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2013.3.31 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 March 31, 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 April 18, 2013, the registrant has outstanding 441,827,441 shares of Common Stock, $1 par value per share.


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 March 31,
 
2013

 
2012

Revenue:
 
 
 
Sales
$
1,749

 
$
1,729

Services
3,481

 
3,626

Total revenue
5,230

 
5,355

Costs and expenses:
 
 
 
Cost of sales
1,384

 
1,368

Cost of services
2,942

 
2,897

Research and engineering
127

 
124

Marketing, general and administrative
322

 
339

Total costs and expenses
4,775

 
4,728

Operating income
455

 
627

Interest expense, net
(55
)
 
(54
)
Income before income taxes
400

 
573

Income taxes
(132
)
 
(193
)
Net income
268

 
380

Net income attributable to noncontrolling interests
(1
)
 
(1
)
Net income attributable to Baker Hughes
$
267

 
$
379

 
 
 
 
Basic earnings per share attributable to Baker Hughes
$
0.60

 
$
0.86

 
 
 
 
Diluted earnings per share attributable to Baker Hughes
$
0.60

 
$
0.86

 
 
 
 
Cash dividends per share
$
0.15

 
$
0.15

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 March 31,
 
2013
 
2012
Net income
$
268

 
$
380

Other comprehensive income (loss):
 
 
 
Foreign currency translation adjustments during the period
(80
)
 
55

Pension and other postretirement benefits, net of tax
10

 
13

Other comprehensive (loss) income
(70
)
 
68

Comprehensive income
198

 
448

Comprehensive income attributable to noncontrolling interests
(1
)
 
(1
)
Comprehensive income attributable to Baker Hughes
$
197

 
$
447

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.


3
Table of Contents                                     

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

 
March 31,
2013
 
December 31,
2012
ASSETS
Current Assets:
 
 
 
Cash and cash equivalents
$
1,101

 
$
1,015

Accounts receivable - less allowance for doubtful accounts
(2013 - $279; 2012 - $308)
5,096

 
4,815

Inventories, net
3,880

 
3,781

Deferred income taxes
266

 
266

Other current assets
492

 
540

Total current assets
10,835

 
10,417

Property, plant and equipment - less accumulated depreciation
(2013 - $6,443; 2012 - $6,315)
8,753

 
8,707

Goodwill
5,956

 
5,958

Intangible assets, net
963

 
993

Other assets
647

 
614

Total assets
$
27,154

 
$
26,689

LIABILITIES AND EQUITY
Current Liabilities:
 
 
 
Accounts payable
$
2,024

 
$
1,737

Short-term debt and current portion of long-term debt
1,248

 
1,079

Accrued employee compensation
613

 
646

Income taxes payable
193

 
226

Other accrued liabilities
418

 
436

Total current liabilities
4,496

 
4,124

Long-term debt
3,844

 
3,837

Deferred income taxes and other tax liabilities
721

 
745

Liabilities for pensions and other postretirement benefits
547

 
579

Other liabilities
128

 
136

Commitments and contingencies


 


Equity:
 
 
 
Common stock
442

 
441

Capital in excess of par value
7,518

 
7,495

Retained earnings
9,810

 
9,609

Accumulated other comprehensive loss
(546
)
 
(476
)
Baker Hughes stockholders’ equity
17,224

 
17,069

Noncontrolling interests
194

 
199

Total equity
17,418

 
17,268

Total liabilities and equity
$
27,154

 
$
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
 
 
 
 
267

 
 
 
1

 
268

Other comprehensive loss
 
 
 
 
 
 
(70
)
 
 
 
(70
)
Activity related to stock plans
1

 
(13
)
 
 
 
 
 
 
 
(12
)
Stock-based compensation
 
 
36

 
 
 
 
 
 
 
36

Cash dividends ($0.15 per share)
 
 
 
 
(66
)
 
 
 
 
 
(66
)
Net activity related to noncontrolling
interests
 
 


 
 
 
 
 
(6
)
 
(6
)
Balance at March 31, 2013
$
442

 
$
7,518

 
$
9,810

 
$
(546
)
 
$
194

 
$
17,418


 
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
 
 
 
 
379

 
 
 
1

 
380

Other comprehensive income
 
 
 
 
 
 
68

 

 
68

Activity related to stock plans
1

 
(2
)
 
 
 
 
 
 
 
(1
)
Stock-based compensation
 
 
38

 
 
 
 
 
 
 
38

Cash dividends ($0.15 per share)
 
 
 
 
(65
)
 
 
 
 
 
(65
)
Net activity related to noncontrolling
interests
 
 
22

 
 
 
 
 
(24
)
 
(2
)
Balance at March 31, 2012
$
438

 
$
7,361

 
$
8,875

 
$
(487
)
 
$
195

 
$
16,382

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)

 
Three Months Ended March 31,
 
2013
 
2012
Cash flows from operating activities:
 
 
 
Net Income
$
268

 
$
380

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
415

 
363

Other noncash items
(3
)
 
(40
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(378
)
 
(131
)
Inventories
(124
)
 
(401
)
Accounts payable
312

 
109

Other operating items, net
(104
)
 
(356
)
Net cash flows provided by (used in) operating activities
386

 
(76
)
Cash flows from investing activities:
 
 
 
Expenditures for capital assets
(490
)
 
(671
)
Proceeds from disposal of assets
94

 
103

Net cash flows used in investing activities
(396
)
 
(568
)
Cash flows from financing activities:
 
 
 
Net proceeds of commercial paper borrowings and other debt with three months or less original maturity
200

 
449

Net repayments of short-term debt
(24
)
 
—

Dividends paid
(66
)
 
(65
)
Other financing items, net
(10
)
 
(13
)
Net cash flows provided by financing activities
100

 
371

Effect of foreign exchange rate changes on cash
(4
)
 
3

Increase (decrease) in cash and cash equivalents
86

 
(270
)
Cash and cash equivalents, beginning of period
1,015

 
1,050

Cash and cash equivalents, end of period
$
1,101

 
$
780

Supplemental cash flows disclosures:
 
 
 
Income taxes paid, net of refunds
$
133

 
$
299

Interest paid
$
71

 
$
70

Supplemental disclosure of noncash investing activities:
 
 
 
Capital expenditures included in accounts payable
$
80

 
$
108

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 accounting principles generally accepted (“GAAP”) in the United States of America (“U.S.”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial information. Accordingly, certain information and disclosures normally included in our annual financial statements have been condensed or omitted. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K 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. 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 the first quarter of 2013.
NOTE 3. INCOME TAXES
Our effective tax rate on income before income taxes for the three months ended March 31, 2013 was 33%. The tax rate for the three months ended March 31, 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 and an increase in reserves related to prior year tax positions.


7
Table of Contents
Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 4. 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 March 31,
 
2013
 
2012
Weighted average common shares outstanding for basic EPS
443

 
439

Effect of dilutive securities - stock plans
1

 
1

Adjusted weighted average common shares outstanding for diluted EPS
444

 
440

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

 
6

NOTE 5. INVENTORIES
Inventories, net of reserves, are comprised of the following:

 
March 31,
2013
 
December 31,
2012
Finished goods
$
3,417

 
$
3,336

Work in process
244

 
228

Raw materials
219

 
217

Total
$
3,880

 
$
3,781

NOTE 6. INTANGIBLE ASSETS
Intangible assets are comprised of the following:

 
March 31, 2013
 
December 31, 2012
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
Definite lived intangibles:
 
 
 
 
 
 
 
 
 
 
 
Technology
$
787

 
$
295

 
$
492

 
$
787

 
$
282

 
$
505

Contract-based
16

 
10

 
6

 
16

 
10

 
6

Trade names
121

 
66

 
55

 
121

 
60

 
61

Customer relationships
494

 
128

 
366

 
494

 
117

 
377

Subtotal
1,418

 
499

 
919

 
1,418

 
469

 
949

Indefinite lived intangibles:
 
 
 
 
 
 
 
 
 
 
 
In-process research and
development
44

 
—

 
44

 
44

 
—

 
44

Total
$
1,462

 
$
499

 
$
963

 
$
1,462

 
$
469

 
$
993

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 ended March 31, 2013 and 2012 was $30 million and $34 million, respectively, and is estimated to be $87 million for the remainder of fiscal year 2013. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2014 - $102 million; 2015 - $94 million; 2016 - $93 million; 2017 - $90 million; and 2018 - $84 million.

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

NOTE 7. 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 March 31, 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 March 31, 2013 and December 31, 2012 was $5,911 million and $5,829 million, respectively, which differs from the carrying amounts of $5,092 million and $4,916 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 8. 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
 
March 31, 2013
 
March 31, 2012
Segments
Revenue
 
Profit (Loss) Before Taxes
 
Revenue
 
Profit (Loss) Before Taxes
North America
$
2,603

 
$
235

 
$
2,863

 
$
401

Latin America
590

 
49

 
573

 
67

Europe/Africa/Russia Caspian
854

 
93

 
893

 
153

Middle East/Asia Pacific
894

 
116

 
745

 
75

Industrial Services and Other
289

 
24

 
281

 
22

Total Operations
5,230

 
517

 
5,355

 
718

Corporate and Other
—

 
(62
)
 
—

 
(91
)
Interest Expense, net
—

 
(55
)
 
—

 
(54
)
Total
$
5,230

 
$
400

 
$
5,355

 
$
573

 
 
 
 
 
 
 
 
NOTE 9. 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.

9
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Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

The components of net periodic cost are as follows for the three months ended March 31:

 
U.S. Pension Plans
 
Non-U.S. Pension Plans
 
Other Postretirement Benefits
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Service cost
$
16

 
$
16

 
$
4

 
$
2

 
$
2

 
$
3

Interest cost
6

 
5

 
8

 
8

 
1

 
2

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

 
—

Amortization of prior service benefit
—

 
—

 
—

 
—

 
(2
)
 
(1
)
Amortization of net actuarial loss
3

 
4

 
2

 
1

 
1

 
1

Benefit settlement
—

 
—

 
—

 
6

 
—

 
—

Net periodic cost
$
15

 
$
16

 
$
4

 
$
8

 
$
2

 
$
5

 
 
 
 
 
 
 
 
 
 
 
 
NOTE 10. 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 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 claims that BHOO's termination was “invalid” constituting a breach and that BHOO “anticipatorily repudiated the Supply Agreement without just excuse.” Hi-Crush claims that it is 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 seeks 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. BHOO intends to vigorously defend itself and seeks to recover the damages it has incurred as a result of Hi-Crush's breach of contract. We do not expect the outcome of this matter to 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 this matter.
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 March 31, 2013. It is not practicable to estimate the fair value of these financial

10
Table of Contents
Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

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, net of tax, consisted of the following:

 
Pensions and Other Postretirement Benefits
Foreign Currency Translation Adjustments
Accumulated Other Comprehensive Loss
Balance at December 31, 2012
 
$
(250
)
 
 
$
(226
)
 
 
$
(476
)
 
Other comprehensive income before reclassifications:
 
 
 
 
 
 
 
 
 
Translation adjustments
 
—

 
 
(80
)
 
 
(80
)
 
Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 
 
 
 
Amortization and effect of exchange rate
 
16

 
 
—

 
 
16

 
Deferred taxes
 
(6
)
 
 
—

 
 
(6
)
 
Balance at March 31, 2013
 
$
(240
)
 
 
$
(306
)
 
 
$
(546
)
 
Certain amounts reclassified from accumulated other comprehensive income during the three months ended March 31, 2013 are included in the computation of net periodic pension cost (see Note 9. Employee Benefit Plans for additional details).


11
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, 2012 (“2012 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. 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 first quarter of 2013, we generated revenue of $5.23 billion, a decrease of $125 million or 2% compared to the first quarter of 2012, and a decrease of $95 million or 2% compared to the fourth quarter of 2012, or sequentially. Net income attributable to Baker Hughes was $267 million for the first quarter of 2013 compared to $379 million for the first quarter of 2012, and $214 million for the fourth quarter of 2012.
North America oilfield revenue for the first quarter of 2013 was $2.60 billion, a decrease of 9% compared to the first quarter of 2012 and an increase of 2% compared to the fourth quarter of 2012. North America oilfield profit before tax for the first quarter of 2013 was $235 million compared to $401 million for the first quarter of 2012 and $222 million for the fourth quarter of 2012. Our first quarter results for 2013 compared to the same quarter a year ago 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. Profitability in North America was also adversely impacted by increased raw material costs in our pressure pumping business. Sequentially, our North American oilfield revenue and profit margins improved due to higher activity levels in Canada, along with improved utilization in our pressure pumping business despite a 3% decline in the U.S. onshore rig count since the fourth quarter of 2012.
Oilfield revenue outside of North America for the first quarter of 2013 was $2.34 billion, an increase of 6% compared to the first quarter of 2012 driven by strong growth in the Middle East/Asia Pacific segment. Sequentially, oilfield revenue outside of North America decreased 5% primarily due to our typical seasonal declines, with particular weakness in our Europe/Africa/Russia Caspian segment, partially offset by the improving performance of our Middle East region.
Oilfield profitability outside North America for the first quarter of 2013 was $258 million compared to $295 million for the first quarter of 2012 and $262 million for the fourth quarter of 2012. Although activity has increased in many of our international segments, particularly Middle East/Asia Pacific, unfavorable sales mix and other operating costs have reduced profitability. Additionally, the first quarter of 2013 includes a loss related to the devaluation of the Venezuelan currency, the Bolivars Fuertes, of $23 million. Sequentially, our profitability declined only slightly reflecting the typical seasonal declines that were offset by the improvement in the Middle East/Asia Pacific segment.

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Table of Contents                                     

As of March 31, 2013, we had approximately 58,900 employees compared to approximately 58,800 employees as of December 31, 2012.
BUSINESS ENVIRONMENT
In North America, rig counts declined 11% in the first quarter of 2013 compared to the same period a year ago. Despite a cold winter and strong demand, continued natural gas production in the unconventional shale plays contributed to above normal natural gas working inventories and ultimately low commodity prices that do not support incremental investment in gas-directed rig activities. As a result, customer spending in the natural gas shale plays remained limited, with natural gas-directed rig activity declining 37% in first quarter of 2013 compared to the same period a year ago. Customer spending for oil in the U.S. remained strong during the first quarter of 2013 as evidenced by the fact that oil-directed rig activity increased 5% compared to the same period in 2012. However, this was partially offset by a 6% reduction in oil-directed rig counts in Canada for the same time periods, as high oil price differentials, primarily due to constrained refinery and pipeline capacity, resulted in reduced customer spending.
Outside of North America, customer spending is most heavily influenced by Brent oil prices. On average, Brent oil prices decreased 5% in the first quarter of 2013 compared to the same period a year ago as Europe's economic concerns increased, growth in China showed signs of slowing and global oil supplies increased. 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. As a result, the international rig count grew by 7% in the first quarter of 2013 compared to the same quarter in 2012, with the largest gains seen in Africa and Europe. Excluding the rigs in Iraq, which Baker Hughes resumed publishing in June 2012, the international rig count grew by 2% in the first quarter of 2013 compared to the same quarter in 2012.
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 March 31,
 
2013

 
2012

Brent oil prices ($/Bbl) (1)
$
112.82

 
$
118.52

WTI oil prices ($/Bbl) (2)
94.35

 
102.87

Natural gas prices ($/mmBtu) (3)
3.49

 
2.45

(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 $112.82/Bbl in the first quarter of 2013. Brent oil prices increased in the first half of the first quarter of 2013 as global economic indicators appeared to be favorable for solid growth in oil demand. In the second half of the quarter, however, prices began to decline as unfavorable economic data in China and continued deterioration in the European economy combined to suggest that oil demand growth might remain relatively weak in 2013. During the quarter, Brent oil prices ranged from a high of $119.34/Bbl in mid-February 2013 to a low of $107.10/Bbl in late March 2013. In its April 2013 Oil Market Report, the International Energy Agency (“IEA”) revised its 2013 estimated global oil demand downward to 90.6 million barrels per day from its original estimate of 90.8 million barrels per day. Despite the downward adjustment, the estimated 2013 global demand still exceeds 2012 global demand of 89.9 million barrels per day.
WTI oil prices averaged $94.35/Bbl in the first quarter of 2013. Prices ranged from a high of $97.94/Bbl in late January 2013 to a low of $90.12/Bbl in early March 2013. WTI prices rebounded to near quarter highs in late March 2013, closing at $97.23/Bbl.

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In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $3.49/mmBtu in the first quarter of 2013. Natural gas prices, which have been low since late 2011, continued to rebound during the first quarter as cold weather in key consuming regions of the U.S. increased demand, resulting in significant storage withdrawals. Overall for the quarter, prices ranged from a low of $3.08/mmBtu at the beginning of January 2013 to a high of $4.08/mmBtu near the end of March 2013. Prices closed at $4.03/mmBtu at the end of March, as natural gas rig counts declined to 14 year lows in the U.S., and natural gas storage declined to its lowest level since April 2011. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of the first quarter of 2013 was 1,687/Bcf, which was 32% or 792/Bcf below the corresponding week in 2012.
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 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. 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 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 March 31,
 
 
2013

2012

% Change
U.S. - land and inland waters
1,706

1,947

(12
)%
U.S. - offshore
52

43

21
 %
Canada
531

584

(9
)%
North America
2,289

2,574

(11
)%
Latin America
426

432

(1
)%
North Sea
48

36

33
 %
Continental Europe
86

76

13
 %
Africa
114

83

37
 %
Middle East
355

311

14
 %
Asia Pacific
245

250

(2
)%
Outside North America
1,274

1,188

7
 %
Worldwide
3,563

3,762

(5
)%
First Quarter of 2013 Compared to the First Quarter of 2012
The rig count in North America decreased 11% in the first quarter of 2013 compared to the same period a year ago as natural gas-directed rig counts declined 37%, partially offset by an increase in oil-directed rig counts of 3%. The natural gas-directed rig count reflected a 41% decrease in the U.S. and a 17% decrease in Canada. The oil-

14
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directed rig count increased 5% in the U.S., but was partially offset by a 6% 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 modest growth in oil-directed drilling in the U.S. was primarily a result of continued strong oil prices sufficient to support continued development of the liquids rich unconventional shale plays. In Canada, many operators continued to curtail their drilling plans during the first quarter of 2013 due to high oil price differentials as compared to WTI and reduced cash flows from natural gas activities. Overall, the Canadian rig count declined 9% in the first quarter of 2013 as compared to the same quarter in 2012.
Outside North America, the rig count in the first quarter of 2013 increased 7% compared to the same period a year ago. Starting June 2012, the Middle East rig count included Iraq. Excluding Iraq, which had 66 rigs during the first quarter of 2013, the international rig count increased 2%. The rig count in Latin America decreased 1% primarily due to lower rig activity in Colombia, Brazil and Venezuela, mostly offset by increased rig activity in Mexico, Argentina and Ecuador. The rig count in the North Sea increased 33%, primarily due to activity improvements in the U.K. and Norway. In Continental Europe, the rig count increased 13% primarily due to higher activity in Turkey. The rig count increased 37% in Africa primarily due to resumption of drilling activities in Libya, as well as higher activity in Algeria. The rig count increased 14% in the Middle East due to higher activity in Saudi Arabia and United Arab Emirates, as well as the inclusion of Iraq. These increases were partially offset by reduced activity in Egypt, and the exclusion of Syria from the rig count. In Asia Pacific, the rig count decreased 2% as a result of decreased activity in Indonesia, partially offset by increased activity in Australia.
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.
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 March 31,
 
$ Change
 
% Change
 
2013
 
2012
 
Revenue:
 
 
 
 
 
 
 
North America
$
2,603

 
$
2,863

 
$
(260
)
 
(9
%)
Latin America
590

 
573

 
17

 
3
%
Europe/Africa/Russia Caspian
854

 
893

 
(39
)
 
(4
%)
Middle East/Asia Pacific
894

 
745

 
149

 
20
%
Industrial Services and Other
289

 
281

 
8

 
3
%
Total
$
5,230

 
$
5,355

 
$
(125
)
 
(2
%)


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Three Months Ended March 31,
 
$ Change
 
% Change
 
2013
 
2012
 
Profit Before Tax:
 
 
 
 
 
 
 
North America
$
235

 
$
401

 
$
(166
)
 
(41
%)
Latin America
49

 
67

 
(18
)
 
(27
%)
Europe/Africa/Russia Caspian
93

 
153

 
(60
)
 
(39
%)
Middle East/Asia Pacific
116

 
75

 
41

 
55
%
Industrial Services and Other
24

 
22

 
2

 
9
%
Total Operations
517

 
718

 
(201
)
 
(28
%)
Corporate and Other
(62
)
 
(91
)
 
29

 
(32
%)
Interest Expense, net
(55
)
 
(54
)
 
(1
)
 
2
%
Total
$
400

 
$
573

 
$
(173
)
 
(30
%)
First Quarter of 2013 Compared to the First Quarter of 2012
Revenue for the first quarter of 2013 decreased $125 million or 2% compared to the first quarter of 2012. North American revenue was significantly impacted by decreased demand and pricing for our pressure pumping product line, partially offset by improved demand for other U.S. product lines and increased activity in the Gulf of Mexico. International revenue increased primarily as a result of increased activity in the Middle East, and to a lesser extent, Latin America.
Profit before tax for the first quarter of 2013 decreased $173 million or 30% compared to the first quarter of 2012. Our profit before tax was significantly impacted by pricing pressure and increased raw material and depreciation expenses in our pressure pumping product line in North America. Increased operating costs and third party expenses related to integrated operations contracts in the Middle East, mobilization costs associated with a new drilling services contract in Norway, and unfavorable sales mix in Europe further eroded profits. Additionally, we recorded a $23 million loss in Latin America due to the devaluation of the Venezuelan currency.
North America
North America revenue decreased 9% in the first quarter of 2013 compared to the first quarter of 2012. The primary catalyst for the decline seen in North America is attributed to the decline in rig activity in the first quarter of 2013 compared to the same period a year ago. The North American rig count decreased 11% overall, the majority of which is attributable to the 37% decline in natural gas-directed drilling year over year. In Canada, although activity was higher than anticipated, oil-directed rig counts decreased 6% and natural gas-directed rig counts were down 17% compared to the first quarter of 2012. The decline in North America revenue is mainly attributed to our pressure pumping product line in the U.S. and Canada, which has been most adversely affected by the reduction in rig activity, pricing pressure resulting from surplus capacity and low natural gas prices. Although our product lines other than pressure pumping were also impacted by the declining number of active rigs, these product lines have benefited from an increasing number of wells drilled per rig. As a result, we experienced modest revenue gains from our completions, drilling services and artificial lift product lines stemming from improved well efficiencies.
North America profit before tax was $235 million in the first quarter of 2013, a decrease of $166 million compared to the first quarter of 2012. In addition to the decline in revenue, profit before tax in U.S. Land and Canada was negatively impacted by an unfavorable change in sales mix to products and services with lower margins. Our pressure pumping product line was also impacted by decreased fleet utilization, increased costs for critical raw materials and higher depreciation expenses, which were largely offset by a reduction in our personnel and repairs and maintenance costs.

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Latin America
Latin America revenue increased 3% in the first quarter of 2013 compared to the first quarter of 2012. The primary drivers of the increase were higher activity in the Andean geomarket and Argentina benefiting our artificial lift and drilling services product lines, as well as profitable growth in Mexico across most product lines. These increases were partially offset by a reduction in overall activity in Brazil, driven by a 12% reduction in rig count in the first quarter of 2013 compared to the first quarter of 2012. Further, we experienced a modest reduction in revenue in Venezuela due to the effect of the recent currency devaluation on transactions denominated in the local currency.
Latin America profit before tax decreased 27% in the first quarter of 2013 compared to the first quarter of 2012. While profit before tax benefited from modest revenue growth and a favorable sales mix, profit before tax was negatively impacted by a $23 million loss due to the devaluation of the Venezuelan currency. Although this devaluation will result in a reduction in the U.S. Dollar reported amount of local currency denominated revenues and expenses, going forward we do not believe the impact will be material to our consolidated financial statements.
Europe/Africa/Russia Caspian
Europe/Africa/Russia Caspian (“EARC”) revenue decreased 4% in the first quarter of 2013 compared to the first quarter of 2012. Despite increases in the North Sea and Continental Europe rig counts year over year, lower pricing for drilling services in Norway, and the completion of drilling services projects in the Eastern Mediterranean resulted in reduced revenue in the first quarter of 2013 compared to the same period a year ago. In Africa, quarterly revenue was relatively flat year over year. Revenue increases associated with resuming operations in Libya were offset by reduced drilling services activity in Nigeria. In the Russia Caspian region, revenue decreased slightly in the first quarter of 2013 compared to the first quarter of 2012 due mainly to a reduction of artificial lift sales.
EARC profit before tax decreased 39% in the first quarter of 2013 compared to the first quarter of 2012. In addition to the reduction in revenue year over year, profit before tax was adversely impacted by an unfavorable change in sales mix to products and services with lower margins in Europe and Africa, and increased personnel costs and mobilization costs in Norway associated with our new integrated drilling services contract.
Middle East/Asia Pacific
Middle East/Asia Pacific (“MEAP”) revenue increased 20% in the first quarter of 2013 compared to the first quarter of 2012. The increase in this segment was largely attributable to the Middle East where we experienced higher demand for drilling services in Saudi Arabia, Kuwait, United Arab Emirates, and Oman, as well as growth in our integrated operations contracts in Iraq and Saudi Arabia. Asia Pacific revenues were up modestly with improved demand for wireline services in Papua New Guinea and Indonesia, and overall activity increases in Japan and Thailand. This increase was partially offset by reduced activity for wireline services in India and lower activity in Malaysia and Vietnam.
MEAP profit before tax increased 55% in the first quarter of 2013 compared to the first quarter of 2012. The primary driver of the increase in profit before tax was higher incremental profit on increased revenue in the Middle East. In addition to the increase in revenue, profit before tax was favorably impacted by a reduction in personnel cost in Asia Pacific due to a decrease in headcount.
Industrial Services and Other
For Industrial Services and Other, revenue increased $8 million and profit before tax increased $2 million in the first quarter of 2013 compared to the first quarter of 2012. The increase in revenue and profit before tax was primarily driven by increased demand for our process and pipeline business in Australia, Canada and the Caspian.

17
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Costs and Expenses
The table below details certain unaudited consolidated condensed statement of income data and their percentage of revenue.

 
Three Months Ended March 31,
 
2013
 
2012
 
$
 
%
 
$
 
%
Revenue
$
5,230

 
100
%
 
$
5,355

 
100
%
Cost of revenue
4,326

 
83
%
 
4,265

 
80
%
Research and engineering
127

 
2
%
 
124

 
2
%
Marketing, general and administrative
322

 
6
%
 
339

 
6
%
Cost of Revenue
Cost of revenue as a percentage of revenue was 83% and 80% for the three months ended March 31, 2013 and 2012, respectively. The increase in cost of revenue as a percentage of revenue was due primarily to lower pricing and increased raw material and depreciation expenses in our pressure pumping product line in North America. An increase in operating costs and third party expenses related to integrated operations contracts in the Middle East, mobilization costs associated with a new drilling services contract in Norway, and an unfavorable change in sales mix in Europe and Africa further reduced our margins.
Marketing, General and Administrative
Marketing, general and administrative (“MG&A”) expenses decreased 5% for the three months ended March 31, 2013 compared to the same period a year ago. The decrease in expenses is primarily due to the winding down of our worldwide integration efforts subsequent to our acquisition of BJ Services. The conclusion of these efforts resulted in decreased costs related to technology, project management and personnel and led to improved efficiencies among our global operations and support functions. These decreases were offset by a loss of $23 million related to the devaluation of the Venezuelan Bolivars Fuertes.
Income Taxes
Total income tax expense was $132 million for the three months ended March 31, 2013. Our effective tax rate on income before income taxes for the three months ended March 31, 2013 was 33%. The tax rate for the three months ended March 31, 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 and an increase in reserves related to prior year tax positions.
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.

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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 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 2013 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. The outlook for the remainder of 2013 is one of general strengthening of economic activity amidst ongoing concerns fueled by sovereign debt issues in Europe, a slowdown of the rate of growth 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 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 world-wide economic growth since the recession of 2008/2009. While China's growth rate slowed down sharply in 2012, activity is expected to pick up in 2013 in response to measures strengthening domestic demand. 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 2013. 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 April 2013 Oil Market Report, the IEA forecasted global demand for oil to increase 0.7 million barrels per day in 2013, to 90.6 million barrels per day. This expected increase in demand for oil, mainly driven by countries outside the OECD, 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 April 2013 Short-Term Energy Outlook, the EIA estimated that U.S. natural gas demand would increase by 0.7 billion cubic feet per day in 2013, to 70.3 billion cubic feet per day.
•
Oil Production - The IEA April 2013 Oil Market Report projects non-OPEC production to grow by 1.1 million barrels per day in 2013 to 54.4 million barrels per day. 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. North American output growth offsets lower European and Latin American supply. Global OPEC production is anticipated to fall by 0.4 million barrels per day in 2013 to 29.7 million barrels per day. Most of the decline comes from Saudi Arabia, in response to growth in non-OPEC supply. Significant investments are expected to be required to increase production capacity, especially in the context of declining production from mature fields and the rapid early well production declines 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 resources. However, 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 - 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 and completion activity in this region. This began to impact North America natural gas production in 2012, resulting in a gradual increase in the Henry Hub spot gas prices in the second half of 2012 and continuing into 2013. Relative cold weather in the later part of the winter season and slightly below average gas in storage has seen spot gas prices rise in late March 2013. 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 of natural gas production. In addition, the announced shift away from nuclear power generation by several countries and the development of natural gas projects in the OECD outside North America are expected to further support natural gas prices.

19
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•
Oil Prices - With WTI oil prices trading between $90.12/Bbl and $97.94/Bbl, and Brent trading between $107.10/Bbl and $119.34/Bbl during the first quarter of 2013, we believe most oil developments globally will continue to provide adequate returns to encourage incremental investment. New midstream infrastructure in the U.S. is expected during 2013, which should help to narrow the price gap between WTI and Brent. Based on oil supply forecasts and modest anticipated economic growth globally, we would expect oil prices to remain relatively stable throughout 2013, barring any major macro-economic event.
•
Natural Gas Prices - With Henry Hub natural gas prices trading between $3.08/mmBtu and $4.08/mmBtu during the first quarter of 2013, which prices are particularly low 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 in 2013. However, for the first time since September 2011, natural gas in storage in March 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. but flat overall production. The EIA expects Henry Hub natural gas prices to increase to an average of $3.52/mmBtu in 2013. Future gas demand and gas pricing in the U.S. is sensitive to assumptions regarding fuel competition for power generation and the start of liquefied natural gas (“LNG”) exports, 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. 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. In the unconventional dry gas plays, while investment declined throughout most of 2012 due to historically low natural gas pricing levels, the rig count for natural gas stabilized in the fourth quarter of 2012 and for most of the first quarter of 2013 as gas prices rebounded moderately. However, natural gas rig activity experienced a small decline in late March 2013. Overall service intensity has increased in North America 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 rest of 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 2013, with additional deep water rigs being added. In Canada, overall rig activity in 2013 is expected to decline approximately 7% 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 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 reserves, increasingly relying on advanced technology services 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 Kurdistan province, and Saudi Arabia; and Latin America, with the largest growth expected in Mexico, Brazil, and Colombia. Within Southeast Asia, there is an increased focus on exploring and developing indigenous 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 provinces such as Ghana, Uganda, Mozambique and Tanzania, while South Sudan has just resumed oil exports. 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. Efforts in Russia at developing tight oil using vertical drilling are already underway with potential for pilot projects in 2013 and beyond for more complex horizontal drilling and completions. 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. 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 overall unconventional drilling outside North America is still at its infancy, activities in Australia, China, Saudi Arabia and Argentina are showing

20
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early promise, with 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 March 31, 2013, we had cash and cash equivalents of $1.10 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 March 31, 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 March 31, 2013, we had $1.10 billion 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 three months ended March 31, 2013, 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 (used) by type of activity, for the three months ended March 31:

(In millions)
2013
 
2012
Operating activities
$
386

 
$
(76
)
Investing activities
(396
)
 
(568
)
Financing activities
100

 
371

Operating Activities
Cash flows from operating activities provided $386 million in the three months ended March 31, 2013. Before changes in operating assets and liabilities, the major source of funds was net income, including noncontrolling interests, of $268 million plus the noncash provision for depreciation and amortization of $415 million. Net changes in operating assets and liabilities used $294 million for the three months ended March 31, 2013. This was primarily the result of an increase in accounts receivable of $378 million due to slower collections and an increase in inventory of $124 million offset by an increase in accounts payable of $312 million.
Investing Activities
Our principal recurring investing activity was 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 $490 million in the three months ended March 31, 2013. The majority of these expenditures were for machinery and equipment. Additionally, we have continued investing in new facilities, expansions of existing facilities and other infrastructure projects.
Proceeds from the disposal of assets were $94 million in the three months ended March 31, 2013. These disposals related to equipment that was lost-in-hole, 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 proceeds from borrowings of $176 million related to commercial paper and other debt in the three months ended March 31, 2013. Total debt outstanding at March 31, 2013 was $5.09 billion, an increase of $0.18 billion compared to December 31, 2012. The total debt to total capitalization (defined as total debt plus equity) ratio was 0.23 at March 31, 2013 and 0.22 at December 31, 2012. We paid dividends of $66 million in the three months ended March 31, 2013.
Available Credit Facility
We have a $2.5 billion committed revolving credit facility with commercial banks that matures in September 2016. At March 31, 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 March 31, 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 March 31, 2013, we had $1.10 billion of commercial paper outstanding resulting in $1.4 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 billion, excluding any amount related to acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support our business and operations. 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 to make interest payments of between $225 million and $240 million, based on debt levels as of March 31, 2013. We anticipate making income tax payments of between $700 million and $800 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 three months ended March 31, 2013 and 2012, we did not repurchase any shares of common stock. At March 31, 2013, we had authorization remaining to repurchase approximately $1.2 billion in common stock. We anticipate paying dividends of between $263 million and $273 million in 2013; however, the Board of Directors can change the dividend policy at any time.
During the three months ended March 31, 2013, we contributed approximately $112 million to our defined benefit, defined contribution and other postretirement plans. We expect to make additional contributions of between $270 million and $300 million to these plans for the remainder of 2013.
New Accounting Standards Updates
In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update

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(“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.
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 three months ended March 31, 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 March 31, 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 March 31, 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 10 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.
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 March 31, 2013.

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 (3)
January 1-31, 2013
277,498

 
$
44.99

—

 
$
—

277,498

 
$
—

February 1-28, 2013
5,110

 
45.55

—

 
—

5,110

 
—

March 1-31, 2013
1,534

 
44.89

—

 
—

1,534

 
—

Total
284,142

 
$
45.00

—

 
$
—

284,142

 
$
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)
There were no share repurchases during the three months ended March 31, 2013 as part of a publicly announced program.
(3)
Our Board of Directors has authorized a program to repurchase our common stock from time to time. During the three months ended March 31, 2013, 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.
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.

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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.

10.1+
 
Performance Goals for Performance Units Granted in 2013 under the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan and the Baker Hughes Incorporated Employee Long-Term Incentive Plan (filed as Exhibit 10.1 to the Current Report of Baker Hughes Incorporated on Form 8-K filed March 4, 2013).
31.1*
 
Certification of Martin S. Craighead, President 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, President 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:
April 24, 2013
By:
/s/ PETER A. RAGAUSS
 
 
 
Peter A. Ragauss
 
 
Senior Vice President and Chief Financial Officer
 
 
 
 
Date:
April 24, 2013
By:
/s/ ALAN J. KEIFER
 
 
 
Alan J. Keifer
 
 
Vice President and Controller

26
2013.3.31 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:
April 24, 2013
By:  
/s/ Martin S. Craighead
 
 
 
Martin S. Craighead
 
 
 
President and
Chief Executive Officer 
 
 


2013.3.31 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:
April 24, 2013
By:  
/s/ Peter A. Ragauss  
 
 
 
Peter A. Ragauss 
 
 
 
Senior Vice President and
Chief Financial Officer 
 
 



2013.03.31 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 March 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Martin S. Craighead, President 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:
 
President and Chief Executive Officer
 
 
Date:
 
April 24, 2013
 
 
 
 
 
 
 
 
 
/s/ Peter A. Ragauss
 
 
 
Name:
 
Peter A. Ragauss
 
 
Title:
 
Senior Vice President and Chief Financial Officer
 
 
Date:
 
April 24, 2013


Q1 FY2013 Mine Safety Disclosure

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 March 31, 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 March 31, 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
Morgan City Grinding Plant/1601357
0
0
0
0
0
$
—

0
N
N
0
0
0
Argenta Mine and Mill/2601152
5 (2)
0
0
0
0
$ 4526 (3)
0
N
N
0
0
0
Corpus Christi Grinding Plant/4103112
0
0
0
0
0
$
—

0
N
N
0
0
0

(1) 
Amounts included are the total dollar value of proposed assessments received from MSHA during the three months ended March 31, 2013, regardless of whether the assessment has been challenged or appealed. Citations and orders can be contested and appealed, and as part of that process, are sometimes reduced in severity and amount, and sometimes dismissed. The number of citations, orders, and proposed assessments vary by inspector and also vary depending on the size and type of the operation.
(2) 
One Section 104 S&S citation issued to an independent contractor (who is not a subsidiary of Baker Hughes) who is working at the Argenta Mine and Mill.
(3) 
Amount includes $190 of assessments proposed by MSHA that relate to one citation issued to an independent contractor (who is not a subsidiary of Baker Hughes) who is working at the Argenta Mine and Mill. As of March 31, 2013, MSHA had not yet proposed an assessment on one citation relating to this site.