2015.06.30 10-Q
        

                                    

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 June 30, 2015
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 July 16, 2015, the registrant has outstanding 435,882,315 shares of Common Stock, $1 par value per share.



Baker Hughes Incorporated
Table of Contents

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


1


PART I — FINANCIAL INFORMATION

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

 
Three Months Ended June 30,
 
Six Months Ended June 30,
(In millions, except per share amounts)
2015
 
2014
 
2015
 
2014
Revenue:
 
 
 
 
 
 
 
Sales
$
1,431

 
$
1,975

 
$
2,959

 
$
3,832

Services
2,537

 
3,960

 
5,603

 
7,834

Total revenue
3,968

 
5,935

 
8,562

 
11,666

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales
1,230

 
1,530

 
2,575

 
3,031

Cost of services
2,385

 
3,215

 
5,382

 
6,434

Research and engineering
124

 
159

 
262

 
302

Marketing, general and administrative
310

 
338

 
625

 
654

Restructuring charges
76

 

 
649

 

Litigation settlements
(13
)
 
62

 
(13
)
 
62

Total costs and expenses
4,112

 
5,304

 
9,480

 
10,483

Operating (loss) income
(144
)
 
631

 
(918
)
 
1,183

Interest expense, net
(53
)
 
(59
)
 
(107
)
 
(116
)
(Loss) income before income taxes
(197
)
 
572

 
(1,025
)
 
1,067

Income taxes
7

 
(213
)
 
242

 
(372
)
Net (loss) income
(190
)
 
359

 
(783
)
 
695

Net loss (income) attributable to noncontrolling interests
2

 
(6
)
 
6

 
(14
)
Net (loss) income attributable to Baker Hughes
$
(188
)
 
$
353

 
$
(777
)
 
$
681

 
 
 
 
 
 
 
 
Basic (loss) earnings per share attributable to Baker Hughes
$
(0.43
)
 
$
0.81

 
$
(1.77
)
 
$
1.56

 
 
 
 
 
 
 
 
Diluted (loss) earnings per share attributable to Baker Hughes
$
(0.43
)
 
$
0.80

 
$
(1.77
)
 
$
1.55

 
 
 
 
 
 
 
 
Cash dividends per share
$
0.17

 
$
0.15

 
$
0.34

 
$
0.30

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

2


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

 
Three Months Ended June 30,
 
Six Months Ended June 30,
(In millions)
2015
 
2014
 
2015
 
2014
Net (loss) income
$
(190
)
 
$
359

 
$
(783
)
 
$
695

Other comprehensive income (loss):
 
 
 
 
 
 
 
Foreign currency translation adjustments during the period
81

 
29

 
(91
)
 
3

Pension and other postretirement benefits, net of tax
(6
)
 
(4
)
 
1

 
(8
)
Other comprehensive income (loss)
75

 
25

 
(90
)
 
(5
)
Comprehensive (loss) income
(115
)
 
384

 
(873
)
 
690

Comprehensive loss (income) attributable to noncontrolling interests
2

 
(6
)
 
6

 
(14
)
Comprehensive (loss) income attributable to Baker Hughes
$
(113
)
 
$
378

 
$
(867
)
 
$
676

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.


3


Baker Hughes Incorporated
Consolidated Condensed Balance Sheets
(Unaudited)

(In millions)
June 30,
2015
 
December 31,
2014
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
1,973

 
$
1,740

Accounts receivable - less allowance for doubtful accounts
(2015 - $322; 2014 - $224)
3,684

 
5,418

Inventories, net
3,535

 
4,074

Deferred income taxes
420

 
418

Other current assets
326

 
395

Total current assets
9,938

 
12,045

Property, plant and equipment - less accumulated depreciation
(2015 - $8,629; 2014 - $8,215)
8,366

 
9,063

Goodwill
6,081

 
6,081

Intangible assets, net
759

 
812

Other assets
874

 
826

Total assets
$
26,018

 
$
28,827

LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Accounts payable
$
1,785

 
$
2,807

Short-term debt and current portion of long-term debt
139

 
220

Accrued employee compensation
634

 
782

Income taxes payable
71

 
265

Other accrued liabilities
485

 
563

Total current liabilities
3,114

 
4,637

Long-term debt
3,904

 
3,913

Deferred income taxes and other tax liabilities
410

 
740

Liabilities for pensions and other postretirement benefits
631

 
629

Other liabilities
162

 
178

Commitments and contingencies


 


Equity:
 
 
 
Common stock
436

 
434

Capital in excess of par value
7,155

 
7,062

Retained earnings
10,953

 
11,878

Accumulated other comprehensive loss
(839
)
 
(749
)
Treasury stock
(8
)
 

Baker Hughes stockholders’ equity
17,697

 
18,625

Noncontrolling interests
100

 
105

Total equity
17,797

 
18,730

Total liabilities and equity
$
26,018

 
$
28,827

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

4


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

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

 
$
7,062

 
$
11,878

 
$
(749
)
 
$

 
$
105

 
$
18,730

Comprehensive loss:
 
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 
 
 
 
(777
)
 
 
 
 
 
(6
)
 
(783
)
Other comprehensive loss
 
 
 
 
 
 
(90
)
 
 
 
 
 
(90
)
Activity related to stock plans
2

 
54

 
 
 
 
 
(8
)
 
 
 
48

Stock-based compensation
 
 
63

 
 
 
 
 
 
 
 
 
63

Cash dividends ($0.34 per share)
 
 
 
 
(148
)
 
 
 
 
 
 
 
(148
)
Net activity related to noncontrolling interests
 
 
(24
)
 
 
 
 
 
 
 
1

 
(23
)
Balance at June 30, 2015
$
436

 
$
7,155

 
$
10,953

 
$
(839
)
 
$
(8
)
 
$
100

 
$
17,797


 
Baker Hughes Stockholders' Equity
 
 
 
(In millions, except per share amounts)
Common Stock
 
Capital
in Excess
of
Par Value
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Non-controlling
Interests
 
Total Equity
Balance at December 31, 2013
$
438

 
$
7,341

 
$
10,438

 
$
(504
)
 
$
199

 
$
17,912

Comprehensive income:
 
 
 
 
 
 
 
 
 
 
 
Net income
 
 
 
 
681

 
 
 
14

 
695

Other comprehensive loss
 
 
 
 
 
 
(5
)
 
 
 
(5
)
Activity related to stock plans
3

 
113

 
 
 
 
 
 
 
116

Repurchase and retirement of common stock
(6
)
 
(394
)
 
 
 
 
 
 
 
(400
)
Stock-based compensation
 
 
63

 
 
 
 
 
 
 
63

Cash dividends ($0.30 per share)
 
 
 
 
(131
)
 
 
 
 
 
(131
)
Net activity related to noncontrolling interests
 
 
 
 
 
 
 
 
1

 
1

Balance at June 30, 2014
$
435

 
$
7,123

 
$
10,988

 
$
(509
)
 
$
214

 
$
18,251

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

5


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

 
Six Months Ended June 30,
(In millions)
2015
 
2014
Cash flows from operating activities:
 
 
 
Net (loss) income
$
(783
)
 
$
695

Adjustments to reconcile net (loss) income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
894

 
891

Impairment of assets
265

 

Benefit for deferred income taxes
(366
)
 
(32
)
Provision for doubtful accounts
116

 
43

Other noncash items
(10
)
 
(59
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
1,590

 
(349
)
Inventories
507

 
(192
)
Accounts payable
(1,000
)
 
(31
)
Other operating items, net
(376
)
 
(270
)
Net cash flows provided by operating activities
837

 
696

Cash flows from investing activities:
 
 
 
Expenditures for capital assets
(573
)
 
(863
)
Proceeds from disposal of assets
171

 
203

Other investing items, net
(11
)
 
(26
)
Net cash flows used in investing activities
(413
)
 
(686
)
Cash flows from financing activities:
 
 
 
Net (repayments) proceeds of commercial paper borrowings and other debt with original maturity of three months or less
(7
)
 
190

Repayments of short-term debt with original maturity greater than three months
(180
)
 
(12
)
Proceeds from short-term debt with original maturity greater than three months
123

 

Repurchase of common stock

 
(400
)
Dividends paid
(148
)
 
(131
)
Other financing items, net
25

 
108

Net cash flows used in financing activities
(187
)
 
(245
)
Effect of foreign exchange rate changes on cash and cash equivalents
(4
)
 
(1
)
Increase (decrease) in cash and cash equivalents
233

 
(236
)
Cash and cash equivalents, beginning of period
1,740

 
1,399

Cash and cash equivalents, end of period
$
1,973

 
$
1,163

Supplemental cash flows disclosures:
 
 
 
Income taxes paid, net of refunds
$
306

 
$
360

Interest paid
$
122

 
$
124

Supplemental disclosure of noncash investing activities:
 
 
 
Capital expenditures included in accounts payable
$
100

 
$
119

See accompanying Notes to Unaudited Consolidated Condensed Financial Statements.

6


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Baker Hughes Incorporated (“Baker Hughes,” “Company,” “we,” “our,” or “us,”) is a leading supplier of oilfield services, products, technology and systems used for drilling, formation evaluation, completion and production, pressure pumping, and reservoir development in the worldwide oil and natural gas industry. We also provide products and services for other businesses including downstream chemicals, and process and pipeline services.

Basis of Presentation

Our unaudited consolidated condensed financial statements included herein have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States of America (“U.S.”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial information. Accordingly, certain information and disclosures normally included in our annual financial statements have been condensed or omitted. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2014. We believe the unaudited consolidated condensed financial statements included herein reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. In the Notes to Unaudited Consolidated Condensed Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

New Accounting Standards Updates

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers. The ASU will supersede most of the existing revenue recognition requirements in U.S. GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The pronouncement initially was effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and is to be applied retrospectively, with early application initially not permitted. In July 2015, the FASB decided to defer for one year the effective date of the new revenue standard (ASU 2014-09) for public and non public entities reporting under U.S. GAAP. The FASB also decided to permit entities to early adopt the standard. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU No. 2015-3, Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The pronouncement is effective for annual reporting periods beginning after December 15, 2015. We currently report debt issuance costs consistent with the guidance of this ASU; therefore there will be no impact on our consolidated financial statements and related disclosures upon adoption.

In April 2015, the FASB issued ASU No. 2015-5, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. The ASU provides guidance to customers about whether a cloud computing arrangement includes a software license and the related accounting treatment. The pronouncement is effective for annual reporting periods beginning after December 15, 2015. Adoption of this pronouncement is not expected to have a material impact upon our consolidated financial statements or notes thereto.

NOTE 2. HALLIBURTON MERGER AGREEMENT
On November 16, 2014, Baker Hughes, Halliburton Company (“Halliburton”) and a wholly owned subsidiary of Halliburton (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”), under which

7


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

Halliburton will acquire all of the outstanding shares of Baker Hughes through a merger of Baker Hughes with and into Merger Sub (the "Merger"). Subject to certain specified exceptions, at the effective time of the Merger, each share of Baker Hughes common stock will be converted into the right to receive (i) 1.12 shares of Halliburton common stock and (ii) $19.00 in cash.
On March 27, 2015, Halliburton's stockholders approved the proposal to issue shares of Halliburton common stock as contemplated by the Merger Agreement. In addition, Baker Hughes’ stockholders adopted the Merger Agreement and thereby approved the proposed combination of the two companies. The obligation of the parties to consummate the Merger is still subject to additional customary closing conditions, including: (i) applicable regulatory approvals, including the termination or expiration of the applicable waiting period under the U.S. Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”); (ii) the absence of legal restraints and prohibitions; and (iii) other customary closing conditions. Halliburton is required to take all actions necessary to obtain regulatory approvals (including agreeing to divestitures) unless the assets, businesses or product lines subject to such actions would account for more than $7.5 billion of 2013 revenue.
As mentioned in the paragraph above, under the HSR Act and the rules promulgated thereunder by the Federal Trade Commission (the “FTC”), the Merger cannot be completed until each of Halliburton and Baker Hughes has filed a notification and report form with the FTC and the Antitrust Division of the Department of Justice (the “DOJ”) under the HSR Act and the applicable waiting period has expired or been terminated. Each of Halliburton and Baker Hughes filed an initial notification and report form on December 8, 2014. Halliburton withdrew its filing on January 7, 2015 and refiled on January 9, 2015 in order to provide the FTC and the DOJ with an additional 30-day period to review the filings. On February 9, 2015, the DOJ issued a request for additional information under the HSR Act (the “Second Request”). On July 10, 2015, Halliburton and Baker Hughes entered into a timing agreement with the DOJ pursuant to which both companies agreed to extend the period for the DOJ's review of the Merger to the later of November 25, 2015 or 90 days after both companies have certified substantial compliance with the Second Request. Baker Hughes certified substantial compliance with the Second Request on July 14, 2015, and Halliburton expects to certify substantial compliance with the Second Request by mid-summer of 2015. Halliburton and Baker Hughes are targeting closing the Merger late in 2015. However, the Merger Agreement provides that the closing can be extended into 2016, if necessary. Baker Hughes cannot predict with certainty when, or if, the Merger will be completed because completion of the Merger is subject to conditions beyond the control of Baker Hughes.
Baker Hughes and Halliburton each made customary representations, warranties and covenants in the Merger Agreement, including, among others, covenants by each of Baker Hughes and Halliburton to, subject to certain exceptions, conduct its business in the ordinary course. In particular, among other restrictions and subject to certain exceptions, Baker Hughes agreed to generally refrain from acquiring new businesses, incurring new indebtedness, repurchasing shares, issuing new common stock or equity awards (other than equity awards granted to employees, officers and directors materially consistent with historical long-term incentive awards granted), or entering into new material contracts or commitments outside the normal course of business, without the consent of Halliburton, during the period between the execution of the Merger Agreement and the consummation of the Merger. With respect to equity awards granted after the Merger Agreement to officers and employees, such awards will not vest solely as a result of the Merger but will be converted to an equivalent Halliburton equity award. However, they will vest entirely if an officer or employee is terminated within one year following the closing of the Merger with Halliburton. Baker Hughes and Halliburton are each permitted to pay regular quarterly cash dividends during such period. In addition, under the terms of the Merger Agreement, Halliburton and Baker Hughes have agreed to coordinate the declaration and payment of dividends in respect of each party's common stock including record dates and payment dates relating thereto, which we expect to be in the third month of each quarter. Under the Merger Agreement, we have agreed not to increase the quarterly dividend while the Merger is pending.
In the event the Merger Agreement is terminated by (i) either party as a result of the failure of the Merger to occur on or before the end date (as it may be extended) due to the failure to achieve certain specified antitrust-related approvals when all other closing conditions (other than receipt of antitrust and other specified regulatory approvals and conditions that by their nature cannot be satisfied until the closing but subject to such conditions being capable of being satisfied if the closing date were the date of termination) have been satisfied, (ii) either party as a result of any antitrust-related final, non-appealable order or injunction prohibiting the closing, or (iii) Baker Hughes as a result of Halliburton’s material breach of its obligations to obtain regulatory approval such that the antitrust-related condition to closing is incapable of being satisfied, then, in each case, Halliburton would be

8


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

required to pay Baker Hughes a termination fee of $3.5 billion.
Baker Hughes incurred costs related to the Merger of $83 million and $111 million for the three and six months ended June 30, 2015, respectively, including costs under our retention program and obligations for minimum incentive compensation costs which, based on meeting eligibility criteria in April, have been treated as merger related expenses.

NOTE 3. RESTRUCTURING AND OTHER CHARGES
Beginning in the second half of 2014 and throughout 2015, the oil and natural gas market experienced a significant over supply of capacity leading to a substantial and rapid decline in oil prices resulting in significantly lower activity in 2015. Accordingly, to adjust to the lower level of activity, we assessed our overall operations and have taken actions to restructure and adjust our operations and cost structure to reflect current and expected near-term activity levels. Depending on future market conditions and activity levels, further actions may be necessary to adjust our operations which may result in additional charges.
During the three and six months ended June 30, 2015, we recorded restructuring charges as summarized below:
 
Three Months Ended
 
Six Months Ended
Restructuring Charges
June 30, 2015
 
June 30, 2015
  Workforce reductions
$
61

 
$
308

  Contract terminations
(3
)
 
83

  Impairment of buildings and improvements
5

 
82

  Impairment of machinery and equipment
13

 
176

Total restructuring charges
$
76

 
$
649


Workforce reduction costs: During the first six months of 2015, we initiated workforce reductions that will result in the total elimination of approximately 13,000 positions worldwide. As of June 30, 2015, we have eliminated approximately 11,000 positions. As a result of these workforce reductions, we recorded a charge for severance expense of $308 million, net of a related benefit plan curtailment gain of $9 million for the first six months of 2015. As of June 30, 2015, we have made payments totaling $230 million relating to workforce reductions. We expect that substantially all of the accrued severance remaining of $87 million will be paid in the second half of 2015.
Contract termination costs: During the first six months of 2015, we incurred costs of $83 million for various contracts being terminated, primarily in North America. This includes the accrual for costs to settle leases on closed facilities and certain equipment, and other estimated exit costs, and is net of expected sublease income. We also incurred costs to terminate a take-or-pay supply contract related to the purchase of materials used in our pressure pumping operations in North America, including the write-off of $14 million of prepayments made in 2014. As of June 30, 2015, we have made payments totaling $52 million relating to contract termination costs. We expect that substantially all of the accrued contract termination costs remaining of $17 million will be paid in the second half of 2015.
Impairment of buildings and improvements: We are consolidating facilities and shutting down certain operations and as a result are closing and abandoning or selling certain facilities, both owned and leased. During the first six months of 2015, we recognized $82 million of impairment charges related to facilities primarily in North America and Latin America. For leased facilities, this charge includes the impairment of the leasehold improvements made to those facilities.
Impairment of machinery and equipment: We are exiting or substantially downsizing our presence in select markets primarily in our pressure pumping product line in North America and Latin America. During the first six months of 2015, we recognized $176 million of impairment losses to adjust the carrying value of certain machinery and equipment to its fair value, net of costs to dispose. We are currently in the process of disposing of this machinery and equipment through sale or scrap.

9


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

Other Charges
In addition to the matters described above, during the first six months of 2015, we also recorded charges of $194 million, of which $37 million is reported in cost of sales and $157 million is reported in cost of services, to write-down the carrying value of certain inventory. The write-down, primarily in North America, includes lower of cost or market adjustments due to the significant decline in activity and related prices for our products coupled with declines in replacement costs. In addition, the adjustments include provisions for excess inventory levels based on estimates of current and future market demand. The product lines impacted are primarily pressure pumping and drilling and completion fluids.
NOTE 4. VENEZUELA CURRENCY DEVALUATION

In February of 2015, the Venezuelan government modified the currency exchange system by the creation of a new exchange mechanism, SIMADI, which allows for the trading of the Venezuelan Bolivars Fuertes ("BsF") at a floating rate. On March 31, 2015, we began using the SIMADI exchange rate of approximately 192 BsF per U.S. Dollar to remeasure our BsF denominated assets and liabilities, which resulted in a foreign currency loss of approximately $5 million. This loss was recorded in MG&A expenses in the first quarter of 2015. We believe any further devaluation of Venezuela's currency would not have a material impact on our financial position, results of operations or cash flows.

NOTE 5. SEGMENT INFORMATION

We are a supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas business, referred to as oilfield operations, which are managed through operating segments that are aligned with our geographic regions. We also provide services and products to the downstream chemicals, and process and pipeline industries, referred to as Industrial Services.

The performance of our operating segments is evaluated based on profit (loss) before tax, which is defined as income (loss) before income taxes and before the following: net interest expense, corporate expenses and certain gains and losses, including restructuring charges, not allocated to the operating segments.

Summarized financial information is shown in the following tables:
 
Three Months Ended
 
Three Months Ended
 
June 30, 2015
 
June 30, 2014
Segments
Revenue
 
Profit (Loss) Before Taxes
 
Revenue
 
Profit (Loss) Before Taxes
North America
$
1,498

 
$
(167
)
 
$
2,843

 
$
340

Latin America
439

 
41

 
544

 
46

Europe/Africa/Russia Caspian
869

 
47

 
1,111

 
183

Middle East/Asia Pacific
856

 
51

 
1,104

 
163

Industrial Services
306

 
29

 
333

 
34

Total Operations
3,968

 
1

 
5,935

 
766

Corporate and other

 
(82
)
 

 
(73
)
Interest expense, net

 
(53
)
 

 
(59
)
Restructuring charges

 
(76
)
 

 

Litigation settlements

 
13

 

 
(62
)
Total
$
3,968

 
$
(197
)
 
$
5,935

 
$
572



10


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

 
Six Months Ended
 
Six Months Ended
 
June 30, 2015
 
June 30, 2014
Segments
Revenue
 
Profit (Loss) Before Taxes
 
Revenue
 
Profit (Loss) Before Taxes
North America
$
3,504

 
$
(376
)
 
$
5,619

 
$
598

Latin America
932

 
74

 
1,074

 
101

Europe/Africa/Russia Caspian
1,764

 
27

 
2,155

 
330

Middle East/Asia Pacific
1,772

 
113

 
2,164

 
293

Industrial Services
590

 
39

 
654

 
61

Total Operations
8,562

 
(123
)
 
11,666

 
1,383

Corporate and other

 
(159
)
 

 
(138
)
Interest expense, net

 
(107
)
 

 
(116
)
Restructuring charges

 
(649
)
 

 

Litigation settlements

 
13

 

 
(62
)
Total
$
8,562

 
$
(1,025
)
 
$
11,666

 
$
1,067


NOTE 6. INCOME TAXES

We estimate our annual effective tax rate based on actual year-to-date operating results and our expectation of operating results for the remainder of the year, by jurisdiction, and apply this rate to the actual year-to-date operating results. If our actual operating results, by jurisdiction, differ from the expected operating results, our effective tax rate can change affecting the tax expense for both interim and annual periods.
Total income tax benefit was $7 million and $242 million for the three and six months ended June 30, 2015, respectively. Our effective tax rate on the loss before income taxes for the three and six months ended June 30, 2015 was 3.7% and 23.6%, respectively. The effective tax rate for the three months ended June 30, 2015 is lower than the U.S. statutory income tax rate of 35% primarily due to $99 million of restructuring charges and inventory write-downs with only partial or no tax-benefit in certain jurisdictions, adjustments to prior years' tax positions, loss of certain tax benefits, and a change in the geographical mix of earnings. The total tax benefit associated with the restructuring charges and inventory write-downs for the three and six months ended June 30, 2015 was $28 million and $235 million, respectively.


11


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 7. EARNINGS PER SHARE

A reconciliation of the number of shares used for the basic and diluted (loss) earnings per share (“EPS”) computations is as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Weighted average common shares outstanding for basic EPS
438

 
437

 
438

 
438

Adjustment for effect of dilutive securities - stock plans

 
3

 

 
2

Weighted average common shares outstanding for diluted EPS
438

 
440

 
438

 
440

 
 
 
 
 
 
 
 
Anti-dilutive shares excluded from diluted EPS (1)
2

 

 
2

 

Future potentially dilutive shares excluded from diluted EPS (2)
2

 
2

 
2

 
2


(1) 
The calculation of diluted net loss per share for both the three and six months ended June 30, 2015, excludes shares potentially issuable under stock-based incentive compensation plans and the employee stock purchase plan, as their effect, if included, would have been anti-dilutive.
(2) 
Options where the exercise price exceeds the average market price are excluded from the calculation of diluted net loss or earnings per share because their effect would be anti-dilutive.

NOTE 8. INVENTORIES

Inventories, net of reserves of $353 million at June 30, 2015 and $319 million at December 31, 2014, are comprised of the following:
 
June 30,
2015
 
December 31,
2014
Finished goods
$
3,173

 
$
3,644

Work in process
199

 
227

Raw materials
163

 
203

Total inventories
$
3,535

 
$
4,074


NOTE 9. INTANGIBLE ASSETS

Intangible assets are comprised of the following:
 
June 30, 2015
 
December 31, 2014
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Less:
Accumulated
Amortization
 
Net
Technology
$
874

 
$
422

 
$
452

 
$
870

 
$
393

 
$
477

Customer relationships
487

 
211

 
276

 
488

 
191

 
297

Trade names
120

 
94

 
26

 
120

 
92

 
28

Other
18

 
13

 
5

 
23

 
13

 
10

Total intangible assets
$
1,499

 
$
740

 
$
759

 
$
1,501

 
$
689

 
$
812





12


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

Intangible assets are generally amortized on a straight-line basis with estimated useful lives ranging from 3 to 30 years. Amortization expense included in the net loss for the three and six months ended June 30, 2015 was $25 million and $51 million, respectively, as compared to $27 million and $53 million reported in 2014 for the same periods.

Amortization expense of these intangibles over the remainder of 2015 and for each of the subsequent five fiscal years is expected to be as follows:
Year
Estimated Amortization Expense
Remainder of 2015
$
52

2016
102

2017
98

2018
92

2019
89

2020
78


NOTE 10. 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 June 30, 2015 and December 31, 2014 approximates their carrying value as reflected in our unaudited consolidated condensed balance sheets.

The estimated fair value of total debt at June 30, 2015 and December 31, 2014 was $4,495 million and $4,663 million, respectively, which differs from the carrying amounts of $4,043 million and $4,133 million, respectively, included in our unaudited consolidated condensed balance sheets. The fair value was determined using quoted period-end market prices.

NOTE 11. EMPLOYEE BENEFIT PLANS

We have both funded and unfunded noncontributory defined benefit pension plans ("Pension Benefits") covering certain employees primarily in the U.S., the United Kingdom, Germany and Canada. We also provide certain postretirement health care benefits (“Other Postretirement Benefits”), through an unfunded plan, to a closed group of U.S. employees who, when they retire, have met certain age and service requirements.

The components of net periodic cost (benefit) are as follows for the three months ended June 30:
 
U.S. Pension Benefits
 
Non-U.S. Pension Benefits
 
Other Postretirement Benefits
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
Service cost
$
16

 
$
18

 
$
4

 
$
4

 
$
1

 
$
2

Interest cost
7

 
7

 
8

 
9

 
1

 
1

Expected return on plan assets
(12
)
 
(11
)
 
(12
)
 
(10
)
 

 

Amortization of prior service credit

 

 

 

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

 
2

 
1

 
1

 
1

 

Other

 

 

 

 

 
1

Net periodic cost (benefit)
$
13

 
$
16

 
$
1

 
$
4

 
$

 
$
2



13


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

The components of net periodic cost (benefit) are as follows for the six months ended June 30:
 
U.S. Pension Benefits
 
Non-U.S. Pension Benefits
 
Other Postretirement Benefits
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
Service cost
$
34

 
$
35

 
$
8

 
$
7

 
$
2

 
$
3

Interest cost
14

 
14

 
16

 
18

 
2

 
3

Expected return on plan assets
(25
)
 
(22
)
 
(24
)
 
(20
)
 

 

Amortization of prior service credit

 

 

 

 
(6
)
 
(3
)
Amortization of net actuarial loss
4

 
4

 
2

 
2

 
2

 
1

Curtailment gain

 

 

 

 
(9
)
 

Other

 

 

 

 

 
(3
)
Net periodic cost (benefit)
$
27

 
$
31

 
$
2

 
$
7

 
$
(9
)
 
$
1

NOTE 12. COMMITMENTS AND CONTINGENCIES

LITIGATION
We are subject to a number of lawsuits and claims arising out of the conduct of our business. The ability to predict the ultimate outcome of such matters involves judgments, estimates and inherent uncertainties. We record a liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated, including accruals for self-insured losses which are calculated based on historical claim data, specific loss development factors and other information. A range of total possible losses for all litigation matters cannot be reasonably estimated. Based on a consideration of all relevant facts and circumstances, we do not expect the ultimate outcome of any currently pending lawsuits or claims against us will have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these matters.
We insure against risks arising from our business to the extent deemed prudent by our management and to the extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending or future legal proceedings or other claims. Most of our insurance policies contain deductibles or self-insured retentions in amounts we deem prudent and for which we are responsible for payment. In determining the amount of self-insurance, it is our policy to self-insure those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability, general liability and workers compensation.
The following lawsuits have been filed in Delaware in connection with our pending merger with Halliburton:
On November 24, 2014, Gary Molenda, a purported shareholder of the Company, filed a class action lawsuit in the Court of Chancery of the State of Delaware ("Delaware Chancery Court") against Baker Hughes, the Company’s Board of Directors, Halliburton, and Red Tiger LLC, a wholly owned subsidiary of Halliburton (“Red Tiger” and together with all defendants, “Defendants”) styled Gary R. Molenda v. Baker Hughes, Inc., et al., Case No. 10390-CB.
On November 26, 2014, a second purported shareholder of the Company, Booth Family Trust, filed a substantially similar class action lawsuit in Delaware Chancery Court.
On December 1, 2014, New Jersey Building Laborers Annuity Fund and James Rice, two additional purported shareholders of the Company, filed substantially similar class action lawsuits in Delaware Chancery Court.
On December 10, 2014, a fifth purported shareholder of the Company, Iron Workers Mid-South Pension Fund, filed another substantially similar class action lawsuit in the Delaware Chancery Court.
On December 24, 2014, a sixth purported shareholder of the Company, Annette Shipp, filed another substantially similar class action lawsuit in the Delaware Chancery Court.

14


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

All of the lawsuits make substantially similar claims.  The plaintiffs generally allege that the members of the Company’s Board of Directors breached their fiduciary duties to our shareholders in connection with the merger negotiations by entering into the merger agreement and by approving the merger, and that the Company, Halliburton, and Red Tiger aided and abetted the purported breaches of fiduciary duties.  More specifically, the lawsuits allege that the merger agreement provides inadequate consideration to our shareholders, that the process resulting in the merger agreement was flawed, that the Company’s directors engaged in self-dealing, and that certain provisions of the merger agreement improperly favor Halliburton and Red Tiger, precluding or impeding third parties from submitting potentially superior proposals, among other things.  The lawsuit filed by Annettee Shipp also alleges that our Board of Directors failed to disclose material information concerning the proposed merger in the preliminary registration statement on Form S-4.  On January 7, 2015, James Rice amended his complaint, adding similar allegations regarding the disclosures in the preliminary registration statement on Form S-4.  The lawsuits seek unspecified damages, injunctive relief enjoining the merger, and rescission of the merger agreement, among other relief.  On January 23, 2015, the Delaware lawsuits were consolidated under the caption In re Baker Hughes Inc. Stockholders Litigation, Consolidated C.A. No. 10390-CB (the "Consolidated Case"). Pursuant to the Court’s consolidation order, plaintiffs filed a consolidated complaint on February 4, 2015, which alleges substantially similar claims and seeks substantially similar relief to that raised in the six individual complaints, except that while Baker Hughes is named as a defendant, no claims are asserted against the Company.
On March 18, 2015, the parties reached an agreement in principle to settle the Consolidated Case in exchange for the Company making certain additional disclosures. Those disclosures were contained in a Form 8-K filed with the SEC on March 18, 2015. The settlement remains subject to certain conditions, including consummation of the merger, final documentation, and court approval.
On November 26, 2014, a seventh class action challenging the merger was filed by a purported Company shareholder in the United States District Court for the Southern District of Texas (Houston Division).  The lawsuit, styled Marc Rovner v. Baker Hughes Inc., et al., Cause No. 4:14-cv-03416 ("the Rovner lawsuit"), asserts claims against the Company, most of our current Board of Directors, Halliburton, and Red Tiger.  The lawsuit asserts substantially similar claims and seeks substantially similar relief as that sought in the Delaware lawsuits.  On March 20, 2015, counsel for Mr. Rovner filed a notice of voluntary dismissal, and on March 23, 2015, the Court entered an order dismissing the Rovner lawsuit without prejudice.
On October 9, 2014, our subsidiary filed a Request for Arbitration against a customer before the London Court of International Arbitration, pursuing claims for the non-payment of invoices for goods and services provided in an amount provisionally quantified to exceed $67.9 million. In our Request for Arbitration, we also noted that invoices in an amount exceeding $57 million had been issued to the customer, and would be added to the claim in the event that they became overdue. The due date for payment of all of these invoices has now passed. On November 6, 2014, the customer filed its Response and Counterclaim, denying liability and counterclaiming damages for breach of contract of approximately $182 million. We deny any liability to the customer and intend to pursue our claims against the customer and defend the claims made under the counterclaim. No timetable for the conduct of the arbitration has yet been established.
During 2014, we received customer notifications related to a possible equipment failure in a natural gas storage system in Northern Germany, which includes certain of our products.  We are currently investigating the cause of the possible failure and, if necessary, possible repair and replacement options for our products. Similar products were utilized in other natural gas storage systems for this and other customers.  The customer initiated arbitral proceedings against us on June 19, 2015, under the rules of the German Institute of Arbitration e.V. (DIS).  The customer alleges damages of approximately $170 million plus interest at an annual rate of prime + 5%.  A procedural schedule for the arbitration has not yet been set and it is not possible to predict the likely outcome of the arbitration at this time.  Additionally, at this time, we are not able to predict what products will need to be repaired or replaced and are not able to reasonably estimate the ultimate impact, if any, such repairs or replacements or other damages would have on our financial position, results of operations or cash flows.
We are a defendant in various labor claims including the following matters.
On April 28, 2014, a collective action lawsuit alleging that we failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act ("FLSA") was filed titled Michael Ciamillo, individually, etc., et

15


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

al. vs. Baker Hughes Incorporated in the U.S. District Court for the District of Alaska (“Ciamillo”). During the fourth quarter of 2014, the parties agreed to settle the Ciamillo lawsuit, including certain state law claims, for $5 million. The court granted final approval of that settlement on June 19, 2015.
On December 10, 2013, a class and collective action lawsuit alleging that we failed to pay a nationwide class of workers overtime in compliance with the FLSA and certain state laws was filed titled Lea et al. v. Baker Hughes, Inc. in the U.S. District Court for the Southern District of Texas, Galveston Division ("Lea"). During the second quarter of 2014, the parties agreed to settle the Lea lawsuit, subject to final court approval, and we recorded a charge of $62 million, which included an estimate of the Lea settlement amount and associated costs and an amount for settlement of another wage and hour lawsuit. A portion of this settlement was to be paid on a claims made basis and during the second quarter of 2015, the date passed by which the class members could file a claim under this provision of the settlement agreement. The amount of claims made was less than estimated and accordingly, we reduced the accrual by approximately $13 million, which was recorded as an adjustment of litigation settlements during the second quarter of 2015.
On April 30, 2015, a class and collective action lawsuit alleging that we failed to pay a nationwide class of workers overtime in compliance with the FLSA and North Dakota law was filed titled Williams et al. v. Baker Hughes Oilfield Operations, Inc. in the U.S. District Court for the District of North Dakota.  We are evaluating the background facts and at this time cannot predict the outcome of this lawsuit and are not able to reasonably estimate the potential impact, if any, such outcome would have on our financial position, results of operations or cash flows.
On May 30, 2013, we received a Civil Investigative Demand ("CID") from the U.S. Department of Justice ("DOJ") pursuant to the Antitrust Civil Process Act. The CID seeks documents and information from us for the period from May 29, 2011 through the date of the CID in connection with a DOJ investigation related to pressure pumping services in the U.S. We are working with the DOJ to provide the requested documents and information. We are not able to predict what action, if any, might be taken in the future by the DOJ or other governmental authorities as a result of the investigation.

OTHER

In the normal course of business with customers, vendors and others, we have entered into off-balance sheet arrangements, such as surety bonds for performance, letters of credit and other bank issued guarantees, which totaled approximately $1.2 billion at June 30, 2015. It is not practicable to estimate the fair value of these financial instruments. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our financial position, results of operations or cash flows.


16


Baker Hughes Incorporated
Notes to Unaudited Consolidated Condensed Financial Statements

NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS

The following tables present the changes in accumulated other comprehensive loss, net of tax:
 
Pensions and Other Postretirement Benefits
Foreign Currency Translation Adjustments
Accumulated Other Comprehensive Loss
Balance at December 31, 2014
 
$
(246
)
 
 
$
(503
)
 
 
$
(749
)
 
Other comprehensive income (loss) before reclassifications
 
5

 
 
(91
)
 
 
(86
)
 
Amounts reclassified from accumulated other comprehensive loss
 
(7
)
 
 

 
 
(7
)
 
Deferred taxes
 
3

 
 

 
 
3

 
Balance at June 30, 2015
 
$
(245
)
 
 
$
(594
)
 
 
$
(839
)
 

 
Pensions and Other Postretirement Benefits
Foreign Currency Translation Adjustments
Accumulated Other Comprehensive Loss
Balance at December 31, 2013
 
$
(217
)
 
 
$
(287
)
 
 
$
(504
)
 
Other comprehensive (loss) income before reclassifications
 
(8
)
 
 
3

 
 
(5
)
 
Amounts reclassified from accumulated other comprehensive loss
 
1

 
 

 
 
1

 
Deferred taxes
 
(1
)
 
 

 
 
(1
)
 
Balance at June 30, 2014
 
$
(225
)
 
 
$
(284
)
 
 
$
(509
)
 

The amounts reclassified from accumulated other comprehensive loss during the six months ended June 30, 2015 and 2014 represent the amortization of prior service credit, net actuarial loss, curtailment gain and other which are included in the computation of net periodic cost (benefit). See Note 11. Employee Benefit Plans for additional details. Net periodic cost (benefit) is recorded in cost of sales and services, research and engineering, and marketing, general and administrative expenses.

17


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the unaudited consolidated condensed financial statements and the related notes included in Item 1 thereto, as well as our Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Annual Report”).

EXECUTIVE SUMMARY

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry, referred to as our oilfield operations. We manage our oilfield operations through four geographic segments consisting of North America, Latin America, Europe/Africa/Russia Caspian (“EARC”), and Middle East/Asia Pacific (“MEAP”). Our Industrial Services businesses are reported in a fifth segment. As of June 30, 2015, Baker Hughes had approximately 49,000 employees compared to approximately 62,000 employees as of December 31, 2014.
Within our oilfield operations, the primary driver of our businesses is our customers’ capital and operating expenditures dedicated to oil and natural gas exploration, field development and production. The main products and services provided by oilfield operations fall into one of two categories, Drilling and Evaluation or Completion and Production. This classification is based on the two major phases of constructing an oil and/or natural gas well, the drilling phase and the completion phase, and how our products and services are utilized in each phase. We also provide products and services to the downstream chemicals, and process and pipeline services, referred to as Industrial Services.
Beginning in the second half of 2014 and throughout 2015, the oil and natural gas market experienced a significant over supply of capacity, leading to a substantial and rapid decline in oil and natural gas prices, and subsequently, to significantly lower activity in the first half of 2015. The decline in activity has occurred throughout the world but most notably in North America where the rig count has declined 38% in the first six months of 2015 compared to the same period in 2014. As a result of these changes in market conditions and the significant decrease in activity and customer spending, we have experienced a decline in demand for our products and services.

Financial Results

For the second quarter of 2015, we generated revenue of $3.97 billion, a decrease of $1.97 billion, or 33%, compared to the second quarter of 2014, outperforming the 36% drop in the worldwide rig count. In the first six months of 2015, revenue totaled $8.56 billion, a decline of $3.10 billion, or 27%, compared to the same period in the prior year, in line with the 27% drop in the worldwide rig count over the same time frame. All segments experienced revenue declines in the second quarter and the first six months of 2015 due primarily to the rapidly declining market conditions. These conditions resulted in reduced activity, an over supply of equipment and an unfavorable pricing environment. Revenue was also negatively impacted, by an unfavorable change in exchange rates of several currencies relative to the U.S. Dollar, predominately in the EARC segment. North America, driven by the drop in the North America onshore rig count, was the largest contributor to the year over year revenue decline.

Net loss attributable to Baker Hughes was $188 million and $777 million for the second quarter and first six months of 2015, respectively, compared to net income attributable to Baker Hughes of $353 million and $681 million for the second quarter and first six months of 2014, respectively. Loss before tax was $197 million and $1.03 billion for the second quarter and first six months of 2015, respectively, compared to income before tax of $572 million and $1.07 billion for the second quarter and first six months of 2014, respectively.

Even though the severity of the revenue decline has compressed our margins, we have lessened the impact over the first half of 2015 by taking actions to reduce costs and adjust our operations and cost structure to reflect current and expected near-term activity levels. These restructuring activities included workforce reductions, contract terminations, facility closures and the removal of excess machinery and equipment which resulted in asset impairments. As a result of these restructuring activities, in the first quarter of 2015, we recorded charges totaling

18


$573 million. In the second quarter of 2015, we recorded additional restructuring charges of $76 million related primarily to workforce reductions. These charges have been excluded from the results of our operating segments. Additionally, we incurred costs of $171 million and $23 million in the first and second quarters of 2015, respectively, to write-down the carrying value of certain inventory. These amounts are included in the results of our operating segments.
Halliburton Merger Agreement
On November 16, 2014, Baker Hughes and Halliburton Company (“Halliburton”) entered into a definitive agreement and plan of merger (the "Merger Agreement") under which Halliburton will acquire all of the outstanding shares of Baker Hughes in a stock and cash transaction, referred to as the "Merger". Under the terms of the agreement and subject to certain specified exceptions, at the effective time of the merger, each share of common stock of Baker Hughes will be converted into the right to receive 1.12 Halliburton shares plus $19.00 in cash. On March 27, 2015, Halliburton's stockholders approved the proposal to issue shares of Halliburton common stock as contemplated by the Merger Agreement. In addition, Baker Hughes’ stockholders adopted the Merger Agreement and thereby approved the proposed combination of the two companies. The transaction is still subject to regulatory approvals and customary closing conditions. Halliburton and Baker Hughes are targeting closing the Merger late in 2015. However, the Merger Agreement provides that the closing can be extended into 2016, if necessary. Baker Hughes cannot predict with certainty when, or if, the Merger will be completed because completion of the Merger is subject to conditions beyond the control of Baker Hughes.For further information about the Merger, see Note 2. “Halliburton Merger Agreement” of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 herein.
Outlook
Our industry is cyclical, and past cycles have been driven primarily by alternating periods of ample supply or shortages 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.
Since 2014, the oil market has experienced an excess of supply as a result of sustained high output from tight oil plays in North America, a slowdown in demand from key consumer regions such as Europe and East Asia and the Organization of the Petroleum Exporting Countries (“OPEC”) position since late November to not cut production. This market imbalance resulted in a rapid decline in oil prices, with both Brent and West Texas Intermediate prices dropping to near six-year lows in mid March of 2015 and 60% below 2014 peak highs, which ultimately led to a significant decrease in activity and customer spending.
In North America, in response to lower oil prices, activity levels began to decline in late December 2014 and as of June 30, 2015, the U.S. rig count had fallen approximately 930 rigs, or 51%, compared to the 2014 year-end rig count; and the Canadian rig count had fallen by more than 158 rigs, or 62%, over the same periods. During the second quarter of 2015, the North American rig count decline began to slow.
For the remainder of the year, we expect unfavorable market conditions to continue across all segments. North America rig counts are anticipated to remain relatively unchanged. Seasonal increases in activity in Canada is expected to be fully offset by lower activity levels in the U.S. onshore and an unfavorable mix of activity in the Gulf of Mexico. In Latin America, we project the rig count to continue to decline, albeit, at a slower pace. In Europe/Africa/Russia Caspian, the rig count is also expected to decline across most of the region, primarily in onshore and shallow water markets. For Middle East/Asia Pacific, we anticipate the rig count to remain relatively stable as any rig count growth in the Middle East will likely to be offset by rig count declines in Asia Pacific.
The near term outlook for our industry remains uncertain. The International Energy Agency (“IEA”) indicates in their June 2015 report that although oil-directed rigs have decreased precipitously since their October 2014 highs and capital expenditure cuts are taking hold, oil production in the U.S. shows no signs of slowing down. Nonetheless, the IEA expects U.S. production growth to begin declining in the second half of 2015.

19


Technology will continue to be a critical differentiator for oilfield service providers in this new environment, as our customers’ need for innovative solutions is more important than ever before. As such, we remain committed to our strategy of focusing on technology development to deliver innovative new products and services which are designed to solve our customers’ challenges of efficient well construction, optimized well production, and increased ultimate recovery. The current market conditions notwithstanding, the long term outlook for our industry remains strong. The world’s demand for energy will continue to rise, and the supply of energy will continue to increase in complexity, requiring greater service intensity and more advanced technology from oilfield service companies.

BUSINESS ENVIRONMENT
We operate in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. Our revenue is predominately generated from the sale of products and services to major, national, and independent oil and natural gas companies worldwide, and is dependent on spending by our customers for oil and natural gas exploration, field development and production. This spending is dependent on a number of factors, including our customers’ forecasts of future energy demand and supply, their access to resources to develop and produce oil and natural gas, their ability to fund their capital programs, the impact of new government regulations and most importantly, their expectations for oil and natural gas prices as a key driver of their cash flows.

Oil and Natural Gas Prices

Oil and natural gas prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Brent oil price ($/Bbl) (1)
$
62.06

 
$
109.77

 
$
58.04

 
$
108.85

WTI oil price ($/Bbl) (2)
57.85

 
103.11

 
53.25

 
100.88

Natural gas price ($/mmBtu) (3)
2.73

 
4.59

 
2.80

 
4.86


(1) 
Bloomberg Dated Brent (“Brent”) Oil Spot Price per Barrel
(2) 
Bloomberg West Texas Intermediate (“WTI”) Cushing Crude Oil Spot Price per Barrel
(3) 
Bloomberg Henry Hub Natural Gas Spot Price per million British Thermal Unit
In North America, customer spending is highly driven by WTI oil prices, which fluctuated widely during the second quarter of 2015, starting from a low of $49.14/Bbl at the beginning of the quarter to a high of $61.43/Bbl in early June 2015 as stronger oil prices were supported by higher than expected withdrawals from U.S. crude stockpiles and an increase in global oil demand. This rise in price abated towards the end of the quarter as a result of an increase in the growth forecast of crude oil production, Iran's renewed efforts to reach a nuclear deal including the ability to freely resume its crude exports, signs of OPEC output at three-year highs, and concerns of a potential negative impact from Greece's debt crisis.
Outside North America, customer spending is most heavily influenced by Brent oil prices, which, similar to WTI prices, fluctuated throughout the quarter, increasing from a low of $54.23/Bbl at the start of the quarter to a high of $66.37/Bbl in early May 2015 with stronger oil prices supported by the same factors as WTI, along with rising tensions in the Middle East and new protests in Libya threatening oil exports. Oil prices in early May were also supported by news that Saudi Arabia had raised its official selling prices for its Arab Light grade crude to the U.S. and Northwest Europe, pointing to strong demand in those regions.
Overall, Brent and WTI oil prices in the second quarter of 2015 averaged 44% lower than the prior year, stemming from heightened concerns of a long term global oversupply imbalance as U.S. production has proven to be more resilient than expected to the impact of reduced drilling activity.

20


In North America, natural gas prices, as measured by the Henry Hub Natural Gas Spot Price, averaged $2.73/mmBtu in the second quarter of 2015. Compared to the prior year, natural gas prices have decreased 41% driven by lower demand for natural gas as a result of milder than usual weather during the winter and summer months. According to the U.S. Department of Energy (“DOE”), working natural gas in storage at the end of the second quarter of 2015 was 2,577 Bcf, which is 1% higher than the previous five-year (2010-2014) average, and 34%, or 648 Bcf, above the corresponding week in 2014 when natural gas storage levels were below the five year average after a very cold winter.

Baker Hughes Rig Count
The Baker Hughes rig counts are an important business barometer for the drilling industry and its suppliers. When drilling rigs are active they consume products and services produced by the oil service industry. Rig count trends are governed by the exploration and development spending by oil and gas companies, which in turn is influenced by current and future price expectations for oil and natural gas. Therefore, the counts may reflect the relative strength and stability of energy prices and overall market activity. However, these counts should not be solely relied on as other specific and pervasive conditions may exist that affect overall energy prices and market activity.
Baker Hughes has been providing rig counts to the public since 1944. We gather all relevant data through our field service personnel, who obtain the necessary data from routine visits to the various rigs, customers, contractors and/or other outside sources. We base the classification of a well as either oil or natural gas primarily upon filings made by operators in the relevant jurisdiction. This data is then compiled and distributed to various wire services and trade associations and is published on our website. We believe the counting process and resulting data is reliable; however, it is subject to our ability to obtain accurate and timely information. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian region, Iran and onshore China because this information is not readily available.
Rigs in the U.S. and Canada are counted as active if, on the day the count is taken, the well being drilled has been started but drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential consumer of our drill bits. In international areas, rigs are counted on a weekly basis and deemed active if drilling activities occurred during the majority of the week. The weekly results are then averaged for the month and published accordingly. The rig count does not include rigs that are in transit from one location to another, rigging up, being used in non-drilling activities including production testing, completion and workover, and are not expected to be significant consumers of drill bits.

The rig counts are summarized in the table below as averages for each of the periods indicated.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2015
2014
% Change
2015
2014
% Change
U.S. - land and inland waters
876

1,796

(51
%)
1,115

1,760

(37
%)
U.S. - offshore
31

56

(45
%)
40

56

(29
%)
Canada
98

199

(51
%)
206

362

(43
%)
North America
1,005

2,051

(51
%)
1,361

2,178

(38
%)
Latin America
322

402

(20
%)
337

402

(16
%)
North Sea
38

44

(14
%)
41

41

%
Continental Europe
78

105

(26
%)
83

101

(18
%)
Africa
108

133

(19
%)
119

137

(13
%)
Middle East
403

415

(3
%)
408

408

%
Asia Pacific
220

249

(12
%)
228

253

(10
%)
Outside North America
1,169

1,348

(13
%)
1,216

1,342

(9
%)
Worldwide
2,174

3,399

(36
%)
2,577

3,520

(27
%)


21


The rig count in North America decreased 51% in the second quarter of 2015 compared to the same period a year ago, as a consequence of reduced spending from our customers as they adapt to a lower oil price environment. During the second quarter of 2015, the U.S. rig count continued to decline, albeit at a slower pace, as drilling activity levels began to indicate signs of stabilization towards the end of the quarter. The reduction in North America rig activity is mainly attributable to oil-directed drilling, which experienced a 56% decline in rig counts as the steep drop in oil prices over the last year resulted in a reduction in exploration and production spending. The natural gas-directed rig count experienced a 32% decrease compared to the same period a year ago. In the U.S., natural gas prices remain below levels that are considered to be economic for new investments in many natural gas fields. In Canada, the reduction in the natural gas-directed rig count was primarily related to lower drilling activity levels in condensate rich zones in Alberta to service oil sands.

Outside North America, the rig count in the second quarter of 2015 decreased 13% compared to the same period a year ago. In Latin America, the rig count declined 20% as a consequence of reduced drilling activity, primarily in Mexico, Colombia, Venezuela and Ecuador. In Europe, the rig count in the North Sea decreased 14%, primarily due to a reduction in offshore drilling activity in the United Kingdom and the Netherlands, while in Continental Europe the rig count declined by 26% driven by lower onshore drilling activity primarily in Turkey and Albania. In Africa, the rig count decreased 19% primarily due to reduced onshore drilling activity in Chad, Libya and Nigeria, and lower offshore drilling activity in Angola; partially offset by an increase in onshore drilling in Algeria. The rig count decreased 3% in the Middle East due to lower drilling activity in Iraq and Egypt, partially offset by higher rig activity in Saudi Arabia, Kuwait, Oman and Abu Dhabi. In Asia Pacific, the rig count declined 12% as a result of reduced drilling activity in India, Australia, New Zealand and Papua New Guinea, partially offset by increased drilling activity in offshore Malaysia, and onshore drilling activity in Thailand and the Philippines.

RESULTS OF OPERATIONS

The discussions below relating to significant line items from our unaudited consolidated condensed statements of income (loss) are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where reasonably practicable, have quantified the impact of such items. In addition, the discussions below for revenue and cost of revenue are on a total basis as the business drivers for product sales and services are similar. All dollar amounts in tabulations in this section are in millions of dollars, unless otherwise stated.

Revenue and Profit (Loss) Before Tax

Revenue and profit (loss) before tax for each of our five operating segments is provided below. The performance of our operating segments is evaluated based on profit (loss) before tax, which is defined as income (loss) before income taxes and before the following: net interest expense, corporate expenses, restructuring charges and certain gains and losses not allocated to the operating segments.

 
Three Months Ended June 30,
 
$
Change
 
%
Change
 
Six Months Ended June 30,
 
$
Change
 
%
Change
 
2015
 
2014
 
 
2015
 
2014
 
Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North America
$
1,498

 
$
2,843

 
$
(1,345
)
 
(47
%)
 
$
3,504

 
$
5,619

 
$
(2,115
)
 
(38
%)
Latin America
439

 
544

 
(105
)
 
(19
%)
 
932

 
1,074

 
(142
)
 
(13
%)
Europe/Africa/Russia Caspian
869

 
1,111

 
(242
)
 
(22
%)
 
1,764

 
2,155

 
(391
)
 
(18
%)
Middle East/Asia Pacific
856

 
1,104

 
(248
)
 
(22
%)
 
1,772

 
2,164

 
(392
)
 
(18
%)
Industrial Services
306

 
333

 
(27
)
 
(8
%)
 
590

 
654

 
(64
)
 
(10
%)
Total
$
3,968

 
$
5,935

 
$
(1,967
)
 
(33
%)
 
$
8,562

 
$
11,666

 
$
(3,104
)
 
(27
%)


22


 
Three Months Ended June 30,
 
$
Change
 
%
Change
 
Six Months Ended June 30,
 
$
Change
 
%
Change
 
2015
 
2014
 
 
2015
 
2014
 
Profit (Loss) Before Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North America
$
(167
)
 
$
340

 
$
(507
)
 
(149
%)
 
$
(376
)
 
$
598

 
$
(974
)
 
(163
%)
Latin America
41

 
46

 
(5
)
 
(11
%)
 
74

 
101

 
(27
)
 
(27
%)
Europe/Africa/Russia Caspian
47

 
183

 
(136
)
 
(74
%)
 
27

 
330

 
(303
)
 
(92
%)
Middle East/Asia Pacific
51

 
163

 
(112
)
 
(69
%)
 
113

 
293

 
(180
)
 
(61
%)
Industrial Services
29

 
34

 
(5
)
 
(15
%)
 
39

 
61

 
(22
)
 
(36
%)
Total Operations
1

 
766

 
(765
)
 
(100
%)
 
(123
)
 
1,383

 
(1,506
)
 
(109
%)
Corporate and other
(82
)
 
(73
)
 
(9
)
 
12
%
 
(159
)
 
(138
)
 
(21
)
 
15
%
Interest expense, net
(53
)
 
(59
)
 
6

 
(10
%)
 
(107
)
 
(116
)
 
9

 
(8
%)
Restructuring charges
(76
)
 

 
(76
)
 
N/M

 
(649
)
 

 
(649
)
 
N/M

Litigation settlements
13

 
(62
)
 
75

 
(121
%)
 
13

 
(62
)
 
75

 
(121
%)
Total
$
(197
)
 
$
572

 
$
(769
)
 
(134
%)
 
$
(1,025
)
 
$
1,067

 
$
(2,092
)
 
(196
%)

“N/M” represents not meaningful.

Second Quarter of 2015 Compared to the Second Quarter of 2014

North America

North America revenue decreased $1.35 billion, or 47%, in the second quarter of 2015 compared to the second quarter of 2014. The drop in revenue is primarily attributable to the reduction in customer spending, which has resulted in a steep decline in onshore and shallow water activity and an unfavorable pricing environment. Compared to the same period last year, the average U.S. and Canadian rig counts are down 51%. In the Gulf of Mexico, deepwater operations were more resilient as a result of a favorable mix of completions activity.

North America loss before tax was $167 million in the second quarter of 2015 compared to profit before tax of $340 million in the second quarter of 2014. Margins were negatively impacted by the sharp reduction in activity and an increasingly unfavorable pricing environment. Actions were taken in the first and second quarters of 2015 to reduce our workforce, close and consolidate facilities and improve commercial terms with vendors, resulting in lower cost of goods sold. Despite these actions to restructure our North American operations to operate in a lower activity environment, the speed of the revenue decline outpaced the benefits of cost saving initiatives.

Latin America

Latin America revenue decreased $105 million, or 19%, in the second quarter of 2015 compared to the second quarter of 2014. Revenue declined largely as a result of sharp activity reductions in the Andean area, as reflected in a 43% drop in the rig count, and in Venezuela from decreased operations and unfavorable exchange rates. In Brazil and Mexico, share gains in offshore activity more than offset other activity reductions.

Latin America profit before tax was $41 million in the second quarter of 2015, a decrease of $5 million compared to the second quarter of 2014. The impact on margins as a result of lower revenue was more than offset by improvements made to the operating cost structure.

Europe/Africa/Russia Caspian

EARC revenue decreased $242 million, or 22%, in the second quarter of 2015 compared to the second quarter of 2014. The decrease can be attributed predominately to the unfavorable change in exchange rates of several currencies across the region relative to the U.S. Dollar, which resulted in a reduction in revenue of approximately $100 million. Activity reductions, unfavorable pricing, and the deconsolidation of a joint venture in North Africa late

23


last year also contributed to the decline. These reductions were slightly offset by share gains in parts of Africa and Europe.

EARC profit before tax was $47 million in the second quarter of 2015 compared to $183 million in the second quarter of 2014. The unfavorable change in exchange rates reduced profitability for the quarter by approximately $54 million. Lower activity levels, pricing deterioration, and unfavorable product mix also impacted margins. Workforce reductions and other cost saving actions partially offset these unfavorable market conditions.

Middle East/Asia Pacific

MEAP revenue decreased $248 million, or 22%, in the second quarter of 2015 compared to the second quarter of 2014. The decline in revenue was driven primarily by lower activity throughout Asia Pacific, as reflected in the 12% drop in the rig count, and in Iraq as a result of a reduction of our integrated operations, including exiting a large turnkey contract in mid-2014. Revenue was also impacted by unfavorable pricing in certain markets across the region.

MEAP profit before tax was $51 million, a decrease of $112 million, or 69%, in the second quarter of 2015 compared to the second quarter of 2014. The reduction in margins was attributed mainly to lower activity levels, an increase in price concessions and mobilization costs in the quarter for new activity in the Middle East. The reduction in margins was slightly offset by improved profitability in Iraq and the benefit of the recent cost-cutting actions.

Industrial Services

For Industrial Services, revenue decreased $27 million and profit before tax decreased $5 million in the second quarter of 2015 compared to the second quarter of 2014. The decrease in revenue was attributed to reduced customer spending across all the industrial businesses, but most notably in process and pipeline services. Revenue was further impacted by the unfavorable change in foreign exchange rates. These reductions were partially offset by the acquisition of a new specialty pipeline services business in the third quarter of 2014. The reduction in profitability associated with lower activity levels was almost entirely offset by savings from recent cost reduction measures.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Revenue for the six months ended June 30, 2015 decreased $3.10 billion, or 27%, compared to the six months ended June 30, 2014. Revenue decreased in all segments, with the steepest drop seen in North America where the average rig count declined 38% for the first half of 2015 compared to the same period a year ago. Reduced activity, unfavorable pricing and foreign exchange rates negatively impacted our revenue from foreign operations.

Loss before tax for the six months ended June 30, 2015 was $1.03 billion, compared to profit before tax of $1.07 billion for the same period a year ago. In North America, margins were negatively impacted by the sharp reduction in activity and an increasingly unfavorable pricing environment. In Latin America, margins remained relatively flat in 2015 compared to 2014 as improvements in our operating cost structure offset the impact of declines in revenue. Profits in our EARC and MEAP segments were negatively impacted by lower activity levels and pricing deterioration. In addition, in EARC the unfavorable change in exchange rates reduced profitability. Actions taken across all segments to reduce our workforce, close and consolidate facilities and improve commercial terms with vendors partially offset these unfavorable market conditions.

During the first six months of 2015, we recorded $649 million of restructuring charges, $194 million in charges to write down the carrying value of certain inventory, $116 million in additional allowance for doubtful accounts, and $111 million of merger related expenses. In comparison, profit before tax for the first six months of 2014 included $29 million of severance costs and $29 million of costs associated with a technology royalty agreement.


24


Costs and Expenses

The table below details certain unaudited consolidated condensed statement of income data and as a percentage of revenue.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
$
 
%
 
$
 
%
 
$
 
%
 
$
 
%
Revenue
$
3,968

 
100
%
 
$
5,935

 
100
%
 
$
8,562

 
100
%
 
$
11,666

 
100
%
Cost of revenue
3,615

 
91
%
 
4,745

 
80
%
 
7,957

 
93
%
 
9,465

 
81
%
Research and engineering
124

 
3
%
 
159

 
3
%
 
262

 
3
%
 
302

 
3
%
Marketing, general and administrative
310

 
8
%
 
338

 
6
%
 
625

 
7
%
 
654

 
6
%

Cost of Revenue

Cost of revenue as a percentage of revenue was 91% and 93% for the three and six months ended June 30, 2015, respectively, and 80% and 81% for the three and six months ended June 30, 2014, respectively. Despite actions to restructure our global operations to operate in a lower activity environment, the speed of the revenue decline outpaced the benefit of cost saving measures. Additionally, the product lines most significantly impacted by the downturn in rig activity are also the most capital-intensive. Accordingly, the fixed costs associated with those product lines lessened the positive impact of our cost reduction efforts in the first and second quarters of 2015. Cost of revenue for the first six months of 2015 was also negatively impacted by $116 million to increase the allowance for doubtful accounts, a charge of $194 million (of which $23 million was recorded in the second quarter of 2015), to adjust the carrying value of certain inventory, and $31 million of expenses related to the Merger.

Research and Engineering

Research and engineering expenses declined by $35 million and $40 million for the three and six months ended June 30, 2015, respectively, compared to the prior year, yet remained relatively flat as a percentage of revenue. The reduction in research and engineering expense was driven by recent cost reduction measures, partially offset by $6 million of expenses related to the Merger, which was recorded in the second quarter of 2015.

Marketing, General and Administrative

Marketing, general and administrative (“MG&A”) expenses declined by $28 million and $29 million for the three and six months ended June 30, 2015, respectively, compared to the same period a year ago. Included in MG&A expenses for the three and six months ended June 30, 2015, are costs of $46 million and $74 million, respectively, related to the Merger, which were more than offset by our recent cost reduction measures.

Restructuring Charges

During the three months ended June 30, 2015, we recorded an additional restructuring charge of $76 million, bringing our year-to-date total restructuring charge to $649 million. The charge in the second quarter of 2015 was primarily related to additional workforce reductions. The year-to-date restructuring charge consists of $308 million for workforce reduction costs, $83 million for contract termination costs and $258 million for asset impairments related to excess machinery and equipment and facilities. Total cash paid during the six months ended June 30, 2015 related to these charges was $282 million. We expect that substantially all of the remaining accrued severance and contract termination costs of $104 million will be paid by the end of 2015. For further discussion of these restructuring charges, see Note 3. “Restructuring and Other Charges” of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 of Part 1 herein.

The reduction in costs from eliminating depreciation and reduced employee expenses in the three months and six months ended June 30, 2015 is approximately $173 million and $201 million, respectively, and is expected to be approximately $452 million for the remainder of 2015 and more than $900 million on an annualized basis.

25


Litigation Settlements

During the second quarter of 2014, we recorded a charge of $62 million related to litigation settlements for wage and hour lawsuits. A portion of this settlement was to be paid on a claims made basis and during the second quarter of 2015, the date passed by which the class members could file a claim under this provision of the settlement agreement. The amount of claims made was less than estimated and accordingly, we reduced the accrual by approximately $13 million, which was recorded as an adjustment for litigation settlements during the second quarter of 2015. For further discussion, see Note 12. “Commitments and Contingencies - Litigation” in the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 herein.

Income Taxes

Total income tax benefit was $7 million and $242 million for the three and six months ended June 30, 2015, respectively. Our effective tax rate on income before income taxes for the three and six months ended June 30, 2015 was 3.7% and 23.6%, respectively. The effective tax rate for the three months ended June 30, 2015 is lower than the U.S. statutory income tax rate of 35% primarily due to $99 million of restructuring charges and inventory write-downs with only partial or no tax-benefit in certain jurisdictions, adjustments to prior years’ tax positions, loss of certain tax benefits, and a change in our geographical mix of earnings. The total tax benefit associated with the restructuring and inventory write-downs for the three and six months ended June 30, 2015 was $28 million and $235 million, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain sufficient liquidity, adequate financial resources and financial flexibility in order to fund the requirements of our business. At June 30, 2015, we had cash and cash equivalents of $1.97 billion, of which approximately $1.60 billion was held by foreign subsidiaries. This compares to $1.74 billion of cash and cash equivalents held at December 31, 2014, of which approximately $1.31 billion was held by foreign affiliates. A substantial portion of the cash held by foreign subsidiaries at June 30, 2015 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 tax credits. We have a committed revolving credit facility (“credit facility”) with commercial banks and a related commercial paper program under which the maximum combined borrowing at any time under both the credit facility and the commercial paper program is $2.50 billion. At June 30, 2015, we had no commercial paper outstanding; therefore, the amount available for borrowing under the credit facility as of June 30, 2015 was $2.50 billion. We believe that cash on hand, cash flows generated from operations and the available credit facility, including the issuance of commercial paper, will provide sufficient liquidity to manage our global cash needs. In the six months ended June 30, 2015, we used cash to fund a variety of activities including certain working capital needs and restructuring costs, capital expenditures, and the payment of dividends.

Cash Flows

Cash flows provided by (used in) each type of activity were as follows for the six months ended June 30:
(In millions)
2015
 
2014
Operating activities
$
837

 
$
696

Investing activities
(413
)
 
(686
)
Financing activities
(187
)
 
(245
)

Operating Activities

Cash flows from operating activities provided cash of $837 million in the six months ended June 30, 2015. Our primary components of working capital (receivables, inventories, accounts payable) declined due to lower activity in the six months ended June 30, 2015, resulting in a net increase in operating cash flows of $1.10 billion. This

26


increase was partially offset by $282 million of payments made for employee severance and contract termination costs as a result of our restructuring activities initiated in 2015.

Investing Activities

Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the appropriate levels and types of machinery and equipment in place to generate revenue from operations. Expenditures for capital assets totaled $573 million in the six months ended June 30, 2015. The majority of these expenditures were for machinery and equipment.

Proceeds from the disposal of assets were $171 million in the six months ended June 30, 2015, which related primarily to equipment that was lost-in-hole, and to a lesser extent, property, machinery and equipment no longer used in operations that was sold throughout the period.

Financing Activities

We had net repayments of short-term debt and other borrowings of $64 million in the six months ended June 30, 2015. Total debt outstanding at June 30, 2015 was $4.04 billion, a decrease of $90 million compared to December 31, 2014. The total debt-to-capital (defined as total debt plus equity) ratio was 0.19 at June 30, 2015 and December 31, 2014. We paid dividends of $148 million in the six months ended June 30, 2015.

Our Board of Directors has previously authorized a program to repurchase our common stock from time to time. In the six months ended June 30, 2015, we did not repurchase any shares of common stock. We had authorization remaining to repurchase approximately $1.05 billion in common stock at June 30, 2015. During the six months ended June 30, 2014, we repurchased 6.2 million shares of our common stock at an average price of $64.30 per share, for a total of $400 million.

Under the merger agreement with Halliburton, as described in Note 2. "Halliburton Merger Agreement" of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 of Part I herein, we have generally agreed not to repurchase any shares of our common stock while the merger is pending.

Available Credit Facility

We have a committed revolving credit facility with commercial banks and a related commercial paper program under which the maximum combined borrowing at any time under both the credit facility and the commercial paper program is $2.50 billion. The credit facility matures in September 2016 and contains certain covenants which, among other things, restrict certain merger transactions or the sale of all or substantially all of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the credit facility may be accelerated. Such events of default include payment defaults to lenders under the credit facility, covenant defaults and other customary defaults. We were in compliance with all of the credit facility’s covenants, and there were no direct borrowings under the credit facility during the quarter ended June 30, 2015. Under the commercial paper program, we may issue from time to time up to $2.50 billion in commercial paper with maturity of no more than 270 days. The amount available to borrow under the credit facility is reduced by the amount of any commercial paper outstanding. At June 30, 2015, we had no outstanding borrowings under the commercial paper program.

If market conditions were to change and our revenue was reduced significantly or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. There are no ratings triggers that would accelerate the maturity of any borrowings under our committed credit facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the credit facility.

We believe our current credit ratings would allow us to obtain interim financing over and above our existing credit facility for any currently unforeseen significant needs.


27


Cash Requirements

In 2015, we believe cash on hand, cash flows from operating activities and the available credit facility will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures and dividends, and support the development of our short-term and long-term operating strategies. If necessary, we may issue commercial paper or other short-term debt to fund cash needs in the U.S. in excess of the cash generated in the U.S.

In 2015, we expect our capital expenditures to be approximately $1.10 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 and managed by us to match market demand and activity levels.

We anticipate making income tax payments of between $450 million and $550 million in 2015.

During the six months ended June 30, 2015, we contributed approximately $170 million to our defined benefit, defined contribution and other postretirement plans. We expect to make additional contributions in the range of $130 million to $145 million to these plans for the remainder of 2015.

We anticipate paying dividends of between $295 million and $305 million in 2015. Under the merger agreement with Halliburton, as described in Note 2. "Halliburton Merger Agreement" of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 of Part I herein, we have agreed not to increase the quarterly dividend while the merger is pending.

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, including the pending merger with Halliburton. 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, tax rates, strategies for our operations, 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 2014 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 (“EDGAR”) system at http://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the six months ended June 30, 2015, does not differ materially from that discussed under Part II, Item 7(a), “Quantitative and Qualitative Disclosures About Market Risk,” in our 2014 Annual Report on Form 10-K.


28


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 June 30, 2015, 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 June 30, 2015 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.


29


PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See discussion of legal proceedings in Note 12 of the Notes to Unaudited Consolidated Condensed Financial Statements in this Quarterly Report, Item 3 of Part I of our 2014 Annual Report and Note 13 of the Notes to Consolidated Financial Statements included in Item 8 of our 2014 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 2014 Annual Report, as well as the following risk factor:

Our restructuring activities may not achieve the results we expect and could change, which could materially and adversely affect our results of operations and financial condition.

In the first quarter of 2015, we announced and began to implement restructuring activities to reduce expenses, which included a reduction in our workforce, the termination of various contracts, the closing or abandoning of certain facilities, and the downsizing of our presence in select markets. There can be no assurance that our restructuring activities will produce the cost savings we anticipate in the expected timeframe or that the cumulative restructuring charge will not have to increase in order to achieve our cost savings targets. Any delay or failure to achieve the expected cost savings and any increase in our anticipated cumulative restructuring charge would likely cause our future earnings to be lower than anticipated.

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 June 30, 2015.
Period
Total Number of Shares Purchased (1)
 
Average Price Paid Per Share
 
Total Number of Shares Purchased as Part of a Publicly Announced Program (2)
 
Maximum Number
(or Approximate Dollar Value)
of Shares that May Yet Be
Purchased Under the Program (3)
April 1-30, 2015
13,864

 
$
68.07

 
 
$
1,049,832,435

May 1-31, 2015
15,323

 
$
64.45

 
 
$
1,049,832,435

June 1-30, 2015

 
$

 
 
$
1,049,832,435

Total
29,187

 
$
66.17

 
 



(1) 
Represents shares purchased from employees to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.
(2) 
There were no repurchases during the second quarter of 2015 under our previously announced purchase program.
(3) 
Under the merger agreement with Halliburton, as described in Note 2. "Halliburton Merger Agreement" of the Notes to Unaudited Consolidated Condensed Financial Statements in Item 1 of Part I herein, we have generally agreed not to repurchase any shares of our common stock while the merger is pending.

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

30


Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Quarterly Report.

ITEM 5. OTHER INFORMATION

None.
ITEM 6. EXHIBITS

Each exhibit identified below is filed as a part of this report. Exhibits designated with an “*” are filed as an exhibit to this Quarterly Report on Form 10-Q. Exhibits designated with a “+” are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference.

21.1*
 
Subsidiaries of Registrant
31.1*
 
Certification of Martin S. Craighead, Chairman and Chief Executive Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
31.2*
 
Certification of Kimberly A. Ross, Chief Financial Officer, furnished pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.
32*
 
Statement of Martin S. Craighead, Chairman and Chief Executive Officer, and Kimberly A. Ross, 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

31


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:
July 22, 2015
By:
/s/ KIMBERLY A. ROSS
 
 
 
Kimberly A. Ross
 
 
Senior Vice President and Chief Financial Officer
 
 
 
 
Date:
July 22, 2015
By:
/s/ ALAN J. KEIFER
 
 
 
Alan J. Keifer
 
 
Vice President and Controller

32
2015.06.30 Exhibit 21.1

Exhibit 21.1

BAKER HUGHES INCORPORATED

SIGNIFICANT SUBSIDIARIES

June 30, 2015


Subsidiary

    Jurisdiction
Percentage Ownership

 
 
 
Western Atlas Inc.
Delaware
100
%
   Baker Hughes Oilfield Operations, Inc
California
(1)

     Baker Hughes International Branches, Inc.
Delaware
(2)

       Baker Hughes EHHC, Inc.
Delaware
(3)

         Baker Hughes International Partners Holdings SCS
Luxembourg
(4)

           Baker Hughes International Financing S.à r.l.
Luxembourg
100