Document
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, 2016

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 21, 2016, there were 864,452,215 shares of Halliburton Company common stock, $2.50 par value per share, 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
2016
2015
2016
2015
Revenue:
 
 
 
 
Services
$
2,695

$
3,999

$
8,320

$
13,460

Product sales
1,138

1,583

3,546

5,091

Total revenue
3,833

5,582

11,866

18,551

Operating costs and expenses:
 

 

 

 

Cost of services
2,743

3,818

8,476

12,612

Cost of sales
919

1,221

2,843

3,945

Baker Hughes related costs and termination fee
—

82

4,057

203

Impairments and other charges
—

381

3,189

1,895

General and administrative
43

37

132

147

Total operating costs and expenses
3,705

5,539

18,697

18,802

Operating income (loss)
128

43

(6,831
)
(251
)
Interest expense, net of interest income of $18, $3, $38 and $10
(141
)
(99
)
(502
)
(311
)
Other, net
(39
)
(34
)
(117
)
(281
)
Loss from continuing operations before income taxes
(52
)
(90
)
(7,450
)
(843
)
Income tax benefit
59

37

1,836

207

Income (loss) from continuing operations
7

(53
)
(5,614
)
(636
)
Loss from discontinued operations, net
—

—

(2
)
(5
)
Net income (loss)
$
7

$
(53
)
$
(5,616
)
$
(641
)
Net (income) loss attributable to noncontrolling interest
(1
)
(1
)
2

(2
)
Net income (loss) attributable to company
$
6

$
(54
)
$
(5,614
)
$
(643
)
Amounts attributable to company shareholders:
 

 

 

 

Income (loss) from continuing operations
$
6

$
(54
)
$
(5,612
)
$
(638
)
Loss from discontinued operations, net
—

—

(2
)
(5
)
Net income (loss) attributable to company
$
6

$
(54
)
$
(5,614
)
$
(643
)
Basic income (loss) per share attributable to company shareholders:
 

 

 

 

Income (loss) from continuing operations
$
0.01

$
(0.06
)
$
(6.53
)
$
(0.75
)
Loss from discontinued operations, net
—

—

—

(0.01
)
Net income (loss) per share
$
0.01

$
(0.06
)
$
(6.53
)
$
(0.76
)
Diluted income (loss) per share attributable to company shareholders:
 

 

 

 

Income (loss) from continuing operations
$
0.01

$
(0.06
)
$
(6.53
)
$
(0.75
)
Loss from discontinued operations, net
—

—

—

(0.01
)
Net income (loss) per share
$
0.01

$
(0.06
)
$
(6.53
)
$
(0.76
)
 
 
 
 
 
Cash dividends per share
$
0.18

$
0.18

$
0.54

$
0.54

Basic weighted average common shares outstanding
862

855

860

852

Diluted weighted average common shares outstanding
864

855

860

852

     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
2016
2015
2016
2015
Net income (loss)
$
7

$
(53
)
$
(5,616
)
$
(641
)
Other comprehensive income (loss), net of income taxes:
 

 

 

 

Unrealized loss on cash flow hedges
$
—

$
(166
)
$
—

$
(62
)
Other
1

13

3

10

Other comprehensive income (loss), net of income taxes
1

(153
)
3

(52
)
Comprehensive income (loss)
$
8

$
(206
)
$
(5,613
)
$
(693
)
Comprehensive (income) loss attributable to noncontrolling interest
(1
)
(1
)
2

(2
)
Comprehensive income (loss) attributable to company shareholders
$
7

$
(207
)
$
(5,611
)
$
(695
)
     See notes to condensed consolidated financial statements.
 
 
 
 


2
Table of Contents


HALLIBURTON COMPANY
Condensed Consolidated Balance Sheets
(Unaudited)

Millions of dollars and shares except per share data
September 30,
2016
December 31,
2015
Assets
Current assets:
 
 
Cash and equivalents
$
3,289

$
10,077

Receivables (net of allowances for bad debts of $197 and $145)
4,360

5,317

Inventories
2,475

2,993

Prepaid income taxes
703

527

Other current assets
933

1,156

Total current assets
11,760

20,070

Property, plant and equipment (net of accumulated depreciation of $10,944 and $11,576)
8,741

12,117

Goodwill
2,383

2,385

Deferred income taxes
1,944

552

Other assets
1,927

1,818

Total assets
$
26,755

$
36,942

Liabilities and Shareholders’ Equity
Current liabilities:
 

 

Accounts payable
$
1,543

$
2,019

Accrued employee compensation and benefits
535

862

Liabilities for Macondo well incident
369

400

Current maturities of long-term debt
152

659

Other current liabilities
1,032

1,397

Total current liabilities
3,631

5,337

Long-term debt
12,163

14,687

Employee compensation and benefits
449

479

Other liabilities
786

944

Total liabilities
17,029

21,447

Shareholders’ equity:
 

 

Common shares, par value $2.50 per share (authorized 2,000 shares,
issued 1,070 and 1,071 shares)
2,675

2,677

Paid-in capital in excess of par value
184

274

Accumulated other comprehensive loss
(360
)
(363
)
Retained earnings
14,445

20,524

Treasury stock, at cost (206 and 215 shares)
(7,262
)
(7,650
)
Company shareholders’ equity
9,682

15,462

Noncontrolling interest in consolidated subsidiaries
44

33

Total shareholders’ equity
9,726

15,495

Total liabilities and shareholders’ equity
$
26,755

$
36,942

     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
2016
2015
Cash flows from operating activities:
 
 
Net loss
$
(5,616
)
$
(641
)
Adjustments to reconcile net loss to cash flows from operating activities:
 

 

Impairments and other charges
3,189

1,895

Deferred income tax benefit, continuing operations
(1,511
)
(411
)
Depreciation, depletion and amortization
1,117

1,433

U.S. tax refund
430

—

Payment related to the Macondo well incident
(33
)
(333
)
Changes in assets and liabilities:
 

 

Receivables
682

1,396

Accounts payable
(461
)
(469
)
Inventories
388

(23
)
Other
(947
)
(826
)
Total cash flows provided by (used in) operating activities
(2,762
)
2,021

Cash flows from investing activities:
 

 

Capital expenditures
(625
)
(1,748
)
Proceeds from sales of property, plant and equipment
176

133

Other investing activities
(73
)
(109
)
Total cash flows used in investing activities
(522
)
(1,724
)
Cash flows from financing activities:
 

 

Payments on long-term borrowings
(3,149
)
(8
)
Dividends to shareholders
(465
)
(460
)
Other financing activities
163

146

Total cash flows used in financing activities
(3,451
)
(322
)
Effect of exchange rate changes on cash
(53
)
(17
)
Decrease in cash and equivalents
(6,788
)
(42
)
Cash and equivalents at beginning of period
10,077

2,291

Cash and equivalents at end of period
$
3,289

$
2,249

Supplemental disclosure of cash flow information:
 

 

Cash payments (receipts) during the period for:
 

 

Interest
$
516

$
355

Income taxes
$
(25
)
$
454

     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 2015 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, 2016, the results of our operations for the three and nine months ended September 30, 2016 and 2015, and our cash flows for the nine months ended September 30, 2016 and 2015. 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, 2016 may not be indicative of results for the full year.

Note 2. Acquisitions and Dispositions
    
Termination of Baker Hughes acquisition
In November 2014, we entered into a merger agreement with Baker Hughes to acquire all outstanding shares of Baker Hughes in a stock and cash transaction. On April 30, 2016, we and Baker Hughes mutually terminated our merger agreement primarily because of the challenges in obtaining remaining regulatory approvals and general industry conditions that severely damaged deal economics.

In April 2015, we had 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 anticipated Baker Hughes transaction. Accordingly, beginning in April 2015, the assets and liabilities for these businesses, which are included within our Drilling and Evaluation operating segment, were classified as held for sale and the corresponding depreciation and amortization expense ceased at that time. Since our proposed divestitures no longer met the assets held for sale accounting criteria at March 31, 2016, we reclassified these businesses to assets held and used in the accompanying condensed consolidated balance sheets for both periods presented. We recorded corresponding charges during the first quarter of 2016 totaling $464 million within "Baker Hughes related costs and termination fee" in our condensed consolidated statements of operations, which included $329 million of accumulated unrecognized depreciation and amortization expense for these businesses during the period the associated assets were classified as held for sale, including the first quarter of 2016, along with $135 million of capitalized and other divestiture-related costs incurred during the first quarter. Beginning April 1, 2016, all depreciation and amortization expense associated with these businesses were included in operating costs and expenses on our condensed consolidated statements of operations.

In conjunction with the termination of our merger agreement, we paid Baker Hughes a termination fee of $3.5 billion in May 2016 and recognized this expense during the second quarter. The termination also triggered a mandatory redemption of $2.5 billion of the senior notes we had issued in November 2015 in contemplation of the transaction. We redeemed those notes in May 2016 using cash on hand at a price of 101% of their principal amount, plus accrued and unpaid interest. The notes redeemed included the $1.25 billion of 2.7% senior notes due in 2020 and $1.25 billion of 3.375% senior notes due in 2022. The redemption resulted in $41 million of fees and associated expenses included in interest expense on our condensed consolidated statements of operations for the nine months ended September 30, 2016.


5
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 whenever events or changes in circumstances indicate that the carrying value may not be recoverable, and we conduct impairment tests on goodwill annually. 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.

Market conditions have negatively impacted our business during 2016 with continued depressed commodity prices and widespread pricing pressure and activity reductions for our products and services on a global basis. As a result of these conditions and their 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. We assessed the fair value of our long-lived assets based on a discounted cash flow analysis, which required the use of significant unobservable inputs such as management’s short-term and long-term forecast of operating performance, including revenue growth rates and expected profitability margins, and a discount rate based on our weighted average cost of capital.

Over the last four years, we have been systematically converting our pressure pumping fleet in North America over to a new pump and blender design. As such, we impaired or wrote off a large portion of our older equipment, primarily during the first quarter of 2016. Additionally, current market conditions required us to take other actions to reduce some of our infrastructure and further reduce our global workforce in an effort to mitigate the impact of the industry downturn and better align our workforce with anticipated activity levels in the near-term. This resulted in a headcount reduction of approximately 13,000 for the first nine months of 2016 and corresponding severance charges recognized during the period. We also determined that the cost of some of our inventory exceeded its market value, resulting in associated write-downs of its carrying value during the nine months ended September 30, 2016.

We executed a financing agreement with our primary customer in Venezuela during the second quarter of 2016 in an effort to actively manage outstanding receivables in the country, resulting in an exchange of $200 million of outstanding trade receivables for an interest-bearing promissory note. We recorded the note at its fair market value at the date of exchange based on available pricing data points for similar assets in an illiquid market, which resulted in a $148 million pre-tax loss on exchange during the second quarter. For additional information, see Note 10 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Environment and Results of Operations.”

As a result of the events described above, we recorded impairments and other charges of approximately $3.2 billion and $1.9 billion during the nine months ended September 30, 2016 and 2015, respectively, and $381 million during the three months ended September 30, 2015. Total impairments and other charges consisted of fixed asset impairments and write-offs, severance costs, impairments of intangible assets, inventory write-downs, country and facility closures, a loss on exchange for the Venezuela promissory note, and other items. There were no impairments and other charges recorded during the three months ended September 30, 2016.

We also performed our annual goodwill impairment assessment at September 30, 2016. This assessment consists of a discounted cash flow analysis based on management’s short-term and long-term forecast of operating performance for each reporting unit. Our discounted cash flow analysis for each reporting unit includes significant assumptions regarding discount rates, revenue growth rates, expected profitability margins, forecasted capital expenditures, the timing of an anticipated market recovery, and the timing of expected future cash flows. As such, these analyses incorporate inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts. As a result of our analyses, 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, 2016.

    

6
Table of Contents

The following table presents various charges we recorded during the nine months ended September 30, 2016 and 2015 and three months ended September 30, 2015 as a result of the downturn in the energy industry and other matters, all of which were recorded within "Impairments and other charges" on our condensed consolidated statements of operations:
 
Nine Months Ended
Three Months Ended
Millions of dollars
September 30, 2016
September 30, 2015
September 30, 2015
Industry downturn:
 
 
 
Fixed asset impairments
$
2,537

$
648

$
154

Severance costs
261

308

96

Inventory write-downs
130

410

64

Intangible asset impairments
87

209

37

Other
40

173

21

Other matters:
 
 
 
Venezuela promissory note loss
148

—

—

Country closures
2

81

4

Other
(16
)
66

5

Total impairments and other charges
$
3,189

$
1,895

$
381



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 within cost of services on our statements of operations, which is part of 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
2016
2015
2016
2015
Revenue:
 
 
 
 
Completion and Production
$
2,176

$
3,200

$
6,614

$
10,890

Drilling and Evaluation
1,657

2,382

5,252

7,661

Total revenue
$
3,833

$
5,582

$
11,866

$
18,551

Operating income (loss):
 
 
 
 
Completion and Production
$
24

$
163

$
22

$
938

Drilling and Evaluation
151

401

546

1,107

Total operations
175

564

568

2,045

Corporate and other (a)
(47
)
(140
)
(4,210
)
(401
)
Impairments and other charges (b)
—

(381
)
(3,189
)
(1,895
)
Total operating income (loss)
$
128

$
43

$
(6,831
)
$
(251
)
Interest expense, net of interest income
(141
)
(99
)
(502
)
(311
)
Other, net
(39
)
(34
)
(117
)
(281
)
Loss from continuing operations before income taxes
$
(52
)
$
(90
)
$
(7,450
)
$
(843
)
(a) Corporate and other includes certain expenses not attributable to a particular business segment such as costs related to support functions and corporate executives and Baker Hughes related costs for all periods presented, including the $3.5 billion termination fee incurred during the second quarter of 2016.
(b) Impairments and other charges are as follows:
-For the three months ended September 30, 2015, 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 nine months ended September 30, 2016, includes $2.0 billion attributable to Completion and Production, $1.1 billion attributable to Drilling and Evaluation, and $8 million attributable to Corporate and other.
-For the nine 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.

Receivables
As of September 30, 2016, 23% of our gross trade receivables were from customers in the United States, 13% in Venezuela, and 11% in Saudi Arabia. As of December 31, 2015, 26% of our gross trade receivables were from customers in the United States and 14% in Venezuela. Other than the United States, Saudi Arabia, and Venezuela, no other country or single customer accounted for more than 10% of our gross trade receivables at these dates.

Venezuela. We have continued to experience delays in collecting payments on our receivables from our primary customer in Venezuela. 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. During the second quarter of 2016, we executed a financing agreement with our primary customer in Venezuela in an effort to actively manage these customer receivables, resulting in an exchange of $200 million of outstanding trade receivables for an interest-bearing promissory note.

Our total outstanding net trade receivables in Venezuela were $564 million as of September 30, 2016, excluding the promissory note receivable discussed above, compared to $704 million as of December 31, 2015, which represents 13% and 14% of total company trade receivables for the respective periods. The majority of our Venezuela receivables are United States dollar-denominated receivables. Of the $564 million of receivables in Venezuela as of September 30, 2016, $138 million have been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets. Of the $704 million of receivables in Venezuela as of December 31, 2015, $175 million have been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets.

8
Table of Contents


As a result of current conditions in Venezuela and the continued delays in collecting payments on our receivables in the country, we began curtailing activity in Venezuela during the first quarter of 2016. See Note 10 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Environment and Results of Operations” for additional information about the promissory note exchange.

Note 5. Income Taxes

During the three months ended September 30, 2016, we recorded a total income tax benefit of $59 million on pre-tax losses of $52 million, resulting in an effective tax rate of 114.3%. Our effective tax rate was primarily impacted by a $29 million tax benefit recognized during the third quarter reflecting the beneficial use of an Argentinian tax treaty that reduces the taxation of royalty payments for intellectual property. Additionally, we recognized third quarter taxable losses in our United States operations in which we recorded tax benefits at the U.S. statutory rate, offset by third quarter taxable income in our foreign operations in which the corresponding tax expenses are applied at lower statutory rates in certain jurisdictions.

During the three months ended September 30, 2015, we recorded a total income tax benefit $37 million on pre-tax losses of $90 million, resulting in an effective tax rate of 40.8%. Our effective tax rate was positively impacted by lower tax rates in certain foreign jurisdictions and 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.

Note 6. 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 $109 million as of September 30, 2016 and $138 million as of December 31, 2015. If the average cost method had been used, total inventories would have been $19 million higher than reported as of September 30, 2016 and $18 million higher as of December 31, 2015. The cost of the remaining inventory was recorded using the average cost method. Inventories consisted of the following:
Millions of dollars
September 30,
2016
December 31,
2015
Finished products and parts
$
1,528

$
1,992

Raw materials and supplies
836

879

Work in process
111

122

Total
$
2,475

$
2,993


As a result of the continued downturn in the oil and gas industry and its corresponding impact on our business outlook, we recorded inventory write-downs as the cost of some of our inventory exceeded its market value, particularly in the first nine months of 2016. See Note 3 for further information about impairments and other charges.

Finished products and parts are reported net of obsolescence reserves of $240 million as of September 30, 2016 and $251 million as of December 31, 2015.


9
Table of Contents

Note 7. 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, 2015
$
15,495

$
15,462

$
33

Payments of dividends to shareholders
(465
)
(465
)
—

Stock plans
348

348

—

Other
(39
)
(52
)
13

Comprehensive loss
(5,613
)
(5,611
)
(2
)
Balance at September 30, 2016
$
9,726

$
9,682

$
44

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


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, 2016. From the inception of this program in February 2006 through September 30, 2016, 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, 2016.
        
Accumulated other comprehensive loss consisted of the following:
Millions of dollars
September 30,
2016
December 31,
2015
Defined benefit and other postretirement liability adjustments
$
(220
)
$
(221
)
Cumulative translation adjustments
(79
)
(78
)
Other
(61
)
(64
)
Total accumulated other comprehensive loss
$
(360
)
$
(363
)

Note 8. 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.


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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. The Court has issued a preliminary approval, with the hearing for the final approval set for November 2016. 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.

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 second quarter of 2016, we made a legal fees payment of $33 million in accordance with our MDL Settlement. During the third quarter of 2016, we revised our estimate-based non-current Macondo liability with a reduction of $28 million. Accordingly, as of September 30, 2016, our remaining loss contingency liability related to the Macondo well incident was $413 million, consisting of a current portion of $369 million related to our MDL Settlement and a non-current portion of $44 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.


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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, 2016, we have incurred approximately $1.5 billion of expenses related to the MDL Settlement, legal fees, and other settlement-related costs, of which $409 million has been reimbursed or is expected to be reimbursed under our insurance program. Some of the insurance carriers that issued policies covering the final layer of insurance coverage relating to the Macondo well incident notified us that they would not reimburse us with respect to our MDL Settlement; however, we have settled with several of them and those settlement recoveries are included in the $409 million discussed above. We have initiated arbitration proceedings to pursue recovery of the remaining balance of approximately $100 million. Due to the uncertainty surrounding such recovery, no related amounts have been recognized in the condensed consolidated financial statements as of September 30, 2016.

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.

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. In June 2014, the Supreme Court reversed the Fifth Circuit and held that we are entitled to rebut that presumption of class member reliance by presenting evidence that there was no impact on our stock price from the alleged misrepresentations. 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

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based on the district court's conclusion that the court was required to assume at class certification that a disclosure was actually corrective. We appealed the ruling to the Fifth Circuit. The Fifth Circuit heard oral argument on the appeal on August 31, 2016. We are currently awaiting a decision from the Fifth Circuit. On October 19, 2016, the district court issued an order continuing the December 2016 trial date. A new trial date will be set at a later date. 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 Foreign Corrupt Practices Act (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 $53 million as of September 30, 2016 and $50 million as of December 31, 2015. Because our estimated liability is typically within a 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.


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Additionally, we have subsidiaries that have been named as potentially responsible parties along with other third parties for eight federal and state Superfund sites for which we have established reserves. As of September 30, 2016, those eight sites accounted for approximately $5 million of our $53 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 $1.9 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of September 30, 2016. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

Note 9. 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. Antidilutive securities represent potentially dilutive securities which are excluded from the computation of diluted income or loss per share as their impact would be antidilutive.

A reconciliation of the number of shares used for the basic and diluted income per share computations is as follows:
 
Three Months Ended
September 30
Nine Months Ended
September 30
Millions of shares
2016
2015
2016
2015
Basic weighted average common shares outstanding
862

855

860

852

Dilutive effect of awards granted under our stock incentive plans
2

—

—

—

Diluted weighted average common shares outstanding
864

855

860

852

 
 
 
 
 
Antidilutive shares:
 
 
 
 
Options with exercise price greater than the average market price
12

13

13

10

Options which are antidilutive due to net loss position
—

2

1

2

Total antidilutive shares
12

15

14

12


Note 10. Fair Value of Financial Instruments

At September 30, 2016, we held $96 million of investments in fixed income securities with maturities ranging from less than one year to May 2019, of which $60 million are classified as “Other current assets” and $36 million are classified as “Other assets” on our condensed consolidated balance sheets. At December 31, 2015, we held $96 million of investments in fixed income securities, of which $63 million are classified as “Other current assets” and $33 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 based on quoted prices for identical assets in less active markets (Level 2).

During the second quarter of 2016, we executed a financing agreement with our primary customer in Venezuela, resulting in an exchange of $200 million of outstanding trade receivables for an interest-bearing promissory note. We recorded the note at its fair market value at the date of exchange based on pricing data points for similar assets in an illiquid market (Level 3), resulting in a $148 million pre-tax loss on exchange. We are using an effective interest method to accrete the carrying amount to its par value as it matures. This accretion income is being recorded through “Interest expense, net of interest income” on our condensed consolidated statements of operations. As of September 30, 2016, the carrying amount of this promissory note was $60 million and approximates its fair value. This amount consists of a current portion of $14 million and non-current portion of $46 million, which are classified as “Receivables” and “Other assets,” respectively, on our condensed consolidated balance sheets. In October 2016, we agreed to exchange this promissory note for a new note with the same maturity and coupon, but which is expected to be tradeable in a more liquid market. We intend to hold the new note to maturity. 


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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. 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, 2016 and December 31, 2015. 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).

We have no financial instruments measured at fair value based on quoted prices in active markets (Level 1). 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, 2016
 
December 31, 2015
Millions of dollars
Level 1
Level 2
Total fair value
Carrying value
 
Level 1
Level 2
Total fair value
Carrying value
Long-term debt
$
783

$
12,943

$
13,726

$
12,315

 
$
1,009

$
14,947

$
15,956

$
15,346


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 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).

Note 11. New Accounting Pronouncements
    
Standards adopted in 2016

Consolidation
On January 1, 2016, we adopted an accounting standards update issued by the Financial Accounting Standards Board (FASB) related to the consolidation analysis, which amended the guidelines for determining whether certain legal entities should be consolidated. This update eliminated the presumption that a general partner should consolidate a limited partnership and modified the evaluation of whether limited partnerships are variable interest entities or voting interest entities. The adoption of this update did not materially impact our condensed consolidated financial statements.

Business Combinations
On January 1, 2016, we adopted an accounting standards update issued by the FASB which simplifies the accounting for measurement-period adjustments for an acquirer in a business combination. The update requires 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. The adoption of this update did not impact our condensed consolidated financial statements.


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Standards not yet adopted

Revenue Recognition
In May 2014, the 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.

Inventory
In July 2015, the FASB issued an accounting standards update to simplify the measurement of inventory, which requires inventory measured using the first in, first out (FIFO) or average cost methods to be subsequently measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation. Currently, these inventory methods are required to be subsequently measured at the lower of cost or market. "Market" could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. This update will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, and will be applied prospectively. Early adoption is permitted. We evaluated this new accounting standard and determined it will not have an impact on our consolidated financial statements.

Leases
In February 2016, the FASB issued an accounting standards update related to accounting for leases, which requires the assets and liabilities that arise from leases to be recognized on the balance sheet. Currently only capital leases are recorded on the balance sheet. This update will require the lessee to recognize a lease liability equal to the present value of the lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases longer than 12 months. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and liabilities and recognize the lease expense for such leases generally on a straight-line basis over the lease term. This update will be effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption is permitted. We are currently evaluating the impact that this update will have on our consolidated financial statements.

Stock-Based Compensation
In March 2016, the FASB issued an accounting standards update to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. In addition, an entity can make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest, which is the current U.S. GAAP practice, or account for forfeitures when they occur.  This update will be effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period.  Early adoption is permitted. We are currently evaluating the impact that this update will have on our consolidated financial statements.


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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, intervention, pressure control, specialty chemicals, artificial lift, and completion products and services. The segment consists of Production Enhancement, Cementing, Completion Tools, Production Solutions, Pipeline and Process Services, 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 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 50,000 employees, we operate in approximately 70 countries around the world, and our corporate headquarters are in Houston, Texas and Dubai, United Arab Emirates.

Termination of Baker Hughes acquisition
In November 2014, we entered into a merger agreement with Baker Hughes to acquire all outstanding shares of Baker Hughes in a stock and cash transaction. On April 30, 2016, primarily because of the challenges in obtaining remaining regulatory approvals and general industry conditions that severely damaged deal economics, we and Baker Hughes mutually terminated our merger agreement. As a result, we paid Baker Hughes a termination fee of $3.5 billion and recognized the tax-deductible expense in the second quarter of 2016. In addition, we mandatorily redeemed $2.5 billion of senior notes during the second quarter of 2016. See Note 2 to the condensed consolidated financial statements for further information.

Financial results
Market conditions continued to negatively impact our business during the third quarter of 2016 marked by lower activity levels and continued pricing pressure around the globe. The North America market continues to face activity and pricing challenges, with the United States land rig count at September 30, 2016 having declined over 70% from the peak in November 2014, which resulted in our recognition of third quarter operating losses in the region. However, crude prices have increased significantly since the low point in February 2016 and the North American rig count has shown improvement since a low point in May 2016, signaling that we may have hit the bottom of the industry downturn and can begin to look ahead for a potential market recovery. The third quarter average United States rig count increased 14% compared to the second quarter.

We generated $3.8 billion of revenue during the third quarter of 2016, a 31% decrease from the $5.6 billion of revenue generated in the third quarter of 2015. This decrease resulted from activity and pricing reductions in all of our product services lines, most notably stimulation activity in the United States land market. We reported operating income of $128 million in the third quarter of 2016, with a mix of positive operating results in our international business partially offset by operating losses in North America. This compares to operating income of $43 million in the third quarter of 2015, which included $381 million of company-wide impairments and other charges and $82 million of Baker Hughes related costs.

We generated $11.9 billion of revenue during the first nine months of 2016, a 36% decline from the $18.6 billion of revenue generated in the first nine months of 2015. Additionally, we recognized $6.8 billion of operating losses during the first nine months of 2016 compared to $251 million of operating losses during the first nine months of 2015. These results were negatively impacted by global activity and pricing reductions, combined with $3.2 billion and $1.9 billion of impairments and other charges recorded in the first nine months of 2016 and 2015, respectively. Additionally, operating results were negatively impacted by Baker Hughes related costs, which were $4.1 billion during the first nine months of 2016 and included a $3.5 billion merger termination fee along with charges resulting from our reversal of assets held for sale accounting, compared to $203 million of Baker Hughes-related costs during the first nine months of 2015.


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The impact of our structural global cost savings initiatives are taking shape, and our operating results are beginning to benefit from cost reductions that have been implemented during the current market downturn. We were required to reduce our global workforce in an effort to address deteriorating market conditions and better align our workforce with anticipated activity levels in the near-term. Personnel expense is one of the largest cost categories for us, and therefore, we implemented cost containment measures as they related to employees and their work locations. We reduced our global headcount by approximately 13,000 during the first nine months of 2016 and by approximately 40% since the beginning of 2015 to help mitigate the industry downturn. See Note 3 to the condensed consolidated financial statements for further information about our impairments and other charges.

Business outlook
The past several years have continued to be extremely 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 since late 2014 to help mitigate the effect on our business from the downturn in the energy market, and we will continue to evaluate our cost structure and make further adjustments as required. However, with commodity price improvements from first quarter lows and the recent uptick in North America rig count, there are signs of optimism in the industry for a potential market recovery, which we believe we are well positioned to benefit from given our delivery platform and cost containment strategies.

In North America, we continued to experience substantial pricing pressure, which has deteriorated our margins across all of our product service lines. Revenue in North America declined 33% in the third quarter of 2016 as compared to the third quarter of 2015, outperforming a 43% decline in the average North America rig count year over year. During this down cycle, we have made structural changes to our delivery platform, eliminating management layers and consolidating roles and locations. The rig count has shown recent improvement, with the average third quarter United States rig count increasing 14% when compared to the second quarter. As a result of this recent uptick in rig count and increased asset utilization in the United States land sector, our North America revenue grew sequentially for the first time in seven quarters and margins are beginning to see an improvement now that our cost savings initiatives are taking effect. Despite uncertainty surrounding customer activity around the upcoming holiday season, we anticipate our North America revenue will perform in-line with changes in the rig count in the fourth quarter. While the supply and demand balance for United States onshore services appears to be heading in the right direction, we are still in an over-supplied equipment market. Our customers remain focused on cost and producing more barrels of oil equivalent. We believe we are well positioned as we continue to collaborate with customers to engineer solutions that deliver the lowest cost per barrel of oil equivalent. We will continue to take advantage of the growing rig count by focusing on increasing equipment utilization, managing costs and expanding our surface efficiency model.

The international markets have been more resilient than North America throughout the downturn, but we experienced further activity and pricing headwinds during the third quarter, with revenue declines compared to the second quarter in all three international regions with margins remaining challenged. 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 software and product sales will be minimal this year as customer budgets are exhausted and seasonal sales may not fully offset continued pricing and activity pressures. As such, we expect margins and revenues to be flat in the fourth quarter, as compared to the third quarter, while the international markets take a little more time to rebound. In Latin America, rig activity remains low across the region, while Venezuela continues to experience significant political and economic turmoil. We expect to see a bottoming of the international rig count in the first half of 2017, driven by both cyclical and traditional seasonal impacts.


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We have adjusted to market conditions and reduced our capital expenditures to $625 million in first nine months of 2016, a reduction of over 60% from the first nine months of 2015. As a result of the actions we have taken over the past few years, we believe we are well positioned for the potential market recovery and will scale up our delivery platform by addressing our product service lines one step at a time through a combination of organic growth, investment, and selective acquisitions. We are continuing to execute the following strategies in 2016:
- 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;
-
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; and
- collaborating with our customers to maximize production at the lowest cost per barrel of oil equivalent.

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. During the second quarter of 2016, in conjunction with the termination of the Baker Hughes transaction, we paid a $3.5 billion termination fee and mandatorily redeemed $2.5 billion of debt that we issued in late 2015. In the third quarter of 2016, we paid off an additional $600 million of senior notes that matured in August, closing the quarter at $3.3 billion of cash and equivalents. This represents a $6.8 billion reduction in our cash position since December 31, 2015, but a cash improvement since June 30, 2016. This quarterly growth was driven by working capital improvements, including a reduction in our days sales outstanding, along with the receipt of a series of tax refunds. We remain committed to operating within our cash flows and continue to execute capital discipline during the current market environment. We also have $3.0 billion available under our revolving credit facility which, with our cash balance, we believe provides us with sufficient liquidity to address the challenges and opportunities of the current market. For additional information on market conditions, see “Liquidity and Capital Resources” and “Business Environment and Results of Operations.”


19
Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

As of September 30, 2016, we had $3.3 billion of cash and equivalents, compared to $10.1 billion at December 31, 2015. Additionally, we held $96 million of investments in fixed income securities at September 30, 2016 and December 31, 2015. These securities are reflected in "Other current assets" and "Other assets" in our condensed consolidated balance sheets. Approximately $1.9 billion of our total cash position as of September 30, 2016 was held by our foreign subsidiaries, a substantial portion of which is available to be repatriated into the United States to fund our U.S. operations or for general corporate purposes, with a portion subject to certain country-specific restrictions. We have provided for U.S. federal income taxes on cumulative undistributed foreign earnings where we have determined that such earnings are not indefinitely reinvested.

Significant sources and uses of cash
- Operating cash flows was a negative $2.8 billion during the first nine months of 2016, driven primarily by the $3.5 billion termination fee paid to Baker Hughes during the second quarter.
- We mandatorily redeemed $2.5 billion of senior notes in the second quarter and repaid $600 million of senior notes that matured during the third quarter.
- Capital expenditures were $625 million in the first nine months of 2016, a reduction of over 60% from the first nine months of 2015, as we continue to adapt to market conditions. These capital expenditures were predominantly made in our Production Enhancement, Sperry Drilling, Cementing, Baroid, and Production Solutions product service lines.
- During the first nine months of 2016, our primary components of working capital (receivables, inventories, and accounts payable) decreased by a net $609 million, primarily due to decreased business activity driven by current market conditions.
- We paid $465 million in dividends to our shareholders during the first nine months of 2016.
- We received a series of United States tax refunds aggregating $430 million during the third quarter of 2016, primarily related to the carryback of our net operating losses recognized in 2015. This was partially offset by tax payments for normal business operations in various foreign jurisdictions.

Future sources and uses of cash
We manufacture our own equipment, which allows us flexibility to increase or decrease our capital expenditures based on market conditions. Capital spending for the full year 2016 is currently expected to be approximately $850 million, a reduction of over 60% from the $2.2 billion of capital expenditures in 2015, which demonstrates our commitment to live within our cash flows during this challenging period for the industry. The capital expenditures plan for the remainder of the year is primarily directed toward our Production Enhancement, Sperry Drilling, Production Solutions, Wireline and Perforating and Cementing 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. In the second quarter of 2016, we made a $33 million payment in accordance with our MDL Settlement. Our total Macondo-related loss contingency liability as of September 30, 2016 was $413 million, of which $369 million is expected to be paid in the first quarter of 2017. See Note 8 to the condensed consolidated financial statements for further information.

Currently, our quarterly dividend rate is $0.18 per common share, or approximately $155 million. Subject to the approval of our Board of Directors, our intention is to continue paying dividends at our current rate.

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, 2016 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, 2016.

Other factors affecting liquidity
Financial position in current market. As of September 30, 2016, we had $3.3 billion of cash and equivalents, $96 million in fixed income investments, and $3.0 billion of available committed bank credit under our revolving credit facility. 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. We believe our cash on hand, cash flows generated from operations and our available credit facility will provide sufficient liquidity to address the challenges and opportunities of the current market and manage our global cash needs for the remainder of 2016, including capital expenditures, scheduled debt maturities, working capital investments, dividends, if any, and contingent liabilities.


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Table of Contents

Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which approximately $1.9 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of September 30, 2016. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

Credit ratings. During the third quarter of 2016, in conjunction with the termination of our merger agreement with Baker Hughes earlier in the year and as a result of general market conditions, Standard & Poor’s (S&P) changed our long-term credit rating from A- to BBB+ and changed our outlook from negative to stable. The credit ratings on our short-term debt remain A-2 with S&P. Our credit ratings with Moody’s Investors Service (Moody's) remain Baa1 for our long-term debt and P-2 for our short-term debt with a negative outlook.
 
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.

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Table of Contents

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 70 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 2016, based upon the location of the services provided and products sold, 40% of our consolidated revenue was from the United States, compared to 45% of consolidated revenue from the United States in the first nine months of 2015. 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, changes in foreign currency exchange rates, 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. Lower oil and natural gas prices usually translate into lower exploration and production budgets. Our financial performance is significantly affected by well count in North America, as well as 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
 
2016
2015
2015
Oil price - WTI (1)
$
44.84

$
46.42

$
48.69

Oil price - Brent (1)
45.79

50.25

52.36

Natural gas price - Henry Hub (2)
2.88

2.76

2.63

 
 
 
 
(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
2016
2015
2016
2015
United States:
 
 
 
 
Land
461

833

459

1,021

Offshore (incl. Gulf of Mexico)
18

33

23

38

Total
479

866

482

1,059

Canada:
 

 

 

 

Land
119

187

110

197

Offshore
2

3

2

3

Total
121

190

112

200

International (excluding Canada):
 

 

 

 

Land
711

865

740

896

Offshore
225

267

225

291

Total
936

1,132

965

1,187

Worldwide total
1,536

2,188

1,559

2,446

Land total
1,291

1,885

1,309

2,114

Offshore total
245

303

250

332

 
 
 
 
 
 
Three Months Ended
September 30
Nine Months Ended
September 30
Oil vs. Natural Gas
2016
2015
2016
2015
United States (incl. Gulf of Mexico):
 

 

 
 

Oil
391

658

388

817

Natural gas
88

208

94

242

Total
479

866

482

1,059

Canada:
 

 

 

 

Oil
64

88

54

90

Natural gas
57

102

58

110

Total
121

190

112

200

International (excluding Canada):
 

 

 

 

Oil
709

885

733

935

Natural gas
227

247

232

252

Total
936

1,132

965

1,187

Worldwide total
1,536

2,188

1,559

2,446

Oil total
1,164

1,631

1,175

1,842

Natural gas total
372

557

384

604

 
Three Months Ended
September 30
Nine Months Ended
September 30
Drilling Type
2016
2015
2016
2015
United States (incl. Gulf of Mexico):
 
 
 
 
Horizontal
373

659

376

805

Vertical
61

123

58

152

Directional
45

84

48

102

Total
479

866

482

1,059


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Table of Contents

Crude oil prices have been extremely volatile during the past few years. WTI oil spot prices declined significantly towards the second half of 2014 with a peak price of $108 per barrel in June 2014, and continued to decline throughout 2015, ranging from a high of $61 per barrel in June 2015 to a low of $35 per barrel in December 2015. WTI oil spot prices declined further into February 2016 to a low of $26 per barrel, a level which had not been experienced since 2002. Brent crude oil spot prices declined from a high of $115 per barrel in June 2014, and continued to decline throughout 2015, ranging from a high of $66 per barrel in May 2015 to a low of $35 per barrel in December 2015, and declined further to $26 per barrel in January 2016. Commodity prices have increased from the low point experienced in early 2016 to highs of $51 per barrel in June 2016 for WTI and $52 per barrel in October 2016 for Brent, although prices have continued to fluctuate significantly. We believe this price improvement could signal the beginning of a turning point in the market. Although crude oil prices continue to be lower than their 2014 and 2015 highs, growing domestic and global consumption has contributed to rising prices.

WTI and Brent crude oil spot prices had a monthly average in September 2016 of $45 per barrel and $47 per barrel, respectively. In September 2016, the partial closure of the Colonial Pipeline system led to rising stockpiles and falling prices, which contributed to decreases from the monthly average of $48 per barrel in June 2016. However, prices are expected to remain relatively unchanged for the remainder of 2016 as significant economic and geopolitical events are expected to affect market participants' expectations and demand growth. Crude oil production in the United States is projected to average 8.7 million barrels per day for the remainder of 2016.

In the United States Energy Information Administration (EIA) October 2016 "Short Term Energy Outlook," the EIA projects that Brent prices will average $48 per barrel in the fourth quarter of 2016, while WTI prices will average about $1 less per barrel. The EIA also notes that price projections are highly uncertain due to the current values of futures and options contracts. During the third quarter of 2016, in an effort to speed the market's rebalancing, the Organization of the Petroleum Exporting Countries (OPEC) tentatively agreed to cut production. This would be the group’s first deal to reduce supply in eight years. Details, including individual country targets, are expected to be finalized at a scheduled meeting in the fourth quarter. The International Energy Agency's (IEA) October 2016 "Oil Market Report" forecasts the 2016 global demand to average approximately 96.3 million barrels per day, which is up 1% from 2015, driven by an increase in the Asia Pacific region, while all other regions remain approximately the same.

For the third quarter of 2016, the average Henry Hub natural gas price in the United States increased approximately 4% from the third quarter of 2015. The Henry Hub natural gas spot price averaged $2.99 per MMBtu in September 2016, an increase of $0.40 per MMBtu, or 15%, from June 2016. Production decline and increased demand for natural gas to fuel electricity generation contributed to higher natural gas prices. The EIA October 2016 “Short Term Energy Outlook” projects Henry Hub natural gas prices to average $3.04 per MMBtu in the fourth quarter of 2016. Over the long term, the EIA expects natural gas consumption to increase primarily in the electric power sector and to a lesser extent in the industrial sector as new fertilizer and chemical projects become available.

North America operations
During the third quarter of 2016, North America oil directed rig count declined 291 rigs, or 39%, from the third quarter of 2015, while the natural gas-directed rig count in North America decreased 165 rigs, or 53%, during the same period. In the United States land market during the third quarter of 2016, there was a decline of 45% in the average rig count compared to the third quarter of 2015.

The United States land rig count has dropped 73% since its peak in November 2014. Price erosion for our services continued during the third quarter of 2016, specifically in North America, and we believe pricing pressure will continue until activity stabilizes. However, the rig count has begun to show improvement since its low point in May 2016 with a 14% increase in the average third quarter United States rig count when compared to the second quarter, and is expected to continue improving for the remainder of the year. As a result of the structural changes to our delivery platform we made during this down cycle, we believe North America margins can begin to recover going forward, and we anticipate our North America revenue for the fourth quarter to perform in-line with changes in the rig count, despite uncertainty surrounding customer activity around the upcoming holiday season. 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 create 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 ultimately recovers.

In the Gulf of Mexico, the average offshore rig count for the third quarter of 2016 was down 45% compared to the third quarter of 2015. Activity in the Gulf of Mexico is dependent on, among the factors described above and other things, governmental approvals for permits, our customers' actions, and the entry and exit of deepwater rigs in the market.


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Table of Contents

International operations
The average international rig count for the third quarter of 2016 decreased by 17% compared to the third quarter of 2015. Depressed crude oil prices have caused many 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. In Latin America, the rig count is at a 15-year low across the region, and Venezuela continues to experience significant political and economic turmoil. Latin America is expected to remain our most challenged region throughout the international down cycle, and we do not expect to see a fundamental improvement for the remainder of 2016. For our overall international business, we believe the typical seasonal uptick in year-end sales will be minimal this year as customer budgets are exhausted and seasonal sales may not fully offset continued pricing and activity pressures.

Venezuela. In February 2015, the Venezuelan government created a three-tier foreign exchange rate system, which included the National Center of Foreign Commerce official rate of 6.3 Bolívares per United States dollar, the SICAD, and the SIMADI. During the first quarter of 2015, we began utilizing the SIMADI floating rate mechanism to remeasure our net monetary assets denominated in Bolívares, with an initial market rate of 192 Bolívares per United States dollar, resulting in a foreign currency loss of $199 million recorded during the first quarter of 2015.

In February 2016, the Venezuelan government revised the three-tier exchange rate system to a new dual-rate system designed to streamline access to dollars for production and essential imports as well as combat inflation. The dual-rate exchange mechanisms are as follows: (i) the DIPRO, which replaced and devalued the official rate from 6.3 to 10.0 Bolívares per United States dollar, and represents a protected rate made available for vital imports such as food, medicine, and raw materials for production; and (ii) the DICOM, which replaces the SIMADI and which is intended to be a free floating system that will fluctuate according to market supply and demand. The DICOM had a market rate of 276 Bolívares per United States dollar at March 31, 2016 and 654 Bolívares per United States dollar at September 30, 2016. We are utilizing the DICOM to remeasure our net monetary assets denominated in Bolívares, and the revised system and continued devaluation did not materially affect our financial statements for the three and nine months ended September 30, 2016.

As of September 30, 2016, our total net investment in Venezuela was approximately $745 million, with only $1 million of net monetary assets denominated in Bolívares, and we had an additional $36 million of surety bond guarantees outstanding relating to our Venezuelan operations.

We have continued to experience delays in collecting payments on our receivables from our primary customer in Venezuela. 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. During the second quarter of 2016, we executed a financing agreement with our primary customer in Venezuela in an effort to actively manage these customer receivables, resulting in an exchange of $200 million of outstanding trade receivables for an interest-bearing promissory note. We recorded the note at its fair market value at the date of exchange, which resulted in a $148 million pre-tax loss on exchange in the second quarter. This instrument provides a more defined schedule around the timing of payments, while generating a return while we await payment. We are using an effective interest method to accrete the carrying amount to its par value as it matures. We received our first interest payment on this promissory note during the third quarter, and the carrying amount of the note was $60 million as of September 30, 2016. In October 2016, we agreed to exchange this promissory note for a new note with the same maturity and coupon, but which is expected to be tradeable in a more liquid market. We intend to hold the new note to maturity. 

Our total outstanding net trade receivables in Venezuela were $564 million as of September 30, 2016, excluding the promissory note receivable discussed above, compared to $704 million as of December 31, 2015, which represents 13% and 14% of total company trade receivables for the respective periods. The majority of our Venezuela receivables are United States dollar-denominated receivables. Of the $564 million receivables in Venezuela as of September 30, 2016, $138 million has been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets. As a result of current conditions in Venezuela and the continued delays in collecting payments on our receivables in the country, we began curtailing activity in Venezuela during the first quarter of 2016.

For additional information, see Part I, Item 1(a), “Risk Factors” in our 2015 Annual Report on Form 10-K.


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Table of Contents

RESULTS OF OPERATIONS IN 2016 COMPARED TO 2015

Three Months Ended September 30, 2016 Compared with Three Months Ended September 30, 2015
REVENUE:
Three Months Ended
September 30
Favorable
Percentage
Millions of dollars
2016
2015
(Unfavorable)
Change
Completion and Production
$
2,176

$
3,200

$
(1,024
)
(32
)%
Drilling and Evaluation
1,657

2,382

(725
)
(30
)
Total revenue
$
3,833

$
5,582

$
(1,749
)
(31
)%
 
 
 
 
 
By geographic region:
 
 
 
 
North America
$
1,658

$
2,488

$
(830
)
(33
)%
Latin America
415

739

(324
)
(44
)
Europe/Africa/CIS
744

1,021

(277
)
(27
)
Middle East/Asia
1,016

1,334

(318
)
(24
)
Total revenue
$
3,833

$
5,582

$
(1,749
)
(31
)%

OPERATING INCOME:
Three Months Ended
September 30
Favorable
Percentage
Millions of dollars
2016
2015
(Unfavorable)
Change
Completion and Production
$
24

$
163

$
(139
)
(85
)%
Drilling and Evaluation
151

401

(250
)
(62
)
Total
175

564

(389
)
(69
)
Corporate and other
(47
)
(140
)
93

66

Impairments and other charges
—

(381
)
381

100

Total operating income
$
128

$
43

$
85

198
 %
 
 
 
 
 
By geographic region:
 
 
 
 
North America
$
(66
)
$
8

$
(74
)
—

Latin America
11

108

(97
)
(90
)%
Europe/Africa/CIS
76

150

(74
)
(49
)
Middle East/Asia
154

298

(144
)
(48
)
Total
$
175

$
564

$
(389
)
(69
)%

Consolidated revenue was $3.8 billion in the third quarter of 2016, a decrease of $1.7 billion, or 31%, as compared to the third quarter of 2015, associated with widespread pricing pressure and activity reductions on a global basis, including significant reductions in North America pressure pumping. Revenue outside of North America was 57% of consolidated revenue in the third quarter of 2016, compared to 55% of consolidated revenue in the third quarter of 2015, which reflects the greater impact our North America operations are experiencing as it relates to the downturn in the energy market.

Consolidated operating income was $128 million during the third quarter of 2016 compared to operating income of $43 million in the third quarter of 2015. Operating results were impacted by declines in drilling activity, logging services and direct sales in our international operations as a result of the global downturn in the energy market. Our operating results for the three months ended September 30, 2015 were also negatively impacted by $381 million of impairments and other charges. See Note 3 to the condensed consolidated financial statements for further information about impairments and other charges.

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Table of Contents

OPERATING SEGMENTS

Completion and Production
Completion and Production (C&P) revenue in the third quarter of 2016 was $2.2 billion, a decrease of $1.0 billion, or 32%, from the third quarter of 2015, due to a decline in activity and pricing in all of our product services lines, particularly North America pressure pumping services which drove the majority of the C&P revenue decline. International revenue also declined as a result of reduced pressure pumping services and completion tool sales.

C&P operating income in the third quarter of 2016 was $24 million, a decrease of $139 million, or 85%, compared to the third quarter of 2015, with decreased profitability across all regions as a result of global activity and pricing reductions, primarily pressure pumping services and completion tool sales in our international operations.

Drilling and Evaluation
Drilling and Evaluation (D&E) revenue in the third quarter of 2016 was $1.7 billion, a decrease of $725 million, or 30%, from the third quarter of 2015. Reductions were seen across all product service lines due to the low rig count, lower pricing and customer budget constraints worldwide. Drilling, fluid and logging activity drove the declines.

D&E operating income in the third quarter of 2016 was $151 million, a decrease of $250 million, or 62%, compared to the third quarter of 2015, driven by a decline in activity and pricing across all regions, particularly drilling activity in the United States, Saudi Arabia and Nigeria. Third quarter of 2016 results were also impacted by depreciation expense from assets previously classified as held for sale in the third quarter of 2015.

GEOGRAPHIC REGIONS

North America
North America revenue in the third quarter of 2016 was $1.7 billion, a 33% decline compared to the third quarter of 2015, relative to a 43% decline in average North America rig count. We had an operating loss of $66 million compared to $8 million of operating income in the third quarter of 2015. These declines were driven by reduced activity and pricing pressure throughout the United States land market.

Latin America
Latin America revenue in the third quarter of 2016 was $415 million, a 44% reduction compared to the third quarter of 2015, with operating income of $11 million, a 90% decline from the third quarter of 2015, primarily as a result of reduced activity in Mexico, Brazil and Argentina, as well as our decision to curtail activity in Venezuela. From a product service line perspective, pressure pumping services, drilling activity and logging experienced the largest declines in both revenue and operating income. 

Europe/Africa/CIS
Europe/Africa/CIS revenue in the third quarter of 2016 was $744 million, a decline of 27% compared to the third quarter of 2015, with operating income of $76 million, a 49% decrease compared to the third quarter of 2015. The decreases during the quarter were driven by a sharp reduction of activity in the North Sea, Angola and Nigeria, along with lower drilling activity, pressure pumping services and completion tools sales throughout the region.

Middle East/Asia
Middle East/Asia revenue in the third quarter of 2016 was $1.0 billion, a reduction of 24% compared to the third quarter of 2015, with operating income of $154 million, a 48% decrease from the third quarter of 2015. This was the result of reduced activity in Indonesia, Iraq and Australia, along with lower drilling activity, direct sales and logging throughout the region.


OTHER OPERATING ITEMS

Corporate and other expenses decreased to $47 million in the third quarter of 2016, compared to $140 million of expenses in the third quarter of 2015. This decrease was primarily due to $82 million of Baker Hughes related costs in the third quarter of 2015, as well as various legal and environmental reserve adjustments in the third quarter of 2016, including a $28 million downward revision of our Macondo loss contingency liability.


27
Table of Contents

Impairments and other charges. We recorded a total of approximately $381 million in company-wide charges during the third quarter of 2015, primarily related to fixed asset impairments and write-offs and severance costs. There were no impairments and other charges recorded during the third quarter of 2016. See Note 3 to the condensed consolidated financial statements for further information.

NONOPERATING ITEMS

Interest expense, net increased $42 million in the third quarter of 2016, compared to the third quarter of 2015, primarily due to additional interest resulting from the senior notes issued in November 2015.

Effective tax rate. During the three months ended September 30, 2016, we recorded a total income tax benefit of $59 million on pre-tax losses of $52 million, resulting in an effective tax rate of 114.3%. During the three months ended September 30, 2015, we recorded a total income tax benefit $37 million on pre-tax losses of $90 million, resulting in an effective tax rate of 40.8%. See Note 5 to the condensed consolidated financial statements for significant drivers of these effective tax rates.


28
Table of Contents

Nine Months Ended September 30, 2016 Compared with Nine Months Ended September 30, 2015
REVENUE:
Nine Months Ended
September 30
Favorable
Percentage
Millions of dollars
2016
2015
(Unfavorable)
Change
Completion and Production
$
6,614

$
10,890

$
(4,276
)
(39
)%
Drilling and Evaluation
5,252

7,661

(2,409
)
(31
)
Total revenue
$
11,866

$
18,551

$
(6,685
)
(36
)%
 
 
 
 
 
By geographic region:
 
 
 
 
North America
$
4,968

$
8,701

$
(3,733
)
(43
)%
Latin America
1,432

2,455

(1,023
)
(42
)
Europe/Africa/CIS
2,317

3,213

(896
)
(28
)
Middle East/Asia
3,149

4,182

(1,033
)
(25
)
Total revenue
$
11,866

$
18,551

$
(6,685
)
(36
)%

OPERATING INCOME:
Nine Months Ended
September 30
Favorable
Percentage
Millions of dollars
2016
2015
(Unfavorable)
Change
Completion and Production
$
22

$
938

$
(916
)
(98
)%
Drilling and Evaluation
546

1,107

(561
)
(51
)
Total
568

2,045

(1,477
)
(72
)
Corporate and other
(4,210
)
(401
)
(3,809
)
—

Impairments and other charges
(3,189
)
(1,895
)
(1,294
)
(68
)
Total operating loss
$
(6,831
)
$
(251
)
$
(6,580
)
—

 
 
 
 
 
By geographic region:
 
 
 
 
North America
$
(229
)
$
417

$
(646
)
(155
)%
Latin America
81

342

(261
)
(76
)
Europe/Africa/CIS
197

400

(203
)
(51
)
Middle East/Asia
519

886

(367
)
(41
)
Total
$
568

$
2,045

$
(1,477
)
(72
)%

Consolidated revenue was $11.9 billion in the first nine months of 2016, a decrease of $6.7 billion, or 36%, as compared to the first nine months of 2015, associated with pricing declines and activity reductions on a global basis, including significant reductions in North America pressure pumping. Revenue outside of North America was 58% of consolidated revenue in the first nine months of 2016, compared to 53% of consolidated revenue in the first nine months of 2015, which reflects the greater impact our North America operations are experiencing as it relates to the downturn in the energy market.

Consolidated operating loss was $6.8 billion in the first nine months of 2016 compared to an operating loss of $251 million during the first nine months of 2015. Operating results were negatively impacted by $3.2 billion and $1.9 billion of impairments and other charges recorded in the nine months ended September 30, 2016 and 2015, respectively. Additionally, we incurred $4.1 billion of Baker Hughes related costs during the first nine months of 2016, primarily due to the $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting, compared to $203 million of Baker Hughes related costs during the first nine months of 2015. Also contributing to these operating results were significant declines in pressure pumping activity and pricing declines in North America as a result of the global downturn in the energy market. See Note 2 to the condensed consolidated financial statements for further discussion of the Baker Hughes transaction and financial statement impact of terminating our merger agreement and Note 3 to the condensed consolidated financial statements for further information about impairments and other charges.


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OPERATING SEGMENTS

Completion and Production
Completion and Production (C&P) revenue in the first nine months of 2016 was $6.6 billion, a decrease of $4.3 billion, or 39%, from the first nine months of 2015, due to a decline in activity and pricing in most of our product services lines, particularly North America pressure pumping services which drove the majority of the C&P revenue decline. International revenue declined as a result of reductions in pressure pumping activity and well completion services in all regions.

C&P operating income in the first nine months of 2016 was $22 million, compared to $938 million of operating income in the first nine months of 2015, with decreased profitability across all regions as a result of global activity and pricing reductions, primarily in North America pressure pumping services.

Drilling and Evaluation
Drilling and Evaluation (D&E) revenue in the first nine months of 2016 was $5.3 billion, a decrease of $2.4 billion, or 31%, from the first nine months of 2015. Reductions were seen across all product service lines due to the low rig count, lower pricing and customer budget constraints worldwide.

D&E operating income in the first nine months of 2016 was $546 million, a decrease of $561 million, or 51%, compared to the first nine months of 2015, driven by a decline in activity and pricing across all regions, particularly drilling and logging activity in North America, as well as reduced drilling activity in Latin America, decreased drilling activity in the Europe/Africa/CIS region, and lower drilling and logging activity in the Middle East/Asia region.

GEOGRAPHIC REGIONS

North America
North America revenue in the first nine months of 2016 was $5.0 billion, a 43% decline compared to the first nine months of 2015, relative to a 53% decline in average North America rig count. We had an operating loss of $229 million, a substantial reduction from the $417 million of operating income reported in the first nine months of 2015. These declines were driven by reduced activity and pricing pressure throughout the United States land market, specifically relating to pressure pumping services and drilling activity.

Latin America
Latin America revenue in the first nine months of 2016 was $1.4 billion, a 42% reduction compared to the first nine months of 2015, with operating income of $81 million, a 76% decline from the first nine months of 2015. These reductions were primarily related to our decision to curtail activity in Venezuela and currency weakness in the country, reduced activity across all product service lines in Mexico, and lower drilling activity in Brazil and Colombia.

Europe/Africa/CIS
Europe/Africa/CIS revenue in the first nine months of 2016 was $2.3 billion, a decline of 28% compared to the first nine months of 2015, with operating income of $197 million, a 51% decrease compared to the first nine months of 2015. These decreases were driven by a sharp reduction of activity in the North Sea, Angola, Nigeria and Congo, along with lower drilling activity, pressure pumping services and completion tools sales throughout the region.

Middle East/Asia
Middle East/Asia revenue in the first nine months of 2016 was $3.1 billion, a reduction of 25% compared to the first nine months of 2015, with operating income of $519 million, a 41% decrease from the first nine months of 2015. This was the result of pricing concessions across the region, along with reduced activity for pressure pumping services in Saudi Arabia and Australia, a decline in drilling and logging activity in Indonesia and Malaysia, and lower project management activity in India, Iraq, and Australia.


OTHER OPERATING ITEMS

Corporate and other expenses were $4.2 billion in the first nine months of 2016 compared to $401 million in the first nine months of 2015, primarily driven by Baker Hughes related costs. During the first nine months of 2016, we incurred a $3.5 billion termination fee and $464 million of charges resulting from our reversal of assets held for sale accounting, as compared to $203 million of Baker Hughes related costs during the first nine months of 2015. See Note 2 to the condensed consolidated financial statements for further discussion of the Baker Hughes transaction and the financial statement impact of terminating our merger agreement.

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Table of Contents


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 $3.2 billion in company-wide charges during the first nine months of 2016, which consisted of fixed asset impairments and write-offs, inventory write-downs, impairments of intangible assets, severance costs, facility closures, a loss on exchange for a promissory note in Venezuela, and other charges. This compares to $1.9 billion of impairments and other charges recorded in 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.

NONOPERATING ITEMS

Interest expense, net increased $191 million in the first nine months of 2016, as compared to the first nine months of 2015. This was primarily due to additional interest resulting from the senior notes issued in November 2015, coupled with $41 million of redemption fees and associated costs related to the $2.5 billion debt mandatorily redeemed during the second quarter of 2016, which was recorded through interest expense.

Other, net was a $117 million loss in the first nine months of 2016, as compared to a $281 million loss in the first nine months of 2015, driven by foreign currency exchange losses in various countries. The primary driver for the decrease was in Venezuela, where we recognized a $199 million foreign currency exchange loss during the first quarter of 2015 as a result of utilizing the new currency exchange mechanism to remeasure net monetary assets in the country. See "Business Environment and Results of Operations" for further information.




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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 8 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 2015 Annual Report on Form 10-K. Our exposure to market risk has not changed materially since December 31, 2015.

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, 2016 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 quarter ended September 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Table of Contents

PART II. OTHER INFORMATION
 
Item 1. Legal Proceedings

Information related to Item 1. Legal Proceedings is included in Note 8 to the condensed consolidated financial statements.

Item 1(a). Risk Factors

The statements in this section describe the known material risks to our business and should be considered carefully. As of September 30, 2016, 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, 2015.

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, 2016.
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
43,606

$43.95
—
$5,700,004,373
August 1 - 31
49,030

$43.87
—
$5,700,004,373
September 1 - 30
81,466

$41.21
—
$5,700,004,373
Total
174,102

$42.65
—
 

(a)
All of the 174,102 shares purchased during the three-month period ended September 30, 2016 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, 2016. From the inception of this program in February 2006 through September 30, 2016, 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.


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Table of Contents

Item 6. Exhibits

 
3.1
By-laws of Halliburton Company revised effective September 14, 2016 (incorporated by reference to Exhibit 3.1 to Halliburton’s Form 8-K filed September 16, 2016, File No. 001-03492).
 
 
 
*†
10.1
Amendment No. 2 to Halliburton Company Benefit Restoration Plan, as amended and restated effective January 1, 2008.
 
 
 
*†
10.2
Second Amendment to Halliburton Company Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2008.
 
 
 
*†
10.3
Form of Nonstatutory Stock Option Agreement.
 
 
 
*
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
 
 
 
*
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
*
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

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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/ Mark A. McCollum
/s/ Charles E. Geer, Jr.
Mark A. McCollum
Charles E. Geer, Jr.
Executive Vice President and
Vice President and
Chief Financial Officer
Corporate Controller


Date: October 28, 2016


35