As a result of the expected continued market
variability, we believe our tax rate will continue to be volatile.
Despite the near-term volatility, the long-term outlook for our industry remains strong. We believe the world’s
demand for energy will continue to rise, and the supply of energy will continue to increase in complexity, requiring
greater service intensity and more advanced technology from oilfield service companies. As such, we remain
focused on delivering innovative cost-efficient solutions that deliver step changes in operating and economic
performance for our customers.
HALLIBURTON TERMINATED MERGER AGREEMENT
On November 16, 2014, Baker Hughes and Halliburton Company ("Halliburton") entered into a definitive
agreement and plan of merger (the "Merger Agreement") under which Halliburton would acquire all outstanding
shares of Baker Hughes in a stock and cash transaction (the "Merger"). In accordance with the provisions of
Section 9.1 of the Merger Agreement, Baker Hughes and Halliburton agreed to terminate the Merger Agreement on
April 30, 2016, as a result of the failure of the Merger to occur on or before April 30, 2016, due to the inability to
obtain certain specified antitrust related approvals. Halliburton paid $3.5 billion to Baker Hughes on May 4, 2016,
representing the antitrust termination fee required to be paid pursuant to the Merger Agreement. For further
information about the Merger, see Note 2. "Halliburton Terminated Merger Agreement" of the Notes to Consolidated
Financial Statements in Item 8 herein.
26
GENERAL ELECTRIC TRANSACTION AGREEMENT
On October 30, 2016, Baker Hughes, GE, Newco and Merger Sub entered into a Transaction Agreement and
Plan of Merger, pursuant to which, among other things, GE’s oil and gas business and Baker Hughes will be
combined and operate under the name "Baker Hughes, a GE Company". The GE Transaction is subject to the
approval of Baker Hughes’ stockholders, regulatory approvals and customary closing conditions. Baker Hughes
and GE expect the GE Transaction to close in mid-2017. However, Baker Hughes cannot predict with certainty
when, or if, the GE Transaction will be completed because completion of the GE Transaction is subject to conditions
beyond the control of Baker Hughes. For further information about the transaction, see Note 3. "General Electric
Transaction Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein. Newco will operate as
a public company.
BUSINESS ENVIRONMENT
We conduct business in more than 80 countries helping customers find, evaluate, drill, produce, transport and
process hydrocarbon resources. Our revenue is predominately generated from the sale of products and services to
major, national, and independent oil and natural gas companies worldwide, and is dependent on spending by our
customers for oil and natural gas exploration, field development and production. This spending is dependent on a
number of factors, including our customers' forecasts of future energy demand and supply, their access to
resources to develop and produce oil and natural gas, their ability to fund their capital programs, the impact of new
government regulations and most importantly, their expectations for oil and natural gas prices as a key driver of
their cash flows.
Oil and Natural Gas Prices
Oil and natural gas prices are summarized in the table below as averages of the daily closing prices during
each of the periods indicated.
Brent oil prices ($/Bbl) (1)
WTI oil prices ($/Bbl) (2)
Natural gas prices ($/mmBtu) (3)
2016
2015
2014
$
44.11
$
52.31
$
98.88
43.34
2.49
48.68
2.61
93.03
4.35
(1) Bloomberg Dated Brent ("Brent") Oil Spot Price per Barrel
(2) Bloomberg West Texas Intermediate ("WTI") Cushing Crude Oil Spot Price per Barrel
(3) Bloomberg Henry Hub Natural Gas Spot Price per million British Thermal Unit
Outside North America, customer spending is most heavily influenced by Brent oil prices, which fluctuated
significantly throughout the year, ranging from a low of $26.39/Bbl in January 2016 to a high of $55.57/Bbl in
December 2016. Oil prices bottomed early in 2016 due to the impending production increases in Iran after
economic sanctions were lifted. During 2016, OPEC considered production cuts, and in the fourth quarter they
announced their first agreement since 2008 to cut production. Along with OPEC's agreed-upon production cuts,
other non-OPEC countries similarly agreed to reduce production. As a result, in the fourth quarter, Brent oil prices
shifted meaningfully higher. In addition, demand for oil was higher than expected due to robust consumption in
North America and revisions to Chinese, Russian, and European demand growth expectations.
In North America, customer spending is highly driven by WTI oil prices, which, similar to Brent oil prices,
fluctuated significantly throughout the year, with the highest prices being recorded towards the end of the year.
Overall, WTI oil prices ranged from a low of $26.21/Bbl in February 2016 to a high of $54.06/Bbl in December 2016.
Although oil prices have rebounded more than 100% from the previous twelve-year low of $26/Bbl reached
earlier this year to near $55/Bbl at the end of the year, there has yet to be any material change in customer
behavior, other than in certain U.S. basins, to suggest a near-term broader recovery in activity levels.
In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $2.49/
mmBtu in 2016, representing a 5% decrease over the prior year. The warmer-than-average winter at the start of
27
2016 significantly reduced demand and storage inventories hit record highs. In late 2016, once production and
drilling activity tapered off and the seasonal demand picked up, the spot prices improved. According to the U.S.
Department of Energy ("DOE"), working natural gas in storage at the end of 2016 was 3,311 billion cubic feet
("Bcf"), which was 9.9%, or 364 Bcf, below the corresponding week in 2015.
Baker Hughes Rig Count
The Baker Hughes rig counts are an important business barometer for the drilling industry and its suppliers.
When drilling rigs are active they consume products and services produced by the oil service industry. Rig count
trends are driven by the exploration and development spending by oil and natural gas companies, which in turn is
influenced by current and future price expectations for oil and natural gas. Therefore, the counts may reflect the
relative strength and stability of energy prices and overall market activity. However, these counts should not be
solely relied on as other specific and pervasive conditions may exist that affect overall energy prices and market
activity.
Baker Hughes has been providing rig counts to the public since 1944. We gather all relevant data through our
field service personnel, who obtain the necessary data from routine visits to the various rigs, customers, contractors
and other outside sources, as necessary. We base the classification of a well as either oil or natural gas primarily
upon filings made by operators in the relevant jurisdiction. This data is then compiled and distributed to various wire
services and trade associations and is published on our website. We believe the counting process and resulting
data is reliable; however, it is subject to our ability to obtain accurate and timely information. Rig counts are
compiled weekly for the U.S. and Canada and monthly for all international rigs. Published international rig counts
do not include rigs drilling in certain locations, such as Russia, the Caspian region, Iran and onshore China because
this information is not readily available.
Rigs in the U.S. and Canada are counted as active if, on the day the count is taken, the well being drilled has
been started but drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential
consumer of our drill bits. In international areas, rigs are counted on a weekly basis and deemed active if drilling
activities occurred during the majority of the week. The weekly results are then averaged for the month and
published accordingly. The rig count does not include rigs that are in transit from one location to another, rigging up,
being used in non-drilling activities including production testing, completion and workover, and are not expected to
be significant consumers of drill bits.
The rig counts are summarized in the table below as averages for each of the periods indicated.
U.S. - onshore
U.S. - offshore
Canada
North America
Latin America
North Sea
Continental Europe
Africa
Middle East
Asia Pacific
Outside North America
Worldwide
2016
2015
2014
490
23
129
642
198
28
68
85
390
187
956
1,598
948
36
194
1,178
319
37
80
106
406
220
1,168
2,346
1,804
57
379
2,240
397
40
105
134
406
254
1,336
3,576
28
2016 Compared to 2015
The rig count in North America decreased 46% in 2016 compared to 2015 primarily driven by a 44% decline in
oil-directed rigs, as a result of reduced spending from our customers as they adapt to a lower oil price environment.
The oil-directed rig count decreased 45% in the U.S. as lower WTI prices have forced operators to reduce their
exploration and development spending in order to protect their cash flows, as they focus more on production
optimization opportunities. In Canada, the oil-directed rig count has decreased by 28% as many operators curtailed
their drilling plans as most heavy oil sands projects are not economical at current oil prices. The natural gas-
directed rig count in North America declined 50% in 2016 as natural gas well productivity improved, with natural
gas-directed drilling declining 56% in the U.S. and 38% in Canada.
Outside North America, the rig count decreased 18% in 2016 compared to 2015, also driven by reduced
customer spending and a lower oil price environment. The rig count in Latin America decreased 38% as a result of
customer budgetary constraints across most of the region, primarily in Argentina, Mexico, Brazil, and Colombia.
The North Sea rig count decreased by 24%, largely due to a decline in the drilling activity in the United Kingdom.
The rig count in Continental Europe decreased by 15% as a result of reduced drilling across the area with the
largest decline seen in Romania. In Africa, the rig count decreased 20%, predominantly due to reduced customer
spending across the majority of the region, particularly in Nigeria, Angola, Chad, and Gabon. The rig count in the
Middle East decreased 4% in 2016 due to reduced activity in Egypt and Iraq, partially offset by increased activity in
Abu Dhabi. The rig count in Asia Pacific decreased 15% as a consequence of reduced drilling activity primarily in
Indonesia and Australia.
2015 Compared to 2014
The rig count in North America decreased 47% in 2015 compared to 2014 primarily driven by a 52% decline in
oil-directed rigs, as a result of reduced spending from our customers as they adapt to a lower oil price environment.
The oil-directed rig count decreased 51% in the U.S. as lower WTI prices have forced operators to reduce their
exploration and development spending in order to protect their cash flows, as they focus more on production
optimization opportunities. In Canada, the oil-directed rig count has decreased by 61% as many operators curtailed
their drilling plans as most heavy oil sands projects are not economical at current oil prices. The natural gas-
directed rig count in North America declined 32% in 2015 as natural gas prices deteriorated 40% compared to the
2014 average, with natural gas-directed drilling declining 32% in the U.S. and 33% in Canada.
Outside North America, the rig count decreased 13% in 2015 compared to 2014, also driven by reduced
customer spending and a lower oil price environment. The rig count in Latin America decreased 20% as a result of
customer budgetary constraints across most of the region, primarily in Mexico, Colombia, and Ecuador. The one
exception was in the emerging unconventional plays in Argentina where activity remained relatively stable in 2015.
The North Sea rig count decreased by 7%, largely due to a decline in the drilling activity in the Netherlands. The rig
count in Continental Europe decreased by 24%, mainly as a result of reduced drilling in Turkey and Romania. In
Africa, the rig count decreased 21%, predominantly due to reduced customer spending across the majority of the
region, particularly in Libya, Chad, Angola, and Nigeria. The 2015 rig count in the Middle East remained unchanged
from 2014 as activity declines in Iraq and Egypt were offset by increased activity in Saudi Arabia, Oman, Abu Dhabi
and Kuwait. The rig count in Asia Pacific decreased 13% as a consequence of reduced drilling activity primarily in
India, Indonesia, Australia and New Zealand.
RESULTS OF OPERATIONS
The discussions below relating to significant line items from our consolidated statements of income (loss) are
based on available information and represent our analysis of significant changes or events that impact the
comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect
comparability or trends and, where reasonably practicable, have quantified the impact of such items. In addition,
the discussions below for revenue and cost of revenue are on a total basis as the business drivers for product sales
and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise
stated.
29
Revenue and Profit Before Tax
Revenue and operating profit (loss) before tax for each of our five operating segments is provided below. The
performance of our operating segments is evaluated based on operating profit (loss) before tax, which is defined as
income (loss) before income taxes and before the following: net interest expense, corporate expenses, impairment
and restructuring charges, goodwill impairment charges, the merger termination fee, loss on sale of business
interest, loss on early extinguishment of debt, and certain gains and losses not allocated to the operating segments.
Beginning in 2016, we excluded merger and related costs, from both the terminated Halliburton and the
proposed GE transactions, from our operating segments. These costs are now presented as a separate line item in
the consolidated statement of income (loss). Prior year merger and related costs have been reclassified to conform
to the current year presentation.
2016 Compared to 2015
Revenue:
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Industrial Services
Total
Operating Profit (Loss) Before Tax:
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Industrial Services
Total Operations
Corporate
Loss on sale of business interest
Loss on early extinguishment of debt
Interest expense, net
Impairment and restructuring charges
Goodwill impairment
Merger and related costs
Merger termination fee
Total
"N/M" represents not meaningful.
North America
Year Ended December 31,
2016
2015
$ Change
% Change
2,936
980
2,201
2,705
1,019
9,841
$
$
6,009
1,799
3,278
3,441
1,215
15,742
$
$
(3,073)
(819)
(1,077)
(736)
(196)
(5,901)
(51)%
(46)%
(33)%
(21)%
(16)%
(37)%
Year Ended December 31,
2016
2015
$ Change
% Change
(687)
(276)
(273)
69
(6)
(1,173)
(158)
(97)
(142)
(178)
(1,735)
(1,858)
(199)
3,500
(2,040)
$
(639)
$
144
183
229
108
25
(133)
—
—
(217)
(1,993)
—
(295)
—
$
(2,613)
$
(48)
(420)
(456)
(160)
(114)
(1,198)
(25)
(97)
(142)
39
258
(1,858)
96
3,500
573
(8)%
(292)%
(249)%
(70)%
(106)%
N/M
19 %
N/M
N/M
(18)%
(13)%
N/M
(33)%
N/M
(22)%
$
$
$
$
North America revenue for 2016 was $2.94 billion, a decrease of $3.07 billion, or 51%, compared to 2015,
primarily as a result of the steep drop in activity as reflected in the 46% year-over-year average rig count decline,
30
and to a lesser extent, deteriorating pricing conditions as operators further reduced their spending levels in 2016.
All product lines have been unfavorably impacted by the drop in activity. In addition, our onshore pressure pumping
business incurred share reductions, driven by efforts to reduce losses and improve cash flow in a market where
pricing was unsustainable. Conversely, production chemicals reflected the smallest decrease in activity as revenue
in this product line is more highly correlated to production than rig count. In addition, deepwater operations and
artificial lift also showed signs of resilience.
North America operating loss before tax was $687 million in 2016, a decrease of $48 million, or 8%, compared
to the $639 million operating loss in 2015. Although operating results were negatively impacted by the sharp
reduction in activity and an increasingly unfavorable pricing environment, actions taken in the past year to reduce
our workforce, close and consolidate facilities and improve commercial terms with vendors resulted in significantly
lower operating costs. These actions to restructure our North America operations to operate in a lower activity and
pricing environment, combined with the reduction of depreciation and amortization expense from asset impairments,
helped mitigate the impact of the ongoing decline in revenue experienced since early 2015. Our operating results
for 2016 include $230 million of costs related to writing off certain excess inventory, compared to costs of $181
million during 2015 due to lower of cost or market adjustments.
On December 30, 2016, we contributed our North American onshore pressure pumping business to a newly
formed venture, of which we retained a 46.7% interest and accounted for as an equity method investment. This
investment, and the related earnings, will be excluded from our operating segments. For further information, see
Note 5. "Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements in Item 8 herein.
Latin America
Latin America revenue for 2016 was $980 million, a decrease of $819 million, or 46%, compared to 2015. The
reduction in this segment is attributed to activity declines across the region as evident in the 38% drop in the rig
count. Activity has declined across the entire segment and across all product lines. The largest year-over-year
declines were pressure pumping in Argentina, artificial lift in the Andean Area, and drilling services in Brazil and
Mexico.
Latin America operating loss before tax was $276 million in 2016, a decrease of $420 million, or 292%,
compared to operating profit before tax of $144 million in 2015. The reduction in profitability is mainly attributed to
the decline in activity, and to a lesser extent price, which was exacerbated by an increase of $96 million for
provisions for doubtful accounts year-over-year, almost entirely in Ecuador. Additionally, we incurred costs of $84
million in 2016 to write off the carrying value of certain excess inventory compared to $13 million in 2015. The
reduction in profitability was partially mitigated by lower operating costs and depreciation and amortization expense
resulting from our efforts to structurally align the segment to reflect current and expected near-term activity levels.
We also benefited from reduced foreign exchanges losses.
Europe/Africa/Russia Caspian ("EARC")
EARC revenue for 2016 was $2.20 billion, a decrease of $1.08 billion, or 33%, compared to 2015. The
decrease can be attributed primarily to activity reductions across all markets and product lines, with the largest
decline experienced in the North Sea and West Africa, most notably in the drilling services and completion systems
product lines. In addition to reduced activity in the North Sea, the region was also negatively impacted by labor
union strikes in the fourth quarter of 2016. To a lesser extent, unfavorable pricing also impacted revenue. In
addition, in 2016 unfavorable exchange rates, mainly for the British Pound, Nigerian Naira, Russian Ruble, Angolan
Kwanza and the Norwegian Krone accounted for more than 10% of the decline in revenue. Despite the activity
reductions, we did see resiliency in our production chemicals product line as a result of increased share in Africa.
EARC operating loss before tax was $273 million in 2016, a decrease of $456 million, or 249%, compared to
operating profit before tax of $183 million in 2015. The decline in operating profit from lower activity levels and
unfavorable pricing was compounded by valuation allowances on indirect taxes in Africa. In addition, we incurred
costs of $143 million to write off certain excess inventory during 2016. These reductions in profitability were partially
offset by the benefit of implemented cost reduction measures, lower depreciation and amortization expense, and
reduced foreign exchange losses.
31
Middle East/Asia Pacific ("MEAP")
MEAP revenue for 2016 was $2.71 billion, a decrease of $736 million, or 21%, compared to 2015. The revenue
decline in this segment was driven by lower activity across most of the region, and to a lesser extent region-wide
pricing pressure. The most noticeable reductions occurred in completion systems, pressure pumping and drilling
services across Asia Pacific, particularly in Australia, Malaysia and Vietnam, across all product lines in Iraq, and in
deepwater operations in India. These reductions were partially offset by activity growth in Kuwait, mainly in artificial
lift, drilling services and pressure pumping.
MEAP operating profit before tax decreased $160 million, or 70%, in 2016 compared to 2015. The reduction in
profitability was driven largely by lower activity levels and unfavorable pricing, partially offset by operating cost
reductions and lower depreciation and amortization expense from asset impairments. During 2016, we incurred
costs of $117 million to write off certain excess inventory. During 2015, we incurred charges in Iraq related to our
integrated operations.
Industrial Services
Industrial Services revenue was $1.02 billion, a decrease of $196 million, or 16%, compared to 2015. The
decline in revenue in this segment was driven by activity reductions as customers reduced spending and delayed
projects including several major pipeline construction and maintenance projects. Revenue was further negatively
impacted by pricing deterioration.
Industrial Services operating loss before tax in 2016 was $6 million, a decrease 106% compared to operating
profit before tax of $108 million in 2015. The reduction in profitability resulting from lower activity levels and pricing
deterioration was partially offset by operating cost reductions and lower depreciation and amortization expense from
asset impairments. During 2016, we incurred costs of $43 million to write off certain excess inventory.
2015 Compared to 2014
Revenue:
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Industrial Services
Total
Year Ended December 31,
2015
2014
$ Change
% Change
$
$
6,009
1,799
3,278
3,441
1,215
15,742
$
$
12,078
2,236
4,417
4,456
1,364
24,551
$
$
(6,069)
(437)
(1,139)
(1,015)
(149)
(8,809)
(50)%
(20)%
(26)%
(23)%
(11)%
(36)%
32
Operating Profit (Loss) Before Tax:
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Industrial Services
Total Operations
Corporate
Interest expense, net
Impairment and restructuring charges
Merger and related costs
Total
North America
Year Ended December 31,
2015
2014
$ Change
% Change
$
(639)
$
1,466
$
(2,105)
(144)%
144
183
229
108
25
(133)
(217)
(1,993)
(295)
290
621
675
119
3,171
(312)
(232)
—
—
(146)
(438)
(446)
(11)
(3,146)
179
15
(1,993)
(295)
(50)%
(71)%
(66)%
(9)%
(99)%
(57)%
(6)%
N/M
N/M
$
(2,613)
$
2,627
$
(5,240)
(199)%
North America revenue for 2015 was $6.01 billion, a decrease of $6.07 billion, or 50%, compared to 2014. The
steep reduction in commodity prices experienced by the industry in 2015 severely impacted onshore North America
exploration and production companies as a result of the higher lifting cost per barrel of many of these producers.
These operators have addressed these cash constraints by reducing drilling activity in less economical
unconventional plays, delaying well completion activities, and driving price discounts from their service providers as
they await higher commodity prices. These lower activity levels, as evident in the 47% rig count drop, and
deteriorating pricing conditions were the main drivers for the revenue decline in this segment. All product lines have
been unfavorably impacted by the drop in activity, with production chemicals, deepwater operations and artificial lift
showing the most resilience. Additionally, the reduced activity and well completion delays created an oversupply of
hydraulic fracturing equipment, which caused the price deterioration in the onshore pressure pumping product line
to be more severe. As such, we lost market share in this product line in 2015 as we worked to maintain cash flow
positive operations despite an oversupplied market.
North America operating loss before tax was $639 million in 2015, a decrease of $2.11 billion, or 144%,
compared to operating profit before tax of $1.47 billion in 2014. The reduction in profitability was primarily due to
the sharp decline in activity and an increasingly unfavorable pricing environment. Additionally, as a result of the
industry downturn and its impact on our business, we incurred costs of $181 million in 2015 to write down the
carrying value of certain inventory. The impact from these unfavorable market conditions was partially mitigated by
actions taken in the year to reduce our workforce, close and consolidate facilities and improve commercial terms
with vendors, which ultimately resulted in lower operating costs.
Latin America
Latin America revenue for 2015 was $1.80 billion, a decrease of $437 million, or 20%, compared to 2014. The
reduction in this segment is attributed to activity declines across the region as a result of customer budgetary
constraints, predominately in the Andean area where the rig count has declined 46%, and in Venezuela where we
restructured our operational footprint in late 2014. This reduction was partially offset by revenue growth in Brazil
from share gains in our drilling services product line.
Latin America operating profit before tax decreased $146 million, or 50%, in 2015 compared to 2014. The
reduction in profitability is mainly attributed to the decline in activity, foreign exchange losses, primarily in Argentina,
and an increase in expense related to reserves for doubtful accounts. Additionally, we incurred costs of $13 million
in 2015 to write down the carrying value of certain inventory. This was partially offset by improvements made to our
operational cost structure.
33
Europe/Africa/Russia Caspian
EARC revenue for 2015 was $3.28 billion, a decrease of $1.14 billion, or 26%, compared to 2014. The
decrease was driven mainly by activity declines and unfavorable pricing across the region. Revenue was also
negatively impacted by the unfavorable change in foreign exchange rates, which accounted for approximately one
third of the revenue reduction in 2015. The deconsolidation of a joint venture in North Africa late last year also
contributed to the decline in revenue. All product lines have been unfavorably impacted by the drop in activity and
price, with production chemicals and drilling services showing the most resilience.
EARC operating profit before tax decreased $438 million, or 71%, in 2015 compared to 2014. The unfavorable
impact to profitability from pricing deterioration, lower activity levels, the change in foreign exchange rates, and
increased costs related to reserves for doubtful accounts was partially offset by the savings from recent cost
reduction measures. In addition, in 2015 unfavorable exchange rates, mainly for the Russian Ruble, Euro and the
British Pound, accounted for approximately 40% of the decline in profitability. Also, 2014 included a $58 million
charge associated with the restructuring of our operations in North Africa, and impairment of certain assets, that did
not repeat in 2015.
Middle East/Asia Pacific
MEAP revenue for 2015 was $3.44 billion, a decrease of $1.02 billion, or 23%, compared to 2014. The revenue
decline in this segment was driven primarily by lower activity across most of Asia, in particular China, Australia and
Vietnam, and reduced revenue in Iraq. The revenue drop in Iraq is attributed to reduced activity, as evident by the
34% decline in rig count, and the rationalization of our operational footprint in the country, including completing our
integrated operations activities. Revenue was also impacted by unfavorable pricing across the region.
MEAP operating profit before tax decreased $446 million, or 66%, in 2015 compared to 2014. The reduction in
profitability was driven largely by lower activity levels and unfavorable pricing. The current year also includes
charges related to reducing our operations in Iraq. These reductions were partially offset by the benefit of the
recent cost-saving actions.
Industrial Services
Industrial Services revenue was $1.22 billion, a decrease of $149 million, or 11%, compared to 2014. The
decline in revenue in this segment was driven primarily by reduced activity and the unfavorable change in foreign
exchange rates.
Industrial Services operating profit before tax decreased 9% in 2015 compared to 2014. The reduction in
profitability resulting from lower activity levels was partially offset by cost-saving efforts. However, Industrial
Services profit before tax for the prior year included integration costs related to the pipeline services business
acquired in 2014, which we did not incur in 2015.
34
Costs and Expenses
The table below details certain data from our consolidated statements of income (loss) and as a percentage of
revenue.
Revenue
Cost of revenue
2016
2015
2014
$
$ 9,841
9,973
%
100 % $ 15,742
$
101 %
14,415
Research and engineering
Marketing, general and administrative
Impairment and restructuring charges
Goodwill impairment
Merger and related costs
Merger termination fee
Loss on sale of business interest
Loss on early extinguishment of debt
Interest expense, net
384
815
1,735
1,858
199
(3,500)
97
142
178
4 %
8 %
18 %
19 %
2 %
(36)%
1 %
1 %
2 %
466
969
1,993
—
295
—
—
—
217
Cost of Revenue
%
100% $ 24,551
$
92%
3%
6%
13%
—%
2%
—%
—%
—%
1%
19,746
613
1,333
—
—
—
—
—
—
232
%
100%
80%
2%
5%
—%
—%
—%
—%
—%
—%
1%
Cost of revenue as a percentage of revenue was 101% and 92% for 2016 and 2015, respectively. The increase
in cost of revenue as a percentage of revenue is due mainly to deteriorating pricing conditions as operators reduced
their spending, partially offset by the benefit of implemented cost reduction measures and lower depreciation and
amortization expense from asset impairments. Despite actions to restructure our global operations to operate in a
lower price and activity environment, the decline in revenue has outpaced the benefit of our cost saving measures.
Additionally, the product lines most significantly impacted by the downturn in rig activity are also the most capital-
intensive. Accordingly, the fixed costs associated with those product lines lessened the positive impact of our cost
reduction efforts in 2016 and 2015. Cost of revenue for 2016 was also negatively impacted by a charge of $617
million to write off and dispose of certain excess inventory compared to a write-down of $194 million in the prior
year due to lower of cost or market adjustments.
Cost of revenue as a percentage of revenue was 92% and 80% for 2015 and 2014, respectively. As a result of
the steep decline in activity and customer spending, we experienced significant pricing pressure and a decline in
the demand for our products and services. Cost of revenue for 2015 was also negatively impacted by a charge of
$194 million to adjust the carrying value of certain inventory due to the industry-wide market decline.
Research and Engineering
Research and engineering expenses decreased 18% in 2016 compared to 2015 and decreased 24% in 2015
compared to 2014. These declines were driven by cost reduction measures in light of the severe decline in activity
resulting in lower revenues and profitability.
Marketing, General and Administrative
Marketing, general and administrative ("MG&A") expenses decreased by $154 million, or 16%, in 2016
compared to 2015. The reduction in MG&A costs is mainly a result of workforce reductions, lower discretionary
spending, reduced foreign exchange losses and a $23 million investment gain, partially offset by legal settlement
costs of $44 million.
MG&A expenses decreased by $364 million, or 27%, in 2015 compared to 2014. The reduction in MG&A costs
is mainly a result of workforce reductions and lower discretionary spending.
35
Impairment and Restructuring Charges
During 2016, we recorded impairment and restructuring charges of $1.74 billion consisting of $272 million for
workforce reduction costs, $192 million for contract termination costs and $1.27 billion for asset impairments related
to excess machinery and equipment, facilities and intangible assets. Total cash paid during 2016 related to
workforce reductions and contract terminations was $419 million.
During 2015, we recorded impairment and restructuring charges of $830 million consisting of $436 million for
workforce reduction costs, $121 million for contract termination costs and $273 million for asset impairments related
to excess machinery and equipment and facilities. Total cash paid during 2015 related to these charges was $446
million. In addition to our restructuring activities, in response to the downturn in the energy market and its impact on
our business outlook, we determined that the carrying amount of a number of our assets exceeded their respective
fair values; therefore, we recorded an impairment charge of $1.16 billion. These charges have been excluded from
the results of our operating segments. For further discussion of these impairment and restructuring charges, see
Note 4. "Impairment and Restructuring Charges" of the Notes to Consolidated Financial Statements in Item 8
herein.
The reduction in costs from eliminated depreciation, reduced employee expenses, and reduced interest
expense on long-term debt in 2016 is approximately $550 million, and is expected to be approximately $900 million
on an annualized basis, $700 million of which is related to actions taken post Halliburton merger.
Goodwill Impairment
In the second quarter of 2016, we determined the fair value of our reporting units using a combination of
techniques including discounted cash flows derived from our long-term plans and a market approach that provides
value indications through a comparison with guideline public companies. Based on the results of our impairment
test, we determined that goodwill of two of our reporting units was impaired, and performed the second step of the
goodwill impairment test. We substantially completed all actions necessary in the determination of the implied fair
value of goodwill in the second quarter of 2016; however, some of the estimated fair values and allocations were
subject to adjustment once the valuations and other computations were completed. Accordingly, in the second
quarter of 2016, we recorded an estimate of the goodwill impairment loss of $1.84 billion, which consisted of $1.53
billion for the North America segment and $311 million for the Industrial Services segment. During the third quarter
of 2016, we finalized all valuations and computations, and adjusted our final goodwill impairment loss for the first
nine months of 2016 to $1.86 billion, consisting of $1.55 billion for the North America segment and $309 million for
the Industrial Services segment. There were no goodwill-related impairments recorded in the fourth quarter of
2016.
Merger and Related Costs and Merger Termination Fee
We incurred costs related to the terminated merger with Halliburton of $180 million and $295 million in 2016
and 2015, respectively. These costs included certain expenses under our retention programs and obligations for
minimum incentive compensation costs which, based on meeting eligibility criteria, have been treated as merger
and related costs. On April 30, 2016, the Merger Agreement with Halliburton was terminated and as a result,
Halliburton paid us $3.5 billion on May 4, 2016, which represents the termination fee required to be paid pursuant to
the Merger Agreement. In 2016, we also incurred costs related to the pending transaction with GE of $19 million.
Interest Expense, Net
Interest expense, net of interest income of $33 million, was $178 million in 2016, a decrease of $39 million
compared to $217 million, net of interest income of $20 million, in 2015. The decrease is due primarily to the bond
buy back that occurred in June of 2016, and to a lesser extent, the growth in interest income earned on higher cash
balances and short-term investments. Interest expense, net of interest income, of $217 million in 2015 decreased
by $15 million compared to $232 million, net of interest income of $13 million, in 2014. The reduction is due
primarily to lower short-term borrowings in Latin America and an increase in interest income.
36
Income Taxes
Total income tax expense was $696 million in 2016 compared to income tax benefit of $639 million for 2015 and
income tax expense of $896 million for 2014. Our effective tax rate on operating profits or losses in 2016, 2015 and
2014 was (34.1)%, 24.5% and 34.1%, respectively. The 2016 negative effective tax rate is due primarily to the
geographical mix of earnings and losses such that taxes in certain jurisdictions, including withholding and deemed
profit taxes, exceed the tax benefit from the losses in other jurisdictions due to valuation allowances provided in
most jurisdictions and goodwill impairments with no tax benefit. The 2015 effective tax rate is lower than the U.S.
statutory income tax rate of 35% due to losses in foreign jurisdictions with no tax benefit and adjustments to prior
years' tax positions, partially offset by favorable amended returns and other return to accrual adjustments. The
2014 effective tax rate is lower than the U.S. statutory income tax rate of 35% due to lower rates on certain
international operations, partially offset by state income taxes and adjustments to prior years' tax positions.
As a result of the geographic mix of earnings and losses, including the goodwill impairment, asset impairment,
restructuring charges, and other discrete tax items, our rate has been, and will continue to be volatile until the
market stabilizes.
COMPLIANCE
We conduct business in more than 80 countries, including approximately 15 of the countries having the lowest
scores in the Transparency International's Corruption Perception Index survey for 2016, which indicates high levels
of corruption. We devote significant resources to the development, maintenance, communication and enforcement
of our Business Code of Conduct, our anti-bribery compliance policies, our internal control processes and
procedures and numerous other compliance related policies. Notwithstanding the devotion of such resources, and
in part as a consequence thereof, from time to time we discover or receive information alleging potential violations
of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct timely
internal investigations of these potential violations and take appropriate action depending upon the outcome of the
investigation.
We anticipate that the devotion of significant resources to compliance-related issues, including the necessity for
investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural
gas exploration, development and production take place and in which we conduct operations. Compliance-related
issues have, from time to time, limited our ability to do business or have raised the cost of operating in these
countries. In order to provide products and services in some of these countries, we may in the future utilize
ventures with third parties, sell products to distributors or otherwise modify our business approach in order to
improve our ability to conduct our business in accordance with applicable laws and regulations and our Business
Code of Conduct.
Our Best-in-Class Global Ethics and Compliance Program (our "Compliance Program") is based on (i) our Core
Values of Integrity, Performance, Teamwork, Learning and Courage; (ii) the standards contained in our Business
Code of Conduct; and (iii) the laws of the countries where we operate. Our Compliance Program is referenced
within the Company as "C2" or "Completely Compliant." The Completely Compliant theme is intended to establish
the proper Tone-at-the-Top throughout the Company. Employees are consistently reminded that they play a crucial
role in ensuring that the Company always conducts its business ethically, legally and safely.
Highlights of our Compliance Program include the following:
• We have comprehensive internal policies over such areas as facilitating payments; travel, entertainment,
gifts and charitable donations connected to non-U.S. government officials; payments to non-U.S.
commercial sales representatives; and the use of non-U.S. police or military organizations for security
purposes. In addition, we have country-specific guidance for customs standards, visa processing, export
and re-export controls, economic sanctions and antiboycott laws.
• We have a comprehensive employee compliance training program covering substantially all employees.
• We have a due diligence procedure for commercial sales, processing and professional agents and an
enhanced risk-based process for classifying distributors and suppliers.
• We have continued our reduction of the use of commercial sales representatives and processing agents,
including the reduction of customs agents.
37
• We have a compliance governance committee, which includes senior officers of the Company, that reviews
our effectiveness and compliance with processes and controls of the Company's global Compliance
Program including all areas covered by the Business Code of Conduct.
• We have a special compliance committee, which is made up of senior officers, that meets no less than once
a year to review the oversight reports for all active commercial sales representatives.
• We have compliance committees that have been formed and are operating successfully in all of the
Company's geomarkets.
• We use technology to monitor and report on compliance matters, including an internal investigations
management software, a web-based antiboycott reporting tool and a global trade management software
tool.
• We have a compliance program designed to encourage reporting of any ethics or compliance matter
without fear of retaliation including a worldwide business helpline operated by a third party and currently
available toll-free in 150 languages to ensure that our helpline is easily accessible to employees in their own
language.
• We have a centralized finance organization including an enterprise-wide accounting system and company-
wide policies. In addition, the corporate audit function has incorporated anti-corruption procedures in audits
of certain countries. We also conduct FCPA risk assessments and legal audit procedures relating to higher
risk third parties in non-U.S. jurisdictions.
• We continue to work to ensure that we have adequate legal compliance coverage around the world,
including the coordination of compliance advice and customized training across all regions and countries
where we do business.
• We have a centralized human resources function, including, among other things, consistent standards for
pre-hire screening of employees, the screening of existing employees prior to promoting them to positions
where they may be exposed to corruption-related risks, and a uniform policy for new hire training with a
compliance component.
LIQUIDITY AND CAPITAL RESOURCES
Our objective in financing our business is to maintain sufficient liquidity, adequate financial resources and
financial flexibility in order to fund the requirements of our business. At December 31, 2016, we had cash and cash
equivalents of $4.57 billion compared to $2.32 billion of cash and cash equivalents at December 31, 2015. On May
4, 2016, Halliburton paid us $3.5 billion, which represents the termination fee required to be paid pursuant to the
Merger Agreement. Part of the proceeds received were used to purchase $1.0 billion face value of our long-term
notes and debentures, which included portions of each tranche of notes and debentures, and $763 million of our
common stock.
At December 31, 2016, approximately $2.92 billion of our cash and cash equivalents was held by foreign
subsidiaries compared to approximately $2.01 billion at December 31, 2015. A substantial portion of the cash held
by foreign subsidiaries at December 31, 2016 was reinvested in our international operations as our current intent is
to use this cash to, among other things, fund the operations of our foreign subsidiaries. If we decide at a later date
to repatriate those funds to the U.S., we may be required to provide taxes on certain of those funds based on
applicable U.S. tax rates net of foreign tax credits. We have a committed revolving credit facility (the "credit facility")
with commercial banks and a related commercial paper program under which the maximum combined borrowing at
any time under both the credit facility and the commercial paper program is $2.5 billion. At December 31, 2016, we
had no commercial paper outstanding; therefore, the amount available for borrowing under the credit facility as of
December 31, 2016 was $2.5 billion. During 2016, we used cash to fund a variety of activities including certain
working capital needs and restructuring costs, capital expenditures, repurchases of long-term debt and common
stock, and the payment of dividends. We believe that cash on hand, cash flows generated from operations and the
available credit facility, including the issuance of commercial paper, will provide sufficient liquidity to manage our
global cash needs.
38
Cash Flows
Cash flows provided by (used in) each type of activity were as follows for the years ended December 31:
(In millions)
Operating activities
Investing activities
Financing activities
Operating Activities
2016
2015
2014
$
4,229
203
(2,185)
$
1,796
(905)
(282)
$
2,953
(1,659)
(939)
Cash flows from operating activities provided cash of $4.23 billion and $1.80 billion for the year ended
December 31, 2016 and 2015, respectively. Cash flows from operating activities increased $2.43 billion in 2016
primarily due to the receipt of the $3.5 billion merger termination fee, changes in the components of our working
capital (receivables, inventories and accounts payable) as a result of lower activity which provided cash of $695
million, and an income tax refund in the U.S. of approximately $415 million. These cash inflows were partially offset
by an increase in our net loss, adjusted for non-cash items. Included in our cash flows from operating activities for
2016 and 2015 are payments of $419 million and $446 million, respectively, made for employee severance and
contract termination costs as a result of our restructuring activities initiated during the year.
Cash flows from operating activities provided cash of $1.80 billion and $2.95 billion for the year ended
December 31, 2015 and 2014, respectively. Cash flows from operating activities decreased $1.16 billion in 2015
primarily due to the decrease in our net income, adjusted for non-cash items, partially offset by the changes in the
components of our working capital due to lower activity levels, which provided more cash in 2015 compared to
2014.
Investing Activities
Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the
appropriate levels and types of machinery and equipment in place to generate revenue from operations.
Expenditures for capital assets totaled $332 million, $965 million and $1.79 billion for 2016, 2015 and 2014,
respectively. The decline in capital expenditures over the past two years is a result of lower demand for our
products and services and our continued focus on capital discipline.
Proceeds from the disposal of assets were $283 million, $388 million and $437 million for 2016, 2015 and 2014,
respectively. These disposals related to equipment that was lost-in-hole and property, machinery, and equipment no
longer used in operations that was sold throughout the year.
In 2016, we purchased short-term and long-term investment securities totaling $349 million and received
proceeds of $453 million from the maturities of various investment securities.
During the fourth quarter of 2016, we contributed our North American onshore pressure pumping business into
a new venture and received $142 million of cash, net of $8 million of direct transaction fees, and a 46.7% interest in
the new venture. As a result of this transaction, we deconsolidated this business and recognized a $97 million loss
on the sale of our majority interest in this business. See Note 5. "Acquisitions and Dispositions" of the Notes to
Consolidated Financial Statements in Item 8 herein for further discussion.
Financing Activities
We had net repayments of commercial paper and other short-term debt of $60 million, $45 million and $248
million in 2016, 2015 and 2014, respectively. Total debt outstanding at December 31, 2016 was $3.02 billion, a
decrease of $1.02 billion compared to December 31, 2015. The total debt-to-capital (defined as total debt plus
equity) ratio was 0.19 at December 31, 2016 and 0.20 at December 31, 2015.
In June 2016, we purchased $1.0 billion of the aggregate outstanding principal amount associated with our
long-term outstanding notes and debentures, which included portions of each tranche of notes and debentures.
39
Pursuant to a cash tender offer, the purchases resulted in the payment of an early-tender premium, including
various fees, of $135 million and a pre-tax loss on the early extinguishment of debt of $142 million, which includes
the premium and the write-off of a portion of the remaining original debt issue costs and debt discounts or
premiums. The bond purchases will result in $55 million of annualized interest savings and $632 million of interest
savings over the life of the bonds.
We received proceeds of $91 million, $116 million and $216 million in 2016, 2015 and 2014, respectively, from
the issuance of common stock through the exercise of stock options and the employee stock purchase plan.
We paid dividends of $293 million, $297 million and $279 million in 2016, 2015 and 2014, respectively.
Beginning in May 2016, following the termination of the Merger with Halliburton, through September 30, 2016,
we repurchased 16.2 million shares of our common stock at an average price of $47.09 per share, for a total of
$763 million. We had authorization remaining to repurchase approximately $1.24 billion in common stock at
December 31, 2016. We had no stock repurchases during the fourth quarter of 2016 or during 2015. In 2014, we
repurchased 9.1 million shares of our common stock at an average price of $65.75 per share, for a total of
$600 million.
Under the Transaction Agreement with GE entered into on October 30, 2016 as described in Note 3. "General
Electric Transaction Agreement" of the Notes to Consolidated Financial Statements in Item 8 herein, we have
generally agreed not to repurchase any shares of common stock or increase the quarterly dividend while the
transaction is pending.
Available Credit Facility
On July 13, 2016, we entered into a new five-year $2.5 billion committed revolving credit facility (the "2016
Credit Agreement") with commercial banks maturing in July 2021, which replaced our existing credit facility of $2.5
billion, but maintained the existing commercial paper program. The previous credit facility had a maturity date in
September of 2016. The maximum combined borrowing at any time under both the 2016 Credit Agreement and the
commercial paper program is $2.5 billion. The 2016 Credit Agreement contains certain covenants, which, among
other things, require the maintenance of a total debt-to-total capitalization ratio, restrict certain merger transactions
or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary
indebtedness. Upon the occurrence of certain events of default, our obligations under the 2016 Credit Agreement
may be accelerated. Such events of default include payment defaults to lenders under the 2016 Credit Agreement,
covenant defaults and other customary defaults.
We were in compliance with all of the credit facility's covenants, and there were no direct borrowings under the
credit facility during 2016. Under the commercial paper program, we may issue from time to time up to $2.5 billion
in commercial paper with maturities of no more than 270 days. The amount available to borrow under the credit
facility is reduced by the amount of any commercial paper outstanding. At December 31, 2016, we had no
outstanding borrowings under the commercial paper program.
If market conditions were to change and our revenue was reduced significantly or operating costs were to
increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our
credit rating. There are no ratings triggers that would accelerate the maturity of any borrowings under our
committed credit facility. However, a downgrade in our credit ratings could increase the cost of borrowings under
the credit facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would
seek alternative sources of funding, including borrowing under the credit facility.
We believe our current credit ratings would allow us to obtain interim financing over and above our existing
credit facility for any currently unforeseen significant needs.
Cash Requirements
In 2017, we believe cash on hand, cash flows from operating activities and the available credit facility will
provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual
obligations, fund capital expenditures and dividends, and support the development of our short-term and long-term
40
operating strategies. If necessary, we may issue commercial paper or other short-term debt to fund cash needs in
the U.S. in excess of the cash generated in the U.S.
Our capital expenditures can be adjusted and managed by us to match market demand and activity levels. In
light of the current market conditions, capital expenditures in 2017 will be made as appropriate at a rate that we
estimate would equal $450 million to $500 million on an annualized basis. The expenditures are expected to be
used primarily for normal, recurring items necessary to support our business. We also anticipate making income tax
payments in the range of $225 million to $275 million in 2017. For all defined benefit, defined contribution and other
postretirement plans, we expect to contribute between $205 million to $222 million to these plans in 2017. See
Note 14. "Employee Benefit Plans" of the Notes to Consolidated Financial Statements in Item 8 herein for further
discussion.
We anticipate paying dividends in the range of $140 million to $160 million in the first half of 2017 prior to the
expected Closing of the GE Transaction.
Contractual Obligations
In the table below, we set forth our contractual cash obligations as of December 31, 2016. Certain amounts
included in this table are based on our estimates and assumptions about these obligations, including their duration,
anticipated actions by third parties and other factors. The contractual cash obligations we will actually pay in future
periods may vary from those reflected in the table because the estimates and assumptions are subjective.
(In millions)
Total debt and capital lease obligations (1)
Estimated interest payments (2)
Operating leases (3)
Purchase obligations (4)
Liabilities for uncertain income tax positions (5)
Other long-term liabilities
Total (6)
Payments Due by Period
Total
Less Than
1 Year
2 - 3
Years
4 - 5
Years
More Than
5 Years
$
3,038 $
132 $
778 $
538 $
1,953
344
286
351
164
168
118
102
216
34
269
106
81
68
42
216
48
66
32
14
1,590
1,300
72
37
35
74
$
6,136 $
770 $
1,344 $
914 $
3,108
(1) Amounts represent the expected cash payments for the principal amounts related to our debt, including
capital lease obligations. Amounts for debt do not include any unamortized discounts or deferred issuance
costs. Expected cash payments for interest are excluded from these amounts.
(2) Amounts represent the expected cash payments for interest on our long-term debt and capital lease
obligations.
(3) Amounts represent the future minimum payments under noncancelable operating leases with initial or
remaining terms of one year or more. We enter into operating leases, some of which include renewal
options; however, we have excluded renewal options from the table above unless it is anticipated that we
will exercise such renewals.
(4) Purchase obligations include capital improvements as well as agreements to purchase goods or services
that are enforceable and legally binding and that specify all significant terms, including: fixed or minimum
quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the
transaction.
(5) The estimated income tax liabilities for uncertain tax positions will be settled as a result of expiring statutes,
audit activity, competent authority proceedings related to transfer pricing, or final decisions in matters that
are the subject of litigation in various taxing jurisdictions in which we operate. The timing of any particular
settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of
a statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the tax
liability would not result in a cash payment.
(6) Amounts do not include expected contributions to our pension and other postretirement defined benefit
plans of between $70 million to $80 million in 2017 as the majority of these contributions are amounts in
excess of minimum funding requirements and as such would not be considered a contractual obligation.
41
Off-Balance Sheet Arrangements
In the normal course of business with customers, vendors and others, we have entered into off-balance sheet
arrangements, such as surety bonds for performance, letters of credit and other bank issued guarantees, which
totaled approximately $1.0 billion at December 31, 2016. It is not practicable to estimate the fair value of these
financial instruments. None of the off-balance sheet arrangements either has, or is likely to have, a material effect
on our consolidated financial statements.
As of December 31, 2016, we had no material off-balance sheet financing arrangements other than normal
operating leases, as discussed above. As such, we are not materially exposed to any financing, liquidity, market or
credit risk that could arise if we had engaged in such financing arrangements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of our consolidated financial statements requires us to make estimates and judgments that
affect the reported amounts of assets, liabilities, revenue and expenses and related disclosures as well as
disclosures about any contingent assets and liabilities. We base these estimates and judgments on historical
experience and other assumptions and information that are believed to be reasonable under the circumstances.
Estimates and assumptions about future events and their effects are subject to uncertainty and, accordingly, these
estimates may change as new events occur, as more experience is acquired, as additional information is obtained
and as the business environment in which we operate changes.
We have defined a critical accounting estimate as one that is both important to the portrayal of either our
financial condition or results of operations and requires us to make difficult, subjective or complex judgments or
estimates about matters that are uncertain. The Audit/Ethics Committee of our Board of Directors has reviewed our
critical accounting estimates and the disclosure presented below. During the past three fiscal years, we have not
made any material changes in the methodology used to establish the critical accounting estimates, and we believe
that the following are the critical accounting estimates used in the preparation of our consolidated financial
statements. There are other items within our consolidated financial statements that require estimation and
judgment but they are not deemed critical as defined above.
Allowance for Doubtful Accounts
The determination of the collectability of amounts due from our customers requires us to make judgments and
estimates regarding our customers' ability to pay amounts due us in order to determine the amount of valuation
allowances required for doubtful accounts. We monitor our customers' payment history and current credit
worthiness to determine that collectability is reasonably assured. We also consider the overall business climate in
which our customers operate. Provisions for doubtful accounts are recorded based on the aging status of the
customer accounts or when it becomes evident that the customer will not make the required payments at either
contractual due dates or in the future. At December 31, 2016 and 2015, the allowance for doubtful accounts totaled
$509 million, or 18%, and $383 million, or 11%, of total gross accounts receivable, respectively. We believe that our
allowance for doubtful accounts is adequate to cover potential bad debt losses under current conditions; however,
uncertainties regarding changes in the financial condition of our customers, either adverse or positive, could impact
the amount and timing of any additional provisions for doubtful accounts that may be required. A five percent
change in the allowance for doubtful accounts would have had an impact on income (loss) before income taxes of
approximately $25 million in 2016.
Inventory Reserves
Inventory is a significant component of current assets and is stated at the lower of cost or net realizable value.
This requires us to record provisions and maintain reserves for excess, slow moving and obsolete inventory. To
determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates
of future product demand, market conditions, production requirements and technological developments. These
estimates and forecasts inherently include uncertainties and require us to make judgments regarding potential
future outcomes. At December 31, 2016 and 2015, inventory reserves totaled $188 million, or 9%, and $278
million, or 9%, of gross inventory, respectively. During 2016, we wrote off the carrying value of certain excess
inventory resulting in charges of $583 million. This amount was net of existing reserves of $272 million. We believe
42
that our reserves are adequate to properly value potential excess, slow moving and obsolete inventory under
current conditions. Significant or unanticipated changes to our estimates and forecasts could impact the amount
and timing of any additional provisions for excess, slow moving or obsolete inventory that may be required. A five
percent change in this inventory reserve balance would have had an impact on income (loss) before income taxes
of approximately $9 million in 2016.
Goodwill and Other Long-Lived Assets
The purchase price of acquired businesses is allocated to its identifiable assets and liabilities based upon
estimated fair values as of the acquisition date. Goodwill is the excess of the purchase price over the fair value of
tangible and identifiable intangible assets and liabilities acquired in a business acquisition. Our goodwill at
December 31, 2016 and 2015, totaled $4.08 billion and $6.07 billion, respectively. We perform an annual
impairment test of goodwill on a qualitative or quantitative basis for each of our reporting units as of October 1 of
each year, or more frequently when circumstances indicate an impairment may exist at the reporting unit level. Our
reporting units are the same as our five reportable segments. When performing the annual impairment test we
have the option of performing a qualitative or quantitative assessment to determine if an impairment has occurred.
If a qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its
carrying amount, then we would be required to perform a quantitative impairment test for goodwill.
Goodwill is tested for impairment using a two-step approach. In the first step, the fair value of each reporting
unit is determined and compared to the reporting unit's carrying value, including goodwill. If the fair value of a
reporting unit is less than its carrying value, the second step of the goodwill impairment test is performed to
measure the amount of impairment, if any. In the second step, the fair value of the reporting unit is allocated to the
assets and liabilities of the reporting unit as if it had been acquired in a business combination and the purchase
price was equivalent to the fair value of the reporting unit. The excess of the fair value of the reporting unit over the
amounts assigned to its assets and liabilities is referred to as the implied fair value of goodwill. The implied fair
value of the reporting unit's goodwill is then compared to the actual carrying value of goodwill. If the implied fair
value of goodwill is less than the carrying value of goodwill, an impairment loss is recognized for the difference.
In determining the carrying amount of reporting units, corporate and other assets and liabilities are allocated to
the extent that they relate to the operations of those reporting units. When necessary, we calculate the fair value of
a reporting unit using various valuation techniques, including a market approach, a comparable transactions
approach and discounted cash flow ("DCF") methodology. The market approach and comparable transactions
approach provide value indications for a company through a comparison with guideline public companies or
guideline transactions, respectively. Both entail selecting relevant financial information of the subject company, and
capitalizing those amounts using valuation multiples that are based on empirical market observations. The DCF
methodology includes, but is not limited to, assumptions regarding matters such as discount rates, anticipated
growth rates, expected profitability rates and the timing of expected future cash flows. Unanticipated changes,
including even small revisions, to these assumptions could result in a provision for impairment in a future period. In
addition, a decline in our stock price could result in an impairment. Given the nature of these evaluations and their
application to specific assets and time-frames, it is not possible to reasonably quantify the impact of changes in
these assumptions.
In the second quarter of 2016, as a result of the termination of the Merger Agreement with Halliburton, we
concluded it was necessary to conduct a quantitative assessment for potential goodwill impairment and determined
that goodwill of two of our reporting units was impaired. The quantitative assessment was calculated using a
combination of market and discounted cash flow approaches. As a result, we recorded an impairment charge of
$1.86 billion, of which $1.55 billion pertained to the North America reporting unit and $309 million pertained to
Industrial Services. See Note 12. "Goodwill and Intangible Assets" of the Notes to Consolidated Financial
Statements in Item 8 herein for further description. In addition to the quantitative assessment performed in the
second quarter of 2016, and consistent with our policy stated above, we also performed our annual goodwill
impairment test for all reporting units as of October 1, 2016. This assessment was performed on a qualitative basis,
and included our consideration of changes in industry and market conditions since the performance of our
quantitative analysis in the second quarter of 2016. Based on this assessment, we determined no additional
impairment of goodwill was necessary in the fourth quarter of 2016. In 2015 and 2014, we performed a qualitative
assessment for our annual goodwill impairment test and determined no impairments of goodwill were necessary in
2015 or 2014.
43
Long-lived assets, which include property and equipment, intangible assets other than goodwill, and certain
other assets, comprise a significant amount of our total assets. We review the carrying values of these assets for
impairment periodically, and at least annually for certain intangible assets or whenever events or changes in
circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the
period in which it is determined that the carrying amount is not recoverable. This requires us to make judgments
regarding long-term forecasts of future revenue and costs and cash flows related to the assets subject to review.
These forecasts are uncertain in that they require assumptions about demand for our products and services, future
market conditions and technological developments. See Note 4. "Impairment and Restructuring Charges" of the
Notes to Consolidated Financial Statements in Item 8 herein for further discussion of impairment of certain property
and equipment and intangible assets recorded in 2016 and 2015.
Income Taxes
The liability method is used for determining our income tax provisions, under which current and deferred tax
liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts
of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in
effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax
assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In
determining the need for valuation allowances, we have considered and made judgments and estimates regarding
estimated future taxable income and ongoing prudent and feasible tax planning strategies. These estimates and
judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to
adjust the valuation allowances for our deferred tax assets. Historically, changes to valuation allowances have been
caused by major changes in the business cycle in certain countries and changes in local country law. The ultimate
realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing
jurisdictions.
We conduct business in more than 80 countries under many legal forms. As a result, we are subject to the
jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among
these governments. Our operations in these different jurisdictions are taxed on various bases, including actual
income before taxes, deemed profits (which are generally determined using a percentage of revenue rather than
profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the
interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant
future events such as the amount, timing and character of deductions, permissible revenue recognition methods
under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations,
agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each
taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.
Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we
conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities
or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary
interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty;
accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. The
resulting change to our tax liability, if any, is dependent on numerous factors including, among others, the amount
and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to
negotiate a fair settlement through an administrative process; the impartiality of the local courts; the number of
countries in which we do business; and the potential for changes in the tax paid to one country to either produce, or
fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and
assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past
experience is only a guide, and the potential exists that the tax resulting from the resolution of current and potential
future tax controversies may differ materially from the amount accrued.
In addition to the aforementioned assessments that have been received from various tax authorities, we also
provide for taxes for uncertain tax positions where formal assessments have not been received. The determination
of these liabilities requires the use of estimates and assumptions regarding future events. Once established, we
adjust these amounts only when more information is available or when a future event occurs necessitating a change
to the reserves such as changes in the facts or law, judicial decisions regarding the application of existing law or a
favorable audit outcome. We believe that the resolution of tax matters will not have a material effect on the
44
consolidated financial condition of the Company, although a resolution could have a material impact on our
consolidated statements of income (loss) for a particular period and on our effective tax rate for any period in which
such resolution occurs.
Pensions and Postretirement Benefit Obligations
Pensions and postretirement benefit obligations and the related expenses are calculated using actuarial models
and methods. This involves the use of two critical assumptions, the discount rate and the expected rate of return on
assets, both of which are important elements in determining pension expense and in measuring plan liabilities. We
evaluate these critical assumptions at least annually, and as necessary, we utilize third-party actuarial firms to assist
us. Although considered less critical, other assumptions used in determining benefit obligations and related
expenses, such as demographic factors like retirement age, mortality and turnover, are also evaluated periodically
and are updated to reflect our actual and expected experience.
The discount rate enables us to determine expected future cash flows at a present value on the measurement
date. The development of the discount rate for our largest plans was based on a bond matching model whereby the
cash flows underlying the projected benefit obligation are matched against a yield curve constructed from a bond
portfolio of high-quality, fixed-income securities. Use of a lower discount rate would increase the present value of
benefit obligations and increase pension expense. We used a weighted average discount rate of 3.9% in 2016,
3.6% in 2015 and 4.5% in 2014 to determine pension expense. A 50 basis point reduction in the weighted average
discount rate would have increased pension expense of our principal pension plans by approximately $1 million in
2016.
To determine the expected rate of return on plan assets, we consider the current and target asset allocations,
as well as historical and expected future returns on various categories of plan assets. A lower rate of return would
decrease plan assets which results in higher pension expense. We assumed a weighted average expected rate of
return on our plan assets of 5.9% in 2016, 6.8% in 2015 and 6.7% in 2014. A 50 basis point reduction in the
weighted average expected rate of return on assets of our principal pension plans would have increased pension
expense by approximately $6 million in 2016.
New Accounting Standards
See Note 1. "Summary of Significant Accounting Policies" of the Notes to Consolidated Financial Statements in
Item 8 herein for further discussion of accounting standards adopted and to be adopted.
RELATED PARTY TRANSACTIONS
There were no significant related party transactions during the three years ended December 31, 2016.
FORWARD-LOOKING STATEMENTS
This Form 10-K, including MD&A and certain statements in the Notes to Consolidated Financial Statements,
contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Exchange Act of 1934, as amended, (each a "forward-looking statement"). The words
"anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "probable," "project," "forecasts," "predict,"
"outlook," "aim," "will," "could," "should," "would," "potential," "may," "likely" and similar expressions, and the
negative thereof, are intended to identify forward-looking statements. Our forward-looking statements are based on
assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not
include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other
transaction that could occur, including the pending Merger with GE. We undertake no obligation to publicly update
or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in
revenue, pricing, capital spending, profitability, strategies for our operations, impact of any common stock
repurchases, oil and natural gas market conditions, the business plans of our customers, market share and contract
terms, costs and availability of resources, legal, economic and regulatory conditions, and environmental matters are
only our forecasts regarding these matters.
45
All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ
materially from the results expected. Although it is not possible to identify all risk factors, these risks and
uncertainties include the factors and the timing of any of those factors identified in this annual report under Item 1A.
Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
and those set forth from time to time in our filings with the SEC. These documents are available through our
website or through the SEC's Electronic Data Gathering and Analysis Retrieval (EDGAR) system at http://
www.sec.gov. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-
looking statements. These forward-looking statements speak only as of the date of this annual report, or if earlier,
as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-
looking statements unless required by securities law.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to certain market risks that are inherent in our financial instruments and arise from changes in
interest rates and foreign currency exchange rates. We may enter into derivative financial instrument transactions
to manage or reduce market risk but do not enter into derivative financial instrument transactions for speculative
purposes. A discussion of our primary market risk exposure in financial instruments is presented below.
INTEREST RATE RISK
We have debt in fixed and floating rate instruments. We are subject to interest rate risk on our debt and
investment portfolio. We maintain an interest rate risk management strategy which primarily uses a mix of fixed and
variable rate debt that is intended to mitigate the risk exposure to changes in interest rates in the aggregate. We
may use interest rate swaps to manage the economic effect of fixed rate obligations associated with certain debt.
There were no outstanding interest rate swap agreements as of December 31, 2016 or 2015. The following table
sets forth our fixed rate long-term debt and the related weighted average interest rates by expected maturity dates.
(In millions)
As of December 31, 2016
Long-term debt (1) (2)
2017
2018
2019
2020
2021
Thereafter Total (3)
$ — $ 751
$
27
$
12
$ 526
$
1,590
$2,906
Weighted average interest rates
—%
7.39%
6.45%
5.03%
3.43%
5.84% 5.86%
As of December 31, 2015
Long-term debt (1) (2)
$
24
$ 1,022
$
22
$
12
$ 761
$
2,077
$3,918
Weighted average interest rates
7.77%
7.28%
5.94%
5.03%
3.40%
5.84% 5.79%
(1) Amounts do not include any unamortized discounts, premiums or deferred issuance costs on our fixed rate
long-term debt.
(2) Fair market value of our fixed rate long-term debt was $3.23 billion at December 31, 2016 and $4.17 billion
at December 31, 2015.
(3) Amounts represent the principal value of our long-term debt outstanding and related weighted average
interest rates at the end of the respective period.
FOREIGN CURRENCY EXCHANGE RISK
We conduct our operations around the world in a number of different currencies, and we are exposed to market
risks resulting from fluctuations in foreign currency exchange rates. Many of our significant foreign subsidiaries
have designated the local currency as their functional currency. As such, future earnings are subject to change due
to fluctuations in foreign currency exchange rates when transactions are denominated in currencies other than our
functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our
objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability
position in a currency other than the functional currency.
At December 31, 2016 and 2015, we had outstanding foreign currency forward contracts with notional amounts
aggregating $271 million and $499 million, respectively, to hedge exposure to currency fluctuations in various
foreign currencies. These contracts are either undesignated hedging instruments or designated and qualify as fair
value hedging instruments. The notional amounts of our foreign currency forward contracts do not generally
46
represent amounts exchanged by the parties, and thus are not a measure of the cash requirements related to these
contracts or of any possible loss exposure. The amounts actually exchanged are calculated by reference to the
notional amounts and by other terms of the derivative contracts, such as exchange rates. Based on quoted market
prices as of December 31, 2016 and 2015 for contracts with similar terms and maturity dates, we recorded a gain of
$1 million and a loss of $1 million, respectively, to adjust these foreign currency forward contracts to their fair market
value. These gains and losses offset designated foreign currency exchange gains and losses resulting from the
underlying exposures and are included in MG&A expenses in the consolidated statements of income (loss).
47
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over our financial
reporting, as such term is defined in Exchange Act Rules 13a-15(f). Our 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.
Under the supervision and with the participation of our management, including our principal executive officer
and principal financial officer, we assessed the effectiveness of our internal control over financial reporting based on
the 2013 framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on our assessment, our principal executive officer and principal
financial officer concluded that our internal control over financial reporting was effective as of December 31, 2016.
This conclusion is based on the recognition that there are inherent limitations in all systems of internal control.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. 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.
Deloitte & Touche LLP, the Company's independent registered public accounting firm, has issued an attestation
report on the effectiveness of the Company's internal control over financial reporting.
/s/ MARTIN S. CRAIGHEAD
Martin S. Craighead
Chairman and
Chief Executive Officer
/s/ KIMBERLY A. ROSS
Kimberly A. Ross
Senior Vice President and
Chief Financial Officer
/s/ KELLY C. JANZEN
Kelly C. Janzen
Vice President, Controller and
Chief Accounting Officer
Houston, Texas
February 7, 2017
48
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas
We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and subsidiaries (the
"Company") as of December 31, 2016 and 2015, and the related consolidated statements of income (loss), comprehensive
income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. Our
audits also included financial statement schedule II, valuation and qualifying accounts, listed in the Index at Item 15. We
also have audited the Company's internal control over financial reporting as of December 31, 2016, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company's management is responsible for these financial statements and financial statement
schedule, 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 these financial statements and financial statement
schedule and an opinion on the Company's internal control over financial reporting 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 and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of
internal control over financial reporting included obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also included performing such other procedures as we considered
necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the
company's principal executive and principal financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements due to error or fraud may not be prevented or detected
on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to
future periods are subject to the risk that the 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, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of Baker Hughes Incorporated and subsidiaries as of December 31, 2016 and 2015, and the results of
their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with
accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 7, 2017
49
BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(In millions, except per share amounts)
Revenue:
Sales
Services
Total revenue
Costs and expenses:
Cost of sales
Cost of services
Research and engineering
Marketing, general and administrative
Impairment and restructuring charges
Goodwill impairment
Merger and related costs
Merger termination fee
Total costs and expenses
Operating (loss) income
Loss on sale of business interest
Loss on early extinguishment of debt
Interest expense, net
(Loss) income before income taxes
Income tax (provision) benefit
Net (loss) income
Net (income) loss attributable to noncontrolling interests
Year Ended December 31,
2016
2015
2014
$ 3,870
$ 5,649
$ 8,056
5,971
9,841
3,722
6,251
384
815
1,735
1,858
199
(3,500)
11,464
(1,623)
(97)
(142)
(178)
(2,040)
(696)
(2,736)
(2)
10,093
15,742
4,833
9,582
466
969
1,993
—
295
—
18,138
(2,396)
—
—
(217)
(2,613)
639
(1,974)
7
16,495
24,551
6,294
13,452
613
1,333
—
—
—
—
21,692
2,859
—
—
(232)
2,627
(896)
1,731
(12)
Net (loss) income attributable to Baker Hughes
$ (2,738)
$ (1,967)
$ 1,719
Basic (loss) earnings per share attributable to Baker Hughes
$ (6.31)
$ (4.49)
Diluted (loss) earnings per share attributable to Baker Hughes
$ (6.31)
$ (4.49)
$
$
3.93
3.92
See Notes to Consolidated Financial Statements
50
BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In millions)
Net (loss) income
Other comprehensive (loss) income:
Foreign currency translation adjustments
Pension and other postretirement benefits, net of tax
Other comprehensive loss
Comprehensive (loss) income
Year Ended December 31,
2016
$ (2,736)
2015
$ (1,974)
2014
$ 1,731
(5)
(23)
(28)
(241)
(15)
(256)
(2,764)
(2,230)
(216)
(29)
(245)
1,486
(12)
Comprehensive (income) loss attributable to noncontrolling interests
(2)
7
Comprehensive (loss) income attributable to Baker Hughes
$ (2,766)
$ (2,223)
$ 1,474
See Notes to Consolidated Financial Statements
51
BAKER HUGHES INCORPORATED
CONSOLIDATED BALANCE SHEETS
(In millions, except par value)
Current Assets:
Cash and cash equivalents
ASSETS
Accounts receivable - less allowance for doubtful accounts
(2016 - $509; 2015 - $383)
Inventories, net
Other current assets
Total current assets
Property, plant and equipment - less accumulated depreciation
(2016 - $6,567; 2015 - $7,378)
Goodwill
Intangible assets, net
Other assets
Total assets
Current Liabilities:
Accounts payable
LIABILITIES AND EQUITY
Short-term debt and current portion of long-term debt
Accrued employee compensation
Income taxes payable
Other accrued liabilities
Total current liabilities
Long-term debt
Deferred income taxes and other tax liabilities
Liabilities for pensions and other postretirement benefits
Other liabilities
Commitments and contingencies
Equity:
Common stock, one dollar par value
(shares authorized - 750; issued and outstanding: 2016 - 424; 2015 - 437)
Capital in excess of par value
Retained earnings
Accumulated other comprehensive loss
Treasury stock
Baker Hughes stockholders' equity
Noncontrolling interests
Total equity
Total liabilities and equity
December 31,
2016
2015
$
4,572
$
2,324
2,251
1,809
535
9,167
4,271
4,084
318
1,194
19,034
1,027
132
566
78
501
2,304
2,886
328
626
153
425
6,708
6,583
(1,033)
(27)
12,656
81
12,737
19,034
$
$
$
3,217
2,917
810
9,268
6,693
6,070
583
1,466
24,080
1,409
151
690
55
470
2,775
3,890
252
646
135
437
7,261
9,614
(1,005)
(9)
16,298
84
16,382
24,080
$
$
$
See Notes to Consolidated Financial Statements
52
BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(In millions, except per share amounts)
Capital in
Excess
of Par
Value
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Treasury
Stock
Non-
controlling
Interests
Total
Balance at December 31, 2013
$
438
$ 7,341
$ 10,438
$
(504) $
— $
199
$17,912
Baker Hughes Stockholders' Equity
Comprehensive income:
Net income
Other comprehensive loss
Activity related to stock plans
Repurchase and retirement of common
stock
Stock-based compensation cost
Cash dividends ($0.64 per share)
Net activity related to noncontrolling
interests
1,719
12
1,731
(245)
5
(9)
200
(591)
122
(10)
(279)
(245)
205
(600)
122
(279)
(106)
(116)
Balance at December 31, 2014
$
434
$ 7,062
$ 11,878
$
(749) $
— $
105
$18,730
Comprehensive income:
Net loss
Other comprehensive loss
Activity related to stock plans
Stock-based compensation cost
Cash dividends ($0.68 per share)
Net activity related to noncontrolling
interests
(1,967)
(7)
(1,974)
3
101
120
(22)
(297)
(256)
(9)
(256)
95
120
(297)
(14)
(36)
Balance at December 31, 2015
$
437
$ 7,261
$ 9,614
$
(1,005) $
(9) $
84
$16,382
Comprehensive income:
Net loss
Other comprehensive loss
Activity related to stock plans
4
69
Repurchase and retirement of common
stock
Stock-based compensation cost
Cash dividends ($0.68 per share)
Net activity related to noncontrolling
interests
(16)
(747)
125
(293)
(2,738)
2
(2,736)
(28)
(18)
(28)
55
(763)
125
(293)
(5)
(5)
Balance at December 31, 2016
$
425
$ 6,708
$ 6,583
$
(1,033) $
(27) $
81
$12,737
See Notes to Consolidated Financial Statements
53
BAKER HUGHES INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2015
2014
2016
$
(2,736)
$
(1,974)
$
1,731
(In millions)
Cash flows from operating activities:
Net (loss) income
Adjustments to reconcile net (loss) income to net cash flows from operating
activities:
Depreciation and amortization
Impairment of assets
Goodwill impairment
Inventory write-down
Loss on early extinguishment of debt
Provision (benefit) for deferred income taxes
Gain on disposal of assets
Provision for doubtful accounts
Provision for excess and obsolete inventory
Other noncash items
Changes in operating assets and liabilities:
Accounts receivable
Inventories
Other current assets
Accounts payable
Income taxes payable
Other assets and liabilities, net
Net cash flows provided by operating activities
Cash flows from investing activities:
Expenditures for capital assets
Proceeds from disposal of assets
Proceeds from maturities of investment securities
Purchase of investment securities
Net proceeds from sale of business interest
Acquisition of businesses, net of cash acquired
Other investing items, net
Net cash flows provided by (used in) investing activities
Cash flows from financing activities:
Net repayments of commercial paper borrowings and other debt with three
months or less original maturity
Repayment of short-term debt with greater than three months original maturity
Proceeds of short-term debt with greater than three months original maturity
Repayment of long-term debt
Repurchase of common stock
Proceeds from issuance of common stock
Dividends paid
Other financing items, net
Net cash flows used in financing activities
Effect of foreign exchange rate changes on cash and cash equivalents
Increase in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental cash flows disclosures:
Income taxes paid, net of refunds
Interest paid
Supplemental disclosure of noncash investing activities:
Capital expenditures included in accounts payable
$
$
$
$
See Notes to Consolidated Financial Statements
54
1,166
1,271
1,858
583
142
349
(109)
188
181
222
762
293
441
(360)
18
(40)
4,229
(332)
283
453
(349)
142
(14)
20
203
(29)
(100)
69
(1,135)
(763)
91
(293)
(25)
(2,185)
1
2,248
2,324
4,572
(74)
217
33
$
$
$
$
1,742
1,436
—
194
—
(809)
(157)
193
195
120
1,943
703
61
(1,349)
(305)
(197)
1,796
(965)
388
—
(310)
—
—
(18)
(905)
(53)
(293)
301
—
—
116
(297)
(56)
(282)
(25)
584
1,740
2,324
483
242
44
$
$
$
$
1,814
—
—
—
—
(70)
(297)
102
37
122
(524)
(296)
23
291
90
(70)
2,953
(1,791)
437
—
—
—
(314)
9
(1,659)
(216)
(217)
185
—
(600)
216
(279)
(28)
(939)
(14)
341
1,399
1,740
881
250
171
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Baker Hughes Incorporated ("Baker Hughes," "Company," "we," "our," or "us,") is a leading supplier of oilfield
services, products, technology and systems used in the worldwide oil and natural gas industry. We also provide
products and services for other businesses including downstream chemicals, and process and pipeline services.
Basis of Presentation
Our consolidated financial statements are prepared in conformity with United States generally accepted
accounting principles ("GAAP"). The consolidated financial statements include the accounts of Baker Hughes and
all of our subsidiaries where we exercise control. For investments in subsidiaries that are not wholly-owned, but
where we exercise control, the equity held by the minority owners and their portions of net income (loss) are
reflected as noncontrolling interests. Investments over which we have the ability to exercise significant influence
over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity
method of accounting. Intercompany accounts and transactions have been eliminated in consolidation. In the
Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in millions of dollars
and shares, respectively, unless otherwise indicated.
Beginning in 2016, all merger and related costs are presented as a separate line item in the consolidated
statements of income (loss). Prior year merger and related costs were reclassified to conform to the current year
presentation. See Note. 2 "Halliburton Merger Agreement" and Note 3. "General Electric Transaction Agreement"
for further information.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and
judgments that affect the reported amounts of assets and liabilities, disclosure of any contingent assets or liabilities
at the date of the financial statements and the reported amounts of revenue and expenses during the reporting
period. We base our estimates and judgments on historical experience and on various other assumptions and
information that are believed to be reasonable under the circumstances. Estimates and assumptions about future
events and their effects cannot be perceived with certainty, and accordingly, these estimates may change as new
events occur, as more experience is acquired, as additional information is obtained and as our operating
environment changes. While we believe that the estimates and assumptions used in the preparation of the
consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are
used for, but are not limited to, determining the following: allowance for doubtful accounts and inventory valuation
reserves; recoverability of long-lived assets; useful lives used in depreciation and amortization; income taxes and
related valuation allowances; accruals for contingencies; actuarial assumptions to determine costs and liabilities
related to employee benefit plans; stock-based compensation expense and the fair value of assets acquired and
liabilities assumed in acquisitions.
Revenue Recognition
Our products and services are sold based upon purchase orders, contracts or other agreements with the
customer that include fixed or determinable prices and that do not include right of return or other similar provisions
or other significant post-delivery obligations. We recognize revenue for products sold when title and risk of loss
passes, when collectability is reasonably assured and when there are no further significant obligations for future
performance. Provisions for estimated warranty returns or similar arrangements are made at the time the related
revenue is recognized. Revenue for services is recognized as the services are rendered and when collectability is
reasonably assured. Rates for services are typically priced on a per day, per distance drilled, per man hour or
similar basis. In certain situations, revenue is generated from transactions that may include multiple products and
services under one contract or agreement and which may be delivered to the customer over an extended period of
time. Revenue from these arrangements is recognized in accordance with the above criteria and as each item or
service is delivered based on their relative fair value.
55
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
Research and Engineering
Research and engineering expenses are expensed as incurred and include costs associated with the research
and development of new products and services and costs associated with sustaining engineering of existing
products and services. Costs for research and development of new products and services were $271 million, $330
million and $430 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Cash and Cash Equivalents
Cash equivalents include only those investments with an original maturity of three months or less. We maintain
cash deposits with major financial institutions. At times, such amounts may exceed federally insured limits. We
monitor the credit ratings and our concentration of risk with these financial institutions on a continuing basis to
safeguard our cash deposits.
Allowance for Doubtful Accounts
We establish an allowance for doubtful accounts based on various factors including the payment history and
financial condition of our customers and the economic environment. Provisions for doubtful accounts are recorded
based on the aging status of the customer accounts or when it becomes evident that the customer will not make the
required payments at either contractual due dates or in the future. Provision for doubtful accounts recorded in cost
of sales was $188 million, $193 million and $102 million for the years ended December 31, 2016, 2015 and 2014,
respectively.
Concentration of Credit Risk
We grant credit to our customers who primarily operate in the oil and natural gas industry. Although this
concentration affects our overall exposure to credit risk, our trade receivables are spread over a diverse group of
customers across many countries, which mitigates this risk. We perform periodic credit evaluations of our
customers' financial condition, including monitoring our customers' payment history and current credit worthiness to
manage this risk. We do not generally require collateral in support of our trade receivables, but we may require
payment in advance or security in the form of a letter of credit or bank guarantee. During 2016, 2015 and 2014, no
individual customer accounted for more than 10% of our consolidated revenue.
Inventories
As of January 1, 2016, inventories are stated at the lower of cost or net realizable value as a result of the
adoption of Accounting Standard Update 2015-11, which is described below. Prior to our adoption of this standard,
inventories were stated at the lower of cost or market. Cost is determined using the average cost method, and
includes the cost of materials, labor and manufacturing overhead. Net realizable value is the estimated selling price
in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. As
necessary, we record provisions and maintain reserves for excess, slow moving and obsolete inventory. To
determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates
of future product demand, market conditions, production requirements and technological developments.
Property, Plant and Equipment and Accumulated Depreciation
Property, plant and equipment ("PP&E") is stated at cost less accumulated depreciation, which is generally
provided by using the straight-line method over the estimated useful lives of the individual assets. Significant
improvements and betterments are capitalized if they extend the useful life of the asset. We manufacture a
substantial portion of our tools and equipment and the cost of these items, which includes direct and indirect
manufacturing costs, is capitalized and carried in inventory until it is completed. When complete, the cost is
reflected in capital expenditures and is classified as machinery, equipment and other in PP&E. Maintenance and
repairs are charged to expense as incurred. Upon sale or other disposition, the applicable amounts of asset cost
and accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from
disposal, is charged or credited to income. The capitalized costs of computer software developed or purchased for
internal use are classified in machinery, equipment and other.
56
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
Goodwill, Intangible Assets and Amortization
Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable
intangible assets and liabilities recognized in acquisitions. Goodwill and intangible assets with indefinite lives are
not amortized. Intangible assets with finite useful lives, all of which are amortized on a basis that reflects the
pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line
basis over the asset's estimated useful life.
Impairment of Goodwill, PP&E, Intangibles and Other Long-lived Assets
We perform an annual impairment test of goodwill for each of our reporting units as of October 1, or more
frequently if an event occurs or circumstances change to indicate that it is more likely than not that an impairment
may exist. Our reporting units are based on our organizational and reporting structure and are the same as our five
reportable segments. Corporate and other assets and liabilities are allocated to the reporting units to the extent that
they relate to the operations of those reporting units in determining their carrying amount. When performing the
annual impairment test we have the option of first performing a qualitative assessment to determine the existence of
events and circumstances that would lead to a determination that it is more likely than not that the fair value of a
reporting unit is less than its carrying amount. If such a conclusion is reached, we would then be required to
perform a quantitative impairment assessment of goodwill. However, if the assessment leads to a determination
that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then no further
assessments are required. A quantitative assessment for the determination of impairment is made by comparing
the carrying amount of each reporting unit with its fair value, which is generally calculated using a combination of
market, comparable transaction and discounted cash flow approaches. See Note 12. "Goodwill and Intangible
Assets" for further information about the goodwill impairment recorded in 2016.
We review PP&E, intangible assets and certain other long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable and at least annually for certain
intangible assets. The determination of recoverability is made based upon the estimated undiscounted future net
cash flows. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a
discounted cash flow analysis, with the carrying value of the related assets.
In 2015 and 2014, we performed a qualitative assessment for our annual goodwill impairment test and
determined that it was more likely than not that the fair value of each of our reporting units exceeded its carrying
amount at that time. As such, no impairments of goodwill were recorded for the years ended December 31, 2015 or
2014.
Income Taxes
We use the liability method in determining our provision and liabilities for our income taxes, under which current
and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Deferred tax
liabilities and assets, which are computed on the estimated income tax effect of temporary differences between
financial and tax bases in assets and liabilities, are determined using the tax rate expected to be in effect when
taxes are actually paid or recovered. A valuation allowance to reduce deferred tax assets is established when it is
more likely than not that some portion or all of the deferred tax assets will not be realized.
We currently intend to indefinitely reinvest certain earnings of our foreign subsidiaries in operations outside the
U.S., and accordingly, we have not provided for U.S. income taxes on such earnings. We do provide for the U.S.
and additional non-U.S. taxes on earnings anticipated to be repatriated from our non-U.S. subsidiaries.
Our tax filings for various periods are subject to audit by tax authorities in most jurisdictions where we conduct
business. These audits may result in assessments of additional taxes that are resolved with the authorities or
through the courts. We have provided for the amounts we believe will ultimately result from these proceedings. In
addition to the assessments that have been received from various tax authorities, we also provide for taxes for
uncertain tax positions where formal assessments have not been received. We classify interest and penalties
related to uncertain tax positions as income taxes in our financial statements.
57
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
Environmental Matters
Estimated remediation costs are accrued using currently available facts, existing environmental permits,
technology and enacted laws and regulations. Our cost estimates are developed based on internal evaluations and
are not discounted. Accruals are recorded when it is probable that we will be obligated to pay for environmental site
evaluation, remediation or related activities, and such costs can be reasonably estimated. As additional information
becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental compliance
costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal are
expensed as incurred. Where we have been identified as a potentially responsible party in a U.S. federal or state
Comprehensive Environmental Response, Compensation and Liability Act ("Superfund") site, we accrue our share
of the estimated remediation costs of the site. This share is based on the ratio of the estimated volume of waste we
contributed to the site to the total volume of waste disposed at the site.
Foreign Currency
A number of our significant foreign subsidiaries have designated the local currency as their functional currency
and, as such, gains and losses resulting from balance sheet translation of foreign operations are included as a
separate component of accumulated other comprehensive loss within stockholders' equity. Gains and losses from
foreign currency transactions, such as those resulting from the settlement of receivables or payables in the non-
functional currency, are included in marketing, general and administrative ("MG&A") expenses in the consolidated
statements of income (loss) as incurred. For those foreign subsidiaries that have designated the U.S. Dollar
("USD") as the functional currency, monetary assets and liabilities are remeasured at period-end exchange rates,
and nonmonetary items are remeasured at historical exchange rates. Gains and losses resulting from this balance
sheet remeasurement are also included in MG&A expenses as incurred.
Fair Value Measurement
We define fair value as the price that would be received from selling an asset or paid to transfer a liability in an
orderly transaction between market participants at a measurement date. We apply the following fair value
hierarchy, which prioritizes the inputs used to measure fair value into three levels and bases the categorization
within the hierarchy upon the lowest level of input that is available and significant to the fair value measurement:
•
•
•
Level One: The use of quoted prices in active markets for identical financial instruments.
Level Two: The use of quoted prices for similar instruments in active markets or quoted prices for identical
or similar instruments in markets that are not active or other inputs that are observable in the market or can
be corroborated by observable market data.
Level Three: The use of significantly unobservable inputs that typically require the use of management's
estimates of assumptions that market participants would use in pricing.
Financial Instruments
Our financial instruments include cash and cash equivalents, accounts receivable, investments, accounts
payable, short and long-term debt, and derivative financial instruments. Except for long-term debt, the estimated
fair value of our financial instruments at December 31, 2016 and 2015 approximates their carrying value as
reflected in our consolidated balance sheets. For further information on the fair value of our debt, see Note 13.
"Indebtedness."
We monitor our exposure to various business risks including commodity prices, foreign currency exchange
rates and interest rates and regularly use derivative financial instruments to manage these risks. Our policies do
not permit the use of derivative financial instruments for speculative purposes. At the inception of a new derivative,
we designate the derivative as a hedge or we determine the derivative to be undesignated as a hedging instrument.
We document the relationships between the hedging instruments and the hedged items, as well as our risk
management objectives and strategy for undertaking various hedge transactions.
We have a program that utilizes foreign currency forward contracts to reduce the risks associated with the
effects of certain foreign currency exposures. Under this program, our strategy is to have gains or losses on the
58
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
foreign currency forward contracts mitigate the foreign currency transaction and translation gains or losses to the
extent practical. These foreign currency exposures typically arise from changes in the value of assets and liabilities
which are denominated in currencies other than the functional currency. Our foreign currency forward contracts
generally settle in less than 180 days. We record all derivatives as of the end of our reporting period in our
consolidated balance sheet at fair value. We record the changes in fair value of the forward contracts in our
consolidated statements of income (loss) along with the change in fair value of the hedged item. Recognized gains
and losses on derivatives entered into to manage foreign currency exchange risk are included in MG&A expenses in
the consolidated statements of income (loss).
We had outstanding foreign currency forward contracts with notional amounts aggregating $271 million and
$499 million to hedge exposure to currency fluctuations in various foreign currencies at December 31, 2016 and
2015, respectively. Based on quoted market prices as of December 31, 2016 or 2015 for forward contracts with
similar terms and maturity dates, we recorded a gain of $1 million and a loss of $1 million, respectively, to adjust
these forward contracts to their fair market value.
New Accounting Standards Adopted
In July 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU")
No. 2015-11, Simplifying the Measurement of Inventory, which requires inventory measured using average cost
methods, which we utilize, to be subsequently measured at the lower of cost or net realizable value. Net realizable
value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of
completion, disposal and transportation. We elected to early adopt this guidance as of January 1, 2016 because we
believe this approach reduces the complexity in the subsequent measurement of our inventory. Previously,
inventory was required to be subsequently measured at the lower of cost or market with market defined as
replacement cost, net realizable value or net realizable value less a normal profit margin. The impact of adopting
this standard was immaterial to our financial statements. The guidance stipulates that the amendments in ASU
No.2015-11 shall be adopted on a prospective basis, therefore our adoption had no impact on prior reporting
periods.
New Accounting Standards To Be Adopted
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. The ASU will
supersede most of the existing revenue recognition requirements in U.S. GAAP and will require entities to recognize
revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for
transferring goods or services to a customer. The new standard also requires significantly expanded disclosures
regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of
revenue and cash flows arising from contracts with customers. The pronouncement is effective for annual reporting
periods beginning after December 15, 2017, including interim periods within that reporting period, and is to be
applied using a retrospective or modified retrospective approach. Early adoption is permitted. We are currently
evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and
results of operations. As part of our assessment work to-date, we have formed an implementation work team,
completed training of the new ASU's revenue recognition model and begun contract review and documentation.
In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, which
amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as
noncurrent on the balance sheet. The pronouncement is effective for annual reporting periods beginning after
December 15, 2016, and will be adopted prospectively. We have completed an evaluation of the pronouncement
and determined that the reclassification of deferred taxes will not be material to our consolidated financial
statements and related disclosures.
In February 2016, the FASB issued ASU No. 2016-02, Leases, a new standard on accounting for leases. The
ASU introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many
of the underlying principles of the new lessor model with those in the current accounting guidance as well as the
FASB's new revenue recognition standard. However, the ASU eliminates the use of bright-line tests in determining
lease classification as required in the current guidance. The ASU also requires additional qualitative disclosures
along with specific quantitative disclosures to better enable users of financial statements to assess the amount,
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements
timing, and uncertainty of cash flows arising from leases. The pronouncement is effective for annual reporting
periods beginning after December 15, 2018, including interim periods within that reporting period, using a modified
retrospective approach. Early adoption is permitted. We are currently evaluating the provisions of ASU 2016-02
and assessing the impact it will have on our consolidated financial statements and related disclosures. As part of
our assessment work to-date, we have formed an implementation work team, completed training of the new ASU's
lease model with the implementation team, and begun review and documentation.
In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment
Accounting. The standard provides a new requirement to record all of the tax effects related to share-based
payments at settlement (or expiration) through the income statement. This pronouncement is effective for annual
reporting periods beginning after December 15, 2016. We have completed an evaluation of the pronouncement and
determined that its impact upon adoption will not be material to our consolidated financial statements and related
disclosures.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit
Losses on Financial Instruments. The new standard amends the impairment model for trade receivables, net
investments in leases, debt securities, loans and certain other instruments to utilize an expected loss methodology
in place of the currently used incurred loss methodology. This pronouncement is effective for annual periods
beginning after December 15, 2019, including interim periods within those annual periods. Early adoption will be
permitted for annual periods beginning after December 15, 2018. We are currently evaluating the provisions of the
pronouncement and assessing the impact, if any, on our financial statements and related disclosures.
In August 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash
Payments. The standard addresses the classification and presentation of eight specific cash flow issues that
currently result in diverse practices. This pronouncement is effective for annual reporting periods beginning after
December 15, 2017. The amendments in this ASU should be applied using a retrospective approach. We have not
completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and
related disclosures, but the impact is not expected to be material.
In October 2016, the FASB issued ASU No. 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers
of Assets Other than Inventory. The standard removes the prohibition in ASC 740 against the immediate
recognition of the current and deferred income tax effects of intra-entity transfers of assets other than inventory.
This pronouncement is effective for annual reporting periods beginning after December 15, 2017. The amendments
in this ASU should be applied using a retrospective approach. We have not completed an evaluation of the impact
the pronouncement will have on our consolidated financial statements and related disclosures, but the impact is not
expected to be material.
NOTE 2. HALLIBURTON TERMINATED MERGER AGREEMENT
On November 16, 2014, Baker Hughes, Halliburton Company ("Halliburton") and a wholly owned subsidiary of
Halliburton ("Merger Sub"), entered into an Agreement and Plan of Merger (the "Merger Agreement"), under which
Halliburton would acquire all of the outstanding shares of Baker Hughes through a merger of Baker Hughes with
and into Merger Sub (the "Merger").
In accordance with the provisions of Section 9.1 of the Merger Agreement, Baker Hughes and Halliburton
agreed to terminate the Merger Agreement on April 30, 2016, as a result of the failure of the Merger to occur on or
before April 30, 2016 due to the inability to obtain certain specified antitrust related approvals. Halliburton paid $3.5
billion to Baker Hughes on May 4, 2016, representing the termination fee required to be paid pursuant to the Merger
Agreement.
Baker Hughes incurred costs related to the Merger of $180 million and $295 million during 2016 and 2015,
respectively, including costs under our retention program and obligations for minimum incentive compensation
costs, which, based on meeting eligibility criteria, have been treated as Merger and related costs.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 3. GENERAL ELECTRIC TRANSACTION AGREEMENT
On October 30, 2016, Baker Hughes, General Electric Company ("GE"), Bear Newco, Inc. ("Newco"), a
Delaware corporation and a direct wholly owned subsidiary of Baker Hughes, and Bear MergerSub, Inc. ("Merger
Sub"), a Delaware corporation and a direct wholly owned subsidiary of Newco, entered into a Transaction
Agreement and Plan of Merger (the "Transaction Agreement"), pursuant to which, among other things, (i) Merger
Sub will merge with and into Baker Hughes, with Baker Hughes as the surviving corporation (the "Surviving Entity")
and a direct wholly owned subsidiary of Newco, (ii) each outstanding share of the Baker Hughes' common stock will
be converted into the right to receive one share of Class A common stock, par value $0.0001 per share, of Newco
("Newco Class A Common Stock"), (iii) Newco will cause the Surviving Entity to be converted into a Delaware
limited liability company ("Newco LLC") and Newco will become the sole managing member of Newco LLC, (iv) GE
will (A) receive an approximate 62.5% membership interest in Newco LLC in exchange for contributing $7.4 billion
(less the Class B Purchase Price, as defined below) in cash and GE's oil and gas business ("GE O&G") to Newco
LLC, and (B) receive Class B common stock, par value $0.0001 per share, of Newco (the "Newco Class B Common
Stock"), representing approximately 62.5% of the voting power of the outstanding shares of common stock of
Newco, in exchange for contributing the par value thereof (the "Class B Purchase Price") to Newco and (v) Newco
will distribute as a special dividend an amount equal to $17.50 per share to the holders of record of the Newco
Class A Common Stock, which are the former Baker Hughes stockholders (collectively the " GE Transaction").
Newco will operate as a public company.
Immediately following the closing of the GE Transaction (the "Closing"), (i) (A) GE will hold 100% of the Newco
Class B Common Stock, which will represent approximately 62.5% of the voting power of the outstanding shares of
common stock of Newco, and (B) Baker Hughes' stockholders immediately prior to the Closing will hold 100% of the
Newco Class A Common Stock, which will represent approximately 37.5% of the voting power of the outstanding
shares of common stock of Newco, (ii) (A) GE will hold an approximate 62.5% membership interest in Newco LLC
and (B) Newco will hold an approximate 37.5% membership interest in Newco LLC and (iii) the membership
interests in Newco LLC, together with the Newco Class B Common Stock, will be exchangeable on a 1:1 basis for
Newco Class A Common Stock, subject to certain adjustments. The rights (including voting rights) of Newco Class
A Common Stock and Newco Class B Common Stock are identical; provided that Newco Class B Common Stock
has no economic rights. Effective from and following the Closing, Newco and its subsidiaries will operate under the
name "Baker Hughes, a GE Company."
Baker Hughes and GE each made customary representations, warranties and covenants in the Transaction
Agreement, including, among others, covenants by each of Baker Hughes and GE to, subject to certain exceptions,
conduct its business (in the case of Baker Hughes) or GE O&G (in the case of GE) in the ordinary course during the
interim period between the execution of the Transaction Agreement and the Closing. In particular, among other
restrictions and subject to certain exceptions, Baker Hughes agreed to generally refrain from acquiring new
businesses, incurring new indebtedness, repurchasing shares, issuing new common stock or equity awards (other
than equity awards granted to employees, officers and directors materially consistent with historical long-term
incentive awards granted), or entering into new material contracts or commitments outside the normal course of
business, without the consent of GE, during the period between the execution of the Transaction Agreement and the
consummation of the GE Transaction. With respect to equity awards granted after the Transaction Agreement to
officers and employees, such awards will not vest solely as a result of the GE Transaction but will be converted to
an equivalent Newco equity award. However, they will vest entirely if an officer or employee is terminated within
one year following the Closing of the GE Transaction.
Baker Hughes is permitted to pay regular quarterly cash dividends to its stockholders between signing and
Closing. GE O&G is permitted to pay dividends to GE between signing and Closing; provided that GE O&G is
required to have a minimum level of working capital at Closing.
The obligation of the parties to consummate the GE Transaction is subject to customary closing conditions,
including, among others, (i) the approval of holders of a majority of the outstanding shares of Baker Hughes
common stock; (ii) (A) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended; (B) the European Commission issuing a decision under the
Council Regulation (EC) No. 139/2004 of January 20, 2004 on the control of concentrations between undertakings
(published in the Official Journal of the European Union on January 29, 2004 at L 24/1) declaring the GE
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements
Transaction compatible with the common market, or, if the European Commission has adopted any decision under
Article 9 of such regulations to refer the GE Transaction in part to any Member State of the European Economic
Area, the European Commission issuing a decision declaring the part of the GE Transaction not so referred to that
Member State compatible with the common market and every Member State to which part of the Transaction has
been referred under Article 9 issuing a decision clearing the GE Transaction; and (C) the expiration or termination of
all other applicable waiting and other time periods under certain other regulatory and competition laws; (iii) the
absence of legal restraints and prohibitions; (iv) the effectiveness of the registration statement on Form S-4 to be
filed by Newco with the Securities and Exchange Commission and the approval of the listing on the New York Stock
Exchange of Newco Class A Common Stock to be issued in the GE Transaction; and (v) the completion in all
material respects of certain restructuring transactions in connection with the Transaction. The obligation of each
party to consummate the GE Transaction is also conditioned upon the other party's representations and warranties
being true and correct (subject to certain materiality exceptions) and the other party having performed in all material
respects its obligations under the Transaction Agreement. In addition, Baker Hughes' obligation to consummate the
Transaction is subject to the financial statement-related condition described below.
As promptly as reasonably practicable following December 31, 2016 (and in any event no later than April 15,
2017 or April 30, 2017 in the case of the September 30, 2016 audited financial statements), GE is required to
deliver to Baker Hughes certain audited financial statements of GE O&G, including those required to be included in
Newco's registration statement on Form S-4. If such audited financial statements differ from the unaudited financial
statements of GE O&G provided to Baker Hughes in a manner that is material to the intrinsic value of GE O&G in
an adverse manner, Baker Hughes may terminate the Transaction Agreement. In the event of such termination, GE
would be required to reimburse Baker Hughes for certain expenses, up to $40 million.
GE is required to take all actions necessary to obtain regulatory approvals (including agreeing to divestitures of
certain specified businesses and any businesses of which any such business forms a substantial part (the
"Specified Businesses")) unless the assets, businesses or product lines subject to such actions would account for
more than $200 million of revenue in 2015. The divestiture of the Specified Businesses will not be taken into
account for purposes of calculating the $200 million divestiture limit. Subject to certain exceptions, proceeds of any
divestitures would remain with GE O&G and be transferred to Newco LLC following the Closing of the Transaction.
Additionally, the Transaction Agreement provides for certain termination rights for each of Baker Hughes and
GE, including (i) GE's right to terminate the Transaction Agreement if Baker Hughes' board of directors changes its
recommendation that Baker Hughes' stockholders approve the Transaction Agreement; (ii) Baker Hughes' right to
terminate the Transaction Agreement, prior to obtaining the approval of its stockholders, to enter into a definitive
agreement providing for a superior proposal; and (iii) the right of each party to terminate the Transaction Agreement
if the GE Transaction has not been consummated by the "termination date" of January 30, 2018, subject to each
party's right to extend the termination date until April 30, 2018, if all closing conditions (other than receipt of certain
regulatory approvals) has been satisfied by January 30, 2018.
The Transaction Agreement provides for the payment by Baker Hughes to GE of a termination fee of $750
million if certain events described in the Transaction Agreement occur, including if Baker Hughes' board of directors
changes its recommendation that Baker Hughes' stockholders approve the Transaction Agreement.
Baker Hughes is also required to reimburse GE for certain expenses (up to $40 million) if the Transaction
Agreement is terminated because Baker Hughes' stockholders have not approved the Transaction Agreement upon
a vote taken thereon, and prior to the Baker Hughes stockholder meeting, a proposal for an alternative transaction
was publicly announced and not withdrawn. If, within twelve months after such termination, Baker Hughes enters
into an agreement providing for, or consummates, an alternative transaction with a third party, thereby triggering the
$750 million termination fee described above, that termination fee will be reduced by the amount of any expenses
previously reimbursed.
In the event the Transaction Agreement is terminated by (i) either party as a result of the failure of the GE
Transaction to occur on or before the termination date (as it may be extended) due to the failure to achieve certain
antitrust-related approvals if all closing conditions (other than receipt of antitrust and other specified regulatory
approvals and conditions that by their nature cannot be satisfied until the Closing but subject to such conditions
being capable of being satisfied if the Closing date were the date of termination) have been satisfied, (ii) either party
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Notes to Consolidated Financial Statements
as a result of any antitrust-related final, non-appealable order or injunction prohibiting the Closing, or (iii) Baker
Hughes, as a result of GE's material breach of its obligations to obtain regulatory approvals such that the antitrust-
related condition to closing is incapable of being satisfied, then in each case GE would be required to pay Baker
Hughes a termination fee of $1.3 billion.
Baker Hughes and GE expect the GE Transaction to close in mid-2017. However, Baker Hughes cannot predict
with certainty when, or if, the GE Transaction will be completed because completion of the GE Transaction is
subject to conditions beyond the control of Baker Hughes. Baker Hughes incurred costs of $19 million related to the
GE Transaction, which was recorded as Merger and related costs during the fourth quarter of 2016.
NOTE 4. IMPAIRMENT AND RESTRUCTURING CHARGES
IMPAIRMENT CHARGES
We conduct impairment tests on long-lived assets whenever events or changes in circumstances indicate that
the carrying value may not be recoverable based on estimated future cash flows. Although oil prices have risen
since the lows reached in February 2016 and rig counts have begun to stabilize, customer spending and activity
remained at low levels throughout 2016, resulting in lower demand for our products and services. We considered
our customers' constrained capital spending budgets for 2016 to be impairment indicators and accordingly
evaluated our long-lived assets for impairment.
As a result of our testing in 2016, certain machinery and equipment was written down to its estimated fair value,
resulting in impairment charges of $453 million. Additionally in 2016, certain intangible assets, comprised of
technology, customer relationships and trade names were written down to their estimated fair values, resulting in
impairment charges of $114 million. Total impairment charges of $567 million for 2016 are described by segment in
the table below. The estimated fair values for these assets were determined using discounted future cash flows.
The significant level 3 unobservable inputs used in the determination of the fair value of these assets were the
estimated future cash flows and the weighted average cost of capital ("WACC"). The WACC's used to discount
future cash flows for the impairments recognized in 2016 are included in the table below.
Impairment Charges
Net Carrying Value
Segments
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Industrial Services
Total
Machinery,
Equipment
and Other
Intangible
Assets
Total
Impairment
Charges
Machinery,
Equipment
and Other
Intangible
Assets
WACC
$
$
84 $
66
124
166
13
85 $
5
4
17
3
169 $
241 $
125
71
128
183
16
245
222
433
196
17
8
49
44
10.0%
16.0%
(1)
(1)
10.0%
453 $
114 $
567 $
1,337 $
243
(1) The WACC's used by region in 2016 were as follows: Europe - 10.5%; Africa - 19.5%; Russia/Caspian -
15.0%; Middle East - 14.0%; Asia Pacific - 13.5%.
As a result of our testing in 2015, certain machinery and equipment with a total carrying value of $1.64 billion
was written down to its estimated fair value, resulting in impairment charges of $1.05 billion. Additionally, certain
intangible assets, comprised primarily of customer relationships and trade names, with a total carrying value of
$178 million were written down to their estimated fair values, resulting in impairment charges of $116 million. Total
impairment charges for 2015 were $1.16 billion, the majority of which related to our pressure pumping business in
North America. The WACC used to discount future cash flows for the impairments recognized in North America was
9.8%.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements
RESTRUCTURING CHARGES
We recognize restructuring charges for costs associated with workforce reductions, contract terminations,
facility closures and impairments related to the permanent removal from service and disposal of excess machinery
and equipment. As a result of the downturn in the industry in 2015 and its impact on our business outlook, we took
actions to restructure and adjust our operations and cost structure to reflect current and expected activity levels to
the extent allowable under the Merger Agreement with Halliburton. Following the termination of the Merger
Agreement in the second quarter of 2016, to address ongoing industry challenges, we took additional actions to
reduce costs, simplify our organization, refine and rationalize our operating strategy and adjust our capacity to meet
expected levels of future demand. These actions necessitated workforce reductions, contract terminations, facility
closures and the permanent removal from service and disposal of excess machinery and equipment. As a result of
these restructuring activities, we recorded restructuring charges of $1.17 billion and $830 million in 2016 and 2015,
respectively. Depending on future market conditions and activity levels, further actions may be necessary to adjust
our operations, which may result in additional charges.
Our restructuring charges as summarized below as of December 31:
Restructuring Charges
Workforce reductions
Contract terminations
Impairment of buildings and improvements
Impairment of machinery and equipment
Total restructuring charges
2016
2015
$
$
272
192
214
490
1,168
$
$
436
121
82
191
830
Workforce reduction costs: During 2016 and 2015, we initiated workforce reductions resulting in the
combined elimination of approximately 26,200 positions worldwide. As a result of these workforce reductions, we
recorded a charge for severance expense of $272 million and $436 million during 2016 and 2015, respectively, net
of related employee benefit plan gains of $9 million and $10 million, respectively. The amount accrued for any
unpaid severance is based on our written severance policy for ongoing benefit arrangements or the country
mandated scheme and the positions being eliminated. In 2016 and 2015, we have made payments totaling $289
million and $365 million, respectively, relating to workforce reductions. We expect that substantially all of the
accrued severance remaining will be paid by the middle of 2017.
Contract termination costs: During 2016 and 2015, we incurred costs of $192 million and $121 million,
respectively, to terminate or restructure various contracts, primarily in North America. This includes the accrual for
costs to settle leases on closed facilities and certain equipment, and other estimated exit costs, and is net of
expected sublease income. This also includes costs to terminate or restructure certain take-or-pay supply contracts
related to the purchase of materials used in our pressure pumping operations in North America, including the write-
off of $14 million of prepayments made in 2014. In 2016 and 2015, we have made payments totaling $130 million
and $81 million, respectively, relating to contract termination costs. We expect that substantially all of the accrued
contract termination costs remaining will be paid by the end of 2017.
Impairment of buildings and improvements: During 2016 and 2015, we consolidated and closed certain
facilities, both owned and leased, and recorded related impairment charges of $214 million and $82 million,
respectively. In 2016, the total impairment of buildings and improvements reduced our segment assets as follows:
North America - $145 million; Latin America - $18 million; Europe/Africa/Russia Caspian - $41 million; Middle East/
Asia Pacific - $9 million; and Industrial Services - $1 million. In 2015, the impairment charges related to facilities
primarily in North America and Latin America. These facilities have been taken out of service and will be disposed.
Impairment of machinery and equipment: Following the termination of the Merger Agreement with
Halliburton in the second quarter of 2016, we evaluated our capacity and made adjustments to align our capacity to
expected future operational levels and strategy. These actions impacted all product lines and as a result, we
recognized an impairment loss of $490 million in 2016 relating to the cost to impair excess machinery and
equipment to its net realizable value. The total machinery and equipment impairments reduced our segment assets
as follows: North America - $203 million; Latin America - $80 million; Europe/Africa/Russia Caspian - $88 million;
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Notes to Consolidated Financial Statements
Middle East/Asia Pacific - $85 million; and Industrial Services - $34 million. In 2015, we exited or substantially
downsized our presence in select markets primarily in our pressure pumping product line in North America and Latin
America. As a result, we recognized $191 million of impairment losses to adjust the carrying value of certain
machinery and equipment to its fair value, net of costs to dispose. We have been disposing of all excess machinery
and equipment, and were substantially complete by the end of 2016.
INVENTORY AND OTHER CHARGES
During 2016, in connection with the evaluation of our current inventory levels and expected future demand and
to align with our future strategy, we recorded charges of $617 million, including $34 million of disposal costs, of
which $204 million is reported in cost of sales and $413 million is reported in cost of services, to write off the
carrying value of inventory deemed excess. These actions impacted all product lines. The amount of the inventory
write-off recorded by segment is as follows: North America - $230 million; Latin America - $84 million; Europe/
Africa/Russia Caspian - $143 million; Middle East/Asia Pacific - $117 million; and Industrial Services - $43 million.
We have been disposing of the excess inventory, and were substantially complete by the end of 2016. During 2015,
we also recorded charges of $194 million, of which $37 million is reported in cost of sales and $157 million is
reported in cost of services, to write down the carrying value of certain inventory. The write-down was primarily due
to lower of cost or market adjustments triggered by the significant decline in activity and related prices for our
products coupled with declines in replacement costs. The product lines impacted are primarily the pressure
pumping and drilling and completion fluids in North America.
NOTE 5. ACQUISITIONS AND DISPOSITIONS
AQUISITIONS
In September 2014, we completed the acquisition of the pipeline and specialty services business of
Weatherford International Ltd. ("PSS") for total cash consideration of $248 million. PSS provides an expanded
range of pre-commissioning, deepwater and in-line inspection services worldwide and is included in our Industrial
Services segment. The transaction has been accounted for using the acquisition method of accounting and
accordingly, assets acquired and liabilities assumed were recorded at their fair values as of the acquisition date. As
a result of the acquisition, we recorded approximately $73 million of goodwill and approximately $37 million of
intangible assets. Pro forma results of operations for this acquisition have not been presented because the effect of
this acquisition was not material to our consolidated financial statements.
DISPOSITIONS
In December 2016, we closed the transaction contemplated by the contribution agreement among Baker
Hughes, CSL Capital Management ("CSL") and West Street Energy Partners ("WSEP"), a fund managed by the
Merchant Banking Division of Goldman Sachs, to create a North American onshore pressure pumping company,
called BJ Services, LLC ("BJ Services"). Under the terms of the agreement, we contributed our wholly-owned North
American onshore cementing and hydraulic fracturing business, which was comprised of the U.S. and Canada
operations. This also includes personnel, technology and infrastructure.
Net book value of the assets contributed totaled approximately $516 million, which was comprised of fixed
assets, inventory and certain patents and technology. We also allocated goodwill to the contributed business of
$139 million. We received consideration of $142 million in cash, net of $8 million of direct transaction fees, and a
46.7% interest in BJ Services, which we recorded as an equity method investment valued at $416 million included
in Other Assets in our consolidated balance sheet. This resulted in a loss on the deconsolidation of this business of
$97 million.
We will provide customary support services during a transition period. BJ Services will have access to certain
of Baker Hughes' pressure pumping technology through a licensing agreement. Utilizing a strategic collaboration,
we will have access to BJ Services' product and service portfolio to continue to provide solutions to customers in the
North American onshore market. Revenue from these operations totaled $231 million, $1.27 billion and $4.30 billion
in 2016, 2015 and 2014, respectively. Operating loss before tax and allocations of indirect costs and expenses
totaled $251 million in 2016 and $559 million in 2015, and operating profit before tax and allocations of indirect
65
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
costs and expenses in 2014 totaled $279 million. See Note. 6 "Segment Information" for our description of
operating profit (loss) before tax.
NOTE 6. SEGMENT INFORMATION
We are a supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas
business, referred to as oilfield operations, which are managed through operating segments that are aligned with
our geographic regions. We also provide services and products to the downstream chemicals, and process and
pipeline services, referred to as Industrial Services.
The performance of our operating segments is evaluated based on operating profit (loss) before tax, which is
defined as income (loss) before income taxes and before the following: net interest expense, corporate expenses,
impairment and restructuring charges, goodwill impairment charges, the merger termination fee, loss on sale of
business interest, loss on early extinguishment of debt, and certain gains and losses not allocated to the operating
segments.
Beginning in 2016, we excluded merger and related costs, from both the terminated Halliburton and the
proposed GE transactions, from our operating segments. These costs are now presented as a separate line item in
the consolidated statement of income (loss). Prior year merger and related costs have been reclassified to conform
to the current year presentation.
The following table presents revenue and operating profit (loss) before tax by segment for the years ended
December 31:
Segments
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Industrial Services
Total Operations
Corporate
Loss on sale of business interest
Loss on early extinguishment of debt
Interest expense, net
Impairment and restructuring charges
Goodwill impairment
Merger and related costs
Merger termination fee
Total
2016
2015
2014
Operating
Profit (Loss)
Before Tax
$
Revenue
6,009
Operating
Profit (Loss)
Before Tax
$
Revenue
(639) $ 12,078
Operating
Profit (Loss)
Before Tax
1,466
$
(687) $
(276)
(273)
69
(6)
(1,173)
(158)
(97)
(142)
(178)
(1,735)
(1,858)
(199)
3,500
1,799
3,278
3,441
1,215
15,742
—
—
—
—
—
—
—
—
144
183
229
108
25
(133)
—
—
(217)
(1,993)
—
(295)
—
2,236
4,417
4,456
1,364
24,551
—
—
—
—
—
—
—
—
290
621
675
119
3,171
(312)
—
—
(232)
—
—
—
—
Revenue
2,936
$
980
2,201
2,705
1,019
9,841
—
—
—
—
—
—
—
—
$
9,841
$
(2,040) $ 15,742
$
(2,613) $ 24,551
$
2,627
66
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The following table presents total assets by segment at December 31:
Segments
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Industrial Services
Shared assets
Total Operations
Corporate
Total
2016
Assets
2015
Assets
2014
Assets
$
3,049
$
6,599
$
1,530
2,446
2,746
631
5,129
15,531
3,503
2,323
3,077
3,441
1,106
5,613
22,159
1,921
9,782
2,508
4,106
4,029
1,260
5,423
27,108
1,719
$
19,034
$
24,080
$
28,827
Shared assets consist primarily of the assets carried at the enterprise level and include assets related to our
supply chain, product line technology and information technology organizations. These assets are used to support
our operating segments and consist primarily of manufacturing inventory, property, plant and equipment used in
manufacturing and information technology, intangible assets related to technology, and certain deferred tax assets.
All costs and expenses from these organizations, including depreciation and amortization, are allocated to our
operating segments as these enterprise organizations support our global operations. Corporate assets include
cash, certain facilities, our equity method investment in BJ Services, and certain other noncurrent assets related to
certain employee retirement plans.
The following table presents capital expenditures and depreciation and amortization by segment for the years
ended December 31:
Segments
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Industrial Services
Shared assets
Total Operations
Corporate
Total
2016
2015
2014
Capital
Expenditures
75
$
Depreciation
and
Amortization
356
$
Capital
Expenditures
228
$
Depreciation
and
Amortization
714
$
Capital
Expenditures
465
$
Depreciation
and
Amortization
842
$
35
122
83
7
9
331
1
332
$
160
268
300
77
—
1,161
5
103
175
247
21
188
962
3
213
378
344
87
—
1,736
6
171
373
385
46
342
1,782
9
220
351
321
70
—
1,804
10
$
1,166
$
965
$
1,742
$
1,791
$
1,814
67
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The following tables present geographic consolidated revenue based on the location to where the product is
shipped or the services are performed for the years ended December 31, and net property, plant and equipment by
its geographic location at December 31. Amounts for Industrial Services have been included in the applicable
geographic locations.
U.S.
Canada and other
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Total
U.S.
Canada and other
North America
Latin America
Europe/Africa/Russia Caspian
Middle East/Asia Pacific
Total
2016
Revenue
2015
Revenue
2014
Revenue
$
2,875
$
5,800
$
11,499
598
3,473
1,006
2,457
2,905
839
6,639
1,847
3,555
3,701
1,336
12,835
2,300
4,705
4,711
$
9,841
$
15,742
$
24,551
2016
Net Property,
Plant and
Equipment
2015
Net Property,
Plant and
Equipment
2014
Net Property,
Plant and
Equipment
$
1,792
$
2,989
$
148
1,940
466
984
881
260
3,249
716
1,400
1,328
$
4,271
$
6,693
$
4,417
482
4,899
890
1,805
1,469
9,063
The following table presents consolidated revenue for each category of similar products and services for the
years ended December 31:
Completion and Production
Drilling and Evaluation
Industrial Services
Total
2016
2015
2014
$
$
5,681
$
8,831
$
14,572
3,141
1,019
5,696
1,215
8,615
1,364
9,841
$
15,742
$
24,551
NOTE 7. 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 generally recognized on a straight-line basis over the vesting period of the equity grant. The
compensation cost is determined 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, if necessary, in subsequent periods to reflect actual forfeitures. There were no stock-based compensation
costs capitalized as the amounts were not material.
68
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
Stock-based compensation costs are as follows for the years ended December 31:
Stock-based compensation cost
Tax benefit
Stock-based compensation cost, net of tax
2016
2015
2014
$
$
125 $
(33)
92 $
120
(28)
92
$
$
122
(26)
96
For our stock options and restricted stock awards and units, we currently have 60.7 million shares authorized
for issuance and as of December 31, 2016, approximately 16.9 million shares were available for future grants. Our
policy is to issue new shares for exercises of stock options, when restricted stock awards are granted, at vesting of
restricted stock units and for issuances under the employee stock purchase plan.
Stock Options
Our stock option plans provide for the issuance of stock options to directors, officers and other key employees
at an exercise price equal to the fair market value of the stock at the date of grant. Although subject to the terms of
the stock option agreement, substantially all of the stock options become exercisable in three equal annual
installments, beginning a year from the date of grant, and generally expire ten years from the date of grant. The
stock option plans provide for the acceleration of vesting upon the employee's retirement; therefore, the service
period is reduced for employees that are or will become retirement eligible during the vesting period, and
accordingly, the recognition of compensation expense for these employees is accelerated. No stock options were
granted in 2016 or 2015.
The fair value of each stock option granted is estimated using the Black-Scholes option pricing model. The
following table presents the weighted average assumptions used in the option pricing model for options granted.
The expected life of the options represents the period of time the options are expected to be outstanding. The
expected life is based on our historical exercise trends and post-vest termination data incorporated into a forward-
looking stock price model. The expected volatility is based on our implied volatility, which is the volatility forecast
that is implied by the prices of actively traded options to purchase our stock observed in the market. The risk-free
interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. The
dividend yield is based on our history of dividend payouts.
Expected life (years)
Risk-free interest rate
Volatility
Dividend yield
Weighted average fair value per share at grant date
2014
4.6
1.5%
31.9%
1.0%
$ 16.81
69
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The following table presents the changes in stock options outstanding and related information (in thousands,
except per option prices):
Outstanding at December 31, 2015
Granted
Exercised
Forfeited
Expired
Outstanding at December 31, 2016
Exercisable at December 31, 2016
Number of
Options
8,602
—
(765)
(78)
(522)
7,237
6,993
Weighted Average
Exercise Price
Per Option
$
54.56
—
44.04
60.35
75.55
54.09
53.76
$
$
The weighted average remaining contractual term for options outstanding and options exercisable at
December 31, 2016 were 3.77 years and 3.66 years, respectively.
The total intrinsic value of stock options (defined as the amount by which the market price of our common stock
on the date of exercise exceeds the exercise price of the option) exercised in 2016, 2015 and 2014 was $11 million,
$15 million and $70 million, respectively. The income tax benefit realized from stock options exercised was $1
million, $3.8 million and $19.6 million in 2016, 2015 and 2014, respectively.
The total fair value of options vested in 2016, 2015 and 2014 was $13 million, $24 million and $29 million,
respectively. As of December 31, 2016, there was $1 million of total unrecognized compensation cost related to
unvested stock options, which is expected to be recognized over a weighted average period of six months.
The total intrinsic value of stock options outstanding at December 31, 2016 was $97 million, of which $96 million
relates to options vested and exercisable. The intrinsic value for stock options outstanding is calculated as the
amount by which the quoted price of $64.97 of our common stock as of the end of 2016 exceeds the exercise price
of the options.
Restricted Stock Awards and Units
In addition to stock options, our officers, directors and key employees may be granted restricted stock awards
("RSA"), which is an award of common stock with no exercise price, or restricted stock units ("RSU"), where each
unit represents the right to receive, at the end of a stipulated period, one unrestricted share of stock with no
exercise price. RSAs and RSUs are subject to cliff or graded vesting, generally ranging over a three year period, or
over a one year period for non-employee directors. We determine the fair value of restricted stock awards and
restricted stock units based on the market price of our common stock on the date of grant. The following table
presents the combined changes of RSAs and RSUs and related information (in thousands, except per award/unit
prices):
Unvested balance at December 31, 2015
Granted
Vested
Forfeited
Unvested balance at December 31, 2016
70
Number of
Awards
and Units
Weighted Average
Grant Date Fair
Value Per Award/Unit
3,356
$
3,313
(1,809)
(809)
4,051
$
58.99
40.56
55.50
49.73
47.33
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The weighted average grant date fair value per share for RSAs and RSUs granted in 2016, 2015 and 2014 was
$40.56, $57.37 and $69.67, respectively. The total fair value of RSAs and RSUs vested in 2016, 2015 and 2014
was $100 million, $72 million and $60 million, respectively. As of December 31, 2016, there was $110 million of
total unrecognized compensation cost related to unvested RSAs and RSUs, which is expected to be recognized
over a weighted average period of two years.
Employee Stock Purchase Plan
The Employee Stock Purchase Plan ("ESPP") provides for eligible employees to purchase shares on an after-
tax basis in an amount between 1% and 10% of their annual pay: (i) on June 30 of each year at a 15% discount of
the fair market value of our common stock on January 1 or June 30, whichever is lower, and (ii) on December 31 of
each year at a 15% discount of the fair market value of our common stock on July 1 or December 31, whichever is
lower. An employee may not contribute more than $5,000 in either of the six-month measurement periods
described above or $10,000 annually.
We currently have 30.5 million shares authorized for issuance, and at December 31, 2016, there were 2.7
million shares reserved for future issuance. Compensation cost for the years ended December 31, was calculated
using the Black-Scholes option pricing model with the following assumptions:
Expected life (years)
Risk-free interest rate
Volatility
Dividend yield
Fair value per share of the 15% cash discount
Fair value per share of the look-back provision
Total weighted average fair value per share at grant date
2016
0.5
2015
0.5
0.5%
0.1%
46.2%
30.9%
1.5%
1.2%
2014
0.5
0.03%
24.7%
1.0%
$ 6.85
$ 8.79
$ 9.72
5.86
4.97
4.39
$12.71
$13.76
$14.11
We calculated estimated volatility using historical daily prices based on the expected life of the stock purchase
plan. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the ESPP
shares were granted. The dividend yield is based on our history of dividend payouts.
NOTE 8. INCOME TAXES
The provision or benefit for income taxes is comprised of the following for the years ended December 31:
Current:
U.S.
Foreign
Total current
Deferred:
U.S.
Foreign
Total deferred
Provision (benefit) for income taxes
2016
2015
2014
$ 139
208
347
$ (55) $ 365
601
966
225
170
269
80
349
$ 696
(762)
(47)
(809)
(52)
(18)
(70)
$ (639) $ 896
71
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The geographic sources of loss or income before income taxes are as follows for the years ended
December 31:
2016
2015
2014
U.S.
Foreign
(Loss) income before income taxes
$
(347) $ (2,288) $
920
1,707
$ (2,040) $ (2,613) $ 2,627
(1,693)
(325)
The benefit or provision for income taxes differs from the amount computed by applying the U.S. statutory
income tax rate to the loss or income before income taxes for the reasons set forth below for the years ended
December 31:
U.S. statutory income tax rate
Effect of foreign operations
Change in valuation allowances
Adjustments of prior years' tax positions
Goodwill impairment
State income taxes - net of U.S. tax benefit
Other - net
Total effective tax rate
2016
35.0 %
2015
2014
35.0%
35.0%
1.3
(39.2)
(3.8)
(27.6)
1.2
(1.0)
(1.5)
(7.3)
(1.5)
—
1.4
(1.6)
(5.3)
4.0
1.2
—
0.9
(1.7)
(34.1)%
24.5%
34.1%
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, as well as
operating loss and tax credit carryforwards.
The tax effects of our temporary differences and carryforwards are as follows at December 31:
Deferred tax assets:
Receivables
Inventory
Property
Employee benefits
Other accrued expenses
Operating loss carryforwards
Tax credit carryforwards
Other
Subtotal
Valuation allowances
Total
Deferred tax liabilities:
Goodwill and other intangibles
Property
Undistributed earnings of foreign subsidiaries
Other
Total
Net deferred tax asset
72
2016
2015
$
184
196
261
128
125
1,111
214
52
2,271
(2,010)
261
$
84
253
—
143
141
1,153
458
112
2,344
(1,210)
1,134
133
—
27
6
166
95
$
272
47
21
35
375
759
$
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
At December 31, 2016, we had approximately $127 million of foreign tax credits which may be carried forward
indefinitely under applicable foreign law, and $59 million of foreign tax credits and $28 million of other credits that
will expire in 2017 through 2036 under U.S. tax law. The decrease in tax credit carryforwards of approximately $244
million is primarily due to utilization of foreign tax credits under U.S. tax law. This is primarily due to the $3.5 billion
termination fee received from Halliburton (see Note 2. "Halliburton Terminated Merger Agreement"), that generated
sufficient taxable income in 2016 resulting in utilization of foreign tax credit carryforwards that existed as of
December 31, 2015. Additionally, we had $1.11 billion of net operating loss carryforwards, of which approximately
$435 million will expire within five years, $142 million will expire over twenty years, and the remainder can be
carried forward indefinitely.
We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax
assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate
sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. At
December 31, 2016, the $2.01 billion of valuation allowances are recorded against various deferred tax assets,
including foreign net operating losses ("NOL") of $1.01 billion, U.S. federal and foreign tax credit carryforwards of
$186 million, other U.S. NOL's and tax credit carryforwards of $55 million, and certain other U.S. and foreign
deferred tax assets of $761 million. The increase in valuation allowances are due to valuation allowances recorded
against U.S. deferred tax assets as well as increased foreign deferred tax assets that require a valuation allowance.
Due to the significant downturn in the U.S. market during the year and the uncertainty as to whether the U.S. will
generate sufficient future taxable income to utilize the U.S. deferred tax assets, we concluded that valuation
allowances were required. There are $76 million of deferred tax assets related to foreign net operating loss
carryforwards without a valuation allowance as we expect that the deferred tax assets will be realized within the
carryforward period.
We have provided relevant U.S. and foreign taxes for the anticipated repatriation of certain earnings of our
foreign subsidiaries. We consider the undistributed earnings of our foreign subsidiaries above the amount for which
taxes have already been provided to be indefinitely reinvested, as we have no current intention to repatriate these
earnings. As of December 31, 2016, the cumulative amount of foreign earnings upon which the U.S. income taxes
have not been provided is approximately $4.5 billion. These additional foreign earnings could become subject to
additional tax, if remitted, or deemed remitted, as a dividend. Computation of the potential deferred tax liability
associated with these undistributed earnings and any other basis differences, is not practicable.
During 2016, property and goodwill were impaired and written down to their estimated fair value and the
majority are not currently deductible for tax purposes. As a result of the impairments, the book basis decreased
with no change in tax basis resulting in a significant change in deferred balances when comparing 2016 to 2015
balances.
At December 31, 2016, we had $351 million of tax liabilities for total gross unrecognized tax benefits related to
uncertain tax positions, which includes liabilities for interest and penalties of $48 million and $26 million,
respectively. If we were to prevail on all uncertain tax positions, the net effect would result in an income tax benefit
of approximately $341 million. The remaining approximately $10 million is offset by deferred tax assets that
represent tax benefits that would be received in different taxing jurisdictions in the event that we did not prevail on
all uncertain tax positions.
73
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The following table presents the changes in our gross unrecognized tax benefits and associated interest and
penalties included in the consolidated balance sheets.
Gross Unrecognized
Tax
Benefits, Excluding
Interest and Penalties
Interest and
Penalties
Total Gross
Unrecognized Tax
Benefits
Balance at December 31, 2013
$
(Decrease) increase in prior year tax positions
Increase in current year tax positions
Decrease related to settlements with taxing authorities
Decrease related to lapse of statute of limitations
Decrease due to effects of foreign currency translation
Balance at December 31, 2014
Increase in prior year tax positions
Increase in current year tax positions
Decrease related to settlements with taxing authorities
Decrease related to lapse of statute of limitations
Decrease due to effects of foreign currency translation
Balance at December 31, 2015
Increase in prior year tax positions
Increase in current year tax positions
Decrease related to settlements with taxing authorities
Decrease related to lapse of statute of limitations
Decrease due to effects of foreign currency translation
Balance at December 31, 2016
$
228
(7)
39
(5)
(6)
(7)
242
19
26
(8)
(11)
(8)
260
28
17
(9)
(8)
(11)
277
$
$
54
1
2
(1)
(3)
(4)
49
15
1
(2)
(7)
(4)
52
34
1
(1)
(8)
(4)
74
$
$
282
(6)
41
(6)
(9)
(11)
291
34
27
(10)
(18)
(12)
312
62
18
(10)
(16)
(15)
351
It is expected that the amount of unrecognized tax benefits will change in the next twelve months due to
expiring statutes, audit activity, tax payments, competent authority proceedings related to transfer pricing or final
decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. At
December 31, 2016, we had approximately $214 million of tax liabilities, net of $2 million of tax assets, related to
uncertain tax positions, each of which are individually insignificant, and each of which are reasonably possible of
being settled within the next twelve months.
At December 31, 2016, approximately $135 million of tax liabilities for total gross unrecognized tax benefits
were included in the noncurrent portion of our income tax liabilities, for which the settlement period cannot be
determined; however, it is not expected to be within the next twelve months.
We conduct business in more than 80 countries and are subject to income taxes in most taxing jurisdictions in
which we operate. The following table summarizes the earliest tax years that remain subject to examination by the
major taxing jurisdictions in which we operate. In addition to the U.S., we include foreign jurisdictions that have
historically generated the highest tax liability.
Jurisdiction Earliest Open Tax Period Jurisdiction Earliest Open Tax Period
Argentina
Norway
2009
2006
Ecuador
Netherlands
2005
2010
Saudi Arabia
U.S.
2004
2010
74
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 9. EARNINGS PER SHARE
A reconciliation of the number of shares used for the basic and diluted loss or earnings per share ("EPS")
computations is as follows for the years ended December 31:
Weighted average common shares outstanding for basic EPS
Effect of dilutive securities - stock plans
Adjusted weighted average common shares outstanding for diluted EPS
Anti-dilutive shares excluded from diluted EPS (1)
Future potentially dilutive shares excluded from diluted EPS (2)
2016
2015
2014
434
—
434
1
3
438
—
438
2
3
437
2
439
—
2
(1) The calculation of diluted net loss per share for 2016 and 2015, excludes shares potentially issuable under
stock-based incentive compensation plans and the employee stock purchase plan, as their effect, if
included, would have been anti-dilutive.
(2) Options where the exercise price exceeds the average market price are excluded from the calculation of
diluted net loss or earnings per share because their effect would be anti-dilutive.
NOTE 10. INVENTORIES
Inventories, net of reserves of $188 million and $278 million in 2016 and 2015, respectively, are comprised of
the following at December 31:
Finished goods
Work in process
Raw materials
Total inventories
2016
$ 1,607
105
97
$ 1,809
2015
$ 2,649
132
136
$ 2,917
During 2016, we wrote off the carrying value of certain excess inventory resulting in charges of $583 million, net
of existing reserves of $272 million. In addition, during 2016 we accrued $34 million of related disposal costs.
During 2015, we recorded charges of $194 million primarily related to lower of cost or market adjustments due to
the significant decline in activity and related prices for our products coupled with declines in replacement costs.
See Note 4. "Impairment and Restructuring Charges" for further discussion. Substantially all of the excess
inventory was disposed by December 31, 2016.
75
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 11. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are comprised of the following at December 31:
Land
Buildings and improvements
Machinery, equipment and other
Subtotal
Less: Accumulated depreciation
Total property, plant and equipment
Useful Life
2016
2015
5 - 30 years
1 - 20 years
$
211
$
263
2,146
8,481
10,838
6,567
2,624
11,184
14,071
7,378
$ 4,271
$ 6,693
Depreciation expense relating to property, plant and equipment was $1.09 billion, $1.64 billion and $1.71 billion
in 2016, 2015 and 2014, respectively. During 2016 and 2015, we recorded impairment charges relating to property,
plant and equipment totaling $1.16 billion and $1.32 billion, respectively. See Note 4. "Impairment and
Restructuring Charges" for further discussion.
NOTE 12. GOODWILL AND INTANGIBLE ASSETS
The changes in the carrying amount of goodwill are detailed below by segment.
Balance at December 31, 2015
Impairments
Disposition
Currency translation adjustments and other
Balance at December 31, 2016
North
America
$ 3,097
(1,549)
(139)
6
$ 1,415
Latin
America
584
$
—
—
4
Europe/
Africa/
Russia
Caspian
$ 1,068
Middle
East/
Asia
Pacific
$
819
—
—
—
—
—
1
Industrial
Services
502
$
Total
Goodwill
$ 6,070
(309)
(1,858)
—
—
(139)
11
$
588
$ 1,068
$
820
$
193
$ 4,084
We perform an annual impairment test of goodwill on a qualitative or quantitative basis for each of our reporting
units as of October 1 of each year, or more frequently when circumstances indicate an impairment may exist at the
reporting unit level. During the second quarter of 2016, as a result of the termination of the Merger Agreement with
Halliburton, we concluded it was necessary to conduct a quantitative goodwill impairment review. Our reporting
units are the same as our five reportable segments. Goodwill is tested for impairment using a two-step approach.
In the first step, the fair value of each reporting unit is determined and compared to the reporting unit's carrying
value, including goodwill. If the fair value of a reporting unit is less than its carrying value, the second step of the
goodwill impairment test is performed to measure the amount of impairment, if any. In the second step, the fair
value of the reporting unit is allocated to the assets and liabilities of the reporting unit as if it had been acquired in a
business combination and the purchase price was equivalent to the fair value of the reporting unit. The excess of
the fair value of the reporting unit over the amounts assigned to its assets and liabilities is referred to as the implied
fair value of goodwill. The implied fair value of the reporting unit's goodwill is then compared to the actual carrying
value of goodwill. If the implied fair value of goodwill is less than the carrying value of goodwill, an impairment loss
is recognized for the difference.
We determined the fair value of our reporting units using a combination of techniques including discounted cash
flows derived from our long-term plans and a market approach that provides value indications through a comparison
with guideline public companies. The inputs used to determine the fair values were classified as Level 3 in the fair
value hierarchy. Based on the results of our impairment test during the second quarter of 2016, we determined that
goodwill of two of our reporting units was impaired, and performed the second step of the goodwill impairment test.
We substantially completed all actions necessary in the determination of the implied fair value of goodwill in the
76
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
second quarter of 2016; however, some of the estimated fair values and allocations were subject to adjustment
once the valuations and other computations were completed. During the third quarter of 2016, we finalized all
valuations and computations. The total impairment is reflected in the table above.
In addition to the quantitative assessment performed in the second quarter of 2016, and consistent with our
policy, we also performed our annual goodwill impairment test for all reporting units as of October 1, 2016. This
assessment was performed on a qualitative basis, and included our consideration of changes in industry and
market conditions since the performance of our quantitative analysis in the second quarter of 2016. Based on
increasing oil prices and projections of increased drilling and exploration activity over the near and long term, which
would drive higher customer spending, we determined that it is more likely than not that the fair value of each of our
reporting units exceeded its carrying amount at that time. Thus, no additional impairment of goodwill was necessary
in the fourth quarter of 2016. In 2015 and 2014, we performed a qualitative assessment for our annual goodwill
impairment test and determined that it was more likely than not that the fair value of each of our reporting units
exceeded its carrying amount at that time. As such, no impairments of goodwill were recorded for the years ended
December 31, 2015 or 2014.
The volatility that currently exists in the oil and natural gas industry and further declines in future commodity
prices and customer spending could negatively impact our forecasted profitability and operating cash flows,
necessitating a future goodwill impairment review. Depending on the changes in our business outlook and other
assumptions underlying the fair value measurements of our reporting units, we may be required to recognize
additional goodwill impairments.
Intangible assets are comprised of the following at December 31:
Gross
Carrying
Amount
Technology(1)
Customer relationships (1)
Trade names (1)
Other
Total intangibles
$
$
527
74
90
17
708
2016
Less:
Accumulated
Amortization
267
$
31
79
13
390
$
$
Gross
Carrying
Amount
866
251
108
18
1,243
$
$
2015
Less:
Accumulated
Amortization
452
$
106
89
13
660
Net
$
260
$
43
11
4
318
Net
414
145
19
5
583
$
$
(1) During 2016 and 2015, we recorded impairments relating to our technology, customer relationships and
trade names intangible assets totaling $114 million and $116 million, respectively. See Note 4. "Impairment
and Restructuring Charges" for further discussion.
Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 3 to
30 years. Amortization expense for the years ended December 31, 2016, 2015 and 2014 was $76 million, $104
million and $107 million, respectively. Estimated amortization expense for each of the subsequent five fiscal years
is expected to be as follows:
Year
2017
2018
2019
2020
2021
Estimated
Amortization
Expense
$
54
49
46
38
33
77
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 13. INDEBTEDNESS
Total debt consisted of the following at December 31, net of unamortized discount and debt issuance cost:
6.0% Notes due June 2018
7.5% Senior Notes due November 2018
3.2% Senior Notes due August 2021
8.55% Debentures due June 2024
6.875% Notes due January 2029
5.125% Notes due September 2040
Other debt
Total debt
Less: short-term debt and current portion of long-term debt
Total long-term debt
$
2016
2015
$
199
524
511
112
301
255
747
746
149
394
1,132
1,482
239
268
3,018
4,041
132
151
$ 2,886
$ 3,890
The estimated fair value of total debt at December 31, 2016 and 2015 was $3.36 billion and $4.32 billion,
respectively, which differs from the carrying amounts of $3.02 billion and $4.04 billion, respectively, included in our
consolidated balance sheets. The fair value was determined using quoted period end market prices.
In June 2016, we purchased $1.0 billion of the aggregate outstanding principal amount associated with our
long-term outstanding notes and debentures, which included portions of each tranche of notes and debentures.
Pursuant to a cash tender offer, the purchases resulted in the payment of an early-tender premium, including
various fees, of $135 million and a pre-tax loss on the early extinguishment of debt of $142 million, which includes
the premium and the write-off of a portion of the remaining original debt issue costs and debt discounts or
premiums.
On July 13, 2016, we entered into a new five-year $2.5 billion committed revolving credit facility (the "2016
Credit Agreement") with commercial banks maturing in July 2021, which replaced our existing credit facility of $2.5
billion, but maintained the existing commercial paper program. The previous credit facility had a maturity date in
September of 2016. The maximum combined borrowing at any time under both the 2016 Credit Agreement and the
commercial paper program is $2.5 billion. The 2016 Credit Agreement contains certain covenants, which, among
other things, require the maintenance of a total debt-to-total capitalization ratio, restrict certain merger transactions
or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary
indebtedness. Upon the occurrence of certain events of default, our obligations under the 2016 Credit Agreement
may be accelerated. Such events of default include payment defaults to lenders under the 2016 Credit Agreement,
covenant defaults and other customary defaults. To the extent we have outstanding commercial paper, the
aggregate ability to borrow under the 2016 Credit Agreement is reduced.
As of December 31, 2016, we were in compliance with all of the credit facility's covenants, and there were no
direct borrowings under the credit facility during 2016. Under the commercial paper program, we may issue from
time to time up to $2.5 billion in commercial paper with maturities of no more than 270 days. The amount available
to borrow under the credit facility is reduced by the amount of any commercial paper outstanding. At December 31,
2016, we had no borrowings outstanding under the commercial paper program. Maturities of debt for each of the
five years in the period ending December 31, 2021, and in the aggregate thereafter, are listed in the table below:
Total debt
$
132 $
753 $
26 $
12 $
524 $
2017
2018
2019
2020
2021
Thereafter
1,571
The weighted average interest rate on short-term borrowings outstanding at December 31, 2016 and 2015 were
12.3% and 12.2%, respectively.
78
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 14. EMPLOYEE BENEFIT PLANS
DEFINED BENEFIT PLANS
We have both funded and unfunded noncontributory defined benefit pension plans ("Pension Benefits")
covering certain employees primarily in the U.S., the U.K., Germany and Canada. Under the provisions of the U.S.
qualified pension plan (the "U.S. Pension Plan"), a hypothetical cash balance account is established for each
participant. Such accounts receive quarterly credits based on a percentage according to the employee's age on the
last day of the quarter applied to quarterly eligible compensation and interest credits based on the balance in the
account on the last day of the quarter. The U.K. and Canada plans are frozen for the majority of the participants;
therefore, we do not accrue benefits for those participants. The Germany pension plan is an unfunded plan where
benefits are based on creditable years of service, creditable pay and accrual rates. We also provide certain
postretirement health care benefits ("Other Postretirement Benefits"), through an unfunded plan, to a closed group
of U.S. employees who retire and have met certain age and service requirements. During 2016 and 2015, as a
result of the workforce reductions stemming from our restructuring activities, we remeasured certain pension and
other postretirement benefit obligations, which resulted in reductions in our projected benefit obligations of $18
million and $28 million, respectively, and curtailment gains of $9 million and $18 million, respectively.
Funded Status
Below is the reconciliation of the beginning and ending balances of benefit obligations, fair value of plan assets
and the funded status of our plans.
U.S. Pension Benefits
Non-U.S.
Pension Benefits
Other Postretirement
Benefits
2016
2015
2016
2015
2016
2015
Change in benefit obligation:
Benefit obligation at beginning of year
Service cost
Interest cost
Actuarial loss (gain)
Benefits paid
Curtailment
Other
Foreign currency translation adjustments
Benefit obligation at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Benefits paid
Other
Foreign currency translation adjustments
Fair value of plan assets at end of year
$
735
52
29
(13)
(63)
(12)
(2)
—
726
595
29
44
(63)
(5)
—
600
$
728
64
26
(4)
(59)
(24)
4
—
735
648
(5)
16
(59)
(5)
—
595
$
798
14
27
165
(38)
(2)
—
(118)
846
713
118
24
(38)
—
(118)
699
Funded status - underfunded at end of year
$ (126)
$ (140)
$ (147)
Accumulated benefit obligation
$
682
$
681
$
810
$
$
$
872
15
30
(23)
(35)
(2)
(6)
(53)
798
767
4
28
(35)
(6)
(45)
713
(85)
763
$
107
4
4
—
(14)
(4)
—
—
97
—
—
14
(14)
—
—
—
$
122
5
4
(10)
(11)
(2)
(1)
—
107
—
—
11
(11)
—
—
—
$
$
(97)
$ (107)
97
$
107
79
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The amounts recognized in the consolidated balance sheets consist of the following at December 31:
U.S. Pension Benefits
Non-U.S.
Pension Benefits
Other Postretirement
Benefits
2016
2015
2016
2015
2016
2015
Noncurrent assets
Current liabilities
Noncurrent liabilities
Net amount recognized
$ — $ — $
(1)
(125)
$ (126)
(2)
(138)
$ (140)
3
(6)
(144)
$ (147)
$
$
51
(6)
(130)
(85)
$ — $ —
(16)
(91)
$ (107)
(16)
(81)
(97)
$
The funded status position represents the difference between the benefit obligation and the plan assets. The
projected benefit obligation ("PBO") for pension benefits represents the actuarial present value of benefits attributed
to employee services and compensation and includes an assumption about future compensation levels. The
accumulated benefit obligation ("ABO") is the actuarial present value of pension benefits attributed to employee
service to date and present compensation levels. The ABO differs from the PBO in that the ABO does not include
any assumptions about future compensation levels.
Information for the plans with ABOs in excess of plan assets is as follows at December 31:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
U.S. Pension Benefits
Non-U.S.
Pension Benefits
Other Postretirement
Benefits
2016
2015
2016
2015
2016
2015
$
$
$
725
682
600
$
$
$
735
681
595
$
$
$
821
786
672
$
$
$
149
114
12
$
n/a
97
n/a
n/a
$
107
n/a
Weighted average assumptions used to determine benefit obligations for these plans are as follows for the
years ended December 31:
Discount rate
Rate of compensation increase
Social security increase
U.S. Pension Benefits
Non-U.S.
Pension Benefits
Other Postretirement
Benefits
2016
2015
2016
2015
4.0%
5.5%
2.8%
4.2%
5.9%
2.8%
2.6%
4.2%
2.0%
3.7%
4.1%
2.2%
2016
3.6%
n/a
n/a
2015
3.7%
n/a
n/a
The development of the discount rate for our U.S. plans and substantially all non-U.S. plans was based on a
bond matching model, whereby a hypothetical bond portfolio of high-quality, fixed-income securities is selected that
will match the cash flows underlying the projected benefit obligation.
80
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
Accumulated Other Comprehensive Loss
The amount recorded before-tax in accumulated other comprehensive loss related to employee benefit plans
consists of the following at December 31:
Net actuarial loss
Net prior service cost (credit)
Total
U.S. Pension Benefits
Non-U.S.
Pension Benefits
Other Postretirement
Benefits
2016
2015
2016
2015
2016
2015
$
$
166
—
166
$
$
191
—
191
$
$
266
—
266
$
$
229
—
229
$
$
6
(37)
(31)
$
$
10
(54)
(44)
The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be
amortized from accumulated other comprehensive loss and included in net periodic benefit cost in 2017 are $16
million and $0.8 million, respectively. The estimated prior service credit for the other postretirement benefits that will
be amortized from accumulated other comprehensive loss and included in net periodic benefit cost in 2017 is $8
million. No amortization of the net actuarial loss for the other postretirement benefits from accumulated other
comprehensive loss is expected in 2017.
Net Periodic Cost
The components of net periodic cost are as follows for the years ended December 31:
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service credit
Amortization of net actuarial loss
Curtailment gain
Other
Net periodic cost
U.S. Pension Benefits
Non-U.S.
Pension Benefits
Other Postretirement
Benefits
2016
$ 52
29
(41)
—
11
—
3
$ 54
2015
$ 64
2014
$ 70
2016
$ 14
2015
$ 15
2014
$ 11
2016
4
$
2015
5
$
2014
6
$
26
(49)
1
9
—
8
28
(44)
—
8
—
—
27
(33)
—
6
(2)
—
$ 59
$ 62
$ 12
$
30
(47)
—
6
(1)
—
3
34
(41)
—
5
—
—
9
$
4
—
(9)
—
(7)
—
4
—
5
—
(11)
(11)
1
(17)
—
1
—
(3)
$ (8) $ (18) $ (2)
Weighted average assumptions used to determine net periodic cost for these plans are as follows for the years
ended December 31:
U.S. Pension Benefits
Non-U.S.
Pension Benefits
Other Postretirement
Benefits
Discount rate
2015
2016
2015
4.2% 3.7% 4.5% 3.7% 3.5% 4.4% 3.7% 3.3% 4.0%
2015
2014
2014
2016
2016
2014
Expected long-term return on plan assets
7.0% 7.6% 7.3% 5.0% 6.3% 6.1%
Rate of compensation increase
5.7% 5.8% 5.6% 4.1% 4.1% 4.4%
Social security increase
2.8% 2.8% 2.8% 2.1% 2.1% 2.4%
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
In selecting the expected rate of return on plan assets, we consider the average rate of earnings expected on
the funds invested or to be invested to provide for the benefits of these plans. This includes considering the trusts'
asset allocation and the expected returns likely to be earned over the life of the plans.
81
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
Health Care Cost Trend Rates
Assumed health care cost trend rates can have a significant effect on the amounts reported for other
postretirement benefits. As of December 31, 2016, the health care cost trend rate was 6.9% for employees under
age 65, declining gradually each successive year until it reaches 4.5%. A one percentage point change in assumed
health care cost trend rates would have had the following effects on 2016:
Effect on total of service and interest cost components
Effect on postretirement welfare benefit obligation
Plan Assets
One Percentage
Point Increase
One Percentage
Point Decrease
$
$
0.1
0.9
$
$
(0.1)
(1.2)
We have investment committees that meet regularly to review the portfolio returns and to determine asset-mix
targets based on asset/liability studies. Third-party investment consultants assist such committees in developing
asset allocation strategies to determine our expected rates of return and expected risk for various investment
portfolios. The investment committees considered these strategies in the formal establishment of the current asset-
mix targets based on the projected risk and return levels for all major asset classes.
The majority of investments are held in the form of units of funds. The funds hold underlying securities and are
redeemable as of the measurement date. Investments in equities and fixed-income funds are generally measured
at fair value based on daily closing prices provided by active exchanges or on the basis of observable, market-
based inputs. Investments in hedge funds are generally measured at fair value on the basis of their net asset
values, which are provided by the investment sponsor or third-party administrator. The fair values of private equity
investments and real estate funds are based on appraised values developed using comparable market transactions
or discounted cash flows.
U.S. Pension Plan
The investment policy of the U.S. Pension Plan was developed after examining the historical relationships of
risk and return among asset classes and the relationship between the expected behavior of the U.S. Plan's assets
and liabilities. The investment policy of the U.S. Plan is designed to provide the greatest probability of meeting or
exceeding the U.S. Plan's objectives at the lowest possible risk. In evaluating risk, the investment committee for the
U.S. Pension Plan ("U.S. Committee") reviews the long-term characteristics of various asset classes, focusing on
balancing risk with expected return. Accordingly, the U.S. Committee selected the following six asset classes as
allowable investments for the assets of the U.S. Pension Plan: U.S. equities, non-U.S. equities, global fixed-income
securities, real estate, hedge funds and private equity.
82
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The table below presents the fair value of the assets in the U.S. Pension Plan by asset category and by
valuation technique at December 31:
Asset Category
Cash and Cash Equivalents
Fixed Income (1)
Non-U.S. Equity (2)
U.S. Equity (3)
Hedge Funds (4)
Real Estate Funds (5)
Real Estate Investment Trust Equity
Private Equity Fund (6)
Total
2016
2015
Total
Asset
Value
2
$
Level
One
Level
Two
$ — $
2
Level
Three
$ — $
Total
Asset
Value
16
120
126
131
150
8
12
51
—
31
—
—
—
—
—
120
95
131
—
—
12
—
—
—
—
150
8
—
51
109
129
129
152
10
9
41
Level
One
$
12
—
31
—
—
—
—
—
Level
Two
$
4
Level
Three
$ —
109
98
129
—
—
9
—
—
—
—
152
10
—
41
$ 600
$
31
$ 360
$ 209
$ 595
$
43
$ 349
$ 203
(1) A multi-manager strategy investing in fixed income securities and funds. The current allocation includes:
39% in unconstrained bond funds; 25% in government bonds; 12% in corporate bonds; 10% in government
mortgage-backed securities; 6% in a passive index bond; 1% in commercial mortgage-backed securities;
1% in short-term bills and notes; 1% in asset-backed securities; and 5% in cash and other securities.
(2) Multi-manager strategy investing in common stocks of non-U.S. listed companies using both value and
growth approaches.
(3) Multi-manager strategy investing in common stocks of U.S. listed companies using value and growth
approaches.
(4) Strategies taking long and short positions in equities, fixed income securities, currencies and derivative
contracts.
(5) Strategy investing in the global private real estate secondary market using a value-based investment
approach.
(6) Partnership making opportunistic investments on a global basis across asset classes, capital structures and
geographies.
Non-U.S. Pension Plans
The investment policies of our pension plans with plan assets, which are primarily in Canada and the U.K., (the
"Non-U.S. Plans"), cover the asset allocations that the governing boards believe are the most appropriate for these
Non-U.S. Plans in the long-term, taking into account the nature of the liabilities they expect to incur. The suitability
of asset allocations and investment policies are reviewed periodically to ensure alignment with plan liabilities.
83
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The table below presents the fair value of the assets in our Non-U.S. Plans by asset category and by valuation
technique at December 31:
2016
2015
Asset Category
Cash and Cash Equivalents
Asset Allocation (1)
Bonds - Canada - Corporate (2)
Bonds - Canada - Government (3)
Bonds - U.K. - Corporate (4)
Bonds - U.K. - Government (5)
Bonds - Global - Corporate (6)
Equities (7)
Real Estate Fund (8)
Pooled Swap Funds (9)
Insurance contracts
Total
Asset
Value
5
$
122
6
17
8
225
57
122
19
106
12
Total
$ 699
$
Level
One
Level
Two
Level
Three
Level
One
$
$ — $ — $
$
Total
Asset
Value
5
5
—
—
—
—
—
—
—
—
—
—
5
122
6
17
8
225
57
122
—
106
—
$ 663
$
—
—
—
—
—
—
—
19
—
12
31
152
6
19
8
211
64
128
23
85
12
$ 713
$
Level
Two
Level
Three
$ — $ —
152
6
19
8
211
64
128
—
85
—
$ 673
$
—
—
—
—
—
—
—
23
—
12
35
5
—
—
—
—
—
—
—
—
—
—
5
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Invests in mixes of global common stocks and bonds to achieve broad diversification.
Invests in Canadian Dollar-denominated high quality corporate bonds.
Invests in Canadian Dollar-denominated government issued bonds intended to match the duration of plan
liabilities.
Invests passively in British Pound Sterling-denominated investment grade corporate bonds.
Invests passively in British Pound Sterling-denominated government issued bonds.
Invests globally in high quality corporate bonds.
Invests in broad equity funds based on securities offered in various regions or countries. Equity funds are
allocated by region as follows: 47% Global; 32% U.K.; 7% Emerging Markets; 5% North America; 5% Asia
Pacific; and 4% Europe.
Invests in a diversified range of property throughout the U.K., principally in the retail, office and industrial/
warehouse sectors.
Invests in a range of pooled funds which include positions in swap contracts and U.K. sovereign bonds;
pooled funds are categorized by maturities of underlying positions. Pooled funds employ leverage in order
to match the U.K. Plan's duration and inflation.
84
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
The following table presents the changes in the fair value of assets determined using level 3 unobservable
inputs:
U.S.
Private
Equity
Fund
U.S.
Real
Estate
Fund
U.S.
Hedge
Funds
Non-U.S.
Real
Estate
Fund
16
—
1
(4)
8
21
—
—
(4)
24
41
3
—
(5)
12
51
$
$
9
1
—
—
—
10
—
1
(2)
1
10
1
—
(3)
—
8
$
190
$
6
7
(85)
46
164
(6)
1
(15)
8
152
—
(1)
(22)
21
150
$
$
21
1
—
—
—
22
—
—
—
1
23
(5)
—
—
1
19
Non-U.S.
Insurance
Contracts
18
$
Total
$
254
(1)
—
—
—
17
(2)
—
(5)
2
12
—
—
(3)
3
12
$
7
8
(89)
54
234
(8)
2
(26)
36
238
(1)
(1)
(33)
37
240
$
Balance at December 31, 2013
$
Unrealized gains (losses)
Realized gains
Sales
Purchases
Balance at December 31, 2014
Unrealized gains (losses)
Realized gains
Sales
Purchases
Balance at December 31, 2015
Unrealized gains (losses)
Realized losses
Sales
Purchases
Balance at December 31, 2016
$
Expected Cash Flows
For all pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts
necessary to meet minimum governmental funding requirements. In 2017, we expect to contribute between $55
million and $60 million to our funded pension plans.
The following table presents the expected benefit payments over the next ten years. The U.S. and non-U.S.
pension benefit payments are made by the respective pension trust funds.
Year
2017
2018
2019
2020
2021
2022-2026
U.S. Pension
Benefits
46
$
Non-U.S. Pension
Benefits
22
$
Other Postretirement
Benefits
16
$
$
$
$
$
$
44
46
47
48
264
$
$
$
$
$
24
29
27
32
182
$
$
$
$
$
12
10
9
9
37
85
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
DEFINED CONTRIBUTION PLANS
During the periods reported, generally all of our U.S. employees were eligible to participate in our sponsored
401(k) plan ("Thrift Plan"). The Thrift Plan allows eligible employees to elect to contribute portions of their salaries
to an investment trust. Employee contributions are matched by the Company in cash at the rate of $1.00 per $1.00
employee contribution for the first 5% of the employee's salary, and such contributions vest immediately. In
addition, we make cash contributions for all eligible employees between 2% and 5% of their salary depending on
the employee's age. Such contributions are fully vested to the employee after three years of employment. Effective
April 2016, employer contributions to certain plans were suspended for the remainder of 2016. All employer
contributions will recommence as of January 1, 2017. The Thrift Plan provides several investment options, for
which the employee has sole investment discretion. The Thrift Plan does not offer the Company's common stock as
an investment option. Our contributions to the Thrift Plan and several other non-U.S. defined contribution plans
amounted to $75 million, $202 million and $263 million in 2016, 2015 and 2014, respectively.
For certain non-U.S. employees who are not eligible to participate in the Thrift Plan, we provide a non-qualified
defined contribution international retirement plan that provides basically the same benefits as those provided in the
Thrift Plan. In addition, we provide a non-qualified supplemental retirement plan ("SRP") for certain officers and
employees whose benefits under the Thrift Plans and/or the U.S. qualified pension plan are limited by federal tax
law. The SRP also allows eligible employees to defer a portion of their eligible compensation and provides for
employer matching and base contributions pursuant to limitations. Both non-qualified plans are invested through
trusts, and the assets and corresponding liabilities are included in our consolidated balance sheets. Our
contributions to these non-qualified plans amounted to $9 million, $15 million and $17 million in 2016, 2015 and
2014, respectively. In 2017, we estimate we will contribute between $135 million and $145 million to all of our
defined contribution plans.
POSTEMPLOYMENT BENEFITS
We provide certain postemployment disability income, medical and other benefits to substantially all qualifying
former or inactive U.S. employees. Income benefits for long-term disability are provided through a fully-insured
plan. The continuation of medical and other benefits while on disability ("Continuation Benefits") are provided
through a qualified self-insured plan. The accrued postemployment liability for Continuation Benefits at
December 31, 2016 and 2015 was $32 million and $34 million, respectively, and is included in other liabilities in our
consolidated balance sheets.
NOTE 15. COMMITMENTS AND CONTINGENCIES
LEASES
At December 31, 2016, we had long-term non-cancelable operating leases covering certain facilities and
equipment. The minimum annual rental commitments, net of amounts due under subleases, for each of the five
years in the period ending December 31, 2021 are $118 million, $62 million, $44 million, $29 million and $19 million,
respectively, and $72 million in the aggregate thereafter. Rent expense was $355 million, $514 million and $747
million for the years ended December 31, 2016, 2015 and 2014, respectively. We did not enter into any significant
capital leases during the three years ended December 31, 2016.
LITIGATION
We are subject to a number of lawsuits and claims arising out of the conduct of our business. The ability to
predict the ultimate outcome of such matters involves judgments, estimates and inherent uncertainties. We record
a liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably
estimated, including accruals for self-insured losses which are calculated based on historical claim data, specific
loss development factors and other information. A range of total possible losses for all litigation matters cannot be
reasonably estimated. Based on a consideration of all relevant facts and circumstances, we do not expect the
ultimate outcome of any currently pending lawsuits or claims against us will have a material adverse effect on our
financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate
outcome of these matters.
86
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
We insure against risks arising from our business to the extent deemed prudent by our management and to the
extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be
sufficient to fully indemnify us against liabilities arising out of pending or future legal proceedings or other claims.
Most of our insurance policies contain deductibles or self-insured retentions in amounts we deem prudent and for
which we are responsible for payment. In determining the amount of self-insurance, it is our policy to self-insure
those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability,
general liability and workers compensation.
The following lawsuits were filed in Delaware in connection with our Merger with Halliburton. Subsequent to the
filing of the lawsuits, on April 30, 2016, the Merger Agreement with Halliburton was terminated as described in Note
2. "Halliburton Terminated Merger Agreement."
• On November 24, 2014, Gary Molenda, a purported shareholder of the Company, filed a class action
lawsuit in the Court of Chancery of the State of Delaware ("Delaware Chancery Court") against Baker
Hughes, the Company's Board of Directors, Halliburton, and Red Tiger LLC, a wholly owned subsidiary of
Halliburton ("Red Tiger" and together with all defendants, "Defendants") styled Gary R. Molenda v. Baker
Hughes, Inc., et al., Case No. 10390-CB.
• On November 26, 2014, a second purported shareholder of the Company, Booth Family Trust, filed a
substantially similar class action lawsuit in Delaware Chancery Court.
• On December 1, 2014, New Jersey Building Laborers Annuity Fund and James Rice, two additional
purported shareholders of the Company, filed substantially similar class action lawsuits in Delaware
Chancery Court.
• On December 10, 2014, a fifth purported shareholder of the Company, Iron Workers Mid-South Pension
Fund, filed another substantially similar class action lawsuit in the Delaware Chancery Court.
• On December 24, 2014, a sixth purported shareholder of the Company, Annette Shipp, filed another
substantially similar class action lawsuit in the Delaware Chancery Court.
All of the lawsuits make substantially similar claims. The plaintiffs generally allege that the members of the
Company's Board of Directors breached their fiduciary duties to our shareholders in connection with the Merger
negotiations by entering into the Merger Agreement and by approving the Merger, and that the Company,
Halliburton, and Red Tiger aided and abetted the purported breaches of fiduciary duties. More specifically, the
lawsuits allege that the Merger Agreement provides inadequate consideration to our shareholders, that the process
resulting in the Merger Agreement was flawed, that the Company's directors engaged in self-dealing, and that
certain provisions of the Merger Agreement improperly favor Halliburton and Red Tiger, precluding or impeding third
parties from submitting potentially superior proposals, among other things. The lawsuit filed by Annette Shipp also
alleges that our Board of Directors failed to disclose material information concerning the proposed Merger in the
preliminary registration statement on Form S-4. On January 7, 2015, James Rice amended his complaint, adding
similar allegations regarding the disclosures in the preliminary registration statement on Form S-4. The lawsuits
seek unspecified damages, injunctive relief enjoining the Merger, and rescission of the Merger Agreement, among
other relief. On January 23, 2015, the Delaware lawsuits were consolidated under the caption In re Baker Hughes
Inc. Stockholders Litigation, Consolidated C.A. No. 10390-CB (the "Consolidated Case"). Pursuant to the Court's
consolidation order, plaintiffs filed a consolidated complaint on February 4, 2015, which alleges substantially similar
claims and seeks substantially similar relief to that raised in the six individual complaints, except that while Baker
Hughes is named as a defendant, no claims are asserted against the Company.
On March 18, 2015, the parties reached an agreement in principle to settle the Consolidated Case in exchange
for the Company making certain additional disclosures. Those disclosures were contained in a Form 8-K filed with
the SEC on March 18, 2015. The settlement was made subject to certain conditions, including consummation of the
Merger, final documentation, and court approval. With the termination of the Merger Agreement with Halliburton,
the March 18, 2015 settlement agreement is rendered null and void. On May 31, 2016, the Consolidated Case and
the claims asserted therein were dismissed, save and except for plaintiffs counsel's Fee and Expense Application to
the Delaware Chancery Court. On October 13, 2016, the Delaware Chancery Court ruled on plaintiffs counsel's
Fee and Expense Application. The amount awarded does not have a material impact on our financial position,
results of operations or cash flows.
87
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
On October 9, 2014, one of our subsidiaries filed a Request for Arbitration against a customer before the
London Court of International Arbitration, pursuing claims for the non-payment of invoices for goods and services
provided in an amount provisionally quantified to exceed $67.9 million. In our Request for Arbitration, we also noted
that invoices in an amount exceeding $57 million had been issued to the customer, and would be added to the claim
in the event that they became overdue. On November 6, 2014, the customer filed its Response and Counterclaim,
denying liability and counterclaiming damages for breach of contract of approximately $182 million. On March 31,
2016, the parties agreed to a settlement principally involving the purchase by the customer of certain inventory held
by our subsidiary, with all other claims and counterclaims being released and discharged by each party, and the
arbitral proceedings being discontinued. On April 18, 2016, all claims and counterclaims filed in the London Court
of International Arbitration were released and discontinued. The settlement did not have a material impact on our
financial position, results of operations or cash flows.
During 2014, we received customer notifications related to a possible equipment failure in a natural gas storage
system in Northern Germany, which includes certain of our products. We are currently investigating the cause of
the possible failure and, if necessary, possible repair and replacement options for our products. Similar products
were utilized in other natural gas storage systems for this and other customers. The customer initiated arbitral
proceedings against us on June 19, 2015, under the rules of the German Institute of Arbitration e.V. (DIS). On
August 3, 2016, the customer amended its claims and now alleges damages of approximately $224 million plus
interest at an annual rate of prime + 5%. A hearing before the arbitration panel was held January 16, 2017 through
January 23, 2017, and an additional hearing is scheduled for March 20, 2017 and March 21, 2017. In addition, on
September 21, 2015, TRIUVA Kapitalverwaltungsgesellschaft mbH filed a lawsuit in the United States District Court
for the Southern District of Texas, Houston Division against the Company and Baker Hughes Oilfield Operations,
Inc. alleging that the plaintiff is the owner of gas storage caverns in Etzel, Germany in which the Company provided
certain equipment in connection with the development of the gas storage caverns. The plaintiff further alleges that
the Company supplied equipment that was either defectively designed or failed to warn of risks that the equipment
posed, and that these alleged defects caused damage to the plaintiff's property. The plaintiff seeks recovery of
alleged compensatory and punitive damages of an unspecified amount, in addition to reasonable attorneys' fees,
court costs and pre-judgment and post-judgment interest. The allegations in this lawsuit are related to the claims
made in the June 19, 2015, German arbitration referenced above. At this time, we are not able to predict the
outcome of these claims or whether either will have any material impact on our financial position, results of
operations or cash flows.
On August 31, 2015, a customer of one of the Company's subsidiaries issued a Letter of Claim pursuant to a
Construction and Engineering Contract. The customer had claimed $369 million plus loss of production resulting
from a breach of contract related to five electric submersible pumps installed by the subsidiary in Europe. On
January 29, 2016, the Customer served its Statement of Claim, Case No. CL-2015-00584, in the Commercial Court
Queen's Bench Division of the High Court of Justice. On September 20, 2016, the parties entered a settlement
agreement by which all claims were released and discharged by each party. On October 6, 2016, the Commercial
Court entered a Consent Order dismissing all claims in the litigation. The settlement did not have a material impact
on our financial position, results of operations or cash flows.
On October 30, 2015, Chieftain Sand and Proppant Barron, LLC initiated arbitration against our subsidiary,
Baker Hughes Oilfield Operations, Inc., in the American Arbitration Association. The Claimant alleged that the
Company failed to purchase the required sand tonnage for the contract year 2014-2015 and further alleged that the
Company repudiated its yearly purchase obligations over the remaining contract term. The Claimant alleged
damages of approximately $110 million plus interest, attorneys' fees and costs. On June 2, 2016, the parties
agreed to a settlement of all claims and counterclaims asserted in the Arbitration. The settlement did not have a
material impact on our financial position, results of operations or cash flows.
On April 30, 2015, a class and collective action lawsuit alleging that we failed to pay a nationwide class of
workers overtime in compliance with the Fair Labor Standards Act and North Dakota law was filed titled Williams et
al. v. Baker Hughes Oilfield Operations, Inc. in the U.S. District Court for the District of North Dakota. On February
8, 2016, the Court conditionally certified certain subclasses of employees for collective action treatment. We are
evaluating the background facts and at this time cannot predict the outcome of this lawsuit and are not able to
reasonably estimate the potential impact, if any, such outcome would have on our financial position, results of
operations or cash flows.
88
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
On July 31, 2015, Rapid Completions LLC filed a lawsuit in federal court in the Eastern District of Texas against
Baker Hughes Incorporated, Baker Hughes Oilfield Operations, Inc., and others claiming infringement of U.S.
Patent Nos. 6,907,936; 7,134,505; 7,543,634; 7,861,774; and 8,657,009. On August 6, 2015, Rapid Completions
amended its complaint to allege infringement of U.S. Patent No. 9,074,451. On September 17, 2015, Rapid
Completions and Packers Plus Energy Services Inc., sued Baker Hughes Canada Company in the Canada Federal
Court on related Canadian patent 2,412,072. On April 1, 2016, Rapid Completions removed U.S. Patent No.
6,907,936 from its claims in the lawsuit. On April 5, 2016, Rapid Completions filed a second lawsuit in federal court
in the Eastern District of Texas against Baker Hughes Incorporated, Baker Hughes Oilfield Operations, Inc. and
others claiming infringement of U.S. Patent No. 9,303,501. These patents relate primarily to certain specific
downhole completions equipment. The plaintiff has requested a permanent injunction against further alleged
infringement, damages in an unspecified amount, supplemental and enhanced damages, and additional relief such
as attorney's fees and costs. During August and September 2016, the United States Patent and Trademark office
agreed to institute an inter-partes review of U.S. Patent Nos 7,861,774; 7,134,505; 7,534,634; 6,907,936;
8,657,009; and 9,074,451. At this time, we are not able to predict the outcome of these claims or whether they will
have a material impact on our financial position, results of operations or cash flows.
On April 6, 2016, a civil Complaint against Baker Hughes Incorporated and Halliburton Company was filed by
the United States of America seeking a permanent injunction restraining Baker Hughes and Halliburton from
carrying out the planned acquisition of Baker Hughes by Halliburton or any other transaction that would combine the
two companies. The lawsuit is styled United States of America v. Halliburton Co. and Baker Hughes Inc., in the U.S.
District Court for the District of Delaware, Case No. 1:16-cv-00233-UNA. The Complaint alleges that the proposed
transaction between Halliburton and Baker Hughes would violate Section 7 of the Clayton Act. Subsequent to the
filing of the Complaint, on April 30, 2016, the Merger Agreement with Halliburton was terminated as described in
Note 2. "Halliburton Terminated Merger Agreement." On May 4, 2016, the United States filed a Notice of Voluntary
Dismissal of the Complaint.
On May 30, 2013, we received a Civil Investigative Demand ("CID") from the U.S. Department of Justice
("DOJ") pursuant to the Antitrust Civil Process Act. The CID sought documents and information from us for the
period from May 29, 2011 through the date of the CID in connection with a DOJ investigation related to pressure
pumping services in the U.S. On May 18, 2016, we received notice from the DOJ that they have closed the
investigation with no further action requested of the Company.
ENVIRONMENTAL MATTERS
Our past and present operations include activities that are subject to extensive domestic (including U.S. federal,
state and local) and international environmental regulations with regard to air, land and water quality and other
environmental matters. Our environmental procedures, policies and practices are designed to ensure compliance
with existing laws and regulations and to minimize the possibility of significant environmental damage.
We are involved in voluntary remediation projects at certain of our facilities. On rare occasions, remediation
activities are conducted as specified by a government agency-issued consent decree or agreed order. Remediation
costs are accrued based on estimates of probable exposure using currently available facts, existing environmental
permits, technology and presently enacted laws and regulations. Remediation cost estimates include direct costs
related to the environmental investigation, external consulting activities, governmental oversight fees, treatment
equipment and costs associated with long-term operation, maintenance and monitoring of a remediation project.
We have also been identified as a potentially responsible party ("PRP") in remedial activities related to various
Superfund sites. In these instances, we participate in the process set out in the Joint Participation and Defense
Agreement to negotiate with government agencies, identify other PRPs, and determine each PRP's allocation and
estimate remediation costs. We have accrued what we believe to be our pro-rata share of the total estimated cost
of remediation and associated management of these Superfund sites. This share is based upon the ratio that the
estimated volume of waste we contributed to the site to the total estimated volume of waste disposed at the site.
Applicable U.S. federal law imposes joint and several liability on each PRP for the cleanup of these sites leaving us
with the uncertainty that we may be responsible for the remediation cost attributable to other PRPs who are unable
to pay their share. No accrual has been made under the joint and several liability concept for those Superfund sites
where our participation is de minimis since we believe that the probability that we will have to pay material costs
89
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
above our volumetric share is remote. We believe there are other PRPs who have greater involvement on a
volumetric calculation basis, who have substantial assets and who may be reasonably expected to pay their share
of the cost of remediation. For those Superfund sites where we are a significant PRP, remediation costs are
estimated to include recalcitrant parties. In some cases, we have insurance coverage or contractual indemnities
from third parties to cover a portion of the ultimate liability.
Our total accrual for environmental remediation is $31 million and $35 million, at December 31, 2016 and 2015,
respectively, which includes accruals of $2 million in each year for the various Superfund sites. The determination
of the required accruals for remediation costs is subject to uncertainty, including the evolving nature of
environmental regulations and the difficulty in estimating the extent and type of remediation activity that is
necessary.
OTHER
In the normal course of business with customers, vendors and others, we have entered into off-balance sheet
arrangements, such as surety bonds for performance, letters of credit and other bank issued guarantees, which
totaled approximately $1.0 billion at December 31, 2016. It is not practicable to estimate the fair value of these
financial instruments. None of the off-balance sheet arrangements either has, or is likely to have, a material effect
on our consolidated financial statements. We also had commitments outstanding for purchase obligations related to
capital expenditures, inventory and services under contracts, for each of the five years in the period ending
December 31, 2021 of $102 million, $43 million, $38 million, $36 million and $30 million, respectively, and $37
million in the aggregate thereafter.
90
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 16. ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table presents the changes in accumulated other comprehensive loss, net of tax:
Balance at December 31, 2014
Other comprehensive income before reclassifications:
Foreign currency translation adjustments
Pensions and other postretirement benefits:
Actuarial net loss arising in the year
Deferred taxes
Amounts reclassified from accumulated other comprehensive loss:
Amortization of net actuarial loss
Amortization of prior service credit
Curtailment
Deferred taxes
Balance at December 31, 2015
Other comprehensive income before reclassifications:
Foreign currency translation adjustments
Pensions and other postretirement benefits:
Actuarial net loss arising in the year
Amounts reclassified from accumulated other comprehensive loss:
Amortization of net actuarial loss
Amortization of prior service credit
Curtailment
Deferred taxes
Balance at December 31, 2016
$
Pensions and
Other
Postretirement
Benefits
Foreign
Currency
Translation
Adjustments
Accumulated
Other
Comprehensive
Loss
$
(246) $
(503) $
(749)
(241)
(241)
(18)
10
16
(10)
(18)
5
(261)
(23)
17
(9)
(9)
1
(284) $
(18)
10
16
(10)
(18)
5
(1,005)
(5)
(23)
17
(9)
(9)
1
(1,033)
(744)
(5)
(749) $
The amounts reclassified from accumulated other comprehensive loss during the twelve months ended
December 31, 2016 and 2015 represent the amortization of net actuarial loss and prior service credit, and
curtailments which are included in the computation of net periodic pension cost (see Note 14. "Employee Benefit
Plans" for additional details). Net periodic pension cost is recorded across the various cost and expense line items
within the consolidated statement of income (loss).
91
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 17. QUARTERLY DATA (UNAUDITED)
2016
Revenue
Gross profit (1)
Impairment and restructuring charges (2)
Goodwill impairment (3)
Merger termination fee (4)
Net loss attributable to Baker Hughes
Basic and diluted loss per share attributable to Baker
Hughes
Dividends per share
Common stock market prices:
High
Low
2015
Revenue
Gross profit (1)
Impairment and restructuring charges (2)
Net loss attributable to Baker Hughes
Basic and diluted loss per share attributable to Baker
Hughes
Dividends per share
Common stock market prices:
High
Low
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
Year
$ 2,670
$ 2,408
$ 2,353
$ 2,410
$ 9,841
(90)
160
—
—
(981)
(2.22)
0.17
(803)
1,126
1,841
(3,500)
(911)
(2.08)
0.17
203
304
17
—
174
145
—
—
(429)
(417)
(1.00)
0.17
(0.98)
0.17
(516)
1,735
1,858
(3,500)
(2,738)
(6.31)
0.68
47.44
38.88
49.52
39.36
52.70
43.54
66.89
49.96
$ 4,594
$ 3,968
$ 3,786
$ 3,394
$ 15,742
114
573
(589)
(1.35)
0.17
266
76
(188)
(0.43)
0.17
301
98
180
1,246
861
1,993
(159)
(1,031)
(1,967)
(0.36)
0.17
(2.35)
0.17
(4.49)
0.68
65.04
53.53
69.13
61.11
61.13
45.76
57.33
43.36
(1) Represents revenue less cost of sales, cost of services and research and engineering.
(2)
Impairment and restructuring charges associated with asset impairments, workforce reductions, facility
closures and contract terminations recorded during 2015 and 2016. See Note 4. "Impairment and
Restructuring Charges" for further discussion.
(3) Goodwill impairment recognized in the second and third quarters of 2016. See Note 12. "Goodwill and
Intangible Assets" for further discussion.
(4) Merger termination fee received from Halliburton. See Note 2. "Halliburton Terminated Merger Agreement"
for further discussion.
92
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this annual report, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act of 1934, as
amended (the "Exchange Act"). This evaluation was carried out under the supervision and with the participation of
our management, including our principal executive officer and principal financial officer. Based on this evaluation,
these officers have concluded that, as of December 31, 2016, our disclosure controls and procedures, as defined by
Rule 13a-15(e) of the Exchange Act, are effective at a reasonable assurance level.
During the quarter ended March 31, 2016, we identified a material weakness in our controls related to the
determination of valuation allowances for deferred tax assets. A material weakness is a deficiency, or a combination
of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material
misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely
basis. Our identified weakness had no impact on any amounts reported in the financial statements for the quarter
ended March 31, 2016 or for any previous period. We evaluated the controls associated with valuation allowances
for deferred tax assets and designed a remediation plan to address the identified weakness by strengthening the
controls over this process. During the second and third quarters of 2016, we implemented a remediation plan which
included various control enhancements. Subsequent to implementation, the control enhancements were tested and
determined to be designed and operating effectively. Accordingly, we believe the weakness is considered
remediated.
Disclosure controls and procedures are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit under the Exchange Act, such as this
annual report, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules
and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to
ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is
accumulated and communicated to our management, including our principal executive officer and principal financial
officer, as appropriate, to allow timely decisions regarding required disclosure.
Design and Evaluation of Internal Control Over Financial Reporting
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their
assessment of the design and effectiveness of our internal controls over financial reporting as part of this annual
report on Form 10-K for the fiscal year ended December 31, 2016. Deloitte & Touche LLP, the Company's
independent registered public accounting firm, has issued an attestation report on the effectiveness of the
Company's internal control over financial reporting. Management's report and the independent registered public
accounting firm's attestation report are included in Item 8 under the caption entitled "Management's Report on
Internal Control Over Financial Reporting" and "Report of Independent Registered Public Accounting Firm" and are
incorporated herein by reference.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal controls over financial reporting during the quarter ended
December 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal controls over
financial reporting.
ITEM 9B. OTHER INFORMATION
None.
93
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding the Business Code of Conduct and Code of Ethical Conduct Certificates for our principal
executive officer, principal financial officer and principal accounting officer are described in Item 1. Business of this
Annual Report. Information concerning our directors is set forth in the sections entitled "Proposal No. 1, Election of
Directors," and "Corporate Governance - Committees of the Board" in our Definitive Proxy Statement for the
2017Annual Meeting of Stockholders to be filed with the SEC pursuant to the Exchange Act within 120 days of the
end of our fiscal year on December 31, 2016 ("Proxy Statement"), which sections are incorporated herein by
reference. For information regarding our executive officers, see "Item 1. Business - Executive Officers" in this
annual report on Form 10-K. Additional information regarding compliance by directors and executive officers with
Section 16(a) of the Exchange Act is set forth under the section entitled "Compliance with Section 16(a) of the
Securities Exchange Act of 1934" in our Proxy Statement, which section is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information for this item is set forth in the following sections of our Proxy Statement, which sections are
incorporated herein by reference: "Compensation Discussion and Analysis," "Director Compensation,"
"Compensation Committee Interlocks and Insider Participation" and "Compensation Committee Report."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
Information concerning security ownership of certain beneficial owners and our management is set forth in the
sections entitled "Voting Securities" and "Security Ownership of Management" in our Proxy Statement, which
sections are incorporated herein by reference.
Our Board of Directors has approved procedures for use under our Securities Trading and Disclosure Policy to
permit our employees, officers and directors to enter into written trading plans complying with Rule 10b5-1 under the
Exchange Act. Rule 10b5-1 provides criteria under which such an individual may establish a prearranged plan to
buy or sell a specified number of shares of a company's stock over a set period of time. Any such plan must be
entered into in good faith at a time when the individual is not in possession of material, nonpublic information. If an
individual establishes a plan satisfying the requirements of Rule 10b5-1, such individual's subsequent receipt of
material, nonpublic information will not prevent transactions under the plan from being executed. Certain of our
officers have advised us that they have and may enter into a stock sales plan for the sale of shares of our common
stock which are intended to comply with the requirements of Rule 10b5-1 of the Exchange Act. In addition, the
Company has and may in the future enter into repurchases of our common stock under a plan that complies with
Rule 10b5-1 or Rule 10b-18 of the Exchange Act.
Equity Compensation Plan Information
The information in the following table is presented as of December 31, 2016 with respect to shares of our
common stock that may be issued under our existing equity compensation plans, including the Baker Hughes
Incorporated 2002 Employee Long-Term Incentive Plan, the Baker Hughes Incorporated 2002 Director & Officer
Long-Term Incentive Plan, and the Employee Stock Purchase Plan, all of which have been approved by our
stockholders (in millions, except per share prices).
94
Equity Compensation Plan
Category
Stockholder-approved plans (excluding Employee
Stock Purchase Plan)
Nonstockholder-approved plans (1)
Subtotal (except for weighted average exercise price)
Employee Stock Purchase Plan (2)
Total
Number of
Securities to be
Issued Upon
Exercise of
Outstanding
Options, Warrants
and Rights
Weighted Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(excluding securities
reflected in the first
column)
7.1
0.1
7.2
—
7.2
$ 54.11
46.72
54.09
—
$ 54.09
16.4
0.5
16.9
2.7
19.6
(1) The table includes the following nonstockholder-approved plan: the Director Compensation Deferral Plan.
A description of this plan is set forth below.
(2) The per share purchase price under the Baker Hughes Incorporated Employee Stock Purchase Plan is
determined in accordance with section 423 of the Code and is 85% of the lower of the fair market value of a
share of our common stock on the date of grant or the date of purchase.
Our nonstockholder-approved plan is described below:
Director Compensation Deferral Plan
The Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective
January 1, 2009 and as further amended on July 25, 2013 (the "Deferral Plan"), is intended to provide a means for
members of our Board of Directors to defer compensation otherwise payable and provide flexibility with respect to
our compensation policies. Under the provisions of the Deferral Plan, directors may elect to defer income with
respect to each calendar year. The compensation deferrals may be stock option-related deferrals or cash-based
deferrals. If a director elects a stock option-related deferral, on the last day of each calendar quarter he or she will
be granted a non-qualified stock option. The number of shares subject to the stock option is calculated by
multiplying the amount of the deferred compensation that otherwise would have been paid to the director during the
quarter by 4.4 and then dividing by the fair market value of our common stock on the last day of the quarter. The
per share exercise price of the option will be the fair market value of a share of our common stock on the date the
option is granted. Stock options granted under the Deferral Plan vest on the first anniversary of the date of grant
and must be exercised within ten years of the date of grant. If a director's directorship terminates for any reason,
any options outstanding will expire on the earlier of five years after the termination of the directorship or the option
expiration date. The maximum aggregate number of shares of our common stock that may be issued under the
Deferral Plan is 0.5 million. As of December 31, 2016, options covering approximately 17,000 shares of our
common stock were outstanding under the Deferral Plan, there were no shares exercised during fiscal year 2016
and approximately 0.5 million shares remained available for future options.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information for this item is set forth in the sections entitled "Corporate Governance-Director Independence" and
"Certain Relationships and Related Transactions" in our Proxy Statement, which sections are incorporated herein by
reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning principal accountant fees and services is set forth in the section entitled "Fees Paid to
Deloitte & Touche LLP" in our Proxy Statement, which section is incorporated herein by reference.
95
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) List of Documents filed as part of this annual report.
(1) Financial Statements
All financial statements of the Company as set forth under Item 8 of this annual report on Form 10-K.
(2) Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts
(3) Exhibits
Each exhibit identified below is filed as a part of this annual report. Exhibits designated with an "*" are filed as
an exhibit to this annual report on Form 10-K and exhibits designated with an "**" are furnished as an exhibit to this
annual report on Form 10-K. Exhibits designated with a "+" are identified as management contracts or
compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference.
Exhibit
Number
2.1
2.2
2.3
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Exhibit Description
Agreement and Plan of Merger dated as of November 16, 2014 among Halliburton Company, Red
Tiger LLC and Baker Hughes Incorporated (filed as Exhibit 2.1 to the Current Report of Baker Hughes
Incorporated on Form 8-K filed on November 18, 2014).
Transaction Agreement and Plan of Merger dated as of October 30, 2016 among General Electric
Company, Baker Hughes Incorporated, Bear Newco, Inc. and Bear MergerSub, Inc. (filed as Exhibit
2.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on November 1, 2016).
Contribution Agreement dated as of November 29, 2016 among Baker Hughes Oilfield Operations,
Inc., BJ Services LLC, and Allied Completions Holdings, LLC (filed as Exhibit 2.1 to the Current Report
to Baker Hughes Incorporated on Form 8-K on December 1, 2016).
Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporation (filed as
Exhibit 3.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended
March 31, 2010).
Restated Bylaws of Baker Hughes Incorporated effective as of January 26, 2017 (filed as Exhibit 3.1 to
the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
Rights of Holders of the Company's Long-Term Debt. The Company has no long-term debt instrument
with regard to which the securities authorized thereunder equal or exceed 10% of the total assets of
the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of
its long-term debt instruments to the SEC upon request.
Certificate of Amendment dated April 22, 2010 and the Restated Certificate of Incorporation (filed as
Exhibit 3.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended
March 31, 2010).
Restated Bylaws of Baker Hughes Incorporated effective as of January 26, 2017 (filed as Exhibit 3.1 to
the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
Indenture dated as of May 15, 1994 between Western Atlas Inc. and The Bank of New York, Trustee,
providing for the issuance of securities in series (filed as Exhibit 4.4 to the Annual Report of Baker
Hughes Incorporated on Form 10-K for the year ended December 31, 2004).
Indenture dated October 28, 2008, between Baker Hughes Incorporated and The Bank of New York
Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Current Report of Baker Hughes
Incorporated on Form 8-K filed on October 29, 2008).
First Supplemental Indenture, dated August 17, 2011, between Baker Hughes Incorporated and The
Bank of New York Mellon Trust Company, N.A., as trustee (including form of Notes) (filed as Exhibit
4.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed August 23, 2011).
Officers' Certificate of Baker Hughes Incorporated dated October 28, 2008 establishing the 6.50%
Senior Notes due 2013 and the 7.50% Senior Notes due 2018 (filed as Exhibit 4.2 to the Current
Report of Baker Hughes Incorporated on Form 8-K filed on October 29, 2008).
96
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
10.1+
10.2+
10.3+
10.4+
10.5+
10.6+
10.7 +*
10.8+
10.9+
10.10+
10.11+
10.12+
Form of 7.50% Senior Notes Due 2018 (filed as Exhibit 4.4 to the Current Report of Baker Hughes
Incorporated on Form 8-K filed on October 29, 2008).
Officers' Certificate of Baker Hughes Incorporated dated August 24, 2010 establishing the 5.125%
Senior Notes due 2040 (filed as Exhibit 4.2 to the Current Report of Baker Hughes Incorporated on
Form 8-K filed on August 24, 2010).
Form of 5.125% Senior Notes due 2040 (filed as Exhibit 4.3 to the Current Report of Baker Hughes
Incorporated on Form 8-K filed on August 24, 2010).
Indenture, dated June 8, 2006, between BJ Services Company, as issuer, and Wells Fargo Bank, N.A.,
as trustee (filed as Exhibit 4.1 to the Current Report of BJ Services Company on Form 8-K filed on
June 12, 2006).
Third Supplemental Indenture, dated May 19, 2008, between BJ Services Company, as issuer, and
Wells Fargo Bank, N.A., as trustee, with respect to the 6% Senior Notes due 2018 (filed as Exhibit 4.2
to the Current Report of BJ Services Company on Form 8-K filed on May 23, 2008).
Fourth Supplemental Indenture, dated April 28, 2010, between BJ Services Company, as issuer, BSA
Acquisition LLC, Baker Hughes Incorporated and Wells Fargo Bank, N.A., as trustee, with respect to
the 5.75% Senior Notes due 2011 and the 6% Senior Notes due 2018 (filed as Exhibit 4.4 to the
Current Report of Baker Hughes Incorporated on Form 8-K filed on April 29, 2010).
Fifth Supplemental Indenture, dated June 21, 2011, between BJ Services Company LLC, as company,
Western Atlas Inc. as successor company and Wells Fargo Bank, N.A., as trustee, with respect to the
6.00% Senior Notes due 2018 (incorporated by reference to Exhibit 4.4 to the Current Report of Baker
Hughes Incorporated on Form 8-K filed on June 23, 2011).
Registration Rights Agreement dated August 17, 2011 among Baker Hughes Incorporated and J.P.
Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of
the several initial purchasers named therein (filed as Exhibit 10.1 to the Current Report of Baker
Hughes Incorporated on Form 8-K filed on August 23, 2011).
Form of Amended and Restated Change in Control Agreement between Baker Hughes Incorporated
and each of the executive officers effective as of January 1, 2009 (filed as Exhibit 10.2 to the Current
Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008).
Amendment and Restatement of the Baker Hughes Incorporated Change in Control Severance Plan
effective as of January 1, 2009 (filed as Exhibit 10.3 to the Current Report of Baker Hughes
Incorporated on Form 8-K filed on December 19, 2008).
Form of Change in Control Agreement between Baker Hughes Incorporated and certain of the
executive officers effective as of July 16, 2012 (filed as Exhibit 10.1 to the Quarterly Report of Baker
Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2012).
Form of Executive Loyalty, Confidentiality, Non-Solicitation, and Non-Competition Agreement between
Baker Hughes Incorporated and certain of the executive officers (filed as Exhibit 10.3 to the Annual
Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2011).
Baker Hughes Incorporated Compensation Recoupment Policy effective January 1, 2014 (filed as
Exhibit 10.10 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on January 28,
2014).
Letter Agreement between Baker Hughes Incorporated and Alan R. Crain dated July 29, 2016 (filed as
Exhibit 10.1 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended September 30, 2016).
Letter Agreement between Baker Hughes Incorporated and Kimberly A. Ross dated December 30,
2016.
Form of Indemnification Agreement between Baker Hughes Incorporated and each of the directors and
executive officers (filed as Exhibit 10.4 to the Annual Report of Baker Hughes Incorporated on Form
10-K for the year ended December 31, 2003).
Form of Amendment to the Indemnification Agreement between Baker Hughes Incorporated and each
of the directors and executive officers effective as of January 1, 2009 (filed as Exhibit 10.4 to the
Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008).
Baker Hughes Incorporated Director Retirement Policy for Certain Members of the Board of Directors
(filed as Exhibit 10.10 to the Annual Report of Baker Hughes Incorporated on Form 10-K for the year
ended December 31, 2003).
Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective
as of January 1, 2009 (filed as Exhibit 10.2 to the Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended June 30, 2008).
Amendment to Baker Hughes Incorporated Director Compensation Deferral Plan effective as of
January 1, 2009 (filed as Exhibit 10.5 to the Current Report of Baker Hughes Incorporated on Form 8-
K filed on December 19, 2008).
97
10.13+
10.14 +
10.15+
10.16+
10.17+
10.18+
10.19+
10.20+
10.21+
10.22+
10.23+
10.24+
10.25+
10.26+
10.27+
10.28+
10.29+
10.30+
10.31+
10.32+
Amendment to the Baker Hughes Incorporated Director Compensation Deferral Plan effective as of
July 25, 2013 (filed as Exhibit 10.11 to the Annual Report of Baker Hughes Incorporated on Form 10-K
for the year ended December 31, 2013).
Amendment and Restatement of the Baker Hughes Incorporated Executive Severance Plan effective
as of May 24, 2016 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form
8-K filed on May 25, 2016).
Baker Hughes Incorporated Annual Incentive Compensation Plan for officers, as amended and
restated on January 23, 2014 (filed as Exhibit 10.5 to the Current Report of Baker Hughes
Incorporated on Form 8-K filed on January 28, 2014).
Amendment to the Amended and Restated Baker Hughes Incorporated Annual Incentive
Compensation Plan for employees dated March 13, 2015 (filed as Exhibit 10.2 to the Current Report of
Baker Hughes Incorporated on Form 8-K filed on March 18, 2015).
Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of
January 1, 2012 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-
K filed on December 20, 2011).
Amended and Restated Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan
effective April 24, 2014 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on
Form 8-K filed on April 29, 2014).
Amended and Restated Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan
effective April 24, 2014 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on
Form 8-K filed on April 29, 2014).
Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of
January 1, 2012 (filed as Exhibit 10.25 to the Annual Report of Baker Hughes Incorporated on Form
10-K for the year ending December 31, 2012).
Amendment to the Baker Hughes Incorporated Employee Stock Purchase Plan effective as of April 25,
2013 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on
April 30, 2013).
Amendment to the Baker Hughes Incorporated Employee Stock Purchase Plan effective as of
December 31, 2014 (filed as Exhibit 10.28 to the Annual Report of Baker Hughes Incorporated on
Form 10-K for the fiscal year ending December 31, 2014).
Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement with Terms and Conditions
for officers (filed as Exhibit 10.30 to the Annual Report of Baker Hughes Incorporated on Form 10-K for
the year ended December 31, 2009).
Form of Baker Hughes Incorporated Nonqualified Stock Option Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.70 to the Annual Report of Baker Hughes Incorporated on
Form 10-K for the year ended December 31, 2011).
Form of Baker Hughes Incorporated Nonqualified Stock Option Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.6 to the Current Report of Baker Hughes Incorporated on
Form 8-K filed on January 28, 2014).
Form of Baker Hughes Incorporated Nonqualified Stock Option Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.6 to the Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended June 30, 2014).
Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.33 to the Annual Report of Baker Hughes Incorporated on
Form 10-K for the year ended December 31, 2009).
Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.71 to the Annual Report of Baker Hughes Incorporated on
Form 10-K for the year ended December 31, 2011).
Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.7 to the Current Report of Baker Hughes Incorporated on
Form 8-K filed on January 28, 2014).
Form of Baker Hughes Incorporated Incentive Stock Option Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.7 to the Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended June 30, 2014).
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.9 to the Current Report of Baker Hughes Incorporated on
Form 8-K filed on January 28, 2014).
Form of Baker Hughes Incorporated Restricted Stock Award Agreement and Terms and Conditions for
officers (filed as Exhibit 10.8 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on
January 28, 2014).
98
10.33+
10.34+
10.35+
10.36+
10.37+
10.38+
10.39+
10.40+
10.41+*
10.42+
10.43+
10.44+
10.45+
10.46+
10.47+
10.48+
10.49+
10.50+
10.51
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.5 to the Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended June 30, 2014).
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for officers (filed as Exhibit 10.42 to the Annual Report of Baker Hughes Incorporated on
Form 10-K for the year ended December 31, 2014).
Form of Baker Hughes Incorporated Restricted Stock Award Agreement and Terms and Conditions for
officers (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K filed on
May 25, 2016).
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for officers with a three-year cliff vesting (filed as Exhibit 10.1 to the Current Report of
Baker Hughes Incorporated on Form 8-K filed on July 29, 2016).
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for officers with a three-year graded vesting (filed as Exhibit 10.2 to the Current Report of
Baker Hughes Incorporated on Form 8-K filed on July 29, 2016).
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for officers with a three-year graded vesting (filed as Exhibit 10.2 to the Current Report of
Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for officers with a three-year cliff vesting (filed as Exhibit 10.1 to the Current Report of
Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for directors (filed as Exhibit 10.44 to the Annual Report of Baker Hughes Incorporated on
Form 10-K for the year ended December 31, 2014).
Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and
Conditions for directors.
Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and Conditions
for directors (filed as Exhibit 10.41 to the Annual Report of Baker Hughes Incorporated on Form 10-K
for the year ended December 31, 2005).
Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions
for certain officers payable in cash (filed as Exhibit 10.3 to the Current Report of Baker Hughes
Incorporated on Form 8-K filed on January 28, 2014).
Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions
for certain officers payable in shares (filed as Exhibit 10.4 to the Current Report of Baker Hughes
Incorporated on Form 8-K filed on January 28, 2014).
Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions
for certain officers payable in cash (filed as Exhibit 10.3 to the Quarterly Report of Baker Hughes
Incorporated on Form 10-Q for the quarter ended June 30, 2014).
Form of Baker Hughes Incorporated Performance Unit Award Agreement and Terms and Conditions
for certain officers payable in shares (filed as Exhibit 10.4 to the Quarterly Report of Baker Hughes
Incorporated on Form 10-Q for the quarter ended June 30, 2014).
Form of Baker Hughes Incorporated Performance Based Restricted Stock Unit Award Agreement and
Terms and Conditions for officers with a three-year cliff vesting (filed as Exhibit 10.3 to the Current
Report of Baker Hughes Incorporated on Form 8-K filed on January 31, 2017).
Performance Goals adopted January 22, 2014 for the Performance Unit Awards payable in cash
granted in 2014 (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K
filed on January 28, 2014).
Performance Goals adopted January 22, 2014 for the Performance Unit Awards payable in shares
granted in 2014 (filed as Exhibit 10.2 to the Current Report of Baker Hughes Incorporated on Form 8-K
filed on January 28, 2014).
Performance Goals adopted January 25, 2017 for the Performance Based Restricted Stock Unit
Awards granted in 2017 (filed as Exhibit 10.4 to the Current Report of Baker Hughes Incorporated on
Form 8-K filed on January 31, 2017).
Credit Agreement dated as of July 13, 2016, among Baker Hughes Incorporated, JP Morgan Chase
Bank, N.A., as Administrative Agent and twenty lenders for $2.5 billion, in the aggregate for all banks
(filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed July 14,
2016).
99
10.52
10.53
21.1*
23.1*
31.1**
31.2**
32**
Plea Agreement between Baker Hughes Services International, Inc. and the United States Department
of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed
as Exhibit 10.5 to the Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended March 31, 2007).
Termination Agreement dated as of April 30, 2016 among Halliburton Company, Red Tiger LLC and
Baker Hughes Incorporated (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated
on Form 8-K filed on May 2, 2016).
Subsidiaries of Company.
Consent of Deloitte & Touche LLP.
Certification of Martin S. Craighead, Chairman and Chief Executive Officer, furnished pursuant to Rule
13a-14(a) of the Securities Exchange Act of 1934, as amended.
Certification of Kimberly A. Ross, Chief Financial Officer, furnished pursuant to Rule 13a-14(a) of the
Securities Exchange Act of 1934, as amended.
Statement of Martin S. Craighead, Chairman and Chief Executive Officer, and Kimberly A. Ross, Chief
Financial Officer, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as
amended.
Mine Safety Disclosures.
95*
101.INS* XBRL Instance Document.
101.SCH* XBRL Schema Document.
101.CAL* XBRL Calculation Linkbase Document.
101.LAB* XBRL Label Linkbase Document.
101.PRE* XBRL Presentation Linkbase Document.
101.DEF* XBRL Definition Linkbase Document.
100
Baker Hughes Incorporated
Schedule II - Valuation and Qualifying Accounts
(In millions)
Year Ended December 31, 2016
Balance at
Beginning
of Period
Charged to
Cost and
Expenses
Write-
offs (1)
Other
Changes (2) (3)
Balance at
End of
Period
Reserve for doubtful accounts receivable
Reserve for inventories
$
Year Ended December 31, 2015
Reserve for doubtful accounts receivable
Reserve for inventories
Year Ended December 31, 2014
Reserve for doubtful accounts receivable
Reserve for inventories
$
383
278
224
319
238
382
188
181
193
195
102
37
$
(59) $
(275)
(23)
(235)
(71)
(92)
(3) $
4
(11)
(1)
(45)
(8)
509
188
383
278
224
319
(1) Represents the elimination of accounts receivable and inventory deemed uncollectible or worthless. See
Note 10. "Inventories" of the Notes to Consolidated Financial Statements in Item 8 herein for further
discussion of the inventory write-offs and related reserves.
(2) Represents transfers, currency translation adjustments and divestitures.
(3) For the year ended December 31, 2014, the reserve for doubtful accounts receivable includes a $39 million
reduction due to the currency devaluation in Venezuela.
101
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: February 7, 2017
BAKER HUGHES INCORPORATED
/s/ MARTIN S. CRAIGHEAD
Martin S. Craighead
Chairman and Chief Executive Officer
KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes
and appoints Martin S. Craighead and Kimberly A. Ross, each of whom may act without joinder of the other, as their
true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for such person
and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual
Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith,
with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and
authority to do and perform each and every act and thing requisite and necessary to be done in and about the
premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all
that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed
below by the following persons on behalf of the registrant and in the capacities indicated on this 7th day of February
2017.
Signature
Title
/S/ MARTIN S. CRAIGHEAD
(Martin S. Craighead)
Chairman and Chief Executive Officer
(principal executive officer)
/S/ KIMBERLY A. ROSS
(Kimberly A. Ross)
/S/ KELLY C. JANZEN
(Kelly C. Janzen)
Senior Vice President and Chief Financial Officer
(principal financial officer)
Vice President, Controller and Chief Accounting Officer
(principal accounting officer)
102
/s/ GREGORY D. BRENNEMAN
(Gregory D. Brenneman)
/s/ CLARENCE P. CAZALOT, JR.
(Clarence P. Cazalot, Jr.)
/s/ WILLIAM H. EASTER III
(William H. Easter III)
/s/ LYNN L. ELSENHANS
(Lynn L. Elsenhans)
/s/ ANTHONY G. FERNANDES
(Anthony G. Fernandes)
/s/ CLAIRE W. GARGALLI
(Claire W. Gargalli)
/s/ PIERRE H. JUNGELS
(Pierre H. Jungels)
/s/ JAMES A. LASH
(James A. Lash)
/s/ J. LARRY NICHOLS
(J. Larry Nichols)
/s/ JAMES W. STEWART
(James W. Stewart)
/s/ CHARLES L. WATSON
(Charles L. Watson)
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
103
PAGE INTENTIONALLY LEFT BLANK
CORPORATE INFORMATION
BOARD OF DIRECTORS
EXECUTIVE LEADERSHIP
Gregory D. Brenneman
Executive Chairman
CCMP Capital Advisors, LLC
Clarence P. Cazalot, Jr.
Former Executive Chairman,
President, and
Chief Executive Officer
Marathon Oil Corporation
Martin S. Craighead
Chairman and
Chief Executive Officer
Baker Hughes Incorporated
William H. Easter III
Former Chairman, President,
and Chief Executive Officer
DCP Midstream LLC
Lynn L. Elsenhans
Former Executive Chairman,
Chief Executive Officer,
and President, Sunoco, Inc.
Anthony G. Fernandes
Former Chairman, President,
and Chief Executive Officer
Philip Services Corporation
Claire W. Gargalli
Former Vice Chairman
Diversified Search and Diversified
Health Search Companies
Pierre H. Jungels, CBE
Former President
The Institute of Petroleum
James A. Lash
Chairman
Manchester Principal LLC
J. Larry Nichols
Emeritus Chairman
Devon Energy Corporation
James W. Stewart
Former Chairman, President,
and Chief Executive Officer
BJ Services Company
Charles L. Watson
Chairman
Twin Eagle Management Resources
OTHER CORPORATE OFFICERS
Dominic A. Savarino
Vice President, Tax
Lee Whitley
Vice President and Corporate
Secretary
Donal Antil
Vice President, Internal Audit
Ok Azie
Vice President, Treasurer
Kelly Janzen
Vice President, Controller and
Chief Accounting Officer
Jay G. Martin
Vice President, Chief Compliance
Officer, and Senior Deputy Counsel
Derek Mathieson
Vice President and
Chief Commercial Officer
Kimberly A. Ross
Senior Vice President and
Chief Financial Officer
Arthur L. Soucy
President, Products and Technology
Richard L. Williams
Senior Advisor, Executive
Leadership Team
Martin S. Craighead
Chairman and
Chief Executive Officer
Belgacem Chariag
President, Global Operations
Archana Deskus
Vice President and
Chief Information Officer
Jack Hinton
Vice President
Health, Safety, and Environment
Murali Kuppuswamy
Vice President and
Chief Human Resources Officer
William D. Marsh
Vice President and General Counsel
As a Baker Hughes stockholder, you are invited to take advantage of
our convenient stockholder services or request more information about
Baker Hughes. Computershare Investor Services, our transfer agent,
maintains the records for our registered stockholders and can help
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Stockholder Information
Transfer Agent and Registrar
Computershare Investor Services
P.O. Box 30170
College Station, Texas
77842-3170
+1.888.216.8057
New York Stock Exchange
Last year our Annual CEO
Certification, without qualifica-
tions, was timely submitted
to the NYSE. Also, we file our
certifications required under
SOX as exhibits to our Form 10-K.
Stock Exchange Listings
Ticker Symbol “BHI”
New York Stock Exchange, Inc.
SIX Swiss Exchange
Investor Relations Office
Alondra Oteyza
Director, Investor Relations
Baker Hughes Incorporated
P.O. Box 4740
Houston, Texas 77210-4740
ir@bakerhughes.com
Form 10-K
Additional copies of the
Company’s Annual Report to
the Securities and Exchange
Commission (Form10-K) are
available by writing:
Baker Hughes Investor Relations
P.O. Box 4740
Houston, Texas 77210-4740
Also available at our website:
http://www.bakerhughes.com/
annualreport
Annual Meeting
The Company’s Annual Meeting
of Stockholders will be held:
9:00 a.m. Houston-Texas-time
April 27, 2017
2001 Rankin Road
Rankin Auditorium
Houston, Texas 77073
Corporate Office Location
and Mailing Address
17021 Aldine Westfield Road
Houston, Texas 77073
Telephone: +1.713.439.8600
P.O. Box 4740
Houston, Texas 77210-4740
Website
www.bakerhughes.com
17021 Aldine Westfield Road
Houston, Texas 77073
P.O. Box 4740
Houston, Texas 77210-4740
BakerHughes.com
46744