10-Q
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

[X]   Quarterly Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the quarterly period ended September 30, 2015

OR

[   ]   Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from _____ to _____

Commission File Number 001-03492

HALLIBURTON COMPANY

(a Delaware corporation)
75-2677995

3000 North Sam Houston Parkway East
Houston, Texas  77032
(Address of Principal Executive Offices)

Telephone Number – Area Code (281) 871-2699

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
[X]
No
[   ]
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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
[X]
No
[   ]

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.

 
Large accelerated filer
[X]
Accelerated filer
[   ]
 
Non-accelerated filer
[   ]
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
[   ]
No
[X]

As of October 16, 2015, 855,813,348 shares of Halliburton Company common stock, $2.50 par value per share, were outstanding.


HALLIBURTON COMPANY

Index

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

HALLIBURTON COMPANY
Condensed Consolidated Statements of Operations
(Unaudited)
 
Three Months Ended
September 30
Nine Months Ended
September 30
Millions of dollars and shares except per share data
2015
2014
2015
2014
Revenue:
 
 
 
 
Services
$
4,103

$
6,665

$
13,830

$
18,332

Product sales
1,479

2,036

4,721

5,768

Total revenue
5,582

8,701

18,551

24,100

Operating costs and expenses:
 

 

 

 

Cost of services
3,791

5,291

12,706

15,207

Cost of sales
1,248

1,702

3,851

4,857

Impairments and other charges
381

—

1,895

—

Baker Hughes acquisition-related costs
82

—

203

—

General and administrative
37

74

147

238

Total operating costs and expenses
5,539

7,067

18,802

20,302

Operating income (loss)
43

1,634

(251
)
3,798

Interest expense, net of interest income of $3, $3, $10 and $10
(99
)
(96
)
(311
)
(283
)
Other, net
(34
)
12

(281
)
(43
)
Income (loss) from continuing operations before income taxes
(90
)
1,550

(843
)
3,472

Income tax benefit (provision)
37

(411
)
207

(939
)
Income (loss) from continuing operations
(53
)
1,139

(636
)
2,533

Income (loss) from discontinued operations, net of income tax benefit (provision) of $0, $(10), $3 and $(8)
—

66

(5
)
63

Net income (loss)
$
(53
)
$
1,205

$
(641
)
$
2,596

Net (income) loss attributable to noncontrolling interest
(1
)
(2
)
(2
)
3

Net income (loss) attributable to company
$
(54
)
$
1,203

$
(643
)
$
2,599

Amounts attributable to company shareholders:
 

 

 

 

Income (loss) from continuing operations
$
(54
)
$
1,137

$
(638
)
$
2,536

Income (loss) from discontinued operations, net
—

66

(5
)
63

Net income (loss) attributable to company
$
(54
)
$
1,203

$
(643
)
$
2,599

Basic income (loss) per share attributable to company shareholders:
 

 

 

 

Income (loss) from continuing operations
$
(0.06
)
$
1.34

$
(0.75
)
$
2.99

Income (loss) from discontinued operations, net
—

0.08

(0.01
)
0.07

Net income (loss) per share
$
(0.06
)
$
1.42

$
(0.76
)
$
3.06

Diluted income (loss) per share attributable to company shareholders:
 

 

 

 

Income (loss) from continuing operations
$
(0.06
)
$
1.33

$
(0.75
)
$
2.97

Income (loss) from discontinued operations, net
—

0.08

(0.01
)
0.08

Net income (loss) per share
$
(0.06
)
$
1.41

$
(0.76
)
$
3.05

 
 
 
 
 
Cash dividends per share
$
0.18

$
0.15

$
0.54

$
0.45

Basic weighted average common shares outstanding
855

848

852

848

Diluted weighted average common shares outstanding
855

854

852

853

     See notes to condensed consolidated financial statements.
 
 
 
 

1
Table of Contents

HALLIBURTON COMPANY
Condensed Consolidated Statements of Comprehensive Income
(Unaudited)

 
Three Months Ended
September 30
Nine Months Ended
September 30
Millions of dollars
2015
2014
2015
2014
Net income (loss)
$
(53
)
$
1,205

$
(641
)
$
2,596

Other comprehensive income, net of income taxes:
 

 

 

 

Unrealized loss on cash flow hedges
$
(166
)
$
—

$
(62
)
$
—

Other
13

(4
)
10

—

Other comprehensive loss, net of income taxes
(153
)
(4
)
(52
)
—

Comprehensive income (loss)
$
(206
)
$
1,201

$
(693
)
$
2,596

Comprehensive (income) loss attributable to noncontrolling interest
(1
)
(2
)
(2
)
3

Comprehensive income (loss) attributable to company shareholders
$
(207
)
$
1,199

$
(695
)
$
2,599

     See notes to condensed consolidated financial statements.
 
 
 
 


2
Table of Contents


HALLIBURTON COMPANY
Condensed Consolidated Balance Sheets

 
September 30,
2015
December 31,
2014
Millions of dollars and shares except per share data
(Unaudited)
 
Assets
Current assets:
 
 
Cash and equivalents
$
2,249

$
2,291

Receivables (net of allowances for bad debts of $138 and $137)
5,791

7,564

Inventories
2,692

3,571

Assets held for sale
2,082

—

Other current assets
2,105

1,642

Total current assets
14,919

15,068

Property, plant, and equipment (net of accumulated depreciation of $9,540 and $11,007)
11,018

12,475

Goodwill
2,124

2,330

Other assets
2,187

2,367

Total assets
$
30,248

$
32,240

Liabilities and Shareholders’ Equity
Current liabilities:
 

 

Accounts payable
$
2,193

$
2,814

Accrued employee compensation and benefits
871

1,033

Current maturities of long-term debt
648

—

Loss contingency for Macondo well incident
400

367

Other current liabilities
1,591

1,669

Total current liabilities
5,703

5,883

Long-term debt
7,243

7,840

Employee compensation and benefits
576

691

Loss contingency for Macondo well incident
72

439

Other liabilities
1,174

1,089

Total liabilities
14,768

15,942

Shareholders’ equity:
 

 

Common shares, par value $2.50 per share (authorized 2,000 shares,
issued 1,071 shares)
2,677

2,679

Paid-in capital in excess of par value
243

309

Accumulated other comprehensive loss
(451
)
(399
)
Retained earnings
20,706

21,809

Treasury stock, at cost (216 and 223 shares)
(7,727
)
(8,131
)
Company shareholders’ equity
15,448

16,267

Noncontrolling interest in consolidated subsidiaries
32

31

Total shareholders’ equity
15,480

16,298

Total liabilities and shareholders’ equity
$
30,248

$
32,240

     See notes to condensed consolidated financial statements.
 
 


3
Table of Contents

HALLIBURTON COMPANY
Condensed Consolidated Statements of Cash Flows
(Unaudited)


 
Nine Months Ended
September 30
Millions of dollars
2015
2014
Cash flows from operating activities:
 
 
Net income (loss)
$
(641
)
$
2,596

Adjustments to reconcile net income (loss) to net cash flows from operating activities:
 

 

Impairments and other charges
1,895

—

Depreciation, depletion, and amortization
1,433

1,569

Deferred income tax benefit, continuing operations
(411
)
(535
)
Payment related to the Macondo well incident
(333
)
—

Other changes:
 

 

Receivables
1,396

(1,339
)
Accounts payable
(469
)
653

Inventories
(23
)
(319
)
Other
(826
)
288

Total cash flows from operating activities
2,021

2,913

Cash flows from investing activities:
 

 

Capital expenditures
(1,748
)
(2,284
)
Purchases of investment securities
(72
)
(166
)
Sales of investment securities
77

256

Payments to acquire businesses, net of cash acquired
(34
)
(230
)
Other investing activities
53

92

Total cash flows from investing activities
(1,724
)
(2,332
)
Cash flows from financing activities:
 

 

Dividends to shareholders
(460
)
(381
)
Payments to reacquire common stock
—

(800
)
Other financing activities
138

311

Total cash flows from financing activities
(322
)
(870
)
Effect of exchange rate changes on cash
(17
)
(38
)
Decrease in cash and equivalents
(42
)
(327
)
Cash and equivalents at beginning of period
2,291

2,356

Cash and equivalents at end of period
$
2,249

$
2,029

Supplemental disclosure of cash flow information:
 

 

Cash payments during the period for:
 

 

Interest
$
355

$
357

Income taxes
$
454

$
1,010

     See notes to condensed consolidated financial statements.
 
 


4
Table of Contents

HALLIBURTON COMPANY
Notes to Condensed Consolidated Financial Statements
(Unaudited)

Note 1. Basis of Presentation
The accompanying unaudited condensed consolidated financial statements were prepared using generally accepted accounting principles for interim financial information and the instructions to Form 10-Q and Regulation S-X. Accordingly, these financial statements do not include all information or notes required by generally accepted accounting principles for annual financial statements and should be read together with our 2014 Annual Report on Form 10-K.
Our accounting policies are in accordance with United States generally accepted accounting principles. The preparation of financial statements in conformity with these accounting principles requires us to make estimates and assumptions that affect:
-
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements; and
-
the reported amounts of revenue and expenses during the reporting period.
Ultimate results could differ from our estimates.
In our opinion, the condensed consolidated financial statements included herein contain all adjustments necessary to present fairly our financial position as of September 30, 2015, the results of our operations for the three and nine months ended September 30, 2015 and 2014, and our cash flows for the nine months ended September 30, 2015 and 2014. Such adjustments are of a normal recurring nature. In addition, certain reclassifications of prior period balances have been made to conform to the current period presentation. The results of our operations for the three and nine months ended September 30, 2015 may not be indicative of results for the full year.

Note 2. Acquisitions and Dispositions
Pending acquisition of Baker Hughes
On November 16, 2014, we and Baker Hughes entered into a merger agreement under which, subject to the conditions set forth in the merger agreement, we will acquire all the outstanding shares of Baker Hughes in a stock and cash transaction. Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. Under the terms of the merger agreement, at the effective time of the acquisition, each share of Baker Hughes common stock will be converted into the right to receive 1.12 shares of our common stock and $19.00 in cash.
Because the exchange ratio was fixed at the time of the merger agreement and the market value of our common stock will continue to fluctuate, the total value of the consideration exchanged will not be determinable until the closing date. The number of shares to be issued will not fluctuate based upon changes in the price of shares of our common stock or shares of Baker Hughes common stock prior to the closing date, but the exact number of Halliburton shares to be issued with respect to Baker Hughes stock awards will not be determinable until the closing of the transaction. We have estimated the total consideration expected to be issued and paid to Baker Hughes stockholders in the acquisition to consist of approximately 492 million shares of our common stock and approximately $8.3 billion to be paid in cash. We intend to finance the cash portion of the acquisition through a combination of cash on hand and debt financing. We have obtained a commitment letter for an $8.6 billion senior unsecured bridge facility, which is greater than the expected cash consideration required upon closing of the Baker Hughes acquisition. We may issue debt securities, obtain bank loans or other debt financings, or use cash on hand in lieu of utilizing all or a portion of the bridge facility.
The merger agreement has been unanimously approved by both companies' Board of Directors, our stockholders have approved the issuance of shares necessary to complete the acquisition of Baker Hughes, and Baker Hughes’ stockholders have adopted the merger agreement and thereby approved the acquisition. During 2015, we announced some of our and Baker Hughes's businesses will be marketed for sale to obtain competition authorities' approvals of the pending transaction. See the section below for further information on these anticipated divestitures. The closing of the transaction is subject to receipt of certain regulatory approvals and other conditions specified in the merger agreement. We and Baker Hughes have entered into a timing agreement with the U.S. Department of Justice (DOJ) under which we have agreed that we will not close the acquisition until the later of December 15, 2015 and 30 days following the date that both companies have certified final, substantial compliance with the DOJ’s second request. In connection therewith, we and Baker Hughes entered into a Notice of Extension on July 10, 2015, extending the termination date under the merger agreement to December 1, 2015, and an additional Notice of Extension on September 25, 2015, further extending the termination date under the merger agreement to December 16, 2015. We continue to target a 2015 close, but the transaction could move into 2016, which is allowed under the merger agreement.


5
Table of Contents

Assets Held for Sale
In April 2015, we announced our decision to market for sale our Fixed Cutter and Roller Cone Drill Bits, our Directional Drilling, and our Logging-While-Drilling/Measurement-While-Drilling businesses in connection with the pending Baker Hughes acquisition. The assets and liabilities for these businesses, which are included within our Drilling and Evaluation operating segment, were classified as held for sale beginning in the second quarter of 2015 and, therefore, the corresponding depreciation and amortization expense was ceased at that time. These anticipated divestitures are not presented as discontinued operations in our condensed consolidated statements of operations, because they do not represent a strategic shift in our business, as we will continue operating similar businesses of Baker Hughes after the acquisition. During the three and nine months ended September 30, 2015, we generated revenue from these assets of $639 million and $2.1 billion, respectively, as compared to $916 million and $2.7 billion during the three and nine months ended September 30, 2014, respectively. Additionally, during the three and nine months ended September 30, 2015, we recognized operating income from these assets, consistent with our business segments presentation in Note 4, of $136 million and $336 million, respectively, as compared to $70 million and $260 million during the three and nine months ended September 30, 2014, respectively. These amounts reflect the impact of ceasing the recording of depreciation and amortization expense for these businesses subsequent to their held for sale reclassification in 2015; the recording of such expenses would have reduced operating income by $86 million and $158 million during the three and nine months ended September 30, 2015, respectively.
When an asset is classified as held for sale, the asset’s book value is evaluated and adjusted to the lower of its carrying amount or fair value less cost to sell. As of September 30, 2015, we determined the fair value less cost to sell exceeded the carrying amount of our assets held for sale.
A summary of the carrying amounts of assets and liabilities held for sale on our condensed consolidated balance sheet as of September 30, 2015 related to the anticipated divestitures discussed above is detailed below.
Millions of dollars
September 30, 2015
Assets
Property, plant, and equipment
$
1,193

Inventories
563

Goodwill
271

Patents and other intangibles
55

Total assets
$
2,082

Liabilities
Employee benefit liabilities (a)
$
50

Other liabilities (a)
6

Total liabilities
$
56

(a) Liabilities held for sale are classified within “Other current liabilities” on our condensed
consolidated balance sheet as of September 30, 2015.

On September 28, 2015, we announced additional businesses that will be marketed for sale in connection with the pending Baker Hughes acquisition. We intend to divest our expandable liner hangers business, which is included within our Completion and Production operating segment. This anticipated divestiture did not meet all of the requirements for classification as assets held for sale at September 30, 2015 and, therefore, is not included in the table above. Additionally, Baker Hughes announced their intention to divest its core completions business, sand control business in the Gulf of Mexico, and offshore cementing businesses in Australia, Brazil, the Gulf of Mexico, Norway, and the United Kingdom.
The final sale of each of the businesses described above will be subject to the ability to negotiate acceptable terms and conditions, each company's Board of Directors approval, as applicable, and final approval of the Baker Hughes acquisition by competition authorities. We anticipate that each company will complete the sale of these businesses concurrent with the closing of the Baker Hughes acquisition.


6
Table of Contents

Note 3. Impairments and Other Charges
We carry a variety of long-lived assets on our balance sheet including property, plant and equipment, goodwill, and other intangibles. We conduct impairment tests on long-lived assets at least annually, and more frequently whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We review the recoverability of the carrying value of our assets based upon estimated future cash flows while taking into consideration assumptions and estimates including the future use of the asset, remaining useful life of the asset, and service potential of the asset. Additionally, inventories are valued at the lower of cost or market.
During the three and nine months ended September 30, 2015, as a result of the downturn in the energy market and its corresponding impact on our business outlook, we determined the carrying amount of a number of our long-lived assets exceeded their respective fair values due to projected declines in asset utilization, and that the cost of some of our inventory exceeded its market value; therefore, we recorded corresponding impairments and other charges. Additionally, we initiated a company-wide reduction in workforce by approximately 21% during the first nine months of 2015 intended to reduce costs and better align our workforce with anticipated activity levels in the near-term, which resulted in us recording severance costs relating to termination benefits. We also recorded a write-off of our operations in both Libya and Yemen during the first quarter of 2015 due to our decision to exit our operations in these countries. As part of the anticipated divestitures of certain businesses included in our Drilling and Evaluation operating segment, we are incurring certain non-capitalizable costs which we have included within "other matters" in the table below.
Primarily as a result of the events described above, we recorded a total of $381 million in charges during the third quarter of 2015 and approximately $1.9 billion in charges during the first nine months of 2015, which consisted of asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, country and facility closures, and other items. We also recorded a $199 million foreign currency exchange loss in Venezuela during the first quarter of 2015 as discussed in further detail below.
The following table presents various charges we recorded during the three and nine months ended September 30, 2015 as a result of the downturn in the energy market and other matters:
Millions of dollars
Three Months Ended
September 30, 2015
Nine Months Ended
September 30, 2015
Income Statement Classification
Economic downturn:
 
 
 
Fixed asset impairments
$
154

$
648

Impairments and other charges
Severance costs
96

308

Impairments and other charges
Inventory write-downs
64

410

Impairments and other charges
Intangible asset impairments
37

209

Impairments and other charges
Other
21

173

Impairments and other charges
Other matters:
 
 
 
Country closures
4

81

Impairments and other charges
Other
5

66

Impairments and other charges
Total impairments and other charges
$
381

$
1,895


Venezuela currency devaluation loss
—

199

Other, net
Total charges
$
381

2,094



Additionally, we performed our annual goodwill impairment assessment as of September 30, 2015. As a result of our analysis, we determined that the fair value of each reporting unit exceeded its net book value and, therefore, no goodwill impairment was necessary as of September 30, 2015. This analysis consists of a discounted cash flow based on management’s short-term and long-term forecast of operating performance for each reporting unit. Should current market conditions worsen or persist for an extended period of time, an impairment of the carrying value of our goodwill could occur, particularly in our Completion and Production operating segment where the fair value exceeded net book value by less than 10% as of September 30, 2015.
In February 2015, the Venezuelan government created a new foreign exchange rate mechanism, called the Marginal Currency System, or SIMADI. The new mechanism, which is the third system in a three-tier exchange control mechanism, is a floating market rate for the conversion of Bolívares to United States dollars based on supply and demand. Prior to 2015, we had remeasured our net monetary assets denominated in Bolívares using the official exchange rate of 6.3 Bolívares per United States dollar. During the first quarter of 2015, we began utilizing SIMADI to remeasure our net monetary assets denominated in Bolívares with a market rate of 192 Bolívares per United States dollar as of March 31, 2015, which resulted in us recording a foreign currency loss of $199 million during the first quarter of 2015.

7
Table of Contents

Note 4. Business Segment and Geographic Information
We operate under two divisions, which form the basis for the two operating segments we report: the Completion and Production segment and the Drilling and Evaluation segment. Intersegment revenue was immaterial. Our equity in earnings and losses of unconsolidated affiliates that are accounted for by the equity method of accounting are included in revenue and operating income of the applicable segment.
The following table presents information on our business segments.
 
Three Months Ended
September 30
Nine Months Ended
September 30
Millions of dollars
2015
2014
2015
2014
Revenue:
 
 
 
 
Completion and Production
$
3,200

$
5,420

$
10,890

$
14,782

Drilling and Evaluation
2,382

3,281

7,661

9,318

Total revenue
$
5,582

$
8,701

$
18,551

$
24,100

Operating income (loss):
 
 
 
 
Completion and Production
$
163

$
1,071

$
938

$
2,619

Drilling and Evaluation
401

451

1,107

1,263

Total operations
564

1,522

2,045

3,882

Corporate and other (a)
(140
)
112

(401
)
(84
)
Impairments and other charges (b)
(381
)
—

(1,895
)
—

Total operating income (loss)
$
43

$
1,634

$
(251
)
$
3,798

Interest expense, net of interest income
(99
)
(96
)
(311
)
(283
)
Other, net
(34
)
12

(281
)
(43
)
Income (loss) from continuing operations before income taxes
$
(90
)
$
1,550

$
(843
)
$
3,472

(a) Includes certain expenses not attributable to a particular business segment such as costs related to support functions and corporate executives, as well as costs related to the pending Baker Hughes acquisition incurred during the three and nine months ended September 30, 2015.
(b) Includes $228 million attributable to Completion and Production, $138 million attributable to Drilling and Evaluation, and $15 million attributable to Corporate and other for the three months ended September 30, 2015. Includes $949 million attributable to Completion and Production, $865 million attributable to Drilling and Evaluation, and $81 million attributable to Corporate and other for the nine months ended September 30, 2015.

Receivables
As of September 30, 2015, 31% of our gross trade receivables were from customers in the United States. As of December 31, 2014, 39% of our gross trade receivables were from customers in the United States. Other than Venezuela, as further discussed below, no other country or single customer accounted for more than 10% of our gross trade receivables at these dates.
Venezuela. During the first quarter of 2015, we began utilizing the new SIMADI exchange rate mechanism to remeasure our net monetary assets denominated in Bolívares, at a market rate of 192 Bolívares per United States dollar as compared to the official exchange rate of 6.3 Bolívares per United States dollar we had previously utilized, resulting in a foreign currency devaluation loss of $199 million. Additionally, we have experienced delays in collecting payment on our receivables from our primary customer in Venezuela, which partially offset the decline in receivables related to the currency devaluation during the period. These receivables are not disputed, and we have not historically had material write-offs relating to this customer.
Our total outstanding trade receivables in Venezuela were $639 million, or approximately 11% of our gross trade receivables, as of September 30, 2015, compared to $670 million, or approximately 9% of our gross trade receivables, as of December 31, 2014. Of the $639 million of receivables in Venezuela as of September 30, 2015, $176 million have been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets. Of the $670 million of receivables in Venezuela as of December 31, 2014, $256 million have been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets.
For additional information about the new currency system, see Note 3 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Environment and Results of Operations.”
    

8
Table of Contents

Note 5. Inventories
Inventories are stated at the lower of cost or market value. In the United States, we manufacture certain finished products and parts inventories for drill bits, completion products, bulk materials, and other tools that are recorded using the last-in, first-out method, which totaled $150 million as of September 30, 2015 and $227 million as of December 31, 2014. If the average cost method had been used, total inventories would have been $1 million higher than reported as of September 30, 2015 and $38 million higher than reported as of December 31, 2014. The cost of the remaining inventory was recorded on the average cost method. Inventories consisted of the following:
Millions of dollars
September 30,
2015
December 31,
2014
Finished products and parts
$
1,965

$
2,606

Raw materials and supplies
584

754

Work in process
143

211

Total
$
2,692

$
3,571


We reclassified $563 million of our inventory to assets held for sale as of September 30, 2015. See Note 2 for further information.
During the first nine months of 2015, as a result of the downturn in the energy market and its corresponding impact on our business outlook, we determined the cost of some of our inventory exceeded its market value; therefore, we recorded corresponding inventory write-downs of approximately $410 million. See Note 3 for further information about the impairments and other charges taken in the three and nine months ended September 30, 2015.
Finished products and parts are reported net of obsolescence reserves of $199 million as of September 30, 2015 and $161 million as of December 31, 2014.

Note 6. Shareholders’ Equity
The following tables summarize our shareholders’ equity activity:
Millions of dollars
Total shareholders' equity
Company shareholders' equity
Noncontrolling interest in consolidated subsidiaries
Balance at December 31, 2014
$
16,298

$
16,267

$
31

Payments of dividends to shareholders
(460
)
(460
)
—

Stock plans
380

380

—

Other
(45
)
(44
)
(1
)
Comprehensive income (loss)
(693
)
(695
)
2

Balance at September 30, 2015
$
15,480

$
15,448

$
32

Millions of dollars
Total shareholders' equity
Company shareholders' equity
Noncontrolling interest in consolidated subsidiaries
Balance at December 31, 2013
$
13,615

$
13,581

$
34

Shares repurchased
(800
)
(800
)
—

Stock plans
505

505

—

Payments of dividends to shareholders
(381
)
(381
)
—

Other
(17
)
(13
)
(4
)
Comprehensive income (loss)
2,596

2,599

(3
)
Balance at September 30, 2014
$
15,518

$
15,491

$
27


Our Board of Directors has authorized a program to repurchase our common stock from time to time. Approximately $5.7 billion remains authorized for repurchases as of September 30, 2015. From the inception of this program in February 2006 through September 30, 2015, we repurchased approximately 201 million shares of our common stock for a total cost of approximately $8.4 billion. There were no repurchases made under the program during the nine months ended September 30, 2015.

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Accumulated other comprehensive loss consisted of the following:
Millions of dollars
September 30,
2015
December 31,
2014
Defined benefit and other postretirement liability adjustments
$
(315
)
$
(326
)
Cumulative translation adjustments
(76
)
(70
)
Accumulated loss on cash flow hedges
(62
)
—

Other
2

(3
)
Total accumulated other comprehensive loss
$
(451
)
$
(399
)

Note 7. Commitments and Contingencies
Macondo well incident
The semisubmersible drilling rig, Deepwater Horizon, sank on April 22, 2010 after an explosion and fire onboard the rig that began on April 20, 2010. The Deepwater Horizon was owned by an affiliate of Transocean Ltd. and had been drilling the Macondo exploration well in the Gulf of Mexico for the lease operator, BP Exploration & Production, Inc. (BP). We performed a variety of services on that well for BP. There were eleven fatalities and a number of injuries as a result of the Macondo well incident.
Litigation and settlements. Numerous lawsuits relating to the Macondo well incident and alleging damages arising from the blowout were filed against various parties, including BP, Transocean and us, in federal and state courts throughout the United States, most of which were consolidated in a Multi District Litigation proceeding (MDL) in the United States Eastern District of Louisiana. The defendants in the MDL proceeding filed a variety of cross claims against each other.
In 2012, BP reached a settlement to resolve the substantial majority of eligible private economic loss and medical claims stemming from the Macondo well incident (BP MDL Settlements). The MDL court has since certified the classes and granted final approval for the BP MDL Settlements, which also provided for the release by participating plaintiffs of compensatory damage claims against us.
The trial for the first phase of the MDL proceeding occurred in February 2013 through April 2013 and covered issues arising out of the conduct and degree of culpability of various parties allegedly relevant to the loss of well control, the ensuing fire and explosion on and sinking of the Deepwater Horizon, and the initiation of the release of hydrocarbons from the Macondo well. In September 2014, the MDL court ruled (Phase One Ruling) that, among other things, (1) in relation to the Macondo well incident, BP’s conduct was reckless, Transocean’s conduct was negligent, and our conduct was negligent, (2) fault for the Macondo blowout, explosion, and spill was apportioned 67% to BP, 30% to Transocean and 3% to us, and (3) the indemnity and release clauses in our contract with BP are valid and enforceable against BP. The MDL court did not find that our conduct was grossly negligent, thereby, subject to any appeals, eliminating our exposure in the MDL for punitive damages. The appeal process for the Phase One Ruling is underway, with various parties filing briefs according to a court-ordered schedule.
In September 2014, prior to the Phase One Ruling, we reached an agreement, subject to court approval, to settle a substantial portion of the plaintiffs’ claims asserted against us relating to the Macondo well incident (our MDL Settlement). Pursuant to our MDL Settlement, we agreed to pay an aggregate of $1.1 billion, which includes legal fees and costs, into a settlement fund in three installments over two years, except that one installment of legal fees will not be paid until all of the conditions to the settlement have been satisfied or waived. Certain conditions must be satisfied before our MDL Settlement becomes effective and the funds are released from the settlement fund. These conditions include, among others, the issuance of a final order of the MDL court, including the resolution of certain appeals. In addition, we have the right to terminate our MDL Settlement if more than an agreed number of plaintiffs elect to opt out of the settlement prior to the expiration of the opt out deadline to be established by the MDL court. Before approving our MDL Settlement, the MDL court must certify the settlement class, the numerous class members must be notified of the proposed settlement, and the court must hold a fairness hearing. We are unable to predict when the MDL court will approve our MDL Settlement.
Our MDL Settlement does not cover claims against us by the state governments of Alabama, Florida, Mississippi, Louisiana, or Texas, claims by our own employees, compensatory damages claims by plaintiffs in the MDL that opted out of or were excluded from the settlement class in the BP MDL Settlements, or claims by other defendants in the MDL or their respective employees. However, these claims have either been dismissed, are subject to dismissal, are subject to indemnification by BP, or are not believed to be material.
On May 20, 2015, we and BP entered into an agreement to resolve all remaining claims against each other, and pursuant to which BP will defend and indemnify us in future trials for compensatory damages. On July 2, 2015, BP announced that it had reached agreements in principle to settle all remaining federal, state and local government claims arising from the Macondo well incident.

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Regulatory action. In October 2011, the Bureau of Safety and Environmental Enforcement (BSEE) issued a notification of Incidents of Noncompliance (INCs) to us for allegedly violating federal regulations relating to the failure to take measures to prevent the unauthorized release of hydrocarbons, the failure to take precautions to keep the Macondo well under control, the failure to cement the well in a manner that would, among other things, prevent the release of fluids into the Gulf of Mexico, and the failure to protect health, safety, property, and the environment as a result of a failure to perform operations in a safe and workmanlike manner. We have appealed the INCs, but the appeal has been suspended pending certain proceedings in the MDL and potential appeals. The BSEE has announced that the INCs will be reviewed for possible imposition of civil penalties once the appeal has ended. We understand that the regulations in effect at the time of the alleged violations provide for fines of up to $35,000 per day per violation.
Loss contingency. During the third quarter of 2015, we made the second installment payment under our MDL Settlement in the amount of $333 million. Accordingly, as of September 30, 2015, our remaining loss contingency liability related to the Macondo well incident was $472 million, consisting of a current portion of $400 million related to our MDL Settlement and a non-current portion of $72 million unrelated to that settlement. Our loss contingency liability has not been reduced for potential recoveries from our insurers. See below for information regarding amounts that we could potentially recover from insurance.
Subject to the satisfaction of the conditions of our MDL Settlement and to the resolution of the appeal of the Phase One Ruling, we believe that the BP MDL Settlement, our MDL Settlement, the Phase One Ruling and our settlement with BP have eliminated any additional material financial exposure to us in relation to the Macondo well incident.
Insurance coverage. We had a general liability insurance program of $600 million at the time of the Macondo well incident. Our insurance was designed to cover claims by businesses and individuals made against us in the event of property damage, injury, or death and, among other things, claims relating to environmental damage, as well as legal fees incurred in defending against those claims. Through September 30, 2015, we have incurred approximately $1.5 billion of expenses related to the MDL Settlement, legal fees, and other settlement-related costs, of which $403 million has been reimbursed under our insurance program. Most of the insurance carriers that issued policies in the final $200 million layer of insurance coverage relating to the Macondo well incident notified us that they would not reimburse us with respect to our MDL Settlement. During the first and third quarters of 2015, we settled with two of the remaining insurance carriers. We have initiated arbitration proceedings to pursue recovery of the remaining balance of approximately $118 million. Due to the uncertainty surrounding such recovery, no related amounts have been recognized in the consolidated financial statements as of September 30, 2015.
Fair Labor Standards Act (FLSA) Claim
In 2014, the U.S. Department of Labor Wage and Hour Division (DOL) commenced an audit to determine whether certain workers have been properly classified by us as exempt under the FLSA. In addition, litigation was commenced against us alleging that certain field professionals were not properly classified. During the first quarter of 2015, upon completion of a detailed analysis of the potential exposure involved and settlement of the pending litigation, we recorded corresponding loss contingency liabilities.
Securities and related litigation
In June 2002, a class action lawsuit was filed against us in federal court alleging violations of the federal securities laws after the Securities and Exchange Commission (SEC) initiated an investigation in connection with our change in accounting for revenue on long-term construction projects and related disclosures. In the weeks that followed, approximately twenty similar class actions were filed against us. Several of those lawsuits also named as defendants several of our present or former officers and directors. The class action cases were later consolidated, and the amended consolidated class action complaint, styled Richard Moore, et al. v. Halliburton Company, et al., was filed and served upon us in April 2003. As a result of a substitution of lead plaintiffs, the case was styled Archdiocese of Milwaukee Supporting Fund (AMSF) v. Halliburton Company, et al. AMSF has changed its name to Erica P. John Fund, Inc. (the Fund). We settled with the SEC in the second quarter of 2004.
In June 2003, the lead plaintiffs filed a motion for leave to file a second amended consolidated complaint, which was granted by the court. In addition to restating the original accounting and disclosure claims, the second amended consolidated complaint included claims arising out of our 1998 acquisition of Dresser Industries, Inc., including that we failed to timely disclose the resulting asbestos liability exposure.
In April 2005, the court appointed new co-lead counsel and named the Fund the new lead plaintiff, directing that it file a third consolidated amended complaint and that we file our motion to dismiss. The court held oral arguments on that motion in August 2005. In March 2006, the court entered an order in which it granted the motion to dismiss with respect to claims arising prior to June 1999 and granted the motion with respect to certain other claims while permitting the Fund to re-plead some of those claims to correct deficiencies in its earlier complaint. In April 2006, the Fund filed its fourth amended consolidated complaint. We filed a motion to dismiss those portions of the complaint that had been re-pled. A hearing was held on that motion in July 2006, and in March 2007 the court ordered dismissal of the claims against all individual defendants other than our Chief Executive Officer (CEO). The court ordered that the case proceed against our CEO and us.

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In September 2007, the Fund filed a motion for class certification, and our response was filed in November 2007. The district court issued an order in November 2008 denying the motion for class certification. The Fifth Circuit Court of Appeals affirmed the district court’s order denying class certification. In June 2011, the United States Supreme Court reversed the Fifth Circuit ruling that the Fund needed to prove loss causation in order to obtain class certification and the case was returned to the lower courts for further consideration.
In January 2012, the district court issued an order certifying the class. In April 2013, the Fifth Circuit issued an order affirming the district court's order.
Our writ of certiorari with the United States Supreme Court was granted and in June 2014 the Supreme Court issued its decision, maintaining the presumption of class member reliance through the “fraud on the market” theory, but holding that we are entitled to rebut that presumption by presenting evidence that there was no impact on our stock price from the alleged misrepresentation. Because the district court and the Fifth Circuit denied us that opportunity, the Supreme Court vacated the Fifth Circuit’s decision and remanded for further proceedings consistent with the Supreme Court decision.
In December 2014, the district court held a hearing to consider whether there was an impact on our stock price from the alleged misrepresentations. On July 27, 2015, the district court denied certification for the plaintiff class with respect to five of the six dates upon which the plaintiffs claimed that disclosures correcting previously misleading statements had been made that resulted in an impact to the stock price. However, the district court certified the class with respect to a disclosure made on December 7, 2001 regarding an adverse jury verdict in an asbestos case that plaintiffs alleged was corrective. The ruling was based on the district court's conclusion that the court was required to assume at class certification that a disclosure was actually corrective. We do not agree with that conclusion and have filed a petition with the Fifth Circuit seeking to appeal the ruling. We cannot predict the outcome or consequences of this case, which we intend to vigorously defend.
Investigations
We are conducting internal investigations of certain areas of our operations in Angola and Iraq, focusing on compliance with certain company policies, including our Code of Business Conduct (COBC), and the FCPA and other applicable laws.
In December 2010, we received an anonymous e-mail alleging that certain current and former personnel violated our COBC and the FCPA, principally through the use of an Angolan vendor. The e-mail also alleges conflicts of interest, self-dealing, and the failure to act on alleged violations of our COBC and the FCPA. We contacted the DOJ to advise them that we were initiating an internal investigation.
During the second quarter of 2012, in connection with a meeting with the DOJ and the SEC regarding the above investigation, we advised the DOJ and the SEC that we were initiating unrelated, internal investigations into payments made to a third-party agent relating to certain customs matters in Angola and to third-party agents relating to certain customs and visa matters in Iraq.
Since the initiation of the investigations described above, we have participated in meetings with the DOJ and the SEC to brief them on the status of the investigations and produced documents to them both voluntarily and as a result of SEC subpoenas to us and certain of our current and former officers and employees.
We expect to continue to have discussions with the DOJ and the SEC regarding issues relevant to the Angola and Iraq matters described above. We have engaged outside counsel and independent forensic accountants to assist us with these investigations.
Because these investigations are ongoing, we cannot predict their outcome or the consequences thereof.
Environmental
We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:
-
the Comprehensive Environmental Response, Compensation, and Liability Act;
-
the Resource Conservation and Recovery Act;
-
the Clean Air Act;
-
the Federal Water Pollution Control Act;
-
the Toxic Substances Control Act; and
-
the Oil Pollution Act.
In addition to the federal laws and regulations, states and other countries where we do business often have numerous environmental, legal, and regulatory requirements by which we must abide. We evaluate and address the environmental impact of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with environmental, legal, and regulatory requirements. Our Health, Safety, and Environment group has several programs in place to maintain environmental leadership and to help prevent the occurrence of environmental contamination. On occasion, in addition to the matters relating to the Macondo well incident described above, we are involved in other environmental litigation and claims, including the remediation of properties we own or have operated, as well as efforts to meet or correct compliance-related matters. We do not expect costs related to those claims and remediation requirements to have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial position. Our accrued liabilities for environmental matters were $57 million as of September 30, 2015 and December 31, 2014. Because our estimated liability is typically within a

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range and our accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in excess of the amount accrued. Our total liability related to environmental matters covers numerous properties.
Additionally, we have subsidiaries that have been named as potentially responsible parties along with other third parties for nine federal and state Superfund sites for which we have established reserves. As of September 30, 2015, those nine sites accounted for approximately $3 million of our $57 million total environmental reserve. Despite attempts to resolve these Superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount accrued. With respect to some Superfund sites, we have been named a potentially responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims with respect to environmental matters for which we have been named as a potentially responsible party.
Guarantee arrangements
In the normal course of business, we have agreements with financial institutions under which approximately $2.0 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of September 30, 2015. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

Note 8. Income per Share
Basic income or loss per share is based on the weighted average number of common shares outstanding during the period. Diluted income per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect had been issued. For the three and nine months ended September 30, 2014, differences between basic and diluted weighted average common shares outstanding resulted from the dilutive effect of awards granted under our stock incentive plans.
Excluded from the computation of diluted income per share are options to purchase two million shares of common stock that were outstanding during the nine months ended September 30, 2014. These options were outstanding but were excluded because they were antidilutive, as the option exercise price was greater than the average market price of the common shares. There were no antidilutive shares outstanding for the three months ended September 30, 2014.
For the three and nine months ended September 30, 2015, we incurred losses from continuing operations attributable to company shareholders and accordingly excluded all potentially dilutive securities from the determination of diluted loss per share as their impact was antidilutive. Antidilutive securities for the three months ended September 30, 2015 totaled 15 million shares, which includes options to purchase 13 million shares of common stock where the exercise price was greater than the average market price and options to purchase two million shares of common stock which ordinarily would be considered dilutive if not for us being in a net loss position for the three months ended September 30, 2015. Antidilutive securities for the nine months ended September 30, 2015 totaled 12 million shares, which includes options to purchase 10 million shares of common stock where the exercise price was greater than the average market price and options to purchase two million shares of common stock which ordinarily would be considered dilutive if not for us being in a net loss position for the nine months ended September 30, 2015.

Note 9. Fair Value of Financial Instruments
At September 30, 2015, we held $89 million of investments in fixed income securities with maturities ranging from less than one year to November 2019, of which $54 million are classified as “Other current assets” and $35 million are classified as “Other assets” on our condensed consolidated balance sheets. At December 31, 2014, we held $103 million of investments in fixed income securities, of which $56 million are classified as “Other current assets” and $47 million are classified as “Other assets” on our condensed consolidated balance sheets.
These securities consist primarily of corporate bonds and other debt instruments, are accounted for as available-for-sale and recorded at fair value, and are classified as Level 2 assets. Our Level 2 asset fair values are based on quoted prices for identical assets in less active markets. We have no financial instruments measured at fair value based on quoted prices in active markets (Level 1) or using unobservable inputs (Level 3). The carrying amount of cash and equivalents, receivables, and accounts payable, as reflected in the condensed consolidated balance sheets, approximates fair value due to the short maturities of these instruments.
The carrying amount and fair value of our long-term debt, including current maturities, is as follows:
 
September 30, 2015
 
December 31, 2014
Millions of dollars
Level 1
Level 2
Total fair value
Carrying value
 
Level 1
Level 2
Total fair value
Carrying value
Long-term debt
$
1,008

$
7,615

$
8,623

$
7,891

 
$
4,822

$
4,257

$
9,079

$
7,840


Our Level 1 debt fair values are calculated using quoted prices in active markets for identical liabilities with transactions occurring on the last two days of period-end. Our Level 2 debt fair values are calculated using significant observable inputs for similar liabilities where estimated values are determined from observable data points on our other bonds and on other similarly rated corporate debt or from observable data points of transactions occurring prior to two days from period-end and adjusting for changes in market conditions. Differences between the periods presented in our Level 1 and Level

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2 classification of our long-term debt relate to the timing of when transactions are executed. We have no debt measured at fair value using unobservable inputs (Level 3).
We maintain an interest rate management strategy that is intended to mitigate the exposure to changes in interest rates in the aggregate for our debt portfolio. We hold a series of interest rate swaps relating to three of our debt instruments with a total notional amount of $1.5 billion in order to effectively convert a portion of our fixed rate debt to floating LIBOR-based rates. These interest rate swaps, which expire when the underlying debt matures, are designated as fair value hedges of the underlying debt and are determined to be highly effective. These derivative instruments are marked to market with gains and losses recognized currently in interest expense to offset the respective gains and losses recognized on changes in the fair value of the hedged debt. During the first nine months of 2015, we executed forward starting interest rate swaps to manage our exposure to interest rate changes associated with the anticipated issuance of fixed-rate debt in connection with the pending Baker Hughes acquisition. These newly executed swaps, which hedge the variability in cash flows of future interest payments due to changes in LIBOR rates, are designated as cash flow hedges, are determined to be highly effective, and are recorded on the balance sheet at fair value with the effective portion of the change in fair value of the hedging instrument recorded in other comprehensive income. The fair value of our interest rate swaps is included in “Other assets” in our condensed consolidated balance sheets and was immaterial as of September 30, 2015 and December 31, 2014. The fair value of our interest rate swaps was determined using an income approach model with inputs, such as the notional amount, LIBOR rate spread, and settlement terms that are observable in the market or can be derived from or corroborated by observable data (Level 2).

Note 10. New Accounting Pronouncements
Revenue Recognition
In May 2014, the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board (IASB) issued a comprehensive new revenue recognition standard that will supersede existing revenue recognition guidance under United States generally accepted accounting principles (U.S. GAAP) and International Financial Reporting Standards (IFRS). The issuance of this guidance completes the joint effort by the FASB and the IASB to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and IFRS.
The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items.
In August 2015, the FASB issued an accounting standards update for a one-year deferral of the revenue recognition standard's effective date for all entities, which changed the effectiveness to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are currently evaluating this standard and our existing revenue recognition policies to determine which contracts in the scope of the guidance will be affected by the new requirements and what impact they would have on our consolidated financial statements upon adoption. We have not yet determined which transition method we will utilize upon adoption on the effective date.

Discontinued Operations
On January 1, 2015, we adopted an accounting standards update issued by the FASB related to discontinued operations, which added criteria providing that only those disposals of a component of an entity or a group of components of an entity that represent a strategic shift in operations should be presented as discontinued operations. The update allows an entity to present a disposal as discontinued operations even when it has continuing cash flows and significant continuing involvement with the disposed component. The update also requires expanded disclosures for discontinued operations and individually significant components of an entity that does not qualify for discontinued operations reporting. The adoption of this update did not impact our condensed consolidated financial statements. This new pronouncement may have a material impact on our consolidated financial statements in connection with the anticipated divestitures related to the pending acquisition of Baker Hughes. Because we will continue operating similar businesses of Baker Hughes after the acquisition, the disposition of the Halliburton businesses discussed in Note 2 does not represent a strategic shift in our business. Accordingly, these businesses anticipated to be divested will not be presented as discontinued operations.

Debt Issuance Costs
In April 2015, the FASB issued an accounting standards update to simplify the presentation of debt issuance costs. The update will require 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, as opposed to current presentation of an asset on the balance sheet. This update is effective for fiscal years beginning after December 15, 2015, and interim periods

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within those fiscal years, and may be adopted earlier on a voluntary basis. We intend to adopt this update upon execution of the debt financing for the pending Baker Hughes acquisition. At that time we will apply the change retrospectively for prior period balances of unamortized debt issuance costs within our statement of financial position. We do not expect the adoption of this update to have a material impact on our consolidated financial statements. See Note 2 for further information about the pending acquisition.

Business Combinations
In September 2015, the FASB issued an accounting standards update to simplify the accounting for measurement-period adjustments for an acquirer in a business combination. The update will require an acquirer to recognize any adjustments to provisional amounts of the initial accounting for a business combination with a corresponding adjustment to goodwill in the reporting period in which the adjustments are determined in the measurement period, as opposed to revising prior periods presented in financial statements. Thus, an acquirer shall adjust its financial statements as needed, including recognizing in its current-period earnings the full effect of changes in depreciation, amortization, or other income effects, by line item, if any, as a result of the change to the provisional amounts calculated as if the accounting had been completed at the acquisition date. This update is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. This new pronouncement may have a material impact on our consolidated financial statements subsequent to the pending acquisition of Baker Hughes for any measurement-period adjustments after the initial accounting period. See Note 2 for further information about the pending acquisition.

Note 11. Revolving Credit Facility
In July 2015, we entered into a new five-year revolving credit agreement, with an initial capacity of $3.0 billion, increasing to $4.5 billion upon closing of the Baker Hughes acquisition and satisfaction of the conditions provided in the credit agreement. The credit agreement is for general working capital purposes and expires on July 21, 2020. 


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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE OVERVIEW

Organization
We are a leading provider of services and products to the energy industry. We serve the upstream oil and natural gas industry throughout the lifecycle of the reservoir, from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Activity levels within our operations are significantly impacted by spending on upstream exploration, development, and production programs by major, national, and independent oil and natural gas companies. We report our results under two segments, the Completion and Production segment and the Drilling and Evaluation segment:
-
our Completion and Production segment delivers cementing, stimulation, well intervention, pressure control services, well control and prevention services, pipeline and process services, specialty chemicals, artificial lift, and completion products and services. The segment consists of Production Enhancement, Cementing, Completion Tools, Production Solutions (formerly Boots & Coots), Multi-Chem, and Artificial Lift.
-
our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and precise wellbore placement solutions that enable customers to model, measure, drill, and optimize their well construction activities. The segment consists of Baroid, Sperry Drilling, Wireline and Perforating, Drill Bits and Services, Landmark Software and Services, Testing and Subsea, and Consulting and Project Management.
The business operations of our segments are organized around four primary geographic regions: North America, Latin America, Europe/Africa/CIS, and Middle East/Asia. We have significant manufacturing operations in various locations, including the United States, Canada, China, Malaysia, Singapore, and the United Kingdom.
With approximately 65,000 employees, we operate in approximately 80 countries around the world, and our corporate headquarters are in Houston, Texas and Dubai, United Arab Emirates.
Pending acquisition of Baker Hughes
On November 16, 2014, we and Baker Hughes entered into a merger agreement under which, subject to the conditions set forth in the merger agreement, we will acquire all the outstanding shares of Baker Hughes in a stock and cash transaction. The acquisition is expected to create a leading global oilfield services company and combine the companies’ product and service capabilities to deliver exceptional depth and breadth of solutions to our customers. We continue to target a 2015 close, but the transaction could move into 2016, which is allowed under the merger agreement. See Note 2 to the condensed consolidated financial statements for further information about the pending acquisition.
Financial results
We experienced a decline in revenue and margins in the third quarter of 2015, as compared to the third quarter of 2014, as a result of the depressed crude oil pricing environment and its corresponding negative impact on both pricing and activity. The industry experienced an unprecedented decline in North America stimulation activity during 2015, which significantly impacted our financial results. Since November 2014, the United States experienced an approximately 58% decrease in rig count, which in turn has resulted in pricing pressure across the services industry. Our consolidated revenue for the third quarter of 2015 was $5.6 billion, a decrease of $3.1 billion, or 36%, from the third quarter of 2014, attributable to reduced activity levels and pricing concessions in all regions, primarily in North America.
During the first nine months of 2015, we had an operating loss of $251 million, as compared to operating income of $3.8 billion in the first nine months of 2014. The decrease was primarily due to approximately $1.9 billion of impairments and other charges recorded during the first nine months of 2015. These charges were recorded primarily as a result of the downturn in the energy market, and consisted of fixed asset impairments and write-offs, impairments of intangible assets, inventory write-downs, severance costs, country and facility closures, and other items. We took actions during the first nine months of 2015 by reducing our cost structure, including a global headcount reduction of approximately 21% since the beginning of the year, to help mitigate the current market conditions that we are experiencing. See Note 3 to the condensed consolidated financial statements for further information about these charges. Additionally, our operating results were negatively impacted by reduced activity and pricing pressure in most of our product services lines, particularly stimulation activity, in the United States land market.
Business outlook
The first nine months of 2015 have been challenging for us, as the impact of reduced commodity prices created widespread pricing pressure and activity reductions on a global basis. We have taken actions during the first nine months of 2015 to help mitigate the downturn in the energy market on our business, and we will continue to evaluate our cost structure and make further adjustments as required.
               In North America, we continue to experience pricing pressures, which have impacted our margins. Lower commodity prices have translated into unprecedented reductions in rig count throughout the first nine months of the year, which translated into substantial pricing pressure across all of our product service lines. The U.S. land rig count has dropped approximately 58% from the peak in late November 2014. This rig count decline compares to an 18% decline in our completions-related activity,

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which demonstrates the customer flight to quality that has emerged during the downturn and it positions us well for when the market recovers. Activity in North America could drop substantially towards the end of 2015 as operators exhaust their 2015 budgets and possibly take extended holiday breaks which may impact our revenues and margins in the fourth quarter of 2015. In 2016, we believe that activity may start at a slow pace as E&P budgets are reloaded with activity perhaps ramping up in the second half of the year.
Internationally, the markets have been more resilient than North America, however they are not immune to the impacts of the lower commodity price environment. We experienced pricing concessions in our international operations and activity reductions during the third quarter of 2015, the impact of which was partially mitigated by our cost management initiatives. Despite some pricing concessions, we have continued to work with customers during this downturn to improve project economics through technology and improved operating efficiency. We believe the typical seasonal uptick in year-end sales will be minimal this year as customer budgets are exhausted and may not fully offset continued pricing pressures, impacting our revenue and margins in the fourth quarter of 2015. Going into 2016, we expect to see a continuation of trends from 2015, with land-based activity, including Mature Fields, being more resilient, and our offshore business experiencing additional project delays.
While the intensity and duration of the current market downturn is uncertain, we intend to remain focused and look beyond the down cycle by continuing to invest in capital and strategic programs, and we will make further adjustments as required to adjust to market conditions. Manufacturing our own equipment provides us with flexibility to adjust our capital spend based on our visibility of the market. Given the continued decline in activity levels, we are reducing our capital expenditures for 2015 to $2.4 billion, representing a 27% decline compared to 2014. We continue to believe in the strength of the long-term fundamentals of our business. Despite the worldwide activity declines in 2015 and challenges we expect to face going into 2016, energy demand is still anticipated to increase over the long term.
We are continuing to execute the following strategies in 2015:
- directing capital and resources into strategic growth markets, including unconventional plays, mature fields, and deepwater;
-
leveraging our broad technology offerings to provide value to our customers and enabling them to more efficiently drill and complete their wells;
-
exploring additional opportunities for acquisitions that will enhance or augment our current portfolio of services and products, including those with unique technologies or distribution networks in areas where we do not already have significant operations;
-
investing in technology that will help our customers reduce reservoir uncertainty and increase operational efficiency;
-
improving working capital, and managing our balance sheet to maximize our financial flexibility; and
-
continuing to seek ways to be one of the most cost efficient service providers in the industry by maintaining capital discipline and leveraging our scale and breadth of operations.
Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations.”
Financial markets, liquidity, and capital resources
We believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations from adverse market conditions. In addition, we have committed financing available to finance the cash portion of the consideration for the pending Baker Hughes acquisition. For additional information, see “Liquidity and Capital Resources” and “Business Environment and Results of Operations.”


17
Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

We had $2.2 billion of cash and equivalents at September 30, 2015 and $2.3 billion at December 31, 2014. Additionally, at September 30, 2015, we held $89 million of investments in fixed income securities compared to $103 million at December 31, 2014. These securities are reflected in "Other current assets" and "Other assets" in our condensed consolidated balance sheets. As of September 30, 2015, approximately $1.4 billion of the $2.2 billion of cash and equivalents was held by our foreign subsidiaries, of which $848 million would be subject to United States tax if repatriated. However, our intent is to permanently reinvest these funds outside of the United States and our current plans do not suggest a need to repatriate them to fund our United States operations.
Significant sources and uses of cash
Cash flows from operating activities were $2.0 billion in the first nine months of 2015.
Capital expenditures were $1.7 billion in the first nine months of 2015, and were predominantly made in our Production Enhancement, Cementing, Sperry Drilling, Production Solutions, and Wireline and Perforating product service lines.
During the first nine months of 2015, our primary components of working capital (receivables, inventories, and accounts payable) decreased by a net $904 million, primarily due to decreased business activity driven by current market conditions.
We paid $460 million in dividends to our shareholders during the first nine months of 2015.
During the third quarter of 2015, we made the second installment payment of $333 million related to the settlement we reached during 2014 for the Macondo well incident. See Note 7 to the condensed consolidated financial statements for further information.
Future sources and uses of cash
We intend to finance the cash portion of the Baker Hughes acquisition through a combination of cash on hand and debt financing. We have obtained a commitment letter for an $8.6 billion senior unsecured bridge facility, which is greater than the expected cash consideration required upon closing of the Baker Hughes acquisition. We have not drawn any amounts under this commitment as of September 30, 2015. We may issue debt securities, obtain bank loans or pursue other debt financings, or use cash on hand in lieu of utilizing all or a portion of the bridge facility. Additionally, we expect to receive cash proceeds from the sale of the businesses we are currently marketing for sale as part of the regulatory review of the pending Baker Hughes acquisition. See Note 2 to the condensed consolidated financial statements for further information about the pending acquisition and related divestitures.
We manufacture our own equipment, which allows us flexibility to increase or decrease our capital expenditures based on market conditions. Capital spending for 2015 is currently expected to be approximately $2.4 billion, a reduction from the $3.3 billion of capital expenditures in 2014, primarily due to the current market environment. We intend to remain focused and look beyond this downturn in the energy market by continuing to invest in capital and strategic programs. The capital expenditures plan for the remainder of the year is primarily directed toward our Production Enhancement, Cementing, Sperry Drilling, Production Solutions, and Wireline and Perforating product service lines.
During 2014, we reached an agreement, subject to court approval, to settle a substantial portion of the plaintiffs' claims asserted against us relating to the Macondo well incident. Our total Macondo-related loss contingency liability as of September 30, 2015 was $472 million, of which $400 million is expected to be paid in 2016. See Note 7 to the condensed consolidated financial statements for further information.
Subject to Board of Directors approval, our intention is to pay dividends representing at least 15% to 20% of our net income on an annual basis. Currently, our dividend rate is $0.18 per common share, or approximately $155 million per quarter.
Our Board of Directors has authorized a program to repurchase our common stock from time to time. Approximately $5.7 billion remains authorized for repurchases as of September 30, 2015 and may be used for open market and other share purchases. There were no repurchases made under the program during the nine months ended September 30, 2015.
Other factors affecting liquidity
Financial position in current market. As of September 30, 2015, we had $2.2 billion of cash and equivalents, $89 million in fixed income investments, and a total of $3.0 billion of available committed bank credit under our revolving credit facility. In July 2015, we executed a new five-year revolving credit agreement with an initial capacity of $3.0 billion, increasing to $4.5 billion upon closing of the pending Baker Hughes acquisition. See Note 11 to the condensed consolidated financial statements for further information. Furthermore, we have no financial covenants or material adverse change provisions in our bank agreements, and our debt maturities extend over a long period of time. Although a portion of earnings from our foreign subsidiaries is reinvested outside the United States indefinitely, we do not consider this to have a significant impact on our liquidity. We currently believe that our capital expenditures, working capital investments, and dividends, if any, during the remainder of 2015 can be fully funded through cash from operations.
As a result, we believe we have a reasonable amount of liquidity and, if necessary, additional financing flexibility given the current market environment to fund our potential contingent liabilities, if any.

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Table of Contents

Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which approximately $2.0 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of September 30, 2015. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.
Credit ratings. Credit ratings for our long-term debt remain A2 with Moody’s Investors Service and A with Standard & Poor’s. The credit ratings on our short-term debt remain P-1 with Moody’s Investors Service and A-1 with Standard & Poor’s. After the announcement of the pending Baker Hughes acquisition, Standard & Poor’s placed all of our ratings on negative watch.
Customer receivables. In line with industry practice, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets as well as unsettled political conditions. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. See “Business Environment and Results of Operations – International operations – Venezuela” for further discussion related to receivables from our primary customer in Venezuela.

19
Table of Contents

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 80 countries throughout the world to provide a comprehensive range of discrete and integrated services and products to the energy industry related to the exploration, development, and production of oil and natural gas. A significant amount of our consolidated revenue is derived from the sale of services and products to major, national, and independent oil and natural gas companies worldwide. The industry we serve is highly competitive with many substantial competitors in each segment of our business. During the first nine months of 2015, based upon the location of the services provided and products sold, 45% of our consolidated revenue was from the United States, compared to 51% of consolidated revenue from the United States in the first nine months of 2014. This decline reflects the impact our North America operations are experiencing from the downturn in the energy market. No other country accounted for more than 10% of our revenue during these periods.
Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, force majeure, war or other armed conflict, sanctions, expropriation or other governmental actions, inflation, foreign currency exchange restrictions, and highly inflationary currencies, as well as other geopolitical factors. We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country, other than the United States, would be materially adverse to our consolidated results of operations.
Activity within our business segments is significantly impacted by spending on upstream exploration, development, and production programs by our customers. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption.
Some of the more significant determinants of current and future spending levels of our customers are oil and natural gas prices, global oil supply, the world economy, the availability of credit, government regulation, and global stability, which together drive worldwide drilling activity. Due to improved drilling and completion efficiencies as more of our customers move to multi-well pad drilling, our financial performance is impacted by well count in the North America market. Additionally, our financial performance is significantly affected by oil and natural gas prices and worldwide rig activity, which are summarized in the tables below.
The following table shows the average oil and natural gas prices for West Texas Intermediate (WTI), United Kingdom Brent crude oil, and Henry Hub natural gas:
 
Three Months Ended
September 30
Year Ended
December 31
 
2015
2014
2014
Oil price - WTI (1)
$
46.42

$
97.78

$
93.37

Oil price - Brent (1)
50.25

101.82

99.04

Natural gas price - Henry Hub (2)
2.76

3.96

4.39

 
 
 
 
(1) Oil price measured in dollars per barrel
(2) Natural gas price measured in dollars per million British thermal units (Btu), or MMBtu


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The historical average rig counts based on the weekly Baker Hughes Incorporated rig count information were as follows:
 
Three Months Ended
September 30
Nine Months Ended
September 30
Land vs. Offshore
2015
2014
2015
2014
United States:
 
 
 
 
Land
833

1,842

1,021

1,788

Offshore (incl. Gulf of Mexico)
33

61

38

57

Total
866

1,903

1,059

1,845

Canada:
 

 

 

 

Land
187

382

197

369

Offshore
3

3

3

2

Total
190

385

200

371

International (excluding Canada):
 

 

 

 

Land
865

1,020

896

1,021

Offshore
267

328

291

324

Total
1,132

1,348

1,187

1,345

Worldwide total
2,188

3,636

2,446

3,561

Land total
1,885

3,244

2,114

3,178

Offshore total
303

392

332

383

 
 
 
 
 
 
Three Months Ended
September 30
Nine Months Ended
September 30
Oil vs. Natural Gas
2015
2014
2015
2014
United States (incl. Gulf of Mexico):
 

 

 
 

Oil
658

1,578

817

1,514

Natural gas
208

325

242

331

Total
866

1,903

1,059

1,845

Canada:
 

 

 

 

Oil
88

220

90

220

Natural gas
102

165

110

151

Total
190

385

200

371

International (excluding Canada):
 

 

 

 

Oil
885

1,074

935

1,074

Natural gas
247

274

252

271

Total
1,132

1,348

1,187

1,345

Worldwide total
2,188

3,636

2,446

3,561

Oil total
1,631

2,872

1,842

2,808

Natural gas total
557

764

604

753

 
Three Months Ended
September 30
Nine Months Ended
September 30
Drilling Type
2015
2014
2015
2014
United States (incl. Gulf of Mexico):
 
 
 
 
Horizontal
659

1,314

805

1,247

Vertical
123

372

152

384

Directional
84

217

102

214

Total
866

1,903

1,059

1,845


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Table of Contents

Our customers’ cash flows, in most instances, depend upon the revenue they generate from the sale of oil and natural gas. Lower oil and natural gas prices usually translate into lower exploration and production budgets.
During the third quarter of 2015, WTI and Brent crude oil spot prices averaged approximately $46 and $50 per barrel, respectively, as compared to $98 and $102 per barrel, respectively, during the third quarter of 2014. Crude oil prices continue to be negatively affected as the combination of robust world crude oil supply growth and weak global demand contribute to an increase in the rate of global inventory builds. Additionally, stronger economic performance in the United States has led to a strengthening in the U.S. dollar relative to most other currencies, contributing further to the fall in the U.S. dollar value of crude oil.
WTI crude oil spot prices decreased throughout the third quarter of 2015, from a monthly average of approximately $60 per barrel in June to $46 per barrel in September, a decline of approximately 23%. Brent crude oil spot prices averaged $61 per barrel in June compared to approximately $48 per barrel in September. The decline in crude oil pricing during the third quarter of 2015 is primarily due to the expectations of weakening global economic activity, persistent uncertainty surrounding the potential lower economic and oil demand growth in emerging market countries, and continued growth in global petroleum inventories.
According to the United States Energy Information Administration (EIA) October 2015 "Short Term Energy Outlook," Brent prices are projected to average $50 per barrel in the fourth quarter of 2015 and $59 per barrel full year 2016, with WTI prices expected to average $5 per barrel below Brent prices. The EIA also noted that global oil inventory builds are expected to slow through the end of 2015 but remain high compared with previous years. Although there are no signs that point to an immediate rebalancing of the market, the International Energy Agency's (IEA) October 2015 "Oil Market Report" forecasts the fourth quarter of 2015 and full year 2016 global demand to average approximately 95.4 million barrels per day and 95.7 million barrels per day, respectively, which are both up 3% from 2014, driven by an increase in all regions except for the Commonwealth of Independent States.
For the third quarter of 2015, the average Henry Hub natural gas price in the United States decreased by 30%, compared to the third quarter of 2014, due to higher natural gas storage levels this year as a result of a mild winter. The Henry Hub natural gas spot price averaged $2.66 per MMBtu in September, a decline of $0.12 per MMBtu from June. The EIA's July 2015 "Short Term Energy Outlook" projects that monthly average spot prices will remain at less than $3 per MMBtu through January, and less than $3.50 per MMBtu through 2016. Over the long term, the EIA expects that increases in drilling efficiency and growth in oil production will continue to support growing natural gas production.
North America operations
Volatility in oil and natural gas prices can impact our customers’ drilling and production activities, particularly in North America. For the third quarter of 2015, the average oil directed rig count decreased 59%, while the average natural gas directed rig count decreased 37%, compared to the third quarter of 2014.
The United States rig count has dropped approximately 58% from the peak in late November 2014. Price erosion continued in the third quarter of 2015, specifically in North America, and we believe pricing will remain fluid until activity stabilizes. Current market conditions aside, in the long run, we believe the shift to unconventional oil and liquids-rich basins in the United States land market will continue to drive increased service intensity and will require higher demand in fluid chemistry and other technologies required for these complex reservoirs which will have positive implications for our operations when the energy market recovers.
In the Gulf of Mexico, the average offshore rig count for third quarter 2015 was down 46% compared to the third quarter of 2014. Activity in the Gulf of Mexico is dependent on, among other things, governmental approvals for permits, our customers' actions, and new deepwater rigs entering the market.
International operations
The average international rig count for the third quarter of 2015 decreased by 16% compared to the third quarter of 2014. Declining crude oil prices have caused several of our customers to reduce their budgets and defer several new projects; however, we have continued to work with our customers to improve project economics through technology and improved operating efficiency. Although the international markets have been more resilient than North America, they are not immune to the impacts of the lower commodity price environment and, therefore, our international operations could be further impacted in the near term.
Despite the current market environment, we believe that international land-based activity, including mature fields, will remain resilient and continue to boost activity improvements over the long term, and we plan to leverage our extensive experience in North America to optimize these opportunities. Consistent with our long-term strategy to grow our operations outside of North America, we also expect to continue to invest in capital equipment for our international operations.

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Table of Contents

Venezuela. In February 2015, the Venezuelan government created a new foreign exchange rate mechanism, called the Marginal Currency System, or SIMADI. The new mechanism, which is the third system in a three-tier exchange control mechanism, is a floating market rate for the conversion of Bolívares to United States dollars based on supply and demand. The three-tier exchange rate mechanisms are as follows: (i) the National Center of Foreign Commerce official rate of 6.3 Bolívares per United States dollar, which remains unchanged; (ii) the SICAD I, which will continue to hold periodic auctions for specific sectors of the economy with a rate of 13.5 Bolívares per United States dollar at September 30, 2015; and (iii) the SIMADI, which replaces the SICAD II system with a market rate of 199 Bolívares per United States dollar at September 30, 2015.
During the first quarter of 2015, we began utilizing the SIMADI mechanism to remeasure our net monetary assets denominated in Bolívares, which resulted in us recording a foreign currency loss of $199 million during the first quarter of 2015. As of September 30, 2015, our total net investment in Venezuela was approximately $568 million, with a minimal amount of net monetary assets denominated in Bolívares. Also, at September 30, 2015 we had $23 million of surety bond guarantees outstanding relating to our Venezuelan operations. The United States dollar value of our net monetary assets and surety bond guarantees have significantly declined from December 31, 2014 primarily as a result of the currency devaluation in Venezuela.
We have experienced delays in collecting payment on our receivables from our primary customer in Venezuela, which partially offset the decline in receivables related to the currency devaluation during the period. These receivables are not disputed, and we have not historically had material write-offs relating to this customer. Additionally, we routinely monitor the financial stability of our customers. Our total outstanding trade receivables in Venezuela were $639 million, or approximately 11% of our gross trade receivables, as of September 30, 2015, compared to $670 million, or approximately 9% of our gross trade receivables, as of December 31, 2014. Of the $639 million receivables in Venezuela as of September 30, 2015, $176 million has been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets.
For additional information, see Part I, Item 1(a), “Risk Factors” in our 2014 Annual Report on Form 10-K.


23
Table of Contents

RESULTS OF OPERATIONS IN 2015 COMPARED TO 2014

Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014
REVENUE:
Three Months Ended
September 30
Favorable
Percentage
Millions of dollars
2015
2014
(Unfavorable)
Change
Completion and Production
$
3,200

$
5,420

$
(2,220
)
(41
)%
Drilling and Evaluation
2,382

3,281

(899
)
(27
)
Total revenue
$
5,582

$
8,701

$
(3,119
)
(36
)%
 
 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 

 

 

North America
$
1,898

$
3,705

$
(1,807
)
(49
)%
Latin America
336

435

(99
)
(23
)
Europe/Africa/CIS
518

699

(181
)
(26
)
Middle East/Asia
448

581

(133
)
(23
)
Total
3,200

5,420

(2,220
)
(41
)
Drilling and Evaluation:
 
 

 

 

North America
590

1,019

(429
)
(42
)
Latin America
403

610

(207
)
(34
)
Europe/Africa/CIS
503

765

(262
)
(34
)
Middle East/Asia
886

887

(1
)
—

Total
2,382

3,281

(899
)
(27
)
Total revenue by region:
 

 

 

 

North America
2,488

4,724

(2,236
)
(47
)
Latin America
739

1,045

(306
)
(29
)
Europe/Africa/CIS
1,021

1,464

(443
)
(30
)
Middle East/Asia
1,334

1,468

(134
)
(9
)

24
Table of Contents


OPERATING INCOME:
Three Months Ended
September 30
Favorable
Percentage
Millions of dollars
2015
2014
(Unfavorable)
Change
Completion and Production
$
163

$
1,071

$
(908
)
(85
)%
Drilling and Evaluation
401

451

(50
)
(11
)
Corporate and other
(140
)
112

(252
)
(225
)
Impairments and other charges
(381
)
—

(381
)
100

Total operating income
$
43

$
1,634

$
(1,591
)
(97
)%
 
 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 
North America
$
(49
)
$
765

$
(814
)
(106
)%
Latin America
53

65

(12
)
(18
)
Europe/Africa/CIS
77

126

(49
)
(39
)
Middle East/Asia
82

115

(33
)
(29
)
Total
163

1,071

(908
)
(85
)
Drilling and Evaluation:
 

 

 

 

North America
57

141

(84
)
(60
)
Latin America
55

73

(18
)
(25
)
Europe/Africa/CIS
73

90

(17
)
(19
)
Middle East/Asia
216

147

69

47

Total
401

451

(50
)
(11
)
Total operating income by region
 

 

 

 

(excluding Corporate and other):
 
 
 
 
North America
8

906

(898
)
(99
)
Latin America
108

138

(30
)
(22
)
Europe/Africa/CIS
150

216

(66
)
(31
)
Middle East/Asia
298

262

36

14


Consolidated revenue decreased $3.1 billion, or 36%, in the third quarter of 2015, as compared to the third quarter of 2014, associated with widespread pricing pressure and activity reductions on a global basis, primarily attributable to pressure pumping in North America. Revenue outside of North America was 55% of consolidated revenue in the third quarter of 2015, compared to 46% of consolidated revenue in the third quarter of 2014, which reflects the greater impact our North America operations are experiencing as it relates to the downturn in the energy market.
Consolidated operating income decreased $1.6 billion, or 97%, during the third quarter of 2015, as compared to the third quarter of 2014, driven by a significant decline in pressure pumping activity and pricing declines in North America, coupled with $381 million of impairments and other charges recorded in the third quarter of 2015, which were primarily associated with the downturn in the energy market. See Note 3 to the condensed consolidated financial statements for further information about impairments and other charges for the third quarter of 2015.


25
Table of Contents

Completion and Production
Revenue decreased $2.2 billion, or 41%, in the third quarter of 2015, compared to the third quarter of 2014.
•
North America revenue dropped 49%, as a result of steep rig count declines, pricing concessions, and reduced activity across all product service lines, specifically stimulation activity in the United States land market.
•
Latin America revenue decreased 23%, mainly due to reduced activity and pricing in Mexico, primarily associated with pressure pumping services, lower stimulation and production solutions activity in Venezuela, and a reduction in cementing services in Colombia and Ecuador.
•
Europe/Africa/CIS revenue decreased 26%, as a result of reduced cementing services in Norway, lower production solutions services in the United Kingdom, and lower overall activity and currency weakness in Russia.
•
Middle East/Asia revenue fell 23%, mainly due to decreased pressure pumping services and production solutions activity in Saudi Arabia and a reduction in most product service lines in Australia, Malaysia, and Indonesia.
•
Revenue outside of North America was 41% of total segment revenue in the third quarter of 2015, compared to 32% of total segment revenue in the third quarter of 2014.

Operating income was $163 million, a decrease of $908 million, or 85%, compared to the third quarter of 2014.
•
North America operating income declined 106%, primarily due to the fall in rig counts and pricing pressure impacting stimulation activity and profitability.
•
Latin America operating income decreased by 18%, primarily as a result of reduced activity and profitability across all product service lines in Mexico, which was partially offset by growing production solutions activity in both Brazil and Venezuela.
•
Europe/Africa/CIS operating income decreased by 39%, mainly due to a drop across all product service lines in Egypt and the United Kingdom, along with a reduction in pressure pumping services and completion tools sales in Angola.
•
Middle East/Asia operating income fell by 29%, mainly due to reduced stimulation activity in Saudi Arabia and lower pressure pumping services in Australia.

Drilling and Evaluation
Revenue decreased $899 million, or 27%, in the third quarter of 2015, compared to the third quarter of 2014.
•
North America revenue dropped 42% due to a drop in activity across all product service lines, primarily as a result of pricing concessions and reduced activity levels for fluid and drilling services.
•
Latin America revenue decreased 34%, primarily due to lower software sales and consulting services in Mexico, reduced activity and pricing of testing services in Brazil, and the currency impact of the new exchange rate in Venezuela.
•
Europe/Africa/CIS revenue decreased 34% as a result of decreased pricing for most product service lines in Russia, lower drilling and fluid activity in Norway and Angola, and reduced drilling services and software sales in the United Kingdom.
•
Middle East/Asia revenue remained flat, as strong activity growth across most product service lines in Iraq and Saudi Arabia were offset by reduced drilling activity in Malaysia and lower logging services in China.
•
Revenue outside of North America was 75% of total segment revenue in the third quarter of 2015, compared to 69% of total segment revenue in the third quarter of 2014.

Operating income was $401 million, a decrease of $50 million, or 11%, compared to the third quarter of 2014. All regions benefited from the cessation of recognizing depreciation expense on assets held for sale. See Note 2 to the condensed consolidated financial statements for further information.
•
North America operating income decreased 60%, primarily due to decreased fluid activity and logging services in the United States land market.
•
Latin America operating income fell 25%, primarily due to declining software sales and consulting services in Mexico, which were partially offset by increased drilling activity in Brazil and Venezuela.
•
Europe/Africa/CIS operating income declined 19%, mainly due to a reduction in activity throughout most product service lines in the United Kingdom and Russia.
•
Middle East/Asia operating income improved by 47%, driven by strong activity growth across most product service lines in Saudi Arabia, Iraq, and United Arab Emirates, primarily drilling services.

Corporate and other was $140 million of expenses in the third quarter of 2015, compared to $112 million of income in the third quarter of 2014, primarily due to $82 million of costs in the third quarter of 2015 related to the pending Baker Hughes acquisition. The third quarter of 2014 included a $195 million positive impact from a reduction of our loss contingency liability and insurance recovery related to the Macondo well incident.
Impairments and other charges. Primarily as a result of the downturn in the energy market and its corresponding impact on the company’s business outlook, we recorded a total of approximately $381 million in company-wide charges during the third quarter of 2015 related to fixed asset impairments and write-offs and severance costs. See Note 3 to the condensed consolidated financial statements for further information.

26
Table of Contents


NONOPERATING ITEMS
Effective tax rate. Our effective tax rate on continuing operations for the quarter ended September 30, 2015 and September 30, 2014 was 40.8% and 26.5%, respectively. The effective tax rates in both periods were positively impacted by lower tax rates in certain foreign jurisdictions. However, the effective tax rate for the quarter ended September 30, 2015 was impacted by the tax effects of the $381 million of impairments and other charges during the period, exacerbated by our lower level of pre-tax earnings during the period. The effective tax rate for the quarter ended September 30, 2014 was positively impacted by a $201 million net operating loss valuation allowance released as a result of a reorganization of our legal entity structure in Brazil. Partially offsetting this item were tax expenses related to Macondo activity recorded during the third quarter of 2014, which was tax-effected at the United States statutory rate, as well as approximately $100 million for a write-off of certain prepaid tax assets recorded in Iraq and additional tax expenses related to the settlement of a research and development credit with the United States tax authorities.


27
Table of Contents

Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014
REVENUE:
Nine Months Ended
September 30
Favorable
Percentage
Millions of dollars
2015
2014
(Unfavorable)
Change
Completion and Production
$
10,890

$
14,782

$
(3,892
)
(26
)%
Drilling and Evaluation
7,661

9,318

(1,657
)
(18
)
Total revenue
$
18,551

$
24,100

$
(5,549
)
(23
)%
 
 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 
 
 
 

North America
$
6,737

$
9,957

$
(3,220
)
(32
)%
Latin America
1,067

1,185

(118
)
(10
)
Europe/Africa/CIS
1,600

1,940

(340
)
(18
)
Middle East/Asia
1,486

1,700

(214
)
(13
)
Total
10,890

14,782

(3,892
)
(26
)
Drilling and Evaluation:
 

 

 

 

North America
1,964

3,012

(1,048
)
(35
)
Latin America
1,388

1,616

(228
)
(14
)
Europe/Africa/CIS
1,613

2,204

(591
)
(27
)
Middle East/Asia
2,696

2,486

210

8

Total
7,661

9,318

(1,657
)
(18
)
Total revenue by region:
 

 

 

 

North America
8,701

12,969

(4,268
)
(33
)
Latin America
2,455

2,801

(346
)
(12
)
Europe/Africa/CIS
3,213

4,144

(931
)
(22
)
Middle East/Asia
4,182

4,186

(4
)
—



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Table of Contents

OPERATING INCOME:
Nine Months Ended
September 30
Favorable
Percentage
Millions of dollars
2015
2014
(Unfavorable)
Change
Completion and Production
$
938

$
2,619

$
(1,681
)
(64
)%
Drilling and Evaluation
1,107

1,263

(156
)
(12
)
Corporate and other
(401
)
(84
)
(317
)
377

Impairments and other charges
(1,895
)
—

(1,895
)
100

Total operating income (loss)
$
(251
)
$
3,798

$
(4,049
)
(107
)%
 
 
 
 
 
By geographic region:
 
 
 
 
Completion and Production:
 

 

 

 
North America
$
258

$
1,841

$
(1,583
)
(86
)%
Latin America
173

161

12

7

Europe/Africa/CIS
222

300

(78
)
(26
)
Middle East/Asia
285

317

(32
)
(10
)
Total
938

2,619

(1,681
)
(64
)
Drilling and Evaluation:
 

 

 

 

North America
159

457

(298
)
(65
)
Latin America
169

138

31

22

Europe/Africa/CIS
178

248

(70
)
(28
)
Middle East/Asia
601

420

181

43

Total
1,107

1,263

(156
)
(12
)
Total operating income by region
 

 

 

 

(excluding Corporate and other):
 
 
 
 
North America
417

2,298

(1,881
)
(82
)
Latin America
342

299

43

14

Europe/Africa/CIS
400

548

(148
)
(27
)
Middle East/Asia
886

737

149

20


Consolidated revenue decreased $5.5 billion, or 23%, in the first nine months of 2015, as compared to the first nine months of 2014, associated with pricing declines and reduced activity levels, primarily attributable to stimulation services in the United States land market, as well as lower pricing and activity in all of our product service lines in the Europe/Africa/CIS, which were partially offset by higher consulting services and drilling and fluid services in Middle East/Asia. Revenue outside of North America was 53% of consolidated revenue in the first nine months of 2015, compared to 46% of consolidated revenue in the first nine months of 2014.
Consolidated operating income decreased $4.0 billion, or 107%, in the first nine months of 2015, as compared to the first nine months of 2014, primarily as a result of $1.9 billion of impairments and other charges recorded in the first nine months of 2015, which were primarily associated with the downturn in the energy market. See Note 3 to the condensed consolidated financial statements for further information. Additionally, our consolidated operating income decline was attributable to reduced stimulation activity in the United States land market, partially offset by higher activity and operating income experienced in Middle East/Asia and Latin America.


29
Table of Contents

Completion and Production
Revenue decreased $3.9 billion, or 26%, in the first nine months of 2015, compared to the first nine months of 2014.
•
North America revenue fell by 32% as a result of decreased stimulation activity in the United States land market related to a significant drop in rig count coupled with pricing declines.
•
Latin America revenue decreased by 10%, mainly due to a decrease in pressure pumping activity in Mexico, which was partially offset by increased production solutions activity levels in Brazil.
•
Europe/Africa/CIS revenue declined by 18%, driven by reduced well completion activity in Norway, Russia and Angola.
•
Middle East/Asia revenue dropped 13%, primarily due to decreased pressure pumping activity and pricing in Australia and lower completion tools sales in Indonesia and Malaysia, which more than offset improved completion tool sales in Saudi Arabia.
•
Revenue outside of North America was 38% of total segment revenue in the first nine months of 2015, compared to 33% of total segment revenue in the first nine months of 2014.

Operating income declined by $1.7 billion, or 64%, in the first nine months of 2015, compared to the first nine months of 2014.
•
North America operating income decreased 86% as a result of reduced pressure pumping services and price degradation in the United States land market.
•
Latin America operating income grew 7%, primarily due to higher activity and profitability across most of our product service lines in Venezuela, partially offset by a decrease in stimulation activity in Argentina.
•
Europe/Africa/CIS operating income decreased 26% as a result of lower cementing services and completion tools sales in both Norway and Angola, as well as a decline across most product service lines in Egypt.
•
Middle East/Asia operating income decreased 10%, mainly due to reduced pressure pumping services in Australia, which was partially offset by increased completion tools sales in Saudi Arabia.

Drilling and Evaluation
Revenue decreased $1.7 billion, or 18%, in the first nine months of 2015, compared to the first nine months of 2014.
•
North America revenue fell by 35%, due to decreases across the majority of our product service lines in the United States land market.
•
Latin America revenue decreased 14%, primarily due to a drop in drilling and logging activity in Ecuador and Colombia coupled with a decline in offshore activity in Brazil. These decreases were partially offset by higher activity levels in most of our product service lines in Argentina, along with increased drilling and fluid activity in Venezuela.
•
Europe/Africa/CIS revenue declined by 27% as a result of reduced fluid activity in Norway, as well as lower drilling and fluid activity in Russia and Angola.
•
Middle East/Asia revenue increased 8% as a result of increased activity in most of our product services lines in Saudi Arabia and improved project management services in Indonesia, Iraq, and India, which were partially offset by lower drilling and fluid activity in Malaysia.
•
Revenue outside of North America was 74% of total segment revenue in the first nine months of 2015, compared to 68% of total segment revenue in the first nine months of 2014.

Operating income fell $156 million, or 12%, in the first nine months of 2015, compared to the first nine months of 2014. All regions benefited from the cessation of recognizing depreciation expense on assets held for sale. See Note 2 to the condensed consolidated financial statements for further information.
•
North America operating income decreased 65% due to a decline in activity for all of our product service lines in the United States land market and continued pricing pressure.
•
Latin America operating income improved by 22%, mainly due to improved drilling and logging services in Brazil, along with higher drilling and fluid activity in Venezuela.
•
Europe/Africa/CIS operating income fell by 28%, as a result of reduced drilling and fluid activity in Russia and Angola, as well as lower fluid activity in Norway.
•
Middle East/Asia operating income increased 43%, primarily due to an increase across most of our product service lines in Saudi Arabia and our drilling and consulting services in Indonesia.

Corporate and other expenses were $401 million in the first nine months of 2015 compared to $84 million in the first nine months of 2014. The increase was primarily due to $203 million of costs in the first nine months of 2015 related to the pending Baker Hughes acquisition. The first nine months of 2014 included a $195 million positive impact from a reduction of our loss contingency liability and insurance recovery related to the Macondo well incident.
Impairments and other charges. Primarily as a result of the downturn in the energy market and its corresponding impact on the company’s business outlook, we recorded a total of approximately $1.9 billion in company-wide charges during the first nine months of 2015, which consisted of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, facility closures, and other charges. See Note 3 to the condensed consolidated financial statements for further information.

30
Table of Contents


NONOPERATING ITEMS
Interest expense, net of interest income increased $28 million in the first nine months of 2015, as compared to the first nine months of 2014, primarily due to fees associated with the $8.6 billion senior unsecured bridge facility commitment related to the pending acquisition of Baker Hughes.
Other, net was a $281 million loss in the first nine months of 2015, as compared to a $43 million loss in the first nine months of 2014, primarily due to a $199 million foreign exchange loss we incurred in Venezuela in the first quarter of 2015 as a result of utilizing the new SIMADI currency exchange mechanism. See Note 3 to the condensed consolidated financial statements and "Business Environment and Results of Operations" for further information.
Effective tax rate. Our effective tax rate was 24.6% for the nine months ended September 30, 2015 and 27.0% for the nine months ended September 30, 2014. The effective tax rates in both periods were positively affected by lower tax rates in certain foreign jurisdictions. The effective tax rate for the nine months ended September 30, 2015 includes positive tax effects of the $1.9 billion of impairments and other charges recorded during the first nine months of 2015. The effective tax rate for the nine months ended September 30, 2014 was positively impacted by a $201 million net operating loss valuation allowance released as a result of a reorganization of our legal entity structure in Brazil. Partially offsetting this item were tax expenses related to Macondo activity recorded during the third quarter of 2014, which was tax-effected at the United States statutory rate, as well as approximately $100 million for a write-off of certain prepaid tax assets recorded in Iraq and additional tax expenses related to the settlement of a research and development credit with the United States tax authorities.


31
Table of Contents

ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. For information related to environmental matters, see Note 7 to the condensed consolidated financial statements.

FORWARD-LOOKING INFORMATION

The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Forward-looking information is based on projections and estimates, not historical information. Some statements in this Form 10-Q are forward-looking and use words like “may,” “may not,” “believe,” “do not believe,” “plan,” “estimate,” “intend,” “expect,” “do not expect,” “anticipate,” “do not anticipate,” “should,” “likely,” and other expressions. We may also provide oral or written forward-looking information in other materials we release to the public. Forward-looking information involves risk and uncertainties and reflects our best judgment based on current information. Our results of operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and the results of our operations may vary materially.
We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether factors change as a result of new information, future events, or for any other reason. You should review any additional disclosures we make in our press releases and Forms 10-K, 10-Q, and 8-K filed with or furnished to the SEC. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts.

Item 3. Quantitative and Qualitative Disclosures About Market Risk
For quantitative and qualitative disclosures about market risk, see Part II, Item 7(a), “Quantitative and Qualitative Disclosures About Market Risk,” in our 2014 Annual Report on Form 10-K. Our exposure to market risk has not changed materially since December 31, 2014.

Item 4. Controls and Procedures
In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2015 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
There has been no change in our internal control over financial reporting that occurred during the three and nine months ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

32
Table of Contents

PART II. OTHER INFORMATION
 
Item 1. Legal Proceedings
Information related to Item 1. Legal Proceedings is included in Note 7 to the condensed consolidated financial statements.

Item 1(a). Risk Factors
As of September 30, 2015, there have been no material changes from the risk factors previously disclosed in Part I, Item 1(a), of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Following is a summary of our repurchases of our common stock during the three months ended September 30, 2015.
Period
Total Number
of Shares Purchased (a)
Average
Price Paid per Share
Total Number
of Shares
Purchased as
Part of Publicly
Announced Plans or Programs (b)
Maximum
Number (or
Approximate
Dollar Value) of
Shares that may yet
be Purchased Under the Program (b)
July 1 - 31
34,284

$42.70
—
$5,700,004,373
August 1 - 31
14,502

$41.16
—
$5,700,004,373
September 1 - 30
20,442

$39.41
—
$5,700,004,373
Total
69,228

$41.40
—
 

(a)
All of the 69,228 shares purchased during the three-month period ended September 30, 2015 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock.
(b)
Our Board of Directors has authorized a program to repurchase our common stock from time to time. Approximately $5.7 billion remains authorized for repurchases as of September 30, 2015. From the inception of this program in February 2006 through September 30, 2015, we repurchased approximately 201 million shares of our common stock for a total cost of approximately $8.4 billion.

Item 3. Defaults Upon Senior Securities
None.

Item 4. Mine Safety Disclosures
Our barite and bentonite mining operations, in support of our fluid services business, are subject to regulation by the federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this quarterly report.

Item 5. Other Information
None.



33
Table of Contents

Item 6. Exhibits

†
10.l
Halliburton Company Stock and Incentive Plan, as amended and restated effective February 24, 2015 (incorporated by reference to Appendix B of Halliburton’s proxy statement filed April 7, 2015, File No. 1-3492).
 
 
 
†
10.2
Form of Nonstatutory Stock Option Agreement (incorporated by reference as Exhibit 99.2 of Halliburton’s Form S-8 filed July 24, 2015, Registration No. 333-205842).
 
 
 
†
10.3
Form of Restricted Stock Agreement (incorporated by reference as Exhibit 99.3 of Halliburton’s Form S-8 filed July 24, 2015, Registration No. 333-205842).
 
 
 
†
10.4
Form of Restricted Stock Unit Agreement (incorporated by reference as Exhibit 99.4 of Halliburton’s Form S-8 filed July 24, 2015, Registration No. 333-205842).
 
 
 
†
10.5
Form of Non-Employee Director Restricted Stock Unit Agreement (Director Plan) (incorporated by reference as Exhibit 99.8 of Halliburton’s Form S-8 filed July 24, 2015, Registration No. 333-205842).
 
 
 
†
10.6
Form of Non-Employee Director Restricted Stock Unit Agreement (Stock and Incentive Plan) (incorporated by reference as Exhibit 99.9 of Halliburton’s Form S-8 filed July 24, 2015, Registration No. 333-205842).
 
 
 
†
10.7
Halliburton Company Employee Stock Purchase Plan, as amended and restated effective February 24, 2015 (incorporated by reference to Appendix C of Halliburton’s proxy statement filed April 7, 2015, File No. 1-3492).
 
 
 
*
12.1
Statement Regarding the Computation of Ratio of Earnings to Fixed Charges.
 
 
 
*
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
*
31.2
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
**
32.1
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
**
32.2
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
*
95
Mine Safety Disclosures
 
 
 
*
99.1
Notice of Extension dated July 10, 2015 of the Agreement and Plan of Merger among Halliburton Company, Red Tiger LLC and Baker Hughes Incorporated dated November 16, 2014, extending termination date to December 1, 2015.
 
 
 
*
99.2
Notice of Extension dated September 25, 2015 of the Agreement and Plan of Merger among Halliburton Company, Red Tiger LLC and Baker Hughes Incorporated dated November 16, 2014, extending termination date to December 16, 2015.
 
 
 
*
101.INS
XBRL Instance Document
*
101.SCH
XBRL Taxonomy Extension Schema Document
*
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
*
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
*
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document

34
Table of Contents

*
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
 
*
Filed with this Form 10-Q.
 
**
Furnished with this Form 10-Q.
 
†
Management contracts or compensatory plans or arrangements.

35
Table of Contents

SIGNATURES


As required by the Securities Exchange Act of 1934, the registrant has authorized this report to be signed on behalf of the registrant by the undersigned authorized individuals.

HALLIBURTON COMPANY

/s/ Christian A. Garcia
/s/ Charles E. Geer, Jr.
Christian A. Garcia
Charles E. Geer, Jr.
Senior Vice President, Finance and
Vice President and
Acting Chief Financial Officer
Corporate Controller


Date: October 23, 2015


36