2012.9.30 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, 2012
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, 2012, the registrant has outstanding 439,646,900 shares of Common Stock, $1 par value per share.



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,
 
2012

 
2011

 
2012

 
2011

Revenue:
 
 
 
 
 
 
 
Sales
$
1,832

 
$
1,663

 
$
5,345

 
$
4,635

Services
3,396

 
3,401

 
10,363

 
9,501

Total revenue
5,228

 
5,064

 
15,708

 
14,136

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales
1,474

 
1,342

 
4,227

 
3,766

Cost of services
2,831

 
2,501

 
8,433

 
7,134

Research and engineering
117

 
115

 
366

 
331

Marketing, general and administrative
344

 
301

 
975

 
862

Total costs and expenses
4,766

 
4,259

 
14,001

 
12,093

Operating income
462

 
805

 
1,707

 
2,043

Interest expense, net
(49
)
 
(58
)
 
(153
)
 
(164
)
Loss on early extinguishment of debt

 
(40
)
 

 
(40
)
Income from continuing operations before income taxes
413

 
707

 
1,554

 
1,839

Income taxes
(143
)
 
(9
)
 
(479
)
 
(434
)
Income from continuing operations
270

 
698

 
1,075

 
1,405

Income from discontinued operations, net of tax
14

 
8

 
27

 
20

Net income
284

 
706

 
1,102

 
1,425

Net (income) loss attributable to noncontrolling interests
(5
)
 

 
(5
)
 

Net income attributable to Baker Hughes
$
279

 
$
706

 
$
1,097

 
$
1,425

 
 
 
 
 
 
 
 
Amounts attributable to Baker Hughes:
 
 
 
 
 
 
 
Income from continuing operations
$
265

 
$
698

 
$
1,070

 
$
1,405

Income from discontinued operations
14

 
8

 
27

 
20

Net Income attributable to Baker Hughes
$
279

 
$
706

 
$
1,097

 
$
1,425

 
 
 
 
 
 
 
 
Basic earnings per share:
 
 
 
 
 
 
 
Income from continuing operations
$
0.60

 
$
1.60

 
$
2.43

 
$
3.22

Income from discontinued operations
0.03

 
0.02

 
0.06

 
0.05

Basic earnings per share attributable to Baker Hughes
$
0.63

 
$
1.62

 
$
2.49

 
$
3.27

 
 
 
 
 
 
 
 
Diluted earnings per share:
 
 
 
 
 
 
 
Income from continuing operations
$
0.60

 
$
1.59

 
$
2.43

 
$
3.21

Income from discontinued operations
0.03

 
0.02

 
0.06

 
0.04

Diluted earnings per share attributable to Baker Hughes
$
0.63

 
$
1.61

 
$
2.49

 
$
3.25

 
 
 
 
 
 
 
 
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,
 
2012
 
2011
 
2012
 
2011
Net Income
$
284

 
$
706

 
$
1,102

 
$
1,425

Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Foreign currency translation adjustments during the
     period
63

 
(116
)
 
61

 
(33
)
Pension and other postretirement benefits

 
5

 
19

 
5

 Net gain on hedge transactions

 

 
1

 

Other comprehensive income (loss), net of tax
63

 
(111
)
 
81

 
(28
)
Comprehensive income
347

 
595

 
1,183

 
1,397

Comprehensive (income) loss attributable to noncontrolling
      interests
(5
)
 
1

 
(5
)
 
1

Comprehensive income (loss) attributable to Baker Hughes
$
342

 
$
596

 
$
1,178

 
$
1,398

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,
2012
 
December 31,
2011
ASSETS
Current Assets:
 
 
 
Cash and cash equivalents
$
1,007

 
$
1,050

Accounts receivable - less allowance for doubtful accounts
   (2012 - $255; 2011 - $226)
5,003

 
4,794

Inventories, net
3,879

 
3,211

Deferred income taxes
252

 
251

Other current assets
432

 
393

Assets of discontinued operations
707

 
646

Total current assets
11,280

 
10,345

 
 
 
 
Property, plant and equipment - less accumulated depreciation (2012 - $5,961; 2011 - $5,192)
8,225

 
7,245

Goodwill
5,612

 
5,637

Intangible assets, net
989

 
1,086

Other assets
650

 
534

Total assets
$
26,756

 
$
24,847

 
 
 
 
LIABILITIES AND EQUITY
Current Liabilities:
 
 
 
Accounts payable
$
1,829

 
$
1,774

Short-term debt and current portion of long-term debt
1,306

 
224

Accrued employee compensation
661

 
695

Income taxes payable
205

 
288

Other accrued liabilities
476

 
464

Liabilities of discontinued operations
55

 
56

Total current liabilities
4,532

 
3,501

 
 
 
 
Long-term debt
3,839

 
3,845

Deferred income taxes and other tax liabilities
602

 
810

Liabilities for pensions and other postretirement benefits
579

 
578

Other liabilities
133

 
149

Commitments and contingencies


 


 
 
 
 
Equity:
 
 
 
Common stock
439

 
437

Capital in excess of par value
7,447

 
7,303

Retained earnings
9,461

 
8,561

Accumulated other comprehensive loss
(474
)
 
(555
)
Baker Hughes stockholders’ equity
16,873

 
15,746

Noncontrolling interests
198

 
218

Total equity
17,071

 
15,964

Total liabilities and equity
$
26,756

 
$
24,847

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, 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 cost
 
 
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


 
Common Stock
 
Capital
in Excess
of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Noncontrolling
Interests
 
Total
Balance at December 31, 2010
$
432

 
$
7,005

 
$
7,083

 
$
(420
)
 
$
186

 
$
14,286

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
1,425

 
 
 
 
 
1,425

Other comprehensive income
 
 
 
 
 
 
(27
)
 
(1
)
 
(28
)
Activity related to stock plans
4

 
143

 
 
 
 
 
 
 
147

Stock-based compensation cost
 
 
85

 
 
 
 
 
 
 
85

Cash dividends ($0.45 per share)
 
 
 
 
(195
)
 
 
 
 
 
(195
)
Net activity related to noncontrolling
      interests
 
 
11

 
 
 
 
 
32

 
43

Balance at September 30, 2011
$
436

 
$
7,244

 
$
8,313

 
$
(447
)
 
$
217

 
$
15,763

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,
 
2012
 
2011
Cash flows from operating activities:
 
 
 
Income from continuing operations
$
1,075

 
$
1,405

Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
 
 
 
Depreciation and amortization
1,122

 
951

Benefit for deferred income taxes
(236
)
 
(312
)
Gain on disposal of assets
(169
)
 
(124
)
Stock-based compensation cost
94

 
85

Loss on early extinguishment of debt

 
40

Provision for doubtful accounts
37

 
76

Loss on impairment of assets
55

 

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(199
)
 
(1,074
)
Inventories
(660
)
 
(465
)
Accounts payable
47

 
179

Accrued employee compensation and other accrued liabilities
(20
)
 
81

Income taxes payable
(62
)
 
(189
)
Other operating items, net
(147
)
 
3

Net cash flows from continuing operations
937

 
656

Net cash flows from discontinued operations
10

 
26

Net cash flows from operating activities
947

 
682

Cash flows from investing activities:
 
 
 
Expenditures for capital assets
(2,160
)
 
(1,624
)
Proceeds from maturities of short-term investments

 
250

Proceeds from disposal of assets
285

 
215

Other investing items, net

 
9

Net cash flows from continuing operations
(1,875
)
 
(1,150
)
Net cash flows from discontinued operations
(21
)
 
(27
)
Net cash flows from investing activities
(1,896
)
 
(1,177
)
Cash flows from financing activities:
 
 
 
Net proceeds (payments) of commercial paper and other short-term debt
1,075

 
(41
)
Net proceeds of long-term debt

 
742

Repayment of long-term debt

 
(813
)
Proceeds from termination of interest rate swap agreements

 
26

Proceeds from issuance of common stock
42

 
144

Dividends paid
(197
)
 
(195
)
Purchase of noncontrolling interest
(4
)
 
(26
)
Other financing items, net
(14
)
 
(1
)
Net cash flows from financing activities
902

 
(164
)
Effect of foreign exchange rate changes on cash
4

 
6

Decrease in cash and cash equivalents
(43
)
 
(653
)
Cash and cash equivalents, beginning of period
1,050

 
1,456

Cash and cash equivalents, end of period
$
1,007

 
$
803


6

Table of Contents                                        
                                    

Supplemental cash flows disclosures:
 
 
 
Income taxes paid, net of refunds
$
811

 
$
934

Interest paid
$
191

 
$
184

Supplemental disclosure of noncash investing activities:
 
 
 
Capital expenditures included in accounts payable
$
115

 
$
78

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

7

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, specialty polymers 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 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, 2011 (“2011 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. In addition, all prior periods reflect the reclassification of certain operations as discontinued. For further discussion see Note 2. Discontinued Operations. 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 June 2011, the Financial Accounting Standards Board (“FASB”) issued an update to Accounting Standards Codification (“ASC”) 220, Comprehensive Income. This Accounting Standards Update (“ASU”) requires entities to present components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements that would include reclassification adjustments by component for items that are reclassified from other comprehensive income to net income on the face of the financial statements. In December 2011, the FASB issued an update to this ASU indefinitely deferring the implementation of the reclassification adjustments by component requirement of the ASU issued in June 2011. We adopted the new presentation requirement in the first quarter of 2012. We elected the two-statement approach presenting other comprehensive income in a separate statement immediately following the unaudited consolidated condensed statement of income.
In September 2011, the FASB issued an update to ASC 350, Intangibles - Goodwill and Other. This ASU amends the guidance in ASC 350-20 on testing for goodwill impairment. The revised guidance allows entities testing for goodwill impairment to have the option of performing a qualitative assessment before calculating the fair value of the reporting unit. The ASU does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test annually for impairment. The ASU is limited to goodwill and does not amend the annual requirement for testing other indefinite-lived intangible assets for impairment. The ASU is effective for goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted this ASU effective January 1, 2012, with no impact to our unaudited consolidated condensed financial statements.
In July 2012, the FASB issued an update to ASC 350, Intangibles - Goodwill and Other.  This ASU amends the guidance in ASC 350-30 on testing indefinite-lived intangible assets for impairment.  The revised guidance permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test.  The ASU is effective for impairment tests performed for fiscal years beginning after September 15, 2012.  We will adopt this ASU for our 2013 impairment testing.  We do not expect this ASU to have a material impact, if any, on our unaudited consolidated condensed financial statements.

8

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


NOTE 2. DISCONTINUED OPERATIONS
Our Board of Directors approved and we have initiated a plan to sell the Process and Pipeline Services (“PPS”) business unit, which was previously reported as part of the Industrial Services segment. PPS is a global provider of pre-commissioning, maintenance and inspection services for upstream, midstream and downstream oil and gas facilities and pipelines. Accordingly, we have reclassified the financial results and related notes thereto for all prior periods presented herein to reflect these operations as discontinued.
Summarized financial information from discontinued operations is as follows:

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2012
2011
 
2012
2011
Revenue
 
$
128

$
114

 
$
328

$
308

 
 
 
 
 
 
 
Income before income taxes
 
$
24

$
13

 
$
45

$
31

Income taxes
 
(10
)
(5
)
 
(18
)
(11
)
Income from discontinued operations
 
$
14

$
8

 
$
27

$
20

Assets and liabilities of discontinued operations are as follows:

 
September 30, 2012
 
December 31, 2011
Assets
 
 
 
Total current assets
$
142

 
$
98

Property, plant and equipment, net
166

 
170

Goodwill
346

 
319

Other assets
53

 
59

Assets of discontinued operations
$
707

 
$
646

 
 
 
 
Liabilities
 
 
 
Accounts payable
$
44

 
$
36

Other liabilities
11

 
20

Liabilities of discontinued operations
$
55

 
$
56



9

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,
 
2012
 
2011
 
2012
 
2011
Weighted average common shares outstanding for basic EPS
440

 
437

 
440

 
436

Effect of dilutive securities - stock plans
1

 
2

 
1

 
2

Adjusted weighted average common shares outstanding for
     diluted EPS
441

 
439

 
441

 
438

Future potentially dilutive shares excluded from diluted EPS:
 
 
 
 
 
 
 
Options with an exercise price greater than the average market
     price for the period
8

 
3

 
8

 
3

NOTE 4. INVENTORIES
Inventories, net of reserves, are comprised of the following:

 
September 30,
2012
 
December 31,
2011
Finished goods
$
3,435

 
$
2,820

Work in process
241

 
231

Raw materials
203

 
160

Total
$
3,879

 
$
3,211

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

 
September 30, 2012
 
December 31, 2011
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
Definite lived intangibles:
 
 
 
 
 
 
 
 
 
 
 
Technology
$
714

 
$
238

 
$
476

 
$
686

 
$
206

 
$
480

Contract-based
17

 
10

 
7

 
17

 
9

 
8

Trade names
116

 
47

 
69

 
116

 
14

 
102

Customer relationships
483

 
102

 
381

 
483

 
73

 
410

Subtotal
1,330

 
397

 
933

 
1,302

 
302

 
1,000

Indefinite lived intangibles:
 
 
 
 
 
 
 
 
 
 
 
In-process research and
     development
56

 

 
56

 
86

 

 
86

Total
$
1,386

 
$
397

 
$
989

 
$
1,388

 
$
302

 
$
1,086

Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 2 to 20 years. Amortization expense included in net income for the three months and nine months ended September 30, 2012 was $34 million

10

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


and $97 million, respectively, and is estimated to be $33 million for the remainder of fiscal year 2012. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2013 - $108 million; 2014 - $94 million; 2015 - $88 million; 2016 - $83 million; and 2017 - $81 million.
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, 2012 and December 31, 2011 approximates their carrying value as reflected in our unaudited consolidated condensed balance sheets.
The estimated fair value of total debt at September 30, 2012 and December 31, 2011 was $6,147 million and $4,910 million, respectively, which differs from the carrying amounts of $5,145 million and $4,069 million, respectively, included in our unaudited consolidated condensed balance sheets. The fair value was determined using Level 2 inputs including quoted period end market prices.
NOTE 7. SEGMENT INFORMATION
We conduct our business primarily through operating segments that are aligned with our geographic regions, which have been aggregated into five reportable segments. 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 from continuing operations before income taxes and before the following: net interest expense, corporate expenses, and certain gains and losses not allocated to the operating segments.
In the first quarter of 2012, we changed our reporting structure to include the reservoir development services business (“RDS”) within our four oilfield geographic segments. All prior period segment disclosures for revenue and profit before tax have been reclassified to include RDS within our four oilfield geographic segments. The impact of these changes to the Industrial Services segment was to reduce revenue by $23 million and $75 million, respectively, for the three months and nine months ended September 30, 2011; and increase profit before tax by $16 million and $35 million for the three months and nine months ended September 30, 2011.
Summarized financial information is shown in the following table.

 
Three Months Ended
 
Three Months Ended
 
September 30, 2012
 
September 30, 2011
Segments
Revenue
 
Profit (Loss) Before Taxes
 
Revenue
 
Profit (Loss) Before Taxes
North America
$
2,742

 
$
288

 
$
2,721

 
$
602

Latin America
583

 
45

 
570

 
71

Europe/Africa/Russia Caspian
866

 
104

 
863

 
103

Middle East/Asia Pacific
844

 
71

 
711

 
75

Industrial Services
193

 
13

 
199

 
32

Total Operations
5,228

 
521

 
5,064

 
883

Corporate and Other

 
(59
)
 

 
(78
)
Interest Expense, net

 
(49
)
 

 
(58
)
Loss on early extinguishment of debt

 

 

 
(40
)
Total
$
5,228

 
$
413

 
$
5,064

 
$
707



11

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


 
Nine Months Ended
 
Nine Months Ended
 
September 30, 2012
 
September 30, 2011
Segments
Revenue
 
Profit (Loss) Before Taxes
 
Revenue
 
Profit (Loss) Before Taxes
North America
$
8,277

 
$
1,046

 
$
7,451

 
$
1,491

Latin America
1,760

 
189

 
1,588

 
204

Europe/Africa/Russia Caspian
2,684

 
413

 
2,462

 
235

Middle East/Asia Pacific
2,393

 
233

 
2,088

 
241

Industrial Services
594

 
58

 
547

 
80

Total Operations
15,708

 
1,939

 
14,136

 
2,251

Corporate and Other

 
(232
)
 

 
(208
)
Interest Expense, net

 
(153
)
 

 
(164
)
Loss on early extinguishment of debt

 

 

 
(40
)
Total
$
15,708

 
$
1,554

 
$
14,136

 
$
1,839

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 substantially all U.S. employees who retire and have met certain age and service requirements.
The components of net periodic cost are as follows for the three months ended September 30:

 
U.S. Pension Plans
 
Non-U.S. Pension Plans
 
Other Postretirement Benefits
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Service cost
$
16

 
$
10

 
$
2

 
$
2

 
$
3

 
$
2

Interest cost
5

 
5

 
8

 
8

 
2

 
2

Expected return on plan assets
(9
)
 
(8
)
 
(9
)
 
(8
)
 

 

Amortization of net loss
4

 
3

 
2

 
1

 

 

Net periodic cost
$
16

 
$
10

 
$
3

 
$
3

 
$
5

 
$
4

The components of net periodic cost are as follows for the nine months ended September 30:

 
U.S. Pension Plans
 
Non-U.S. Pension Plans
 
Other Postretirement Benefits
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Service cost
$
48

 
$
28

 
$
6

 
$
6

 
$
9

 
$
6

Interest cost
15

 
15

 
24

 
24

 
6

 
6

Expected return on plan assets
(27
)
 
(24
)
 
(27
)
 
(24
)
 

 

Amortization of prior service
    benefit

 

 

 

 
(2
)
 
(2
)
Amortization of net loss
12

 
7

 
5

 
3

 
1

 

Benefit settlement

 

 
6

 

 

 

Net periodic cost
$
48

 
$
26

 
$
14

 
$
9

 
$
14

 
$
10



12

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


We invest the assets of our pension plans in investments according to the policies developed by our investment committees. The majority of these assets are in investments whose fair values are determined using Level 2 observable inputs. The changes in the fair value of pension plan assets determined using Level 3 unobservable inputs are as follows:

 
Three Months Ended September 30, 2012
 
U.S.
Private
Equity
Fund
 
U.S.
Property
Fund
 
U.S.
Hedge
Funds
 
Non-U.S.
Property
Fund
 
Non-U.S.
Insurance
Contracts
 
Total
Ending balance at June 30, 2012
$
17

 
$
6

 
$
163

 
$
19

 
$
15

 
$
220

Unrealized gains

 

 
5

 
1

 

 
6

Unrealized losses
(2
)
 

 

 

 

 
(2
)
Purchases
1

 
1

 

 

 

 
2

Ending balance at September 30, 2012
$
16

 
$
7

 
$
168

 
$
20

 
$
15

 
$
226


 
Nine Months Ended September 30, 2012
 
U.S.
Private
Equity
Fund
 
U.S.
Property
Fund
 
U.S.
Hedge
Funds
 
Non-U.S.
Property
Fund
 
Non-U.S.
Insurance
Contracts
 
Total
Ending balance at December 31, 2011
$

 
$
5

 
$
110

 
$
19

 
$
15

 
$
149

Unrealized gains

 

 
6

 
1

 

 
7

Unrealized losses
(2
)
 

 

 

 

 
(2
)
Purchases
18

 
2

 
52

 

 

 
72

Ending balance at September 30, 2012
$
16

 
$
7

 
$
168

 
$
20

 
$
15

 
$
226

NOTE 9. INCOME TAXES
Our effective tax rate on income from continuing operations before income taxes for the three months and nine months ended September 30, 2012 was 34.6% and 30.8%, respectively. The tax rate for the three months ended September 30, 2012 is lower than the U.S. statutory income tax rate of 35% primarily due to lower rates of tax in certain foreign jurisdictions, partially offset by an increase in tax reserves and state income taxes.
The tax rate for the nine months ended September 30, 2012 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 net reversal of tax reserves arising from audit settlements and the expiration of statutes of limitations, partially offset by state income taxes.
NOTE 10. COMMITMENTS AND CONTINGENCIES
LITIGATION
We are involved in litigation or proceedings that have arisen in our ordinary business activities. 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. Many 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. The accruals for losses are calculated by estimating losses for claims using historical claim data, specific loss development factors and other information as necessary.


13

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


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, 2012. 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 unaudited consolidated condensed financial statements.
NOTE 11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Total accumulated other comprehensive loss attributable to Baker Hughes, net of tax, consisted of the following:

 
September 30, 2012
 
December 31, 2011
Foreign currency translation adjustments
$
(243
)
 
$
(304
)
Pension and other postretirement benefits
(232
)
 
(251
)
Net gain on hedge transactions
1

 

Total accumulated other comprehensive loss attributable to Baker Hughes
$
(474
)
 
$
(555
)


14

Table of Contents                                        
                                    

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, 2011 (“2011 Annual Report”). Phrases such as “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. The products and services we provide from our ongoing operations are:

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 specialty polymers.
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. 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 2012, we generated revenue of $5.23 billion, an increase of $164 million or 3% compared to the same quarter a year ago. North America oilfield revenue for the third quarter of 2012 was $2.74 billion, an increase of 1% compared to the same quarter a year ago. Our results continued to be impacted by the pressure pumping business, which remains unbalanced primarily due to excess capacity in the market combined with lower Canadian activity. Oilfield revenue outside of North America for the third quarter of 2012 was $2.29 billion, an increase of 7% compared to the same quarter a year ago driven by strong growth in the Middle East and Asia Pacific regions.
Income from continuing operations attributable to Baker Hughes was $265 million for the third quarter of 2012 compared to $698 million for the same quarter a year ago. Profitability in North America was adversely impacted by the continued volatility related to our pressure pumping product line including both pricing pressure, as a result of the increasing supply of pressure pumping capacity in the market, and increased personnel and raw material costs. Our other product lines in U.S. Land, particularly drilling services, upstream chemicals, artificial lift and completions, experienced increased demand in the third quarter of 2012 compared to the same quarter a year ago. International profitability decreased in the third quarter of 2012 compared to the same quarter a year ago. Although activity has increased in many of our international regions, particularly Africa, Europe and the Middle East, increases in personnel and other operating costs have reduced profitability. Additionally, the third quarter of 2012 includes charges of $63 million before-tax ($43 million after-tax) primarily related to the impairment of information technology assets and the closing of a chemical manufacturing facility. The third quarter of 2011 was favorably impacted by a $214 million tax benefit associated with the reorganization of certain foreign subsidiaries.
The Company recently made the decision to sell its Process and Pipeline Services (“PPS”) business, which is a provider of precommissioning, maintenance and inspection services for oil and gas facilities and pipelines. As a result, the financial results of PPS have been reclassified to discontinued operations. PPS was previously a component of the Industrial Services segment, which now consists primarily of the Company's downstream refining and specialty polymers businesses.
As of September 30, 2012, we had approximately 58,800 employees compared to approximately 57,700 employees as of December 31, 2011, which included employees from our PPS business of approximately 1,200 and 1,100, respectively.
BUSINESS ENVIRONMENT
In North America, rig counts declined 6% in the third quarter of 2012 compared to the same period a year ago. Increased production in the unconventional natural gas shale plays continued to contribute to high natural gas working inventories and

15

Table of Contents                                        
                                    

ultimately lower commodity prices. Customer spending in the natural gas shale plays remained limited, and as a result, natural gas-directed rig activity declined 45% in the third quarter of 2012 compared to the same period a year ago. This was partly offset by a 23% increase in oil-directed rig activity for the same time periods. Customer spending for oil in the U.S. remained strong during the third quarter of 2012 as evidenced by the fact that oil-directed rig activity increased 36% compared to the same period in 2011. However, this was offset by reduced activity in Canada where periods of wet weather and sluggish customer spending resulted in a 26% reduction in rig counts for the same time periods.
Outside of North America, customer spending is most heavily influenced by Brent oil prices. On average, Brent oil prices decreased 2% in the third quarter of 2012 compared to the same period a year ago as Europe's economic concerns increased, growth in China showed signs of contraction and global oil supplies increased. However, compared to the third quarter of 2011, our customers’ activity and spending levels increased in the third quarter of 2012. Due to the long-term planning cycles associated with many international projects, customers do not tend to react to short-term movements in oil prices.
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,
 
2012
 
2011
 
2012
 
2011
Brent oil prices ($/Bbl) (1)
$
109.90

 
$
112.38

 
$
112.46

 
$
111.44

WTI oil prices ($/Bbl) (2)
92.16

 
89.54

 
96.15

 
95.47

Natural gas prices ($/mmBtu) (3)
2.88

 
4.05

 
2.54

 
4.21


(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 $109.90/Bbl in the third quarter of 2012. Oil prices generally increased throughout the third quarter of 2012 primarily due to increasing geopolitical concerns in the Middle East and supply interruptions in the Gulf of Mexico due to Hurricane Isaac. However, renewed concerns about the global economy had an offsetting effect on prices and resulted in volatility in oil prices during the quarter. Prices ranged from a low of $96.59/Bbl at the beginning of July 2012 to a high of $117.59/Bbl in mid-September 2012. In its October 2012 Oil Market Report, the International Energy Agency (“IEA”) revised its 2012 estimated global oil demand downward to 89.7 million barrels per day from its original estimate of 89.9 million barrels. Despite the downward adjustment, the estimated 2012 global demand still exceeds 2011 global demand of 89.1 million barrels per day.
WTI oil prices averaged $92.16/Bbl in the third quarter of 2012. Similar to the Brent oil prices, WTI oil prices generally increased throughout the third quarter of 2012. Prices ranged from a low of $83.75/Bbl in early July 2012 to a high of $99.00/Bbl in mid-September 2012.
Natural gas prices averaged $2.88/mmBtu in the third quarter of 2012. Natural gas prices, which have been low since late 2011, continued to rebound during the early part of the quarter as warm weather in key consuming regions of the U.S. increased demand. However, natural gas storage injections outpaced analyst expectations throughout much of the quarter, resulting in lower prices in August and much of September. Overall for the quarter, prices ranged from a high of $3.20/mmBtu at the end of July 2012 to a low of $2.63/mmBtu at the end of August 2012. Prices closed at $3.08/mmBtu at the end of September, as natural gas rig counts declined to 13 year lows in the U.S. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of the third quarter of 2012 was 3,653/Bcf, which was 7% or 244/Bcf above the corresponding week in 2011.
Rig Counts
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

16

Table of Contents                                        
                                    

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, Iran and onshore China because this information is not readily available. Baker Hughes resumed publication in June 2012 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 our drill bits. In international areas, rigs are counted on a weekly basis and deemed active if drilling activities occurred during the majority of the week. The weekly results are then averaged for the month and published accordingly. The rig count does not include rigs that are in transit from one location to another, rigging up, being used in non-drilling activities, including production testing, completion and workover, and are not expected to be significant consumers of drill bits.
The rig counts are summarized in the table below as averages for each of the periods indicated.

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2012
2011
% Change
2012
2011
% Change
U.S. - land and inland waters
1,855

1,911

(3
)%
1,909

1,805

6
 %
U.S. - offshore
51

34

50
 %
47

30

57
 %
Canada
325

441

(26
)%
362

401

(10
)%
North America
2,231

2,386

(6
)%
2,318

2,236

4
 %
Latin America
414

437

(5
)%
428

421

2
 %
North Sea
38

38

 %
38

40

(5
)%
Continental Europe
79

85

(7
)%
78

77

1
 %
Africa
108

71

52
 %
93

76

22
 %
Middle East
390

289

35
 %
348

288

21
 %
Asia Pacific
230

249

(8
)%
240

258

(7
)%
Outside North America
1,259

1,169

8
 %
1,225

1,160

6
 %
Worldwide
3,490

3,555

(2
)%
3,543

3,396

4
 %
Third Quarter of 2012 Compared to the Third Quarter of 2011
The rig count in North America decreased 6% in the third quarter of 2012 compared to the same period a year ago as natural gas-directed rig counts declined 45%, partially offset by an increase in oil-directed rig counts of 23%. The natural gas-directed rig count reflected a 46% decrease in the U.S. and a 39% decrease in Canada. The oil-directed rig count increased 36% in the U.S., but was offset by a 21% decrease in Canada. Natural gas-directed drilling was negatively impacted by the continued weakness in North America natural gas prices which discouraged new investment in natural gas fields. The growth in oil-directed drilling in the U.S. was primarily a result of strong oil prices and the industry’s ability to apply drilling and completion techniques to unconventional oil reservoirs that were originally applied to similar natural gas reservoirs. In Canada, many operators curtailed their drilling plans during the third quarter of 2012 due to recent oil price volatility, reduced cash flows and wet weather.
Outside North America, the rig count increased 8%. Starting June 2012, the Middle East rig count included Iraq. Excluding Iraq, which had 76 rigs during the third quarter of 2012, the international rig count increased 1%. The rig count in Latin America decreased primarily due to lower rig activity in Brazil, Colombia and Venezuela, partially offset by increased rig activity in Ecuador, Mexico and Argentina. The rig count in the North Sea remained flat. In Continental Europe, the rig count decreased primarily due to lower activity in Norway, Poland and Romania. The rig count increased in Africa primarily due to resumption of drilling activities in Libya, as well as higher activity in Algeria and Nigeria. The rig count increased in the Middle East due to higher activity in Saudi Arabia, Oman and Egypt, as well as the inclusion of Iraq. In Asia Pacific, the rig count decreased as a result of decreased activity in Indonesia and offshore China, offset by modest increased activity in Malaysia and Australia.


17

Table of Contents                                        
                                    

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 for revenue and cost of revenue are on a total basis as 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.
We conduct our business primarily through operating segments that are aligned with our geographic regions, which have been aggregated into five reportable segments. Prior to 2012, our reservoir development services business (“RDS”), consisting of consulting services provided to third parties and internal support to our oilfield operations, was included within the Industrial Services segment. In the first quarter of 2012, we changed our reporting structure to include RDS within our four oilfield geographic segments. All prior period segment disclosures for revenue and profit before tax have been reclassified to include RDS within our four oilfield geographic segments. The impact of this change to the Industrial Services segment was to reduce revenue by $23 million and $75 million for the three months and nine months ended September 30, 2011, respectively; and increase profit before tax by $16 million and $35 million for the three months and nine months ended September 30, 2011, respectively.
We recently initiated a plan to sell our PPS business, which was previously reported as part of the Industrial Services segment. Accordingly, we have reclassified the financial results for all prior periods to discontinued operations. Revenue was $114 million and $308 million for the three months and nine months ended September 30, 2011, respectively; and profit before tax was $13 million and $31 million for the three months and nine months ended September 30, 2011, respectively.
Revenue and Profit Before Tax
The performance of our operating segments is evaluated based on profit before tax, which is defined as income from continuing operations 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
 
2012
 
2011
 
 
2012
 
2011
 
Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North America
$
2,742

 
$
2,721

 
$
21

 
1
%
 
$
8,277

 
$
7,451

 
$
826

 
11
%
Latin America
583

 
570

 
13

 
2
%
 
1,760

 
1,588

 
172

 
11
%
Europe/Africa/
     Russia Caspian
866

 
863

 
3

 
%
 
2,684

 
2,462

 
222

 
9
%
Middle East/
     Asia Pacific
844

 
711

 
133

 
19
%
 
2,393

 
2,088

 
305

 
15
%
Industrial Services
193

 
199

 
(6
)
 
(3
%)
 
594

 
547

 
47

 
9
%
Total
$
5,228

 
$
5,064

 
$
164

 
3
%
 
$
15,708

 
$
14,136

 
$
1,572

 
11
%


18

Table of Contents                                        
                                    

 
Three Months Ended September 30,
 
$ Change
 
% Change
 
Nine Months Ended September 30,
 
$ Change
 
% Change
 
2012
 
2011
 
 
2012
 
2011
 
Profit Before Tax:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North America
$
288

 
$
602

 
$
(314
)
 
(52
%)
 
$
1,046

 
$
1,491

 
$
(445
)
 
(30
)%
Latin America
45

 
71

 
(26
)
 
(37
%)
 
189

 
204

 
(15
)
 
(7
)%
Europe/Africa/
     Russia Caspian
104

 
103

 
1

 
1
%
 
413

 
235

 
178

 
76
 %
Middle East/
     Asia Pacific
71

 
75

 
(4
)
 
(5
%)
 
233

 
241

 
(8
)
 
(3
)%
Industrial Services
13

 
32

 
(19
)
 
(59
%)
 
58

 
80

 
(22
)
 
(28
)%
Total Operations
521

 
883

 
(362
)
 
(41
%)
 
1,939

 
2,251

 
(312
)
 
(14
)%
Corporate and Other
(59
)
 
(78
)
 
19

 
(24
%)
 
(232
)
 
(208
)
 
(24
)
 
12
 %
Interest Expense, net
(49
)
 
(58
)
 
9

 
(16
%)
 
(153
)
 
(164
)
 
11

 
(7
)%
Loss on early extinguishment of debt

 
(40
)
 
40

 
(100
%)
 

 
(40
)
 
40

 
(100
)%
Total
$
413

 
$
707

 
$
(294
)
 
(42
%)
 
$
1,554

 
$
1,839

 
$
(285
)
 
(15
)%
Third Quarter of 2012 Compared to the Third Quarter of 2011
Revenue for the third quarter of 2012 increased $164 million or 3% compared to the third quarter of 2011, driven by increased activity across all segments, particularly in the Middle East/Asia Pacific (“MEAP”), North America and Latin America segments.
Profit before tax for the third quarter of 2012 decreased $294 million or 42% compared to the third quarter of 2011. Despite the increase in revenue, our profit before tax was significantly impacted by pricing pressure, higher personnel costs, and increased raw material expenses in our pressure pumping product line in North America. Increased allowance for doubtful accounts in Latin America and Europe, high operating costs and third party expenses related to new integrated operations contracts in the Middle East further eroded profits. In the third quarter of 2012, we incurred a charge of $43 million before-tax related to the impairment of certain information technology assets primarily associated with internally developed software and other assets. Additionally, in the third quarter of 2012, we incurred a charge of $20 million before-tax related to the closure of a chemical manufacturing facility that is part of the cost saving initiative in our global supply chain organization. As our information technology and supply chain organizations support our global operations, these charges have been allocated to all segments.
North America
North America revenue increased 1% in the third quarter of 2012 compared to the third quarter of 2011, despite rig counts declining 6%. The primary catalysts for the growth seen in North America include sustained high oil prices during the third quarter of 2012 compared to historical prices; new innovative technologies for drilling systems and completion systems that have resulted in increased market share, particularly in the unconventional reservoirs in U.S. Land; a continuing shift of drilling activities from the natural gas-directed unconventional reservoirs to the oil-directed reservoirs in U.S. Land; and improved rig activity in the offshore Gulf of Mexico. In the third quarter of 2012, there were significant increases in completions systems, drilling services, artificial lift, upstream chemicals and drill bits activities. In the Gulf of Mexico, revenue increased 30% in the third quarter of 2012 compared to the third quarter of 2011 as rig counts increased 50%, driven by increased deepwater activity, which more than offset the impact of Hurricane Isaac. These increases in revenue were offset by reduced demand and pricing in our pressure pumping product line in the U.S. and Canada. Additionally, as a result of reduced customer spending in Canada, oil-directed rig counts decreased 21% and natural gas-directed rig counts were down 39% compared to the third quarter of 2011. Overall, this resulted in a 14% reduction in our Canadian revenue during the third quarter of 2012 compared to the third quarter of 2011.
North America profit before tax was $288 million in the third quarter of 2012, a decrease of $314 million compared to the third quarter of 2011. Despite slightly higher revenue, profits in U.S. Land and Canada declined due to decreased fleet utilization and lower pricing, higher personnel costs, increased costs for critical raw materials and higher depreciation expenses primarily in our pressure pumping product line. Partially offsetting these reductions were improved profits in the Gulf of Mexico, where both revenue and profit margins have returned to pre-moratorium levels as activity levels have increased substantially. North America profit before tax was negatively impacted by a $33 million charge associated with the information technology expenses and the facility closure.

19

Table of Contents                                        
                                    

Latin America
Latin America revenue increased 2% in the third quarter of 2012 compared to the third quarter of 2011. The primary drivers of the increase were higher activity benefiting our drill bit, wireline services and artificial lift product lines in Venezuela. This was partially offset by reduced activity in Mexico field lab projects.
Latin America profit before tax decreased 37% in the third quarter of 2012 compared to the third quarter of 2011. While revenue modestly increased, profits were negatively impacted by an increase of $22 million in our allowance for doubtful accounts with a major customer and higher personnel costs. Latin America profit before tax was also negatively impacted by a $7 million charge associated with the information technology expenses and the facility closure.
Europe/Africa/Russia Caspian
Europe/Africa/Russia Caspian (“EARC”) revenue remained relatively flat in the third quarter of 2012 compared to the third quarter of 2011. Strong growth was seen in Africa, particularly with drilling systems in Mozambique and Nigeria, completion systems in Nigeria, Angola and Ghana and wireline services in Nigeria, Uganda and Angola. Revenue increases in Africa were offset by declines in our Europe region due primarily to reduced drilling fluids activity in Norway and unfavorable currency fluctuations.
EARC profit before tax also remained relatively flat in the third quarter of 2012 compared to the third quarter of 2011. A favorable change in sales mix in Sub Sahara Africa and Russia contributed to improved margins and increased profitability but were offset by a $7 million increase in our allowance for doubtful accounts due to a customer bankruptcy and an $11 million charge associated with the information technology expenses and the facility closure.
Middle East/Asia Pacific
MEAP revenue increased 19% in the third quarter of 2012 compared to the third quarter of 2011. The increase in this segment was attributable to new integrated operations contracts in Iraq; higher demand for drilling services, drilling fluids, and completions systems in Saudi Arabia; and improved demand for completions systems in Australia and Indonesia. This increase was partially offset by reduced activity for pressure pumping, drilling fluids and drill bits in India.
MEAP profit before tax remained relatively flat in the third quarter of 2012 compared to the third quarter of 2011. While revenue increased, profit before tax was impacted by high operating and third party costs associated with the new integrated operations activities in Iraq and increased personnel costs. MEAP profit before tax was also negatively impacted by a $10 million charge associated with the information technology expenses and the facility closure.
Industrial Services
For Industrial Services, which now excludes our PPS business, revenue decreased $6 million and profit before tax decreased $19 million in the third quarter of 2012 compared to the third quarter of 2011. The decrease in revenue and profit before tax was primarily driven by reduced demand for polymers in Europe and Asia Pacific due to unfavorable economic conditions. Industrial Services profit before tax was also negatively impacted by a $2 million charge associated with the information technology expenses and the facility closure.
Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
Revenue for the nine months ended September 30, 2012 increased $1.57 billion or 11% compared to the nine months ended September 30, 2011, driven by increased activity across all segments, particularly in the North America and MEAP segments. Increased revenue in North America is attributed to the strong performance of our product lines other than pressure pumping, while MEAP revenue is being driven by our integrated operations contracts in Iraq and higher demand for completions systems in Saudi Arabia and Australia.
Profit before tax for the nine months ended September 30, 2012 decreased $285 million or 15% compared to the nine months ended September 30, 2011. In North America, despite the increase in revenue, profit before tax was significantly impacted by pricing pressure, higher personnel costs, and increased raw material expenses in our pressure pumping product line. Profitability in our EARC segment has improved mainly as a result of increased revenue in Norway, Nigeria, Libya and Sub Sahara Africa. High operating costs and third party expenses related to new integrated operations contracts in the Middle East reduced profitability. Additionally, increased information technology expenses, charges associated with the closing of a chemical manufacturing facility along with increased amortization also impacted profitability.

20

Table of Contents                                        
                                    

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,
 
2012
 
2011
 
2012
 
2011
 
$
%
 
$
%
 
$
%
 
$
%
Revenue
$
5,228

100
%
 
$
5,064

100
%
 
$
15,708

100
%
 
$
14,136

100
%
Cost of revenue
4,305

82
%
 
3,843

76
%
 
12,660

81
%
 
10,900

77
%
Research and engineering
117

2
%
 
115

2
%
 
366

2
%
 
331

2
%
Marketing, general and
    administrative
344

7
%
 
301

6
%
 
975

6
%
 
862

6
%
Cost of Revenue
Cost of revenue as a percentage of revenue was 82% and 81% for the three months and nine months ended September 30, 2012, respectively, compared to 76% and 77% for the three months and nine months ended September 30, 2011, respectively. The increase in cost of revenue as a percentage of revenue for the three and nine months was due primarily to lower pricing and higher costs with respect to our pressure pumping product line in North America, start-up and third party costs associated with the new integrated operations activities in Iraq, as well as increased expenses related to amortization. Additionally, during the third quarter of 2012, we recorded a charge of $20 million related to the closure of a chemical manufacturing facility as part of our supply chain cost saving initiative, and a $29 million charge to increase our allowance for doubtful accounts in Latin America and Europe.
Research and Engineering
Research and engineering expenses increased 2% and 11% for the three months and nine months ended September 30, 2012, respectively, compared to the same periods a year ago. The increase in research and engineering expenses was primarily driven by an increase in research materials and personnel costs associated with the opening and staffing of technology centers in Brazil and Saudi Arabia.
Marketing, General and Administrative
Marketing, general and administrative (“MG&A”) expenses increased 14% and 13% for the three months and nine months ended September 30, 2012, respectively, compared to the same periods a year ago. The increase in expenses for the three months is primarily due to a charge of $43 million related to the impairment of certain information technology assets primarily associated with internally developed software and other assets. In addition to these costs, the increase in expenses for the nine months resulted from ongoing activities to further improve productivity and efficiency through the coordination and integration of our worldwide operations, including software implementations, partially offset by decreased personnel costs.
Income Taxes
Total income tax expense was $143 million and $479 million for the three months and nine months ended September 30, 2012, respectively. Our effective tax rate on income from continuing operations before income taxes for the three months and nine months ended September 30, 2012 was 34.6% and 30.8%, respectively. The tax rate for the three months ended September 30, 2012 is lower than the U.S. statutory income tax rate of 35% primarily due to lower rates of tax in certain foreign jurisdictions, partially offset by an increase in tax reserves and state income taxes. The tax rate for the nine months ended September 30, 2012 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 net reversal of tax reserves arising from audit settlements and the expiration of statutes of limitations, partially offset by state income taxes.



21

Table of Contents                                        
                                    

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 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 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 that 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 International Energy Agency (“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 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 2012 business environment include the following:
Worldwide Economic Growth - In general there is a strong linkage between overall economic activity, growth and the demand for hydrocarbons. Although we continue to see modest economic growth across the OECD countries and relatively strong growth among many developing economies, there is substantial concern regarding the economic outlook through the rest of 2012 and the beginning of 2013. These concerns are primarily fueled by sovereign debt issues in Europe, an apparent slowdown in the Chinese economy, and the moderate rate of the economic growth in the U.S. The European sovereign debt crisis and the reduction in economic activity have impacted the economies of major exporters, including the U.S. and China. Although steps are being taken by governments to resolve this issue, there is still concern that further downward adjustments to economic growth will occur in the coming months. China's rapid economic growth and industrialization has been a major factor in driving up world-wide economic growth since the recession of 2008/2009. While it is expected that China will continue to grow at a meaningful pace, there has been a slowdown in China's growth rate through September 2012 which is expected to continue during the remainder of the year. In the U.S., there has been a slow recovery from the recession of 2008/2009 as the economy continues to deal with the effects of the financial crisis, and the expectation is for only modest economic growth in the U.S. throughout 2012. However, this growth may be hampered by weakness or further deterioration of the global economy, particularly in China and Europe.
Demand for Hydrocarbons - In its October 2012 Oil Market Report, the IEA forecasted global demand for oil to increase 0.7 million barrels per day to a record 89.7 million barrels per day in 2012. Oil demand is expected to further increase by 0.8 million barrels per day in 2013. This expected increase in demand for oil should support increased expenditures within the oil and gas sector. In addition, natural gas is an increasingly important hydrocarbon to meet the world’s energy needs. In its October 2012 Short-Term Energy and Winter Fuels Outlook, the EIA stated that U.S. natural gas demand will reach a record 69.8 billion cubic feet per day in 2012. Although slightly down from 2012, U.S. natural gas demand in 2013 is forecasted to remain high at 69.6 billion cubic feet per day. Global demand for natural gas is also expected to increase as production from major gas fields in the Middle East, Africa and Asia Pacific are imported into the consuming regions, particularly in Europe and Asia.

Oil Production - OPEC considers global spare oil production capacity to be at comfortable levels with healthy commercial stock levels. However, sustained higher oil prices have led non-OPEC producers, particularly in the U.S., to increase capital spending and apply new technology to increase oil production. Although this is a positive trend for the U.S. that is expected to continue for many years to come, increased price volatility, driven by global economic and geopolitical uncertainties, may lead to delays in operator investment decisions across the rest of the world.


22

Table of Contents                                        
                                    

Natural Gas Production - Worldwide natural gas production continues to grow. Despite this overall trend, low natural gas prices in North America have resulted in a reduction in the natural gas-directed rig activity in this region. This has begun to impact North America natural gas production, though not enough to result in a substantial increase in prices. Overall, worldwide natural gas production will, however, tend to be more stable as high natural gas prices in places such as Europe and Asia encourage sustained global growth of natural gas production. In addition, the announced shift away from nuclear power generation by several countries is expected to further support natural gas prices, and the development of natural gas projects in the OECD outside North America.

Oil Prices - With WTI oil prices trading between $78/Bbl and $109/Bbl, and Brent trading between $89/Bbl and $127/Bbl during the first nine months of 2012, we believe most oil developments globally will continue to provide adequate returns to encourage incremental investment. Based on oil supply forecasts and modest anticipated economic growth globally, we would expect oil prices to remain relatively strong throughout 2012 barring any major macro-economic event.

Natural Gas Prices - With natural gas prices trading between $1.84/mmBtu and $3.20/mmBtu during the first nine months of 2012, which are particularly low when compared to oil on a BTU equivalent basis, we believe that the economics of many dry natural gas-directed investments in North America have become 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. The EIA, however, expects natural gas prices in North America to moderately increase in 2013 as a result of the reduction in natural gas-directed drilling activity throughout 2012.
Activity and Spending Outlook for North America - Overall customer spending in North America is expected to increase in 2012 compared to 2011, but the average annual rig count is expected to decrease 1%. The slowdown in the spending directly related to natural gas development has been largely offset by incremental investment to develop unconventional plays with crude oil and natural gas liquids content. However, due to recent volatility in oil prices, customer spending is expected to hold at current levels in the near term, resulting in a flat oil rig count for the remainder of the year. In the unconventional dry gas plays, while investment has declined throughout the year due to historically low natural gas pricing levels, we expect the reductions in rig counts will slow going forward as gas prices have rebounded moderately. Overall service intensity has increased in North America during the year as customers are demanding key technologies, such as advanced directional drilling, more complex completion systems and pressure pumping to develop the unconventional plays with liquids content. Despite this increase in demand, however, pricing has declined in some basins, particularly for hydraulic fracturing where current pressure pumping capacity exceeds demand. This pricing pressure is expected to continue for the remainder of 2012 and into early 2013. In the Gulf of Mexico, the active rig count has increased to near pre-moratorium levels. Activity on the continental shelf has been strong, and there has been a steady increase in the granting of new deepwater permits. It is expected that exploration drilling as well as completions and development activity in the Gulf of Mexico will continue to increase throughout the remainder of 2012 and 2013, with additional deepwater rigs being added.
Activity and Spending Outlook Outside North America - International activity is driven primarily by the price of oil which is high enough to provide attractive economic returns in almost every region and some major gas export projects. Customers are expected to increase spending to develop new resources and offset declines from existing developed reserves. Areas that are expected to see increased spending throughout the rest of the year and into 2013 include: the Middle East, in particular Iraq, including the Kurdistan province, and Saudi Arabia; and Latin America, with the largest growth expected in Brazil, Mexico and Colombia. In Africa, traditional growth areas such as Angola and Nigeria are being augmented by new provinces such as Ghana, Uganda and Mozambique. Russia is striving to maintain 10 million barrels of oil per day until the end of the decade by investing in Eastern Siberia and eventually in the Arctic offshore. Australia is leading the expansion of export LNG projects, requiring conventional offshore gas drilling in the northwest shelf as well as coal bed methane operations onshore Queensland. While overall unconventional drilling outside North America is still at its infancy, activities in Australia, China, Saudi Arabia and Argentina are showing early promise.
LIQUIDITY AND CAPITAL RESOURCES
Our objective in financing our business is to maintain adequate financial resources and access to sufficient liquidity. At September 30, 2012, we had cash and cash equivalents of $1.01 billion, of which substantially all was held by foreign subsidiaries. A substantial portion of the cash held by foreign subsidiaries at September 30, 2012 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

23

Table of Contents                                        
                                    

combined borrowing at any time under both the credit facility and commercial paper program is $2.5 billion. We had $1.19 billion of outstanding commercial paper at September 30, 2012. 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.
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 302012, we used cash to pay for a variety of activities including working capital needs, capital expenditures and payment of dividends.
Cash Flows
Cash flows provided (used) by continuing operations, by type of activity, were as follows for the nine months ended September 30:

(In millions)
2012
 
2011
Operating activities
$
937

 
$
656

Investing activities
(1,875
)
 
(1,150
)
Financing activities
902

 
(164
)
Operating Activities
Cash flows from operating activities provided $937 million and $656 million in the nine months ended September 302012 and 2011, respectively. Despite a decrease in income from continuing operations of $330 million, cash flows from operating activities increased $281 million. This increase is primarily due to the change in net operating assets and liabilities, which used less cash in the nine months ended September 302012 compared to the same period in 2011.
The underlying drivers of the changes in operating assets and liabilities are as follows:
An increase in accounts receivable used cash of $199 million and $1,074 million in the nine months ended September 302012 and 2011, respectively. The change in accounts receivable in the nine months ended September 302012 was primarily due to an increase in activity. The change in accounts receivable in the nine months ended September 302011 was primarily due to an increase in activity as well as an increase in days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenue) due to temporary invoicing delays resulting from the implementation of our enterprise wide software system for BJ Services in North America.
An increase in inventory used cash of $660 million and $465 million in the nine months ended September 302012 and 2011, respectively, driven by an increase in production of finished goods to support current activity levels.
Accrued employee compensation and other accrued liabilities used cash of $20 million and provided cash of $81 million in the nine months ended September 302012 and 2011, respectively. The net change of $101 million was due primarily to an increase in p