2013.09.30 10Q
Table of Contents

                                    

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, 2013
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)
 
 
 
2929 Allen Parkway, Suite 2100, Houston, Texas
77019-2118
(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 17, 2013, the registrant has outstanding 443,225,722 shares of Common Stock, $1 par value per share.


Table of Contents

                                    

Baker Hughes Incorporated
INDEX
 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


1

Table of Contents

                                    

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Baker Hughes Incorporated
Consolidated Condensed Statements of Income
(In millions, except per share amounts)
(Unaudited)

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Revenue:
 
 
 
 
 
 
 
Sales
$
1,936

 
$
1,847

 
$
5,554

 
$
5,387

Services
3,851

 
3,508

 
10,950

 
10,649

Total revenue
5,787

 
5,355

 
16,504

 
16,036

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales
1,490

 
1,486

 
4,341

 
4,258

Cost of services
3,260

 
2,910

 
9,326

 
8,657

Research and engineering
142

 
118

 
400

 
370

Marketing, general and administrative
319

 
355

 
970

 
999

Total costs and expenses
5,211

 
4,869

 
15,037

 
14,284

Operating income
576

 
486

 
1,467

 
1,752

Interest expense, net
(58
)
 
(49
)
 
(173
)
 
(153
)
Income before income taxes
518

 
437

 
1,294

 
1,599

Income taxes
(178
)
 
(153
)
 
(441
)
 
(497
)
Net income
340

 
284

 
853

 
1,102

Net loss (income) attributable to noncontrolling interests
1

 
(5
)
 
(5
)
 
(5
)
Net income attributable to Baker Hughes
$
341

 
$
279

 
$
848

 
$
1,097

 
 
 
 
 
 
 
 
Basic earnings per share attributable to Baker Hughes
$
0.77

 
$
0.63

 
$
1.91

 
$
2.49

 
 
 
 
 
 
 
 
Diluted earnings per share attributable to Baker Hughes
$
0.77

 
$
0.63

 
$
1.91

 
$
2.49

 
 
 
 
 
 
 
 
Cash dividends per share
$
0.15

 
$
0.15

 
$
0.45

 
$
0.45

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

2

Table of Contents

                                    

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

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Net income
$
340

 
$
284

 
$
853

 
$
1,102

Other comprehensive income (loss):
 
 
 
 
 
 
 
Currency translation adjustments
60

 
63

 
(50
)
 
61

Pension and other postretirement benefits, net of tax
(4
)
 

 
9

 
19

Hedge transactions, net of tax
2

 

 
(1
)
 
1

Other comprehensive income (loss)
58

 
63

 
(42
)
 
81

Comprehensive income
398

 
347

 
811

 
1,183

Comprehensive loss (income) attributable to noncontrolling interests
1

 
(5
)
 
(5
)
 
(5
)
Comprehensive income attributable to Baker Hughes
$
399

 
$
342

 
$
806

 
$
1,178

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.


3

Table of Contents

                                    

Baker Hughes Incorporated
Consolidated Condensed Balance Sheets
(In millions)
(Unaudited)

 
September 30,
2013
 
December 31,
2012
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
1,368

 
$
1,015

Accounts receivable - less allowance for doubtful accounts
(2013 - $310; 2012 - $308)
5,343

 
4,815

Inventories, net
3,960

 
3,781

Deferred income taxes
373

 
266

Other current assets
463

 
540

Total current assets
11,507

 
10,417

Property, plant and equipment - less accumulated depreciation
(2013 - $7,004; 2012 - $6,315)
8,964

 
8,707

Goodwill
5,967

 
5,958

Intangible assets, net
915

 
993

Other assets
721

 
614

Total assets
$
28,074

 
$
26,689

LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Accounts payable
$
2,474

 
$
1,737

Short-term debt and current portion of long-term debt
737

 
1,079

Accrued employee compensation
717

 
646

Income taxes payable
227

 
226

Other accrued liabilities
544

 
436

Total current liabilities
4,699

 
4,124

Long-term debt
3,838

 
3,837

Deferred income taxes and other tax liabilities
797

 
745

Liabilities for pensions and other postretirement benefits
595

 
579

Other liabilities
152

 
136

Commitments and contingencies


 


Equity:
 
 
 
Common stock
443

 
441

Capital in excess of par value
7,614

 
7,495

Retained earnings
10,257

 
9,609

Accumulated other comprehensive loss
(518
)
 
(476
)
Baker Hughes stockholders’ equity
17,796

 
17,069

Noncontrolling interests
197

 
199

Total equity
17,993

 
17,268

Total liabilities and equity
$
28,074

 
$
26,689

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

4

Table of Contents

                                    

Baker Hughes Incorporated
Consolidated Condensed Statements of Equity
(In millions)
(Unaudited)

 
Common Stock
 
Capital
in Excess
of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Noncontrolling
Interests
 
Total
Balance at December 31, 2012
$
441

 
$
7,495

 
$
9,609

 
$
(476
)
 
$
199

 
$
17,268

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
848

 
 
 
5

 
853

Other comprehensive loss
 
 
 
 
 
 
(42
)
 
 
 
(42
)
Activity related to stock plans
2

 
26

 
 
 
 
 
 
 
28

Stock-based compensation
 
 
93

 
 
 
 
 
 
 
93

Cash dividends ($0.45 per share)
 
 
 
 
(200
)
 
 
 
 
 
(200
)
Net activity related to noncontrolling
interests
 
 


 
 
 
 
 
(7
)
 
(7
)
Balance at September 30, 2013
$
443

 
$
7,614

 
$
10,257

 
$
(518
)
 
$
197

 
$
17,993


 
Common Stock
 
Capital
in Excess
of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Noncontrolling
Interests
 
Total
Balance at December 31, 2011
$
437

 
$
7,303

 
$
8,561

 
$
(555
)
 
$
218

 
$
15,964

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
1,097

 
 
 
5

 
1,102

Other comprehensive income
 
 
 
 
 
 
81

 

 
81

Activity related to stock plans
2

 
28

 
 
 
 
 
 
 
30

Stock-based compensation
 
 
94

 
 
 
 
 
 
 
94

Cash dividends ($0.45 per share)
 
 
 
 
(197
)
 
 
 
 
 
(197
)
Net activity related to noncontrolling
interests
 
 
22

 
 
 
 
 
(25
)
 
(3
)
Balance at September 30, 2012
$
439

 
$
7,447

 
$
9,461

 
$
(474
)
 
$
198

 
$
17,071

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

5

Table of Contents

                                    

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

 
Nine Months Ended September 30,
 
2013
 
2012
Cash flows from operating activities:
 
 
 
Net income
$
853

 
$
1,102

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
1,262

 
1,151

Other noncash items
(53
)
 
(219
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(651
)
 
(242
)
Inventories
(191
)
 
(661
)
Accounts payable
749

 
55

Other operating items, net
189

 
(239
)
Net cash flows provided by operating activities
2,158

 
947

Cash flows from investing activities:
 
 
 
Expenditures for capital assets
(1,552
)
 
(2,183
)
Proceeds from disposal of assets
276

 
287

Other investing items, net
(28
)
 

Net cash flows used in investing activities
(1,304
)
 
(1,896
)
Cash flows from financing activities:
 
 
 
Net (repayments) proceeds of commercial paper borrowings and other debt with three months or less original maturity
(391
)
 
1,075

Repayments of short-term debt with greater than three months original maturity
(119
)
 

Proceeds from short-term debt with greater than three months original maturity
178

 

Dividends paid
(200
)
 
(197
)
Other financing items, net
33

 
24

Net cash flows (used in) provided by financing activities
(499
)
 
902

Effect of foreign exchange rate changes on cash and cash equivalents
(2
)
 
4

Increase (decrease) in cash and cash equivalents
353

 
(43
)
Cash and cash equivalents, beginning of period
1,015

 
1,050

Cash and cash equivalents, end of period
$
1,368

 
$
1,007

Supplemental cash flows disclosures:
 
 
 
Income taxes paid, net of refunds
$
498

 
$
811

Interest paid
$
194

 
$
191

Supplemental disclosure of noncash investing activities:
 
 
 
Capital expenditures included in accounts payable
$
99

 
$
115

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

6

Table of Contents                                
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 refining, 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 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 for the year ended December 31, 2012 (“2012 Annual Report”). 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. Certain prior year amounts have been reclassified to present our Process and Pipelines Services business as continuing operations, consistent with the presentation in our 2012 Annual Report. 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 the unaudited consolidated condensed financial statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.
New Accounting Standards Updates
In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This ASU requires entities to present separately, among other items, the amount of the change that is due to reclassifications, and the amount that is due to current period other comprehensive income. We adopted the new presentation requirements in the notes to our financial statements in the first quarter of 2013.
NOTE 2. VENEZUELAN CURRENCY DEVALUATION
In February 2013, Venezuela's currency was devalued from the prior exchange rate of 4.3 Bolivars Fuertes per U.S. Dollar to 6.3 Bolivars Fuertes per U.S. Dollar, which applies to our local currency denominated balances. The impact of this devaluation was a loss of $23 million that was recorded in marketing, general and administrative expense in the first quarter of 2013.


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Table of Contents                                
Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 3. EARNINGS PER SHARE
A reconciliation of the number of shares used for the basic and diluted earnings per share (“EPS”) computations is as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Weighted average common shares outstanding for basic EPS
444

 
440

 
443

 
440

Effect of dilutive securities - stock plans
1

 
1

 
1

 
1

Adjusted weighted average common shares outstanding for diluted EPS
445

 
441

 
444

 
441

Future potentially dilutive shares excluded from diluted EPS:
 
 
 
 
 
 
 
Options with an exercise price greater than the average market price for the period
5

 
8

 
8

 
8

NOTE 4. INVENTORIES
Inventories, net of reserves, are comprised of the following:
 
September 30,
2013
 
December 31,
2012
Finished goods
$
3,500

 
$
3,336

Work in process
240

 
228

Raw materials
220

 
217

Total inventories
$
3,960

 
$
3,781

NOTE 5. INTANGIBLE ASSETS
Intangible assets are comprised of the following:

 
September 30, 2013
 
December 31, 2012
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
Definite lived intangibles:
 
 
 
 
 
 
 
 
 
 
 
Technology
$
816

 
$
323

 
$
493

 
$
787

 
$
282

 
$
505

Contract-based
16

 
11

 
5

 
16

 
10

 
6

Trade names
121

 
76

 
45

 
121

 
60

 
61

Customer relationships
494

 
148

 
346

 
494

 
117

 
377

Subtotal
1,447

 
558

 
889

 
1,418

 
469

 
949

Indefinite lived intangibles:
 
 
 
 
 
 
 
 
 
 
 
In-process research and development
26

 

 
26

 
44

 

 
44

Total intangible assets
$
1,473

 
$
558

 
$
915

 
$
1,462

 
$
469

 
$
993


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Table of Contents                                
Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 3 to 30 years. Amortization expense included in net income for the three months and nine months ended September 30, 2013 was $30 million and $89 million, respectively, as compared to $34 million and $97 million reported in 2012 for the same periods.
Amortization expense of these intangibles over the remainder of 2013 and for each of the subsequent five fiscal years is expected to be as follows:
Year
Estimated Amortization Expense
Remainder of 2013
$
30

2014
105

2015
97

2016
96

2017
92

2018
86

NOTE 6. FINANCIAL INSTRUMENTS
Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, debt and foreign currency forward contracts. Except as described below, the estimated fair value of such financial instruments at September 30, 2013 and December 31, 2012 approximates their carrying value as reflected in our unaudited consolidated condensed balance sheets.
The estimated fair value of total debt at September 30, 2013 and December 31, 2012 was $5,134 million and $5,829 million, respectively, which differs from the carrying amounts of $4,575 million and $4,916 million, respectively, included in our unaudited consolidated condensed balance sheets. The fair value was determined using quoted period-end market prices.
NOTE 7. SEGMENT INFORMATION
We conduct our business primarily through operating segments that are aligned with our geographic regions. We aggregate our operating segments within each reportable segment because they have similar economic characteristics and because the long-term financial performance of the operating segments is affected by similar economic conditions. The performance of our operating segments is evaluated based on profit before tax, which is defined as income before income taxes and before the following: net interest expense, corporate expenses and certain gains and losses not allocated to the operating segments.
Summarized financial information is shown in the following table:
 
Three Months Ended
 
Three Months Ended
 
September 30, 2013
 
September 30, 2012
Segments
Revenue
 
Profit (Loss) Before Taxes
 
Revenue
 
Profit (Loss) Before Taxes
North America
$
2,854

 
$
295

 
$
2,742

 
$
288

Latin America
557

 
(23
)
 
583

 
45

Europe/Africa/Russia Caspian
984

 
170

 
866

 
104

Middle East/Asia Pacific
1,064

 
156

 
844

 
70

Industrial Services and Other
328

 
38

 
320

 
38

Total Operations
5,787

 
636

 
5,355

 
545

Corporate and Other

 
(60
)
 

 
(59
)
Interest expense, net

 
(58
)
 

 
(49
)
Total
$
5,787

 
$
518

 
$
5,355

 
$
437


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Table of Contents                                
Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements


 
Nine Months Ended
 
Nine Months Ended
 
September 30, 2013
 
September 30, 2012
Segments
Revenue
 
Profit (Loss) Before Taxes
 
Revenue
 
Profit (Loss) Before Taxes
North America
$
8,134

 
$
741

 
$
8,277

 
$
1,046

Latin America
1,704

 
8

 
1,760

 
189

Europe/Africa/Russia Caspian
2,804

 
414

 
2,684

 
413

Middle East/Asia Pacific
2,929

 
387

 
2,393

 
232

Industrial Services and Other
933

 
101

 
922

 
104

Total Operations
16,504

 
1,651

 
16,036

 
1,984

Corporate and Other

 
(184
)
 

 
(232
)
Interest expense, net

 
(173
)
 

 
(153
)
Total
$
16,504

 
$
1,294

 
$
16,036

 
$
1,599

NOTE 8. EMPLOYEE BENEFIT PLANS
We have both funded and unfunded noncontributory defined benefit pension plans covering certain employees primarily in the U.S., the U.K., 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 retire and have met certain age and service requirements.
The components of net periodic pension cost are as follows for the three months ended September 30:
 
U.S. Pension Plans
 
Non-U.S. Pension Plans
 
Other Postretirement Benefits
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Service cost
$
16

 
$
16

 
$
4

 
$
2

 
$
1

 
$
3

Interest cost
5

 
5

 
8

 
8

 
1

 
2

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

 

Amortization of prior service benefit

 

 

 

 
(2
)
 

Amortization of net actuarial loss
3

 
4

 
2

 
2

 
1

 

Net periodic pension cost
$
15

 
$
16

 
$
5

 
$
3

 
$
1

 
$
5


The components of net periodic pension cost are as follows for the nine months ended September 30:
 
U.S. Pension Plans
 
Non-U.S. Pension Plans
 
Other Postretirement Benefits
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Service cost
$
48

 
$
48

 
$
12

 
$
6

 
$
5

 
$
9

Interest cost
16

 
15

 
24

 
24

 
3

 
6

Expected return on plan assets
(29
)
 
(27
)
 
(29
)
 
(27
)
 

 

Amortization of prior service benefit

 

 

 

 
(6
)
 
(2
)
Amortization of net actuarial loss
10

 
12

 
6

 
5

 
3

 
1

Benefit settlement

 

 

 
6

 

 

Net periodic pension cost
$
45

 
$
48

 
$
13

 
$
14

 
$
5

 
$
14


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Table of Contents                                
Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 9. 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 insure against these risks 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 and future legal proceedings. Most of these 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. 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 as necessary.
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.
On May 30, 2013, we received a Civil Investigative Demand (“CID”) from the United States Department of Justice (“DOJ”) pursuant to the Antitrust Civil Process Act.  The CID seeks 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 United States.  We are working with the DOJ to provide the requested documents and information. We are not able to predict what action, if any, might be taken in the future by the DOJ or other governmental authorities as a result of the investigation.
On September 19, 2012, our subsidiary, Baker Hughes Oilfield Operations, Inc. (“BHOO”) terminated a sand supply agreement it had entered into with Hi-Crush Operating, LLC (“Hi-Crush”) on October 28, 2011 (as amended by the First Amendment to Supply Agreement on May 10, 2012, collectively the “Supply Agreement”) as a result of Hi-Crush's breach of the Supply Agreement. On November 12, 2012, Hi-Crush filed a lawsuit against BHOO in the 129th Judicial District Court in Harris County, Texas, Cause No. 2012-67261; Hi-Crush Operating, LLC v. Baker Hughes Oilfield Operations, Inc. In its petition, Hi-Crush claimed that BHOO's termination was “invalid” constituting a breach and that BHOO “anticipatorily repudiated the Supply Agreement without just excuse.” Hi-Crush claimed that it was entitled to recover liquidated damages of $187 million based on the undelivered Minimum Purchase Requirement provision defined in the Supply Agreement; in the alternative, Hi-Crush sought an unspecified amount of actual damages. On December 17, 2012, BHOO filed a responsive pleading denying Hi-Crush's allegations and also filed a counter claim for breach of contract. On October 10, 2013, BHOO and Hi-Crush entered into a settlement agreement pursuant to which both parties agreed to jointly dismiss the above litigation.  In connection with this settlement agreement, the parties have entered into a new supply agreement.  The settlement agreement did not have a material impact on our financial position, results of operations or cash flows.
OTHER
In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, including surety bonds for performance, letters of credit and other bank guarantees, which totaled approximately $1.5 billion at September 30, 2013. 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.


11

Table of Contents                                
Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 10. ACCUMULATED OTHER COMPREHENSIVE LOSS
Total accumulated other comprehensive loss consists of the following:
 
Pensions and Other Postretirement Benefits
Currency Translation Adjustments
Hedge Transactions
Accumulated Other Comprehensive Loss
Balance at December 31, 2012
 
$
(250
)
 
 
$
(226
)
 
 
$

 
 
$
(476
)
 
Other comprehensive loss before reclassifications
 

 
 
(50
)
 
 
(1
)
 
 
(51
)
 
Amounts reclassified from accumulated other comprehensive loss
 
13

 
 

 
 

 
 
13

 
Deferred taxes
 
(4
)
 
 

 
 

 
 
(4
)
 
Balance at September 30, 2013
 
$
(241
)
 
 
$
(276
)
 
 
$
(1
)
 
 
$
(518
)
 
 
Pensions and Other Postretirement Benefits
Currency Translation Adjustments
Hedge Transactions
Accumulated Other Comprehensive Loss
Balance at December 31, 2011
 
$
(251
)
 
 
$
(304
)
 
 
$

 
 
$
(555
)
 
Other comprehensive income before reclassifications
 
9

 
 
61

 
 
1

 
 
71

 
Amounts reclassified from accumulated other comprehensive loss
 
16

 
 

 
 

 
 
16

 
Deferred taxes
 
(6
)
 
 

 
 

 
 
(6
)
 
Balance at September 30, 2012
 
$
(232
)
 
 
$
(243
)
 
 
$
1

 
 
$
(474
)
 
The amounts reclassified from accumulated other comprehensive loss during the nine months ended September 30, 2012 and 2013 represent the amortization of prior service benefit and net actuarial loss which are included in the computation of net periodic pension cost (see Note 8. Employee Benefit Plans for additional details). Net periodic pension cost is recorded in cost of sales and services, research and engineering, and marketing, general and administrative expenses.


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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 thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report”). Phrases such as "Baker Hughes," “Company,” “we,” “our” and “us” intend to refer to Baker Hughes Incorporated when used.
EXECUTIVE SUMMARY
Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. We provide products and services for:
drilling and evaluation of oil and natural gas wells;
completion and production of oil and natural gas wells; and
other businesses, including downstream refining, and process and pipeline services.
We operate our business primarily through geographic regions that have been aggregated into five reportable segments: North America, Latin America, Europe/Africa/Russia Caspian, Middle East/Asia Pacific and Industrial Services and Other. The four geographical segments represent our oilfield operations.
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. Our business is cyclical and is dependent upon our customers’ expectations for future oil and natural gas prices, economic growth, hydrocarbon demand and estimates of current and future oil and natural gas production.
For the third quarter of 2013, we generated revenue of $5.79 billion, an increase of $432 million, or 8%, compared to the third quarter of 2012, and an increase of $300 million, or 5%, compared to the second quarter of 2013, or sequentially. Revenue for the nine months ended September 30, 2013 was $16.50 billion compared to $16.04 billion for the same period in 2012. Net income attributable to Baker Hughes was $341 million for the third quarter of 2013 compared to $279 million for the third quarter of 2012, and $240 million for the second quarter of 2013. Net income attributable to Baker Hughes was $848 million for the first nine months of 2013 compared to $1,097 million for the first nine months of 2012.
North America oilfield revenue for the third quarter of 2013 was $2.85 billion, an increase of $112 million, or 4%, compared to the third quarter of 2012, and an increase of $177 million, or 7%, compared to the second quarter of 2013. North America oilfield profit before tax for the third quarter of 2013 was $295 million compared to $288 million for the third quarter of 2012, and $211 million for the second quarter of 2013. Our third quarter revenue and profitability for 2013 compared to the same quarter a year ago improved due to increased demand for our Pressure Pumping product line in both the U.S. and the Gulf of Mexico, and for the Wireline Services and Drilling and Completion Fluids product lines in the Gulf of Mexico, offset by the reduced activity for our Pressure Pumping product line in Canada. Compared to the second quarter of 2013, North America revenue and profit before tax improved primarily due to seasonal recovery in Canada, tempered by flooding in Alberta early in the third quarter of 2013. North America oilfield revenue for the nine months ended September 30, 2013 was $8.13 billion, a decrease of 2% compared to the same period in 2012. North America oilfield profit before tax for the nine months ended September 30, 2013 was $741 million compared to $1,046 million for the nine months ended September 30, 2012.
Oilfield revenue outside of North America for the third quarter of 2013 was $2.61 billion, an increase of 14% compared to the third quarter of 2012, driven by strong growth in both the Europe/Africa/Russia Caspian and Middle East/Asia Pacific segments. Sequentially, oilfield revenue outside of North America increased 4% due primarily to growth in the Middle East/Asia Pacific segment. Oilfield profitability outside of North America for the third quarter of 2013 was $303 million compared to $219 million for the third quarter of 2012 and $248 million for the second quarter of 2013. The Europe/Africa/Russia Caspian and Middle East/Asia Pacific segments experienced improvements in profitability compared to both the third quarter of 2012 and the second quarter of 2013. Profitability in Latin America declined when compared to the same two periods predominantly due to a significant

13

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decline in our drilling activities in Brazil as well as increases in our allowance for doubtful accounts and severance charges related to restructuring activities. Oilfield revenue outside of North America for the nine months ended September 30, 2013 was $7.44 billion, an increase of 9% compared to the nine months ended September 30, 2012. Oilfield profitability outside of North America for the nine months ended September 30, 2013 was $809 million compared to $834 million for the same period in 2012.
As of September 30, 2013, we had approximately 60,300 employees compared to approximately 58,800 employees as of December 31, 2012.
BUSINESS ENVIRONMENT
In North America, rig counts declined 5% in the third quarter of 2013 compared to the same period a year ago. Despite an 18 year low in the U.S. natural gas-directed rig count, natural gas production in the unconventional shale plays remained strong during the quarter, contributing to continued high natural gas working inventories. As a result, customer spending in the natural gas shale plays remained limited, with natural gas-directed rig activity declining 12% in North America during the third quarter of 2013 compared to the same period a year ago. Customer spending for oil in North America declined slightly during the third quarter of 2013 as evidenced by the decrease in the oil-directed rig count of 50 rigs, or 3%, compared to the same period in 2012.
Outside of North America, customer spending is most heavily influenced by Brent oil prices. On average, Brent oil prices were relatively flat in the third quarter of 2013 compared to the same period a year ago. Despite flat oil prices, the international rig count grew by 2% in the third quarter of 2013 compared to the same quarter in 2012, with the largest gains seen in Africa and Europe.
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,
 
2013
 
2012
 
2013
 
2012
Brent oil price ($/Bbl) (1)
$
110.04

 
$
109.90

 
$
108.61

 
$
112.46

WTI oil price ($/Bbl) (2)
105.78

 
92.16

 
98.15

 
96.15

Natural gas price ($/mmBtu) (3)
3.55

 
2.88

 
3.69

 
2.54

(1)
Bloomberg Dated Brent (“Brent”)
(2)
Bloomberg West Texas Intermediate (“WTI”) Cushing Crude Oil Spot Price
(3)
Bloomberg Henry Hub Natural Gas Spot Price
Brent oil prices averaged $110.04/Bbl in the third quarter of 2013. Brent oil prices increased sharply in the first two months of the third quarter of 2013 due to the near shut-down of Libya oil production and increasing geopolitical tensions in Syria. Prices began to decline, however, in September as tensions in Syria eased and concerns over a U.S. government shut-down increased fears for an economic downturn. During the quarter, Brent oil prices ranged from a low of $102.76/Bbl at the beginning of July 2013 to a high of $118.11/Bbl at the end of August 2013. Brent oil prices closed the quarter at $109.22/Bbl. According to the October 2013 Oil Market Report published by the International Energy Agency (“IEA”), recent demand growth has raised the 2013 oil demand forecast to 91.0 million barrels per day, and demand in 2014 is expected to increase by another 1.1 million barrels per day due to macroeconomic improvements. The estimated 2013 global demand exceeds 2012 global demand of 89.9 million barrels per day.
WTI oil prices averaged $105.78/Bbl in the third quarter of 2013. Prices ranged from a low of $97.99/Bbl at the beginning of July 2013 to a high of $110.53/Bbl in early September 2013. WTI prices closed the quarter at $102.33/Bbl. During the quarter, the Brent-WTI spread, or the difference between the spot prices of Brent and WTI crude

14

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oils, continued to narrow in the early part of the quarter to within $0.66/Bbl. This represents the lowest spread in three years, and is primarily attributed to displacement of Brent-quality crude imports into North America by increased U.S. oil production and improved crude-by-rail and pipeline infrastructure within the U.S.
In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $3.55/mmBtu in the third quarter of 2013. Natural gas prices were relatively flat during the quarter as temperatures in the key consuming regions of the U.S. were near average levels, and natural gas working inventory levels were within analysts' expectations. Overall for the quarter, prices ranged from a high of $3.78/mmBtu in July 2013 to a low of $3.27/mmBtu in August 2013. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of the third quarter of 2013 was 3,487/Bcf, which was 5%, or 166/Bcf, below the corresponding period in 2012.
Baker Hughes Rig Count
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/or other outside sources. 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. As of February 2013, Syria is excluded from the rig count due to difficulty obtaining data as a result of continued civil unrest. In June 2012, Baker Hughes resumed publication of the rig count in Iraq for the first time since August 1990.
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 drill bits. In international areas, rigs are counted on a weekly basis and deemed active if drilling activities occurred during 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,
 
 
2013
2012
% Change
2013
2012
% Change
U.S. - land and inland waters
1,709

1,855

(8
%)
1,708

1,909

(11
%)
U.S. - offshore
61

51

20
%
55

47

17
%
Canada
350

325

8
%
344

362

(5
%)
North America
2,120

2,231

(5
%)
2,107

2,318

(9
%)
Latin America
407

414

(2
%)
419

428

(2
%)
North Sea
43

38

13
%
44

38

16
%
Continental Europe
97

79

23
%
91

78

17
%
Africa
124

108

15
%
122

93

31
%
Middle East
373

390

(4
%)
366

348

5
%
Asia Pacific
241

230

5
%
246

240

3
%
Outside North America
1,285

1,259

2
%
1,288

1,225

5
%
Worldwide
3,405

3,490

(2
%)
3,395

3,543

(4
%)
The rig count in North America decreased 5% in the third quarter of 2013 compared to the same period a year ago as natural gas-directed rig counts declined 12%, and oil-directed rig counts were down 3%. The natural gas-

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directed rig count reflected a 22% decrease in the U.S., partially offset by a 48% increase in Canada. The oil-directed rig count decreased 2% in the U.S. and 7% in Canada. Natural gas-directed drilling was negatively impacted by the continued weakness in U.S. natural gas prices, which discouraged new investment in natural gas fields. In Canada, wet weather in southern Alberta and Saskatchewan negatively affected oil-directed drilling activity during the third quarter of 2013. This decrease was, however, more than offset by increased natural gas-directed rig activity in West Central Alberta.
Outside North America, the rig count in the third quarter of 2013 increased 2% compared to the same period a year ago. The rig count in Latin America decreased 2% primarily due to lower land rig activity in Brazil and Mexico, partially offset by increased rig activity in Argentina and Venezuela. In Europe, the rig count in the North Sea increased 13% primarily due to Norway, while in Continental Europe, the rig count increased 23% primarily due to higher activity in Turkey, the Balkans and Sakhalin. The rig count increased 15% in Africa primarily due to increased drilling activities in Angola and Kenya. The rig count decreased 4% in the Middle East primarily due to the exclusion of Syria from the rig count and a sharp drop in Egypt. These declines were offset by increased activity in Iraq. In Asia Pacific, the rig count increased 5% as a result of higher activity in India.
Baker Hughes Well Count

Baker Hughes began providing well count data to the oil and natural gas industry in July 2013. The Baker Hughes Well Count is an extension of the Baker Hughes Rig Count, and provides a quarterly census of the number of new onshore oil and natural gas wells where drilling began, or spud, in the U.S. The Baker Hughes Well Count includes wells that are identified to be significant consumers of oilfield services and supplies, and excludes wells categorized as workover, plugged and abandoned or completed. We believe the counting process and resulting data is reliable; however, it is subject to our ability to obtain accurate and timely information.
During the third quarter of 2013, 9,175 wells were spud on land in the U.S. This compares to 9,411 wells spud in the third quarter of 2012, or a reduction of 3%. For the nine months ended September 30, 2013, 26,720 wells were spud on land in the U.S. This compares to 28,166 wells during the first nine months of 2012, or a reduction of 5%.
RESULTS OF OPERATIONS
The discussions below relating to significant line items from our unaudited consolidated condensed statements of income 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 possible and practical, have quantified the impact of such items. In addition, the discussions below are based on total revenue and total cost of revenue because the business drivers for the individual components of product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.

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Revenue and Profit Before Tax
We conduct our business primarily through operating segments that are aligned with our geographic regions, which have been aggregated into five reportable segments. The performance of our operating segments is evaluated based on profit before tax, which is defined as income before income taxes and before the following: net interest expense, corporate expenses, and certain gains and losses not allocated to the segments.

 
Three Months Ended September 30,
 
$ Change
 
% Change
 
Nine Months Ended September 30,
 
$ Change
 
% Change
 
2013
 
2012
 
 
2013
 
2012
 
Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North America
$
2,854

 
$
2,742

 
$
112

 
4
%
 
$
8,134

 
$
8,277

 
$
(143
)
 
(2
%)
Latin America
557

 
583

 
(26
)
 
(4
%)
 
1,704

 
1,760

 
(56
)
 
(3
%)
Europe/Africa/Russia Caspian
984

 
866

 
118

 
14
%
 
2,804

 
2,684

 
120

 
4
%
Middle East/Asia Pacific
1,064

 
844

 
220

 
26
%
 
2,929

 
2,393

 
536

 
22
%
Industrial Services and Other
328

 
320

 
8

 
3
%
 
933

 
922

 
11

 
1
%
Total
$
5,787

 
$
5,355

 
$
432

 
8
%
 
$
16,504

 
$
16,036

 
$
468

 
3
%

 
Three Months Ended September 30,
 
$ Change
 
% Change
 
Nine Months Ended September 30,
 
$ Change
 
% Change
 
2013
 
2012
 
 
2013
 
2012
 
Profit Before Tax:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North America
$
295

 
$
288

 
$
7

 
2
%
 
$
741

 
$
1,046

 
$
(305
)
 
(29
%)
Latin America
(23
)
 
45

 
(68
)
 
(151
%)
 
8

 
189

 
(181
)
 
(96
%)
Europe/Africa/Russia Caspian
170

 
104

 
66

 
63
%
 
414

 
413

 
1

 
%
Middle East/Asia Pacific
156

 
70

 
86

 
123
%
 
387

 
232

 
155

 
67
%
Industrial Services and Other
38

 
38

 

 
%
 
101

 
104

 
(3
)
 
(3
%)
Total Operations
636

 
545

 
91

 
17
%
 
1,651

 
1,984

 
(333
)
 
(17
%)
Corporate and Other
(60
)
 
(59
)
 
(1
)
 
2
%
 
(184
)
 
(232
)
 
48

 
(21
%)
Interest Expense, net
(58
)
 
(49
)
 
(9
)
 
18
%
 
(173
)
 
(153
)
 
(20
)
 
13
%
Total
$
518

 
$
437

 
$
81

 
19
%
 
$
1,294

 
$
1,599

 
$
(305
)
 
(19
%)
Third Quarter of 2013 Compared to the Third Quarter of 2012
Revenue for the third quarter of 2013 increased $432 million, or 8%, compared to the third quarter of 2012. North American revenue increased 4% due to improved demand for pressure pumping in the U.S. and the Gulf of Mexico, offset by lower revenue for pressure pumping in Canada. International revenue increased primarily as a result of increased activity in the Middle East, Africa, Russia Caspian and Asia Pacific regions.
Profit before tax for the third quarter of 2013 increased $81 million, or 19%, compared to the third quarter of 2012. The improvement in profit before tax was largely attributable to increased revenue in the Middle East, Africa, Russia Caspian and Asia Pacific regions, partially offset by a decline in activity, increased reserves for doubtful accounts and severance charges in Latin America.

17

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North America
North America revenue for the third quarter of 2013 was $2.85 billion, an increase of $112 million, or 4%, compared to the third quarter of 2012, despite a 5% decrease in the overall North America rig count during this time. Revenue from our Pressure Pumping product line in the U.S. increased year over year due to share gains across several basins. In addition, revenue increased for our Drilling Services, Artificial Lift and Completions Systems product lines in the U.S. The Gulf of Mexico experienced an increase in revenue as a result of the growth of the U.S. offshore rig count. The increase in rig activity primarily benefited our Wireline Services, Pressure Pumping and Drilling and Completion Fluids product lines. These results were partially offset by a decline in our Pressure Pumping product line in Canada, where lower demand for hydraulic fracturing adversely impacted revenue for the quarter.
North America profit before tax was $295 million in the third quarter of 2013, an increase of $7 million compared to the third quarter of 2012. Gulf of Mexico profitability improved due to increased activity for our Drilling Services and Wireline Services product lines, along with improved mix for deepwater completions, which provide higher margins. Pressure Pumping margins in the U.S. improved mainly due to improved asset utilization and wellsite efficiencies and reduced raw material costs. However, these gains were largely offset by declining demand for the Pressure Pumping product line in Canada.
Latin America
Latin America revenue decreased 4% in the third quarter of 2013 compared to the third quarter of 2012 due primarily to lower activity levels in Brazil and Venezuela, partially offset by revenue growth in other countries. In Brazil, the rig count declined 32% in the third quarter of 2013 compared to the third quarter of 2012, which resulted in reduced demand for our Drilling Services product line. In addition to reduced demand for our drilling services, our current drilling services contract provides lower pricing than in the prior year. In Venezuela, reduced activity levels also led to lower revenue across most product lines. Revenue in Latin America was also negatively impacted due to unfavorable exchange rates. These reductions were partially mitigated by increases in demand for drilling services and artificial lift in Ecuador and Colombia and for pressure pumping in Mexico.
Latin America profit before tax decreased 151% in the third quarter of 2013 compared to the third quarter of 2012. The decrease in profit before tax in Latin America was related to Brazil where our activity and market share declined as a result of our current drilling services contract as well as reduced activity in Venezuela. Due to the decline in activity in Latin America described above, we took action to restructure the organization, which resulted in a charge for severance of $19 million in the third quarter of 2013. Profit before tax in Latin America was further reduced by a charge of $42 million related to our allowance for doubtful accounts in the third quarter of 2013 compared to $22 million in the third quarter of 2012.
Europe/Africa/Russia Caspian
Europe/Africa/Russia Caspian (“EARC”) revenue increased 14% in the third quarter of 2013 compared to the third quarter of 2012 primarily due to activity growth in Africa and the Russia Caspian region. In Africa, revenue grew due to increased activity in North Africa benefiting our Wireline Services, Drill Bits, Completions Systems and Pressure Pumping product lines. Increased activity in Nigeria for our Drilling Services, Pressure Pumping and Drilling and Completion Fluids product lines also contributed. Revenue in the Russia Caspian region improved due to increased product sales for our Completions Systems product line, as well as higher activity for drilling services and artificial lift. In Europe, revenue decreased slightly during the third quarter of 2013 compared to the third quarter of 2012. The primary drivers of the decrease were lower activity in the United Kingdom for most product lines coupled with the completion of drilling and completion fluids projects in the Eastern Mediterranean. These declines in Europe were offset by increased revenue in Norway from our Drilling Services, Drilling and Completion Fluids and Pressure Pumping product lines.
EARC profit before tax increased 63% in the third quarter of 2013 compared to the third quarter of 2012. The higher revenue for this segment, driven by increased activity in both Africa and Russia Caspian, was the primary reason for this increase in profitability. Profit before tax in Europe was flat year over year.

18

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Middle East/Asia Pacific
Middle East/Asia Pacific (“MEAP”) revenue increased 26% in the third quarter of 2013 compared to the third quarter of 2012. The increase in this segment was largely attributable to the Middle East where we experienced higher demand for our Drilling Services product line in Saudi Arabia, growth in our Integrated Operations contracts in both Iraq and Saudi Arabia, and increased activity for our Drilling Services, Wireline Services and Completions Systems product lines in the Arabian Gulf. In Asia Pacific, revenue improved in Southeast Asia for our Drilling Services, Pressure Pumping and Integrated Operations product lines. In China, we experienced increased demand for our Drilling Services and Artificial Lift product lines.
MEAP profit before tax increased 123% in the third quarter of 2013 compared to the third quarter of 2012. The increase in profit before tax was the result of revenue growth across the majority of our product lines and improved margins resulting from share gains and increased activity for drilling services in the Arabian Gulf, Indonesia, Australia and Southeast Asia.
Industrial Services and Other
For Industrial Services and Other, revenue increased $8 million in the third quarter of 2013 compared to the third quarter of 2012 with profit before tax remaining flat.
Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012
Revenue for the nine months ended September 30, 2013 increased $468 million compared to the nine months ended September 30, 2012. Revenue increases in the Europe/Africa/Russia Caspian and Middle East/Asia Pacific segments were partially offset by lower revenue in North America which was impacted by the Pressure Pumping product line in both the U.S. and Canada, and lower revenue in Latin America.
Profit before tax for the nine months ended September 30, 2013 decreased $305 million, or 19%, compared to the nine months ended September 30, 2012. The North America segment saw the largest decline due to lower rig count activity and decreased fleet utilization for the Pressure Pumping product line in both the U.S. and Canada. The Latin America segment saw deterioration in profit due to lower rig count activity in Brazil that impacted our Drilling Services and Artificial Lift product lines, the impact of the currency devaluation in Venezuela, severance costs and additional reserves for doubtful accounts across the segment. These reductions were partially offset by strong improvement in the Middle East/Asia Pacific segment, in particular for our Drilling Services product line. The Europe/Africa/Russia Caspian segment experienced improved profitability in both Africa and Russia Caspian, which was offset by an unfavorable change in sales mix along with increased personnel and start up costs associated with our integrated drilling services contract in Norway.
Costs and Expenses
The table below details certain unaudited consolidated condensed statement of income data and their percentage of revenue.

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
 
$
 
%
 
$
 
%
 
$
 
%
 
$
 
%
Revenue
$
5,787

 
100
%
 
$
5,355

 
100
%
 
$
16,504

 
100
%
 
$
16,036

 
100
%
Cost of revenue
4,750

 
82
%
 
4,396

 
82
%
 
13,667

 
83
%
 
12,915

 
81
%
Research and engineering
142

 
2
%
 
118

 
2
%
 
400

 
2
%
 
370

 
2
%
Marketing, general and administrative
319

 
6
%
 
355

 
7
%
 
970

 
6
%
 
999

 
6
%

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Cost of Revenue
Cost of revenue as a percentage of revenue was 82% for the three months ended September 30, 2013 and 2012, 83% for the nine months ended September 30, 2013, and 81% for the nine months ended September 30, 2012. The increase in cost of revenue as a percentage of revenue for the nine months ended September 30, 2013 was due primarily to lower margins in our Pressure Pumping product line in North America. Additionally, in Latin America, margins declined due to reduced pricing for drilling services, increased severance costs, and an increase in our allowance for doubtful accounts. Margins were also negatively impacted by an increase in operating costs and third party expenses related to integrated operations contracts in the Middle East, start up costs associated with a drilling services contract in Norway, and an unfavorable change in sales mix in Europe.
Marketing, General and Administrative
Marketing, general and administrative expenses decreased 10% and 3% for the three months and nine months ended September 30, 2013, respectively, compared to the same periods a year ago. General and administrative expenses in 2013 decreased as a result of a non-recurring charge recorded in the third quarter of 2012 of $43 million related to the impairment of certain information technology assets as well as the winding down of our worldwide integration efforts subsequent to our acquisition of BJ Services. The conclusion of our integration efforts resulted in decreased costs related to technology, project management and personnel, and led to improved efficiencies among our global operations and support functions. The reduction in general and administrative expenses was partially offset by the loss of $23 million due to the currency devaluation in Venezuela that occurred in the first quarter of 2013, higher salaries and wage costs for personnel and foreign exchange losses caused by unfavorable movements in exchange rates for most foreign currencies against the U.S. Dollar.
Income Taxes
Total income tax expense was $178 million and $441 million for the three months and nine months ended September 30, 2013, respectively. Our effective tax rate on income before income taxes for the three months and nine months ended September 30, 2013 was 34.4% and 34.1%, respectively. The tax rate for the nine months ended September 30, 2013 is lower than the U.S. statutory income tax rate of 35% primarily due to lower rates of tax in certain foreign jurisdictions and the tax benefits recorded as part of the American Taxpayer Relief Act of 2012, partially offset by state income taxes.
OUTLOOK
This section should be read in conjunction with the factors described in “Part II, Item 1A. Risk Factors” and in the “Forward-Looking Statements” section in this Part I, Item 2, both contained herein. These factors could impact, either positively or negatively, our expectation for: oil and natural gas demand; oil and natural gas prices; exploration and development spending and drilling activity; and production spending.
Our industry is cyclical, and past cycles have been driven primarily by alternating periods of ample supply or shortage of oil and natural gas relative to demand. As an oilfield services company, our revenue 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, their expectations for future energy prices, their access to resources to develop and produce oil and natural gas, their ability to fund their capital investment programs, and the impact of new government regulations.
Our outlook for exploration and development spending is based upon our expectations for customer spending in the global markets in which we operate, and is driven primarily by our perception of industry expectations for oil and natural gas prices, and their likely impact on customer capital and operating budgets as well as other factors that could impact the economic return oil and natural gas companies expect for developing oil and natural gas reserves. Our forecasts are based on evaluating a number of external sources as well as our internal estimates. External sources include publications by the IEA, Organization of Petroleum Exporting Countries (“OPEC”), the Energy Information Administration (“EIA”), and the Organization for Economic Cooperation and Development (“OECD”). We acknowledge that there is a substantial amount of uncertainty regarding these forecasts, thus, while we have

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internal estimates regarding economic expansion, hydrocarbon demand and overall oilfield activity, we position ourselves to be flexible and responsive to a wide range of potential outcomes.
The primary drivers impacting the 2013 business environment include the following:
Worldwide Economic Growth - In general, there is a strong correlation between overall economic growth and global demand for hydrocarbons. The economic outlook for the remainder of 2013 includes strengthening activity but also heightened risks: European countries face concerns over rising sovereign debt levels, China's economy is experiencing slower growth, and the U.S. continues its moderate pace of recovery. The sovereign debt crisis in Europe has had repercussions for the economies of major exporters, including the U.S. and China. Although steps have been taken by governments to resolve this issue, the crisis and the worsening macroeconomic conditions in the Euro area remain a threat to the global economic outlook. China's rapid economic growth and industrialization has been a major factor in driving up worldwide economic growth since the recession of 2008/2009. China's economic growth rate slowed significantly to 7.8% in 2012, representing its slowest pace since 1999. The economy was projected to pick up in 2013 with year over year forecasts of 8.0% across the board. However, the first quarter 2013 growth rate came in at 7.7% and second quarter growth was 7.5%. The International Monetary Fund and World Bank, among other major financial institutions, have cut estimates for China's 2013 economic growth to approximately 7.6%. Further, China's economic growth for 2014 is currently forecast at 7.3% as policymakers refrain from stimulating activity amid concerns for financial stability and the need to support a more balanced and sustainable growth plan. In the U.S., the expectation for economic growth is to rise from a modest 1.6% throughout 2013 to 2.6% in 2014 driven by continued strength in private demand, which is supported by a recovering housing market. However, this growth may be hampered by weakness or further deterioration of the global economy, particularly in China and Europe. Additionally, the Federal Reserve has hinted on the potential withdrawal of quantitative easing by the middle of 2014, which would eliminate approximately $1 trillion in yearly liquidity injections. The reduction in quantitative easing could result in significant increases in interest rates, and therefore, the cost of borrowing towards new capital projects.
Demand for Hydrocarbons - In its October 2013 Oil Market Report, the IEA forecasted global demand for oil to increase by 1.0 million barrels per day (“bpd”) in 2013, reaching 91.0 million bpd. For 2014, the IEA expects global oil demand to grow further by 1.1 million bpd to 92.1 million bpd. This expected increase in demand for oil, mainly driven by countries outside the OECD, should support upstream investment in oil and natural gas production around the world. In addition to the global growth in oil demand, natural gas will play an increasingly important role in meeting the world’s energy needs. In its October 2013 Short-Term Energy Outlook, the EIA estimated that U.S. natural gas demand would increase by 0.3 billion cubic feet per day (“bcfd”) in 2013, reaching 70.0 bcfd. For 2014, the EIA projects that U.S. natural gas demand will decline by 0.6 bcfd to 69.4 bcfd.
Oil Production - The October 2013 IEA Oil Market Report projected non-OPEC production to grow by 1.1 million bpd in 2013 to 54.7 million bpd, and a further 1.7 million bpd in 2014. This increase is largely due to continued production growth from U.S. tight oil formations and Canadian oil sands, fostered by sustained higher oil prices. This North American output growth offsets lower supply from European and Latin American countries. Global OPEC production is anticipated to fall by 0.4 million bpd in 2013 to 29.9 million bpd, and a further 0.9 million bpd in 2014. Significant investments are expected to be required to increase production capacity, especially in the context of declining production from mature fields and the rapid declines in early well production observed in many unconventional plays. New production is anticipated to be increasingly sourced from technically challenging fields with high unit costs, such as in deepwater environments, shale plays and heavy oil deposits. Price volatility driven by global economic and geopolitical uncertainties may lead to delays in operator investment decisions across the rest of the world.
Natural Gas Production - Natural gas production continues to grow worldwide, including North America where drilling activity has slowed. Despite U.S. natural gas-directed rig counts reaching 18-year lows in recent months, natural gas production in the U.S. has increased. In its October 2013 Short-Term Energy Outlook, the EIA estimated that U.S. natural gas production would increase by 0.8 bcfd in 2013, reaching 70.0 bcfd. For 2014, the EIA projects that U.S. natural gas production will further increase by 0.4 bcfd to 70.4 bcfd. Overall, worldwide natural gas production will tend to be more stable as high natural gas prices in places such as Europe and Asia encourage sustained global growth.

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Oil Prices - With WTI oil prices trading between $97.99/Bbl and $110.53/Bbl, and Brent trading between $102.76/Bbl and $118.11/Bbl during the third quarter of 2013, most global oil activity will continue to provide adequate returns to encourage incremental investment. Based on oil supply forecasts and modest anticipated economic growth globally, oil prices are expected to remain relatively stable throughout 2013, barring any major macroeconomic changes.
Natural Gas Prices - With Henry Hub natural gas prices trading between $3.27/mmBtu and $3.78/mmBtu during the third quarter of 2013, particularly low prices when compared to oil on a Btu-equivalent basis, we believe that the economics of most dry natural gas-directed investments in North America will continue to be marginal. This is primarily due to the abundant supplies available from the unconventional plays in North America, including natural gas produced in association with unconventional oil wells, which is expected to remain high for the remainder of 2013. However, natural gas in storage between April and July 2013 fell below the five-year average for that time of year. The decline of natural gas in storage resulted from the combination of increased demand for natural gas in the U.S. and flat overall production. In its October 2013 Short-Term Energy Outlook, the EIA projected Henry Hub natural gas prices will trade at an average of $3.71/mmBtu in 2013 and $4.00/mmBtu in 2014. In the medium-term, natural gas demand and pricing in the U.S. are highly sensitive to assumptions regarding fuel competition for power generation and the start of exports of liquefied natural gas (“LNG”), currently anticipated to be in the fourth quarter of 2015.
Activity and Spending Outlook for North America - Overall customer spending in North America is expected to increase in 2013 compared to 2012, but the average annual rig count is expected to remain close to the levels set in the fourth quarter of 2012, in part reflecting improved efficiencies in drilling performance. Driven by sustained high ratios of liquids-to-natural gas prices, incremental investment to develop liquids-rich unconventional plays has offset the slowdown in spending. Overall service activity has increased in North America as customers are demanding robust technologies such as advanced directional drilling, complex completion systems and pressure pumping to develop liquids-rich unconventional plays such as the Bakken shale basin. Activity on the continental shelf has been strong after a record level of new permits for deepwater wells were issued in 2012. The pace of permitting has leveled out thus far in 2013. It is expected that exploration drilling as well as completions and development activity in the Gulf of Mexico will continue to increase through the remainder of 2013, with additional deep water rigs being added. In Canada, overall rig activity in 2013 is expected to decline by approximately 2% compared to 2012.
Activity and Spending Outlook Outside North America - International activity is driven primarily by the price of oil and natural gas, both of which are high enough to provide attractive economic returns in almost every geographic region and to support some major natural gas export projects. Customers are expected to increase spending to develop new resources and offset declines from existing developed fields, increasingly relying on advanced drilling techniques to support exploration and production activities in deep water, heavy or viscous oils and tight reservoirs. Areas that are expected to see increased spending in 2013 include: the Middle East, in particular Iraq (including the province of Kurdistan), and Saudi Arabia; and Latin America, with the largest growth expected in Mexico, Brazil and Colombia.
Around the world, the drivers of commercialization have changed. Within Southeast Asia, there is an increased focus on exploration and development of oil and natural gas resources to meet rapid local demand growth rather than the historic role of meeting exports. In Africa, traditional growth areas such as Angola and Nigeria are being augmented by new producers such as Ghana, Uganda, Mozambique and Tanzania, while South Sudan resumed oil exports in the first quarter of 2013. Russia is striving to maintain 10 million barrels of oil production per day until the end of the decade by investing in Eastern Siberia and eventually in technically challenging offshore Arctic deposits. Efforts in Russia at developing tight oil using vertical drilling are already underway with government support for pilot projects in 2013 and for more complex horizontal drilling and completions. Focusing on natural gas, Australia is leading the expansion of LNG export projects, requiring conventional offshore gas drilling in the northwest shelf as well as coal bed methane operations onshore in Queensland. Large scale gas pipeline exports from the Caspian region to China and Europe are expected to grow significantly in the next five years, spurring drilling for deeper targets, both onshore and offshore, and increased natural gas process plant capacity.
While the development of unconventional oil and natural gas deposits is still in its infancy outside North America, there is a broad consensus that unconventional resources will play a growing role in the future of global energy supply. Countries taking active steps to develop their unconventional reserves base include Australia,

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China, Saudi Arabia and Argentina. However, there is a demonstrated active interest at ministry and national oil company level in defining unconventional resource potential in almost all countries with active oil and natural gas industries.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2013, we had cash and cash equivalents of $1.37 billion, compared to $1.02 billion of cash and cash equivalents held at December 31, 2012. Substantially all of the consolidated cash balances were held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at September 30, 2013 was reinvested in our international operations as our 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 taxes.
In addition, we have a $2.5 billion committed revolving credit facility with commercial banks and a commercial paper program under which we may issue up to $2.5 billion. The maximum combined borrowing at any time under both the credit facility and commercial paper program is $2.5 billion. At September 30, 2013, we had $494 million of commercial paper outstanding. We believe that cash on hand, cash flows from operating activities, and the available credit facility, including the issuance of commercial paper, will provide sufficient liquidity to manage our global cash needs.
Cash Flows
Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our Company. In the nine months ended September 302013, we used cash to pay for a variety of activities including working capital needs, capital expenditures and the payment of dividends.
The following table summarizes cash flows provided by (used in) type of activity, for the nine months ended September 30:

(In millions)
2013
 
2012
Operating activities
$
2,158

 
$
947

Investing activities
(1,304
)
 
(1,896
)
Financing activities
(499
)
 
902

Operating Activities
Cash flows from operating activities provided $2,158 million in the nine months ended September 302013. Before changes in operating assets and liabilities, the major source of funds was net income, including noncontrolling interests, of $853 million plus the noncash provision for depreciation and amortization of $1,262 million. Net changes in operating assets and liabilities provided $96 million in the nine months ended September 302013. This was primarily the result of an increase in accounts receivable of $651 million due to an increase in revenue and an increase in inventory of $191 million offset by an increase in accounts payable of $749 million.
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 and other infrastructure in place to support operations. Expenditures for capital assets totaled $1,552 million in the nine months ended September 302013. These expenditures were for machinery and equipment, new facilities, expansions of existing facilities and other infrastructure projects.
Proceeds from the disposal of assets were $276 million in the nine months ended September 302013. These disposals related to lost-in-hole equipment and property, machinery and equipment no longer used in operations that were sold throughout the period.

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Financing Activities
We had net repayments related to commercial paper and other debt with three months or less original maturity of $391 million and net proceeds from borrowings of other short-term debt of $59 million in the nine months ended September 302013. Total debt outstanding at September 30, 2013 was $4.58 billion, a decrease of $341 million compared to December 31, 2012. The total debt-to-capital (defined as total debt plus equity) ratio was 0.20 at September 30, 2013 and 0.22 at December 31, 2012. We paid dividends of $200 million in the nine months ended September 302013.
Available Credit Facility
We have a $2.5 billion committed revolving credit facility with commercial banks that matures in September 2016. At September 30, 2013, we were in compliance with all of the facility’s covenants. There were no direct borrowings under the committed credit facility during the quarter ended September 30, 2013. We also have an outstanding commercial paper program under which we may issue from time to time up to $2.5 billion in commercial paper with maturity of no more than 270 days. The maximum combined borrowing at any point in time under both the commercial paper program and the credit facility is $2.5 billion. At September 30, 2013, we had $494 million of commercial paper outstanding resulting in $2.0 billion available under the credit facility.
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 our short-term borrowing costs or the cost of new debt financing.
We believe our current credit ratings would allow us to obtain additional financing over and above our existing credit facility for any currently unforeseen significant needs or growth opportunities. We also believe that such additional financing could be funded with subsequent issuances of long-term debt or equity, if necessary.
Cash Requirements
In 2013, 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 support the development of our short-term and long-term operating strategies.
In 2013, we expect our capital expenditures to be approximately $2.1 billion, excluding any amount related to acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support our business. A significant portion of our capital expenditures can be adjusted based on future activity of our customers, and accordingly, we will manage our capital expenditures to match market demand. In 2013, we also expect interest payments to be in the range of $225 million to $240 million, based on debt levels as of September 30, 2013. We expect income tax payments to be in the range of $675 million to $725 million in 2013.
Our Board of Directors has authorized a program to repurchase our common stock. We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. In the nine months ended September 302013 and 2012, we did not repurchase any shares of common stock. At September 30, 2013, we had authorization remaining to repurchase approximately $1.2 billion in common stock. We expect to pay dividends in the range of $263 million to $273 million in 2013; however, the Board of Directors can change the dividend policy at any time.
During the nine months ended September 30, 2013, we contributed approximately $250 million to our defined benefit, defined contribution and other postretirement plans. We expect to make additional contributions in the range of $80 million to $110 million to these plans for the remainder of 2013.

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New Accounting Standards Updates
For further information, see Note 1 of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 herein.
FORWARD-LOOKING STATEMENTS
MD&A and certain statements in the Notes to Unaudited Consolidated Condensed Financial Statements, includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act (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 transactions that could occur. 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.
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 factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in “Part II, Item 1A. Risk Factors” section contained herein, as well as the risk factors described in our 2012 Annual Report, this filing 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 system (“EDGAR”) at http://www.sec.gov.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information about market risks for the nine months ended September 30, 2013, does not differ materially from that discussed under Part II, Item 7(a), “Quantitative and Qualitative Disclosures About Market Risk,” in our 2012 Annual Report on Form 10-K.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this Quarterly 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 September 30, 2013, our disclosure controls and procedures, as defined by Rule 13a-15(e) of the Exchange Act, are effective at a reasonable assurance level. There has been no change in our internal controls over financial reporting during the quarter ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
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 Quarterly 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.


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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See discussion of legal proceedings in Note 9 of the Notes to Unaudited Consolidated Condensed Financial Statements in this Quarterly Report, Item 3 of Part I of our 2012 Annual Report and Note 11 of the Notes to Consolidated Financial Statements included in Item 8 of our 2012 Annual Report.
ITEM 1A. RISK FACTORS
As of the date of this filing, the Company and its operations continue to be subject to the risk factors previously disclosed in our “Risk Factors” in the 2012 Annual Report as well as the following risk factor:

Our business is dependent upon the issuance of permits, licenses, and other regulatory approvals, which could be delayed by government disruptions.

Many products and services used in oil and natural gas operations and distributed via our supply chain are subject to export controls and other regulations. This would include radioactive materials, explosives, certain chemicals and other controlled materials. Likewise, our customers’ ability to operate is dependent upon similar export controls, as well as the issuance of permits by national, state, and local governments. 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. This could decrease the activity in the affected regions. Additionally, it could hinder our ability, and the ability of our customers, to export and import materials to and from the affected countries.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table contains information about our purchases of equity securities during the three months ended September 302013.

Period
Total
 Number
of Shares
Purchased (1)
 
Average
Price
Paid Per Share (1)
Total
 Number
of Shares
Purchased as
Part of a
Publicly
Announced
Program (2)
 
Average
Price
Paid Per Share (2)
Total
 Number
of Shares
Purchased in the Aggregate
 
Maximum Number
(or Approximate
Dollar Value) of
Shares that May Yet
Be Purchased Under the Program (2)
July 1-31, 2013
21,726

 
$
48.02


 
$

21,726

 
$

August 1-31, 2013
832

 
45.90


 

832

 

September 1-30, 2013
1,150

 
49.07


 

1,150

 

Total
23,708

 
$
48.00


 
$

23,708

 
$
1,197,127,803

(1)
Represents shares purchased from employees to pay the option exercise price related to stock-for-stock exchanges in option exercises or to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.
(2)
Our Board of Directors has authorized a program to repurchase our common stock from time to time. During the three months ended September 302013, we did not repurchase any shares of our common stock under the program. We had authorization remaining to repurchase up to a total of approximately $1.2 billion of our common stock.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.

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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 Quarterly Report.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
Each exhibit identified below is filed as a part of this report. Exhibits designated with an “*” are filed as an exhibit to this Quarterly Report on Form 10-Q. Exhibits designated with a "+" are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference.

31.1*
 
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.
31.2*
 
Certification of Peter A. Ragauss, Senior Vice President and Chief Financial Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
32*
 
Statement of Martin S. Craighead, Chairman and Chief Executive Officer, and Peter A. Ragauss, Senior Vice President and Chief Financial Officer, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.
95*
 
Mine Safety Disclosure.
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


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
 
BAKER HUGHES INCORPORATED
(Registrant)
 
 
 
 
Date:
October 23, 2013
By:
/s/ PETER A. RAGAUSS
 
 
 
Peter A. Ragauss
 
 
Senior Vice President and Chief Financial Officer
 
 
 
 
Date:
October 23, 2013
By:
/s/ ALAN J. KEIFER
 
 
 
Alan J. Keifer
 
 
Vice President and Controller

28
2013.09.30 Exhibit 31.1


Exhibit 31.1
CERTIFICATION
I, Martin S. Craighead, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Baker Hughes Incorporated;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 
 
 
Date:
October 23, 2013
By:  
/s/ Martin S. Craighead
 
 
 
Martin S. Craighead
 
 
 
Chairman and
Chief Executive Officer 
 
 


2013.09.30 Exhibit 31.2


Exhibit 31.2
CERTIFICATION
I, Peter A. Ragauss, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Baker Hughes Incorporated;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 
 
 
Date:
October 23, 2013
By:  
/s/ Peter A. Ragauss  
 
 
 
Peter A. Ragauss 
 
 
 
Senior Vice President and
Chief Financial Officer 
 
 



2013.09.30 Exhibit 32


Exhibit 32
CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Baker Hughes Incorporated (the “Company”) on Form 10-Q for the period ended September 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Martin S. Craighead, Chairman and Chief Executive Officer of the Company, and Peter A. Ragauss, the Chief Financial Officer of the Company, each of the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(i)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(ii)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.
The certification is given to the knowledge of the undersigned.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
/s/ Martin S. Craighead 
 
 
Name:
 
Martin S. Craighead
 
 
Title:
 
Chairman and Chief Executive Officer
 
 
Date:
 
October 23, 2013
 
 
 
 
 
 
 
 
 
/s/ Peter A. Ragauss
 
 
 
Name:
 
Peter A. Ragauss
 
 
Title:
 
Senior Vice President and Chief Financial Officer
 
 
Date:
 
October 23, 2013


Q3 FY2013 Mine Safety Disclosure Exhibit 95

Exhibit 95

Mine Safety Disclosure
The following disclosures are provided pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K, which require certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977.
The table that follows reflects citations, orders, violations and proposed assessments issued by the Mine Safety and Health Administration (the “MSHA”) for each mine of which Baker Hughes and/or its subsidiaries is an operator. The disclosure is with respect to the three months ended September 30, 2013. Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by the MSHA at www.MSHA.gov.

Three Months Ended September 30, 2013

Mine or Operating Name/MSHA
Identification Number
Section
104 S&S
Citations
Section
104(b)
Orders
Section
104(d)
Citations
and
Orders
Section
110(b)(2)
Violations
Section
107(a)
Orders
Proposed
MSHA
Assessments
(1)
Mining
Related
Fatalities
Received
Notice of
Pattern of
Violations
Under
Section
104(e)
(yes/no)
Received
Notice of
Potential to Have
Pattern
Under
Section
104(e)
(yes/no)
Legal
Actions
Pending
as of Last
Day of
Period
Legal
Actions
Initiated
During
Period
Legal
Actions
Resolved
During
Period
Mo