Document
                                                        

                                    

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
þ
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2016
OR
o
 
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
76-0207995
(State or other jurisdiction
(I.R.S. Employer Identification No.)
of incorporation or organization)
 
 
 
17021 Aldine Westfield, Houston, Texas
77073-5101
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: (713) 439-8600
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 þ NO o
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 þ NO o
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 þ
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
 
 
(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 Exchange Act).
YES o NO þ
As of October 19, 2016, the registrant has outstanding 422,794,027 shares of Common Stock, $1 par value per share.



Baker Hughes Incorporated
Table of Contents

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


1


PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
Baker Hughes Incorporated
Consolidated Condensed Statements of Income (Loss)
(Unaudited)

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(In millions, except per share amounts)
2016
 
2015
 
2016
 
2015
Revenue:
 
 
 
 
 
 
 
Sales
$
933

 
$
1,363

 
$
2,900

 
$
4,322

Services
1,420

 
2,423

 
4,531

 
8,026

Total revenue
2,353

 
3,786

 
7,431

 
12,348

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales
794

 
1,138

 
2,920

 
3,703

Cost of services
1,265

 
2,237

 
4,909

 
7,598

Research and engineering
91

 
110

 
292

 
366

Marketing, general and administrative
203

 
211

 
632

 
749

Impairment and restructuring charges
304

 
98

 
1,590

 
747

Goodwill impairment
17

 

 
1,858

 

Merger and related costs

 
93

 
180

 
204

Merger termination fee

 

 
(3,500
)
 

Total costs and expenses
2,674

 
3,887

 
8,881

 
13,367

Operating loss
(321
)
 
(101
)
 
(1,450
)
 
(1,019
)
Loss on early extinguishment of debt

 

 
(142
)
 

Interest expense, net
(39
)
 
(55
)
 
(142
)
 
(162
)
Loss before income taxes
(360
)
 
(156
)
 
(1,734
)
 
(1,181
)
Income taxes
(70
)
 

 
(589
)
 
242

Net loss
(430
)
 
(156
)
 
(2,323
)
 
(939
)
Net (income) loss attributable to noncontrolling interests
1

 
(3
)
 
2

 
3

Net loss attributable to Baker Hughes
$
(429
)
 
$
(159
)
 
$
(2,321
)
 
$
(936
)
 
 
 
 
 
 
 
 
Basic and diluted loss per share attributable to Baker Hughes
$
(1.00
)
 
$
(0.36
)
 
$
(5.31
)
 
$
(2.13
)
 
 
 
 
 
 
 
 
Cash dividends per share
$
0.17

 
$
0.17

 
$
0.51

 
$
0.51

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

2


Baker Hughes Incorporated
Consolidated Condensed Statements of Comprehensive Income (Loss)
(Unaudited)

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(In millions)
2016
 
2015
 
2016
 
2015
Net loss
$
(430
)
 
$
(156
)
 
$
(2,323
)
 
$
(939
)
Other comprehensive income (loss):
 
 
 
 
 
 
 
Foreign currency translation adjustments during the period
7

 
(91
)
 
47

 
(182
)
Pension and other postretirement benefits, net of tax
5

 
5

 
19

 
6

Other comprehensive income (loss)
12

 
(86
)
 
66

 
(176
)
Comprehensive loss
(418
)
 
(242
)
 
(2,257
)
 
(1,115
)
Comprehensive (income) loss attributable to noncontrolling interests
1

 
(3
)
 
2

 
3

Comprehensive loss attributable to Baker Hughes
$
(417
)
 
$
(245
)
 
$
(2,255
)
 
$
(1,112
)
See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.


3


Baker Hughes Incorporated
Consolidated Condensed Balance Sheets
(Unaudited)

(In millions)
September 30,
2016
 
December 31,
2015
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
3,736

 
$
2,324

Accounts receivable - less allowance for doubtful accounts
(2016 - $558; 2015 - $383)
2,207

 
3,217

Inventories, net
1,966

 
2,917

Deferred income taxes
159

 
301

Other current assets
934

 
509

Total current assets
9,002

 
9,268

Property, plant and equipment - less accumulated depreciation
(2016 - $6,759; 2015 - $7,378)
4,874

 
6,693

Goodwill
4,216

 
6,070

Intangible assets, net
407

 
583

Other assets
992

 
1,466

Total assets
$
19,491

 
$
24,080

LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Accounts payable
$
951

 
$
1,409

Short-term debt and current portion of long-term debt
127

 
151

Accrued employee compensation
466

 
690

Income taxes payable
131

 
55

Other accrued liabilities
549

 
470

Total current liabilities
2,224

 
2,775

Long-term debt
2,895

 
3,890

Deferred income taxes and other tax liabilities
382

 
252

Liabilities for pensions and other postretirement benefits
631

 
646

Other liabilities
122

 
135

Commitments and contingencies


 


Equity:
 
 
 
Common stock, one dollar par value
(shares authorized - 750; issued and outstanding: 2016 - 423; 2015 - 437)
423

 
437

Capital in excess of par value
6,625

 
7,261

Retained earnings
7,072

 
9,614

Accumulated other comprehensive loss
(939
)
 
(1,005
)
Treasury stock
(22
)
 
(9
)
Baker Hughes stockholders’ equity
13,159

 
16,298

Noncontrolling interests
78

 
84

Total equity
13,237

 
16,382

Total liabilities and equity
$
19,491

 
$
24,080

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

4


Baker Hughes Incorporated
Consolidated Condensed Statements of Changes in Equity
(Unaudited)

 
Baker Hughes Stockholders' Equity
 
 
 
 
(In millions, except per share amounts)
Common Stock
 
Capital
in Excess
of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Treasury Stock
 
Non-controlling
Interests
 
Total Equity
Balance at December 31, 2015
$
437

 
$
7,261

 
$
9,614

 
$
(1,005
)
 
$
(9
)
 
$
84

 
$
16,382

Comprehensive loss:
 
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 
 
 
 
(2,321
)
 
 
 
 
 
(2
)
 
(2,323
)
Other comprehensive income
 
 
 
 
 
 
66

 
 
 
 
 
66

Activity related to stock plans
2

 
18

 
 
 
 
 
(13
)
 
 
 
7

Repurchase and retirement of common stock
(16
)
 
(747
)
 
 
 
 
 
 
 
 
 
(763
)
Stock-based compensation
 
 
93

 
 
 
 
 
 
 
 
 
93

Cash dividends ($0.51 per share)
 
 
 
 
(221
)
 
 
 
 
 
 
 
(221
)
Net activity related to noncontrolling interests
 
 


 
 
 
 
 
 
 
(4
)
 
(4
)
Balance at September 30, 2016
$
423

 
$
6,625

 
$
7,072

 
$
(939
)
 
$
(22
)
 
$
78

 
$
13,237


 
Baker Hughes Stockholders' Equity
 
 
 
 
(In millions, except per share amounts)
Common Stock
 
Capital
in Excess
of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Treasury Stock
 
Non-controlling
Interests
 
Total Equity
Balance at December 31, 2014
$
434

 
$
7,062

 
$
11,878

 
$
(749
)
 
$

 
$
105

 
$
18,730

Comprehensive loss:
 
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 
 
 
 
(936
)
 
 
 
 
 
(3
)
 
(939
)
Other comprehensive loss
 
 
 
 
 
 
(176
)
 
 
 
 
 
(176
)
Activity related to stock plans
2

 
62

 
 
 
 
 
(9
)
 
 
 
55

Stock-based compensation
 
 
92

 
 
 
 
 
 
 
 
 
92

Cash dividends ($0.51 per share)
 
 
 
 
(222
)
 
 
 
 
 
 
 
(222
)
Net activity related to noncontrolling interests
 
 
(24
)
 
 
 
 
 
 
 
(11
)
 
(35
)
Balance at September 30, 2015
$
436

 
$
7,192

 
$
10,720

 
$
(925
)
 
$
(9
)
 
$
91

 
$
17,505

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

5


Baker Hughes Incorporated
Consolidated Condensed Statements of Cash Flows
(Unaudited)

 
Nine Months Ended September 30,
(In millions)
2016
 
2015
Cash flows from operating activities:
 
 
 
Net loss
$
(2,323
)
 
$
(939
)
Adjustments to reconcile net loss to net cash flows from operating activities:
 
 
 
Depreciation and amortization
921

 
1,326

Impairment of assets
1,241

 
265

Goodwill impairment
1,858

 

Inventory write-down
556

 
194

Loss on early extinguishment of debt
142

 

Provision (benefit) for deferred income taxes
292

 
(359
)
Provision for doubtful accounts
209

 
160

Other noncash items
(15
)
 
(3
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
802

 
1,692

Inventories
408

 
570

Accounts payable
(457
)
 
(1,289
)
Other operating items, net
(37
)
 
(352
)
Net cash flows provided by operating activities
3,597

 
1,265

Cash flows from investing activities:
 
 
 
Expenditures for capital assets
(226
)
 
(751
)
Proceeds from disposal of assets
199

 
269

Proceeds from maturities of investment securities
307

 

Purchases of investment securities
(308
)
 
(217
)
Other investing items, net

 
(14
)
Net cash flows used in investing activities
(28
)
 
(713
)
Cash flows from financing activities:
 
 
 
Net repayments of short-term debt and other borrowings
(57
)
 
(38
)
Repayment of long-term debt
(1,135
)
 

Repurchase of common stock
(763
)
 

Dividends paid
(221
)
 
(222
)
Other financing items, net
17

 
21

Net cash flows used in financing activities
(2,159
)
 
(239
)
Effect of foreign exchange rate changes on cash and cash equivalents
2

 
(10
)
Increase in cash and cash equivalents
1,412

 
303

Cash and cash equivalents, beginning of period
2,324

 
1,740

Cash and cash equivalents, end of period
$
3,736

 
$
2,043

Supplemental cash flows disclosures:
 
 
 
Income taxes paid, net of refunds
$
239

 
$
395

Interest paid
$
183

 
$
192

Supplemental disclosure of noncash investing activities:
 
 
 
Capital expenditures included in accounts payable
$
25

 
$
52

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

6


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed 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 for drilling, formation evaluation, completion and production, pressure pumping, and reservoir development 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 unaudited consolidated condensed financial statements included herein have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States of America ("U.S.") and pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") for interim financial information. Accordingly, certain information and disclosures normally included in our annual financial statements have been condensed or omitted. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K/A for the year ended December 31, 2015. We believe the unaudited consolidated condensed financial statements included herein reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. In the Notes to Unaudited Consolidated Condensed 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 condensed statements of income (loss). Prior year merger and related costs were reclassified to conform to the current year presentation.
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 adopted this guidance as of January 1, 2016 because we believe this approach will reduce the complexity in the subsequent measurement of our inventory. 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 retrospectively. Early adoption is permitted. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures.
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 may be applied either prospectively or retrospectively. Based on our current evaluation,

7


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

the reclassification of deferred tax assets from current to noncurrent could be significant. We do not expect a significant reclassification for deferred tax liabilities.
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, 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 have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures.
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 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.

NOTE 2. HALLIBURTON 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 $204 million for the nine months ended September 30, 2016 and 2015, respectively, including costs under our retention programs and obligations for minimum incentive compensation costs which, based on meeting eligibility criteria, have been treated as merger and related expenses. No costs related to the Merger were incurred during the three months ended September 30, 2016, compared to $93 million for the three months ended September 30, 2015.

NOTE 3. 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 continue to remain at low levels, thus continuing lower demand for our products and services. We consider our

8


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

customers' constrained capital spending budgets for 2016 and the current outlook for low activity levels to be impairment indicators and accordingly continue to evaluate our long-lived assets for impairment.
As a result of our impairment testing during the first three quarters of 2016, we have recorded impairment charges of $578 million, of which $462 million pertains to certain machinery and equipment and $116 million pertains to certain intangible assets that were written down to their estimated fair value. These assets remain in use. Specific to the third quarter of 2016, certain machinery and equipment, with an initial total carrying value of $380 million, was written down to its estimated fair value, resulting in an impairment charge of $116 million. Additionally, certain intangible assets, with an initial total carrying value of $40 million, were written down to their estimated fair values, resulting in an impairment charge of $15 million. Total impairment charges for the three months ended September 30, 2016 were $131 million. The majority of the machinery and equipment and intangible assets impaired in the third quarter of 2016 were related to our pressure pumping business in North America and Latin America. 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 of 10.0% for North America and 16.0% for Latin America.
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. Depending on future market conditions and activity levels, further actions may be necessary to adjust our operations, which may result in additional charges.
During the three and nine months ended September 30, 2016 and 2015, we recorded restructuring charges as summarized below:
 
Three Months Ended
 
Nine Months Ended
Restructuring Charges
September 30, 2016
September 30, 2015
 
September 30, 2016
September 30, 2015
  Workforce reductions
$
58

$
108

 
$
203

$
416

  Contract terminations
55


 
146

83

  Impairment of buildings and improvements
91


 
196

82

  Impairment of machinery and equipment
(31
)
(10
)
 
467

166

Total restructuring charges
$
173

$
98

 
$
1,012

$
747


Workforce reduction costs: During the first nine months of 2016, we initiated workforce reductions that will result in the elimination of approximately 6,400 additional positions worldwide, of which 1,400 workforce reductions were initiated during the third quarter of 2016. As a result, we recorded a charge for severance expense of $203 million for the nine months ended September 30, 2016, and made payments totaling $236 million during the same period. As of September 30, 2016, we had $42 million of accrued severance. We expect that substantially all of the accrued severance will be paid by the end of 2016.
Contract termination costs: During the first nine months of 2016, we canceled supply contracts and certain facility and equipment leases and recorded a charge of $146 million. During the same period, we made payments totaling $97 million relating to contract termination costs. As of September 30, 2016, we had accrued contract termination costs of $75 million. We expect that substantially all of the accrued contract termination costs will be paid within the next twelve months.

9


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

Impairment of buildings and improvements: During the first nine months of 2016, we consolidated and closed certain facilities and recorded related impairment charges of $196 million. The total impairment of buildings and improvements for the first nine months of 2016 reduced our segment assets as follows: North America - $130 million; Latin America - $18 million; Europe/Africa/Russia Caspian - $41 million; and Middle East/Asia Pacific - $7 million. 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 $467 million for the nine months ended September 30, 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 - $200 million; Latin America - $82 million; Europe/Africa/Russia Caspian - $81 million; Middle East/Asia Pacific - $71 million; and Industrial Services - $33 million. We have been disposing of all excess machinery and equipment and expect to be substantially complete by the end of 2016.
OTHER CHARGES
During the nine months ended September 30, 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 $587 million, including $31 million of disposal costs, of which $194 million is reported in cost of sales and $393 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 - $200 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 completed by the end of the third quarter of 2016. During the first nine months of 2015, we 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 product lines impacted were primarily pressure pumping and drilling and completion fluids.
The second quarter of 2016 was benefited by a reversal of a loss on a firm purchase commitment of $51 million that was recorded in cost of service in the first quarter of 2016 as the contract was settled in the second quarter of 2016.

NOTE 4. SEGMENT INFORMATION
We are a supplier of oilfield services, products, technology and systems used in 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, and certain gains and losses not allocated to the operating segments.
Beginning in 2016, we excluded merger and related costs from our operating segments. These costs are now presented as a separate line item in the consolidated condensed statement of income (loss). Prior year merger and related costs have been reclassified to conform to the current year presentation.

10


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

Summarized financial information is shown in the following tables:
 
Three Months Ended
 
Three Months Ended
 
September 30, 2016
 
September 30, 2015
Segments
Revenue
 
Operating Profit (Loss) Before Tax
 
Revenue
 
Operating Profit (Loss) Before Tax
North America
$
674

 
$
(65
)
 
$
1,368

 
$
(153
)
Latin America
243

 
20

 
439

 
51

Europe/Africa/Russia Caspian
519

 
22

 
791

 
98

Middle East/Asia Pacific
649

 
71

 
849

 
76

Industrial Services
268

 
30

 
339

 
44

Total Operations
2,353

 
78

 
3,786

 
116

Corporate

 
(78
)
 

 
(26
)
Interest expense, net

 
(39
)
 

 
(55
)
Impairment and restructuring charges

 
(304
)
 

 
(98
)
Goodwill impairment

 
(17
)
 

 

Merger and related costs

 

 

 
(93
)
Total
$
2,353

 
$
(360
)
 
$
3,786

 
$
(156
)

 
Nine Months Ended
 
Nine Months Ended
 
September 30, 2016
 
September 30, 2015
Segments
Revenue
 
Operating Profit (Loss) Before Tax
 
Revenue
 
Operating Profit (Loss) Before Tax
North America
$
2,161

 
$
(601
)
 
$
4,872

 
$
(512
)
Latin America
755

 
(289
)
 
1,371

 
129

Europe/Africa/Russia Caspian
1,711

 
(254
)
 
2,555

 
135

Middle East/Asia Pacific
2,018

 
(22
)
 
2,621

 
198

Industrial Services
786

 
(17
)
 
929

 
86

Total Operations
7,431

 
(1,183
)
 
12,348

 
36

Corporate

 
(139
)
 

 
(104
)
Loss on early extinguishment of debt

 
(142
)
 

 

Interest expense, net

 
(142
)
 

 
(162
)
Impairment and restructuring charges

 
(1,590
)
 

 
(747
)
Goodwill impairment

 
(1,858
)
 

 

Merger and related costs

 
(180
)
 

 
(204
)
Merger termination fee

 
3,500

 

 

Total
$
7,431

 
$
(1,734
)
 
$
12,348

 
$
(1,181
)


11


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

The following table presents total assets by segment at September 30, 2016 and December 31, 2015:
 
September 30, 2016
 
December 31, 2015
Segments
Assets
 
Assets
North America
$
3,541

 
$
6,599

Latin America
1,595

 
2,323

Europe/Africa/Russia Caspian
2,488

 
3,077

Middle East/Asia Pacific
2,867

 
3,441

Industrial Services
678

 
1,106

Shared assets
5,314

 
5,613

Total Operations
16,483

 
22,159

Corporate
3,008

 
1,921

Total
$
19,491


$
24,080

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, and certain other noncurrent assets related to certain employee retirement plans.

NOTE 5. INCOME TAXES
For the three months ended September 30, 2016, total income tax expense was $70 million on a loss before income taxes of $360 million, resulting in a negative effective tax rate of 19.4%. The 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 loss jurisdictions.
In the third quarter of 2016, we filed a carryback claim for the 2015 U.S. Net Operating Loss ("NOL") to prior tax years. As a result, a $370 million current income tax receivable is reflected in other current assets in the balance sheet as of September 30, 2016.

NOTE 6. EARNINGS PER SHARE
A reconciliation of the number of shares used for the basic and diluted loss per share computations is as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Weighted average common shares outstanding for basic and diluted loss per share
430

 
439

 
437

 
438

 
 
 
 
 
 
 
 
Anti-dilutive shares excluded from diluted loss per share (1)
1

 
1

 
1

 
2

Future potentially dilutive shares excluded from diluted loss per share (2)
3

 
3

 
5

 
3



12


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

(1) 
The calculation of diluted loss per share for both the three and nine months ended September 30, 2016 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 7. INVENTORIES

Inventories, net of reserves of $128 million at September 30, 2016 and $278 million at December 31, 2015, are comprised of the following:
 
September 30,
2016
 
December 31,
2015
Finished goods
$
1,744

 
$
2,649

Work in process
117

 
132

Raw materials
105

 
136

Total inventories
$
1,966

 
$
2,917


In the first nine months of 2016, we wrote off the carrying value of certain excess inventory resulting in a charge of $556 million, net of existing reserves of $260 million. In addition, we accrued $31 million of related disposal costs. See Note 3. "Impairment and Restructuring Charges" for further discussion. We have been disposing of the excess inventory, and were substantially completed by the end of the third quarter of 2016.

NOTE 8. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are comprised of the following at September 30, 2016 and December 31, 2015:

 
Useful Life
 
September 30, 2016
 
December 31, 2015
Land
 
 
$
241

 
$
263

Buildings and improvements
5 - 30 years
 
2,440

 
2,624

Machinery, equipment and other
1 - 20 years
 
8,952

 
11,184

Subtotal
 
 
11,633

 
14,071

Less: Accumulated depreciation
 
 
6,759

 
7,378

Total property, plant and equipment
 
 
$
4,874

 
$
6,693


During the first nine months of 2016, we recorded impairment charges relating to property, plant and equipment totaling approximately $1,125 million. See Note 3. "Impairment and Restructuring Charges" for further discussion.


13


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 9. GOODWILL AND INTANGIBLE ASSETS
The changes in the carrying amount of goodwill are detailed below by segment.

 
North
America
 
Latin
America
 
Europe/
Africa/
Russia
Caspian
 
Middle
East/
Asia
Pacific
 
Industrial
Services
 
Total Goodwill
Balance at December 31, 2015
$
3,097

 
$
584

 
$
1,068

 
$
819

 
$
502

 
$
6,070

Impairments
(1,549
)
 

 

 

 
(309
)
 
(1,858
)
Currency translation adjustments
3

 
3

 
(1
)
 

 
(1
)
 
4

Balance at September 30, 2016
$
1,551

 
$
587

 
$
1,067

 
$
819

 
$
192

 
$
4,216

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 we commenced 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 $1,841 million, which consisted of $1,530 million 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, which resulted in an immaterial adjustment. The total impairment is reflected in the table above. 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.


14


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

Intangible assets are comprised of the following:
 
September 30, 2016
 
December 31, 2015
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
Technology
$
792

 
$
439

 
$
353

 
$
866

 
$
452

 
$
414

Customer relationships
67

 
28

 
39

 
251

 
106

 
145

Trade names
90

 
78

 
12

 
108

 
89

 
19

Other
16

 
13

 
3

 
18

 
13

 
5

Total intangible assets
$
965

 
$
558

 
$
407

 
$
1,243

 
$
660

 
$
583


During the first nine months of 2016, we recorded impairments relating to various intangible assets totaling $116 million. See Note 3. "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 three and nine months ended September 30, 2016 was $17 million and $59 million, respectively, as compared to $26 million and $77 million reported in 2015 for the same periods.

Amortization expense of these intangibles over the remainder of 2016 and for each of the subsequent five fiscal years is expected to be as follows:
Year
Estimated Amortization Expense
Remainder of 2016
$
17

2017
65

2018
60

2019
57

2020
48

2021
43



15


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 10. INDEBTEDNESS
Total debt consisted of the following at September 30, 2016, net of unamortized discount and debt issuance cost:

 
September 30, 2016
 
December 31, 2015
6.0% Notes due June 2018
$
200

 
$
255

7.5% Senior Notes due November 2018
524

 
747

3.2% Senior Notes due August 2021
511

 
746

8.55% Debentures due June 2024
112

 
149

6.875% Notes due January 2029
301

 
394

5.125% Notes due September 2040
1,132

 
1,482

Other debt
242

 
268

Total debt
3,022

 
4,041

Less: short-term debt and current portion of long-term debt
127

 
151

Total long-term debt
$
2,895

 
$
3,890

The estimated fair value of total debt at September 30, 2016 and December 31, 2015 was $3,404 million and $4,321 million, respectively, which differs from the carrying amounts of $3,022 million and $4,041 million, respectively, included in our unaudited consolidated condensed 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.
During the first nine months of 2016, there were no direct borrowings under either the previous credit facility or the 2016 Credit Agreement, and we were in compliance with all of the covenants under both credit facilities. 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 would be reduced by the amount of any commercial paper outstanding. At September 30, 2016, we had no borrowings outstanding under the commercial paper program.

NOTE 11. 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

16


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

value of our financial instruments at September 30, 2016 and December 31, 2015 approximates their carrying value as reflected in our unaudited consolidated condensed balance sheets. For further information on the fair value of our debt, see Note 10. "Indebtedness."

NOTE 12. EMPLOYEE BENEFIT PLANS
We have both funded and unfunded noncontributory defined benefit pension plans ("Pension Benefits") covering certain employees primarily in the U.S., the United Kingdom, Germany and Canada. We also provide certain postretirement health care benefits ("Other Postretirement Benefits"), through an unfunded plan, to a closed group of U.S. employees who, when they retire, have met certain age and service requirements.
The components of net periodic cost (benefit) are as follows for the three months ended September 30:
 
U.S. Pension Benefits
 
Non-U.S. Pension Benefits
 
Other Postretirement Benefits
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
Service cost
$
13

 
$
15

 
$
4

 
$
4

 
$
1

 
$
1

Interest cost
7

 
6

 
7

 
7

 
1

 
1

Expected return on plan assets
(10
)
 
(12
)
 
(9
)
 
(12
)
 

 

Amortization of prior service credit

 

 

 

 
(2
)
 
(2
)
Amortization of net actuarial loss
3

 
3

 
1

 
2

 

 

Curtailment gain

 

 

 

 

 
(2
)
Other
3

 
8

 

 

 

 

Net periodic cost (benefit)
$
16

 
$
20

 
$
3

 
$
1

 
$

 
$
(2
)
The components of net periodic cost (benefit) are as follows for the nine months ended September 30:
 
U.S. Pension Benefits
 
Non-U.S. Pension Benefits
 
Other Postretirement Benefits
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
Service cost
$
39

 
$
49

 
$
11

 
$
12

 
$
3

 
$
3

Interest cost
21

 
20

 
21

 
23

 
3

 
3

Expected return on plan assets
(30
)
 
(37
)
 
(27
)
 
(36
)
 

 

Amortization of prior service credit

 

 

 

 
(6
)
 
(8
)
Amortization of net actuarial loss
8

 
7

 
4

 
4

 

 
2

Curtailment gain

 

 

 

 

 
(11
)
Other
3

 
8

 

 

 

 

Net periodic cost (benefit)
$
41

 
$
47

 
$
9

 
$
3

 
$

 
$
(11
)
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. During the nine months ended September 30, 2016, we contributed approximately $77 million to our defined benefit and other postretirement plans. We expect to contribute between $4 million and $5 million to our funded and unfunded pension plans and to make payments of between $3 million and $4 million related to other postretirement benefits in the fourth quarter of 2016.
We contributed approximately $76 million to our defined contribution plans during the nine months ended September 30, 2016. Effective April 2016, employer contributions to certain plans were suspended indefinitely. We estimate we will contribute between $11 million and $12 million to other defined contribution plans in the fourth quarter of 2016.


17


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 13. COMMITMENTS AND CONTINGENCIES
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.
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 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

18


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

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.
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%. The hearing before the arbitration panel is scheduled to commence on January 16, 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

19


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

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.
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 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.
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 September 30, 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 financial position, results of operations or cash flows.


20


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 14. ACCUMULATED OTHER COMPREHENSIVE LOSS

The following tables present the changes in accumulated other comprehensive loss, net of tax:
 
Pensions and Other Postretirement Benefits
Foreign Currency Translation Adjustments
Accumulated Other Comprehensive Loss
Balance at December 31, 2015
 
$
(261
)
 
 
$
(744
)
 
 
$
(1,005
)
 
Other comprehensive income before reclassifications
 
14

 
 
47

 
 
61

 
Amounts reclassified from accumulated other comprehensive loss
 
6

 
 

 
 
6

 
Deferred taxes
 
(1
)
 
 

 
 
(1
)
 
Balance at September 30, 2016
 
$
(242
)
 
 
$
(697
)
 
 
$
(939
)
 

 
Pensions and Other Postretirement Benefits
Foreign Currency Translation Adjustments
Accumulated Other Comprehensive Loss
Balance at December 31, 2014
 
$
(246
)
 
 
$
(503
)
 
 
$
(749
)
 
Other comprehensive income (loss) before reclassifications
 
9

 
 
(182
)
 
 
(173
)
 
Amounts reclassified from accumulated other comprehensive loss
 
(6
)
 
 

 
 
(6
)
 
Deferred taxes
 
3

 
 

 
 
3

 
Balance at September 30, 2015
 
$
(240
)
 
 
$
(685
)
 
 
$
(925
)
 

The amounts reclassified from accumulated other comprehensive loss during the nine months ended September 30, 2016 and 2015 represent the amortization of prior service credit, net actuarial loss, curtailment gain and certain other items which are included in the computation of net periodic cost (benefit). See Note 12. "Employee Benefit Plans" for additional details. Net periodic cost (benefit) is recorded in cost of sales and services, research and engineering, and marketing, general and administrative expenses.


21


ITEM 2. 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 unaudited consolidated condensed financial statements and the related notes included in Item 1 thereto, as well as our Annual Report on Form 10-K/A for the year ended December 31, 2015 ("2015 Annual Report").
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 ("EARC"), and Middle East/Asia Pacific ("MEAP"). Our Industrial Services businesses are reported in a fifth segment. As of September 30, 2016, Baker Hughes had approximately 34,000 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 the second quarter, following the termination of the merger with Halliburton, we announced a series of actions to reduce costs and simplify our business, enhance our commercial strategy and optimize our capital structure by paying down debt and buying back shares. More specifically, we have restructured the company to remove significant costs and create a more efficient organization which aligns with our operational strategy to take our products and technology to market faster and more efficiently and through a broader set of sales channels. In an effort to improve our return on invested capital, we have conducted an analysis of our product offerings and as a result of that review, we have begun the process of reducing certain product offerings in specific markets based on our objectives of profitable growth. While these potential reductions will have a minimal impact on our current revenue, they are expected to have a positive impact on operating profitability. We expect to have two-thirds of these product exits completed by the end of 2016, with the balance achieved in 2017. Additionally, we have decided to retain a selective footprint in our North America onshore pressure pumping business, and are considering a range of ownership models that will allow us to participate in this market while mitigating the resource requirements and capital intensity that are inherent in this particular business.
In the first nine months of 2016, we continued to face difficult industry conditions. Activity declined across the globe as reflected by the worldwide rig count, which decreased 36% compared to the same period last year, resulting in additional pricing deterioration for our products and services in many markets. The steady decline in U.S. oil production, along with the initial announcement by the Organization of Petroleum Exporting Countries ("OPEC") in late September to re-establish a production ceiling, drove oil prices higher resulting in more than a 30% increase in oil prices in the first nine months of the year. Despite this improvement in oil prices, customer spending continued to decline as most operators are looking for a sustainable rebalancing of the oil market before increasing activity. As a result, we continued to experience a significant decline in demand as well as increased pricing pressure for our products and services throughout the third quarter of 2016.
Financial Results
In the third quarter of 2016, we generated revenue of $2.35 billion, a decrease of $1.43 billion, or 38%, compared to the third quarter of 2015, generally consistent with the 30% drop in the worldwide rig count. In the first nine months of 2016, revenue totaled $7.43 billion, a decline of $4.92 billion, or 40%, compared to the same period in the prior year, with a 36% drop in the worldwide rig count over the same time frame. All geographic segments experienced revenue declines in the third quarter and first nine months of 2016 driven by reduced customer

22


spending. North America was the largest contributor to the year-over-year revenue decline in both the quarter and nine months ended September 30, 2016, driven by the drop in the onshore and inland water rig count. As a result, we continued to experience reduced activity, an oversupply of equipment and an unfavorable pricing environment in this segment. Additionally, the decision to minimize our operational footprint in the onshore pressure pumping business in North America has resulted in share reductions in this product line. Revenue was also negatively impacted by an unfavorable change in exchange rates of several currencies relative to the U.S. Dollar, predominately in the EARC segment.
Loss before income tax was $360 million and $1.73 billion for the third quarter and first nine months of 2016, respectively, and included impairment and restructuring charges of $304 million and $1.59 billion, respectively. These charges were recorded primarily as a result of the recent downturn in the oil and natural gas market brought about by the decline in commodity prices. Throughout this downturn, we took actions to reduce costs and adjust our operational cost structure, within the limitations of the Merger Agreement, to reflect current and expected near-term activity levels. As described above, following the termination of the Merger Agreement in the second quarter of 2016, we took additional actions to reduce costs, simplify the organization, and rationalize our operating structure to address the ongoing industry challenges and to support our future operational strategy. These restructuring activities included workforce reductions, contract terminations, facility closures and the removal of excess machinery and equipment. Additionally, we incurred costs of $587 million in the first nine months of 2016 to write off the carrying value of certain inventory deemed excess. For the third quarter and first nine months of 2015, loss before income tax was $156 million and $1.18 billion, respectively, which also included impairment and restructuring charges of $98 million and $747 million, respectively. Further, we incurred $194 million in the first nine months of 2015 to write down the carrying value of certain inventory.
Also during the first nine months of 2016, we recorded a loss due to the impairment of goodwill for the North America and Industrial Services segments totaling $1.86 billion. This charge is excluded from the results of our operating segments as well.
Halliburton 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.
Outlook
While oil prices have started to rebound as a result of the U.S. production edging down and the initial announcement by OPEC in late September to re-establish a production ceiling, the uncertainty from the lack of critical details regarding production cuts and the various country exclusions, has limited the confidence that it could lead to a more sustainable improvement in oil prices, and in turn, to a more material increase in exploration and production companies' spending.
We continue to believe that oil prices in the mid-to upper-$50s are required for a sustainable recovery in North America. As we previously projected, the North American market has been continuing to climb slowly upward, and we expect that to continue. In order for a broader recovery to take place, a series of milestones need to be reached before the market can respond in a predictable way. First, supply and demand surplus has to rebalance allowing commodity prices to improve. Second, commodity prices need to stabilize for confidence in the customer community to improve and investment to accelerate. Third, activity needs to increase meaningfully before service capacity can be substantially absorbed and pricing recovery takes place. Until then, we will continue to see the dislocation we have today in the relationship between commodity prices and service pricing. We expect a slow ramp up of customer spending driven by a measured increase in U.S. onshore activity as well as increased seasonal activity in Canada. Despite this expected gradual improvement in the North American environment, we

23


believe pricing will continue to remain challenging. As a result, we expect only modest growth in North America in the fourth quarter of 2016.
Internationally, we expect continued activity declines and pricing pressure in the near term due to customers continuing to restrict spending. We don’t expect year-end, seasonal product sales to significantly offset those declines. In markets where lifting costs are higher, such as deepwater, we expect that those activity declines will be even steeper. In conventional markets, such as the Middle East and North Africa, we believe there could be modest growth given the lower lifting costs. Despite these market dynamics, we continue to see opportunities for our capabilities and product innovations. Our products and services help our customers maximize production and lower overall costs allowing for improvements in our growth and profitability.

BUSINESS ENVIRONMENT
We operate 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 driven by 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.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Brent oil price ($/Bbl) (1)
$
45.82

 
$
50.17

 
$
42.13

 
$
55.36

WTI oil price ($/Bbl) (2)
44.88

 
46.48

 
41.40

 
50.94

Natural gas price ($/mmBtu) (3)
2.85

 
2.75

 
2.32

 
2.78


(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
In North America, customer spending is highly driven by WTI oil prices, which began the third quarter of 2016 at $48.99/Bbl, declined to $39.51/Bbl in early August 2016, and then rebounded to $48.24/Bbl by the end of the quarter due to peak summer demand for crude oil. According to the September 2016 Oil Market Report published by the International Energy Agency, global oil demand growth is slowing at a faster pace than initially predicted. Forecasted oil demand growth for 2016 is now only 1.3 mb/d compared to 1.4 mb/d at the end of the second quarter of 2016. Further, oil demand growth for 2017 is expected to ease further to 1.2 mb/d as underlying macroeconomic conditions remain uncertain.
Outside North America, customer spending is most heavily influenced by Brent oil prices, which experienced a similar trend as WTI throughout the quarter, exiting at $47.71/Bbl. Brent oil price fluctuations were driven by the same factors as WTI.
Overall, WTI and Brent oil prices in the first nine months of 2016 averaged lower than the prior year by 19% and 24%, respectively. Although oil prices have rebounded more than 80% from the previous twelve-year-low of $26/Bbl reached earlier this year to near $48/Bbl at the end of the quarter, there has yet to be any material change in customer behavior to suggest a significant near-term improvement in activity levels.

24


In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, remained fairly stable during the third quarter of 2016, exiting the quarter at $2.84/mmBtu, relatively unchanged from where it began the quarter. Compared to the same quarter in the prior year, natural gas prices increased 4%, driven by expectations of a colder than usual winter season. For the nine months ending September 30, 2016, natural gas prices declined by 17% as a result of higher storage levels. According to the U.S. Department of Energy ("DOE"), working natural gas in storage at the end of the third quarter of 2016 was 3,680 Bcf, which is 3% higher than the previous five-year (2011-2015) average, and 4%, or 142 Bcf, above 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. 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.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
2015
% Change
2016
2015
% Change
U.S. - land and inland waters
461

833

(45
%)
465

1,021

(54
%)
U.S. - offshore
18

32

(44
%)
23

38

(39
%)
Canada
121

190

(36
%)
112

200

(44
%)
North America
600

1,055

(43
%)
600

1,259

(52
%)
Latin America
187

318

(41
%)
203

331

(39
%)
North Sea
29

37

(22
%)
29

39

(26
%)
Continental Europe
65

72

(10
%)
68

80

(15
%)
Africa
80

95

(16
%)
87

111

(22
%)
Middle East
385

393

(2
%)
392

403

(3
%)
Asia Pacific
190

217

(12
%)
187

224

(17
%)
Outside North America
936

1,132

(17
%)
966

1,188

(19
%)
Worldwide
1,536

2,187

(30
%)
1,566

2,447

(36
%)

25


The rig count in North America decreased 43% in the third quarter of 2016 compared to the same period last year, as a consequence of reduced spending from our customers as they continue to operate in a lower commodity price environment. Reduced cash flows over the last two years have prompted many companies to scale back investment programs, deferring new drilling projects until a sustained price recovery occurs. Also, higher interest rates and tighter lending conditions have limited the availability of capital for many smaller producers, giving rise to distressed asset sales and consolidation of acreage holdings by firms that are more financially sound. The oil-directed drilling rig count, which represents approximately 80% of the North America rig count, experienced a 39% decline as the steep drop in oil prices over the last year resulted in a reduction in exploration and production spending across the region, especially in the U.S. onshore and Canadian oil sands. The natural gas-directed rig count experienced a 53% decrease compared to the same period a year ago as a result of lower natural gas prices. In the U.S., natural gas prices remain below levels that are considered to be economic for new investments in many natural gas fields. In Canada, the reduction in the natural gas-directed rig count was primarily related to lower drilling activity levels in condensate rich zones in Alberta to service oil sands.
Outside North America, the rig count in the third quarter of 2016 decreased 17% compared to the same period a year ago. In Latin America, the rig count declined 41% as a consequence of customer spending reductions throughout the entire region, but most notably in Argentina, Brazil, Venezuela, Colombia, Mexico and Ecuador. In Europe, the rig count in the North Sea decreased 22%, primarily due to a reduction in offshore drilling activity in the United Kingdom, and in Continental Europe the rig count declined by 10% driven by lower onshore drilling activity primarily in Romania, Serbia and Lithuania. In Africa, the rig count decreased 16% primarily due to reduced drilling activity across the region, mainly in Nigeria, Gabon, Angola, Cameroon and Kenya. The rig count decreased 2% in the Middle East due to lower drilling activity in Egypt and Iraq, partially offset by increased drilling activity in Abu Dhabi and Kuwait. In Asia Pacific, the rig count declined 12% as a result of reduced drilling activity in Australia, Indonesia, Malaysia, and Thailand.
RESULTS OF OPERATIONS
The discussions below relating to significant line items from our unaudited consolidated condensed 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.
Revenue and Operating Profit (Loss) 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, and certain gains and losses not allocated to the operating segments. Beginning in 2016, we excluded merger and related costs from our operating segments. These costs are now presented as a separate line item in the consolidated condensed statement of income (loss). Prior year merger and related costs have been reclassified to conform to the current year presentation.

26


 
Three Months Ended September 30,
 
$
Change
 
%
Change
 
Nine Months Ended September 30,
 
$
Change
 
%
Change
 
2016
 
2015
 
 
2016
 
2015
 
Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North America
$
674

 
$
1,368

 
$
(694
)
 
(51
%)
 
$
2,161

 
$
4,872

 
$
(2,711
)
 
(56
%)
Latin America
243

 
439

 
(196
)
 
(45
%)
 
755

 
1,371

 
(616
)
 
(45
%)
Europe/Africa/Russia Caspian
519

 
791

 
(272
)
 
(34
%)
 
1,711

 
2,555

 
(844
)
 
(33
%)
Middle East/Asia Pacific
649

 
849

 
(200
)
 
(24
%)
 
2,018

 
2,621

 
(603
)
 
(23
%)
Industrial Services
268

 
339

 
(71
)
 
(21
%)
 
786

 
929

 
(143
)
 
(15
%)
Total
$
2,353

 
$
3,786

 
$
(1,433
)
 
(38
%)
 
$
7,431

 
$
12,348

 
$
(4,917
)
 
(40
%)

 
Three Months Ended September 30,
 
$
Change
 
%
Change
 
Nine Months Ended September 30,
 
$
Change
 
%
Change
 
2016
 
2015
 
 
2016
 
2015
 
Operating Profit (Loss) Before Tax:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North America
$
(65
)
 
$
(153
)
 
$
88

 
58
%
 
$
(601
)
 
$
(512
)
 
$
(89
)
 
(17
%)
Latin America
20

 
51

 
(31
)
 
(61
%)
 
(289
)
 
129

 
(418
)
 
(324
%)
Europe/Africa/Russia Caspian
22

 
98

 
(76
)
 
(78
%)
 
(254
)
 
135

 
(389
)
 
(288
%)
Middle East/Asia Pacific
71

 
76

 
(5
)
 
(7
%)
 
(22
)
 
198

 
(220
)
 
(111
%)
Industrial Services
30

 
44

 
(14
)
 
(32
%)
 
(17
)
 
86

 
(103
)
 
(120
%)
Total Operations
78

 
116

 
(38
)
 
(33
%)
 
(1,183
)
 
36

 
(1,219
)
 
N/M

Corporate
(78
)
 
(26
)
 
(52
)
 
200
%
 
(139
)
 
(104
)
 
(35
)
 
34
%
Loss on early extinguishment of debt

 

 

 
N/M

 
(142
)
 

 
(142
)
 
N/M

Interest expense, net
(39
)
 
(55
)
 
16

 
(29
%)
 
(142
)
 
(162
)
 
20

 
(12
%)
Impairment and restructuring charges
(304
)
 
(98
)
 
(206
)
 
210
%
 
(1,590
)
 
(747
)
 
(843
)
 
113
%
Goodwill impairment
(17
)
 

 
(17
)
 
N/M

 
(1,858
)
 

 
(1,858
)
 
N/M

Merger and related costs

 
(93
)
 
93

 
(100
%)
 
(180
)
 
(204
)
 
24

 
(12
%)
Merger termination fee

 

 

 
N/M

 
3,500

 

 
3,500

 
N/M

Loss Before Income Taxes
$
(360
)
 
$
(156
)
 
$
(204
)
 
(131
%)
 
$
(1,734
)
 
$
(1,181
)
 
$
(553
)
 
(47
%)
"N/M" represents not meaningful.
Third Quarter of 2016 Compared to the Third Quarter of 2015
North America
North America revenue decreased $694 million, or 51%, in the third quarter of 2016 compared to the third quarter of 2015 primarily as a result of the steep drop in activity, as reflected in the 43% year-over-year rig count decline, 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 activity drop, most notably in pressure pumping and completion systems. Our production chemicals, deepwater operations, and artificial lift product lines showed the most resilience. Revenue has also been impacted by onshore pressure pumping share reductions, driven by efforts to reduce losses and improve cash flow in a market where pricing remains unsustainable.
North America operating loss before tax was $65 million in the third quarter of 2016 compared to $153 million in the third quarter of 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 lower operating costs. These actions to restructure our North American operations to operate in a lower activity and pricing environment, combined with

27


the reduction of depreciation and amortization from asset impairments, helped mitigate the impact of the ongoing decline in revenue experienced since early 2015.
Latin America
Latin America revenue decreased $196 million, or 45%, in the third quarter of 2016 compared to the third quarter of 2015 primarily driven by reduced activity, as evident in the 41% rig count drop, and to a lesser extent lower pricing. Activity has declined swiftly across the entire segment and all product lines, with the Andean area and Mexico experiencing the largest decline as reflected by the year-over-year decline in the rig count of 71% and 41%, respectively.
Latin America operating profit before tax was $20 million in the third quarter of 2016 compared to