HALLIBURTON CO - FORM 10-Q - April 28, 2017

Attached files

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EX-12.1 - STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - HALLIBURTON COhal_03312017-ex121.htm
EX-95 - MINE SAFETY DISCLOSURES - HALLIBURTON COhal_03312017-ex95.htm
EX-32.2 - 906 CERTIFICATION FOR CFO - HALLIBURTON COhal_03312017-ex322.htm
EX-32.1 - 906 CERTIFICATION FOR CEO - HALLIBURTON COhal_03312017-ex321.htm
EX-31.2 - 302 CERTIFICATION FOR CFO - HALLIBURTON COhal_03312017-ex312.htm
EX-31.1 - 302 CERTIFICATION FOR CEO - HALLIBURTON COhal_03312017-ex311.htm
EX-10.1 - EXECUTIVE AGREEMENT (ANNE LYN BEATY) - HALLIBURTON COhal_03312017-ex101.htm
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 March 31, 2017

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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
[X]
Accelerated filer
[   ]
 
Non-accelerated filer
[   ]
(Do not check if a smaller reporting company)
 
Smaller reporting company
[   ]
Emerging growth company
[   ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Yes
[   ]
No
[ ]

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 April 21, 2017, there were 867,868,425 shares of Halliburton Company common stock, $2.50 par value per share, outstanding.


HALLIBURTON COMPANY

Index

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

HALLIBURTON COMPANY
Condensed Consolidated Statements of Operations
(Unaudited)
 
Three Months Ended
March 31
Millions of dollars and shares except per share data
2017
2016
Revenue:
 
 
Services
$
3,151

$
2,985

Product sales
1,128

1,213

Total revenue
4,279

4,198

Operating costs and expenses:
 

 

Cost of services
3,103

2,956

Cost of sales
918

969

General and administrative
55

48

Impairments and other charges
—

2,766

Merger-related costs
—

538

Total operating costs and expenses
4,076

7,277

Operating income (loss)
203

(3,079
)
Interest expense, net of interest income of $23 and $10
(242
)
(165
)
Other, net
(18
)
(47
)
Loss from continuing operations before income taxes
(57
)
(3,291
)
Income tax benefit
25

875

Loss from continuing operations
(32
)
(2,416
)
Loss from discontinued operations, net
—

(2
)
Net loss
$
(32
)
$
(2,418
)
Net loss attributable to noncontrolling interest
—

6

Net loss attributable to company
$
(32
)
$
(2,412
)
Amounts attributable to company shareholders:
 

 

Loss from continuing operations
$
(32
)
$
(2,410
)
Loss from discontinued operations, net
—

(2
)
Net loss attributable to company
$
(32
)
$
(2,412
)
 
 

 

Basic and diluted net loss per share attributable to company
$
(0.04
)
$
(2.81
)
Basic and diluted weighted average common shares outstanding
867

858

Cash dividends per share
$
0.18

$
0.18

     See notes to condensed consolidated financial statements.
 
 

1

HALLIBURTON COMPANY
Condensed Consolidated Statements of Comprehensive Income
(Unaudited)

 
Three Months Ended
March 31
Millions of dollars
2017
2016
Net loss
$
(32
)
$
(2,418
)
Other comprehensive income (loss), net of income taxes
2

(1
)
Comprehensive loss
$
(30
)
$
(2,419
)
Comprehensive loss attributable to noncontrolling interest
—

6

Comprehensive loss attributable to company shareholders
$
(30
)
$
(2,413
)
     See notes to condensed consolidated financial statements.
 
 


2


HALLIBURTON COMPANY
Condensed Consolidated Balance Sheets
(Unaudited)

Millions of dollars and shares except per share data
March 31,
2017
December 31,
2016
Assets
Current assets:
 
 
Cash and equivalents
$
2,107

$
4,009

Receivables (net of allowances for bad debts of $156 and $175)
4,008

3,922

Inventories
2,295

2,275

Prepaid income taxes
555

585

Other current assets
863

886

Total current assets
9,828

11,677

Property, plant and equipment (net of accumulated depreciation of $11,446 and $11,198)
8,415

8,532

Goodwill
2,419

2,414

Deferred income taxes
2,141

1,960

Other assets
2,082

2,417

Total assets
$
24,885

$
27,000

Liabilities and Shareholders’ Equity
Current liabilities:
 

 

Accounts payable
$
2,006

$
1,764

Accrued employee compensation and benefits
544

544

Current maturities of long-term debt
97

163

Other current liabilities
1,195

1,552

Total current liabilities
3,842

4,023

Long-term debt
10,812

12,214

Employee compensation and benefits
539

574

Other liabilities
703

741

Total liabilities
15,896

17,552

Shareholders’ equity:
 

 

Common shares, par value $2.50 per share (authorized 2,000 shares,
issued 1,069 and 1,070 shares)
2,674

2,674

Paid-in capital in excess of par value
222

201

Accumulated other comprehensive loss
(452
)
(454
)
Retained earnings
13,569

14,141

Treasury stock, at cost (202 and 204 shares)
(7,062
)
(7,153
)
Company shareholders’ equity
8,951

9,409

Noncontrolling interest in consolidated subsidiaries
38

39

Total shareholders’ equity
8,989

9,448

Total liabilities and shareholders’ equity
$
24,885

$
27,000

     See notes to condensed consolidated financial statements.
 
 


3

HALLIBURTON COMPANY
Condensed Consolidated Statements of Cash Flows
(Unaudited)


 
Three Months Ended
March 31
Millions of dollars
2017
2016
Cash flows from operating activities:
 
 
Net loss
$
(32
)
$
(2,418
)
Adjustments to reconcile net loss to cash flows from operating activities:
 

 

Depreciation, depletion and amortization
383

346

Payment related to the Macondo well incident
(335
)
—

Deferred income tax benefit, continuing operations
(132
)
(857
)
Impairments and other charges
—

2,766

Changes in assets and liabilities:
 

 

Accounts payable
228

(170
)
Receivables
(178
)
228

Inventories
(18
)
34

Other
89

(100
)
Total cash flows provided by (used in) operating activities
5

(171
)
Cash flows from investing activities:
 

 

Capital expenditures
(265
)
(234
)
Proceeds from sales of property, plant and equipment
41

50

Other investing activities
(13
)
(24
)
Total cash flows used in investing activities
(237
)
(208
)
Cash flows from financing activities:
 

 

Payments on long-term borrowings
(1,566
)
—

Dividends to shareholders
(156
)
(154
)
Other financing activities
63

77

Total cash flows used in financing activities
(1,659
)
(77
)
Effect of exchange rate changes on cash
(11
)
(28
)
Decrease in cash and equivalents
(1,902
)
(484
)
Cash and equivalents at beginning of period
4,009

10,077

Cash and equivalents at end of period
$
2,107

$
9,593

Supplemental disclosure of cash flow information:
 

 

Cash payments during the period for:
 

 

Interest
$
173

$
164

Income taxes
$
77

$
121

     See notes to condensed consolidated financial statements.
 
 


4

HALLIBURTON COMPANY
Notes to Condensed Consolidated Financial Statements
(Unaudited)

Note 1. Basis of Presentation

The accompanying unaudited condensed consolidated financial statements were prepared using United States generally accepted accounting principles (U.S. GAAP) 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 U.S. GAAP for annual financial statements and should be read together with our 2016 Annual Report on Form 10-K.

Our accounting policies are in accordance with U.S. GAAP. 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 March 31, 2017, the results of our operations for the three months ended March 31, 2017 and 2016, and our cash flows for the three months ended March 31, 2017 and 2016. 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 months ended March 31, 2017 may not be indicative of results for the full year.

Note 2. 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 using 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
March 31
Millions of dollars
2017
2016
Revenue:
 
 
Completion and Production
$
2,604

$
2,324

Drilling and Evaluation
1,675

1,874

Total revenue
$
4,279

$
4,198

Operating income (loss):
 
 
Completion and Production
$
147

$
30

Drilling and Evaluation
122

241

Total operations
269

271

Corporate and other (a)
(66
)
(584
)
Impairments and other charges
—

(2,766
)
Total operating income (loss)
$
203

$
(3,079
)
Interest expense, net of interest income (b)
(242
)
(165
)
Other, net
(18
)
(47
)
Loss from continuing operations before income taxes
$
(57
)
$
(3,291
)
(a) Includes certain expenses not attributable to a particular business segment such as costs related to support functions and corporate executives, as well as merger-related costs incurred during the three months ended March 31, 2016.
(b) Includes $104 million of costs related to the early extinguishment of $1.4 billion of senior notes in the three months ended March 31, 2017.

5


Receivables
As of March 31, 2017, 37% of our gross trade receivables were from customers in the United States and 15% were from customers in Venezuela. As of December 31, 2016, 28% of our gross trade receivables were from customers in the United States and 15% were from customers in Venezuela. Other than the United States 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.

Our total outstanding net trade receivables in Venezuela were $636 million as of March 31, 2017, compared to $610 million as of December 31, 2016, which represents 15% of total company trade receivables for both periods. The majority of our Venezuela receivables are United States dollar-denominated receivables. Of the $636 million of receivables in Venezuela as of March 31, 2017, $441 million have been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets.

In addition, we currently hold an interest-bearing promissory note with our primary customer in Venezuela with a par value of $200 million, and we have been receiving quarterly interest payments on this note in accordance with the dates outlined in the agreement. See Note 8 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.

Note 3. Inventories

Inventories are stated at the lower of cost and net realizable 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 $135 million as of March 31, 2017 and $133 million as of December 31, 2016. If the average cost method had been used, total inventories would have been $18 million higher than reported as of March 31, 2017 and $16 million higher as of December 31, 2016. The cost of the remaining inventory was recorded using the average cost method. Inventories consisted of the following:
Millions of dollars
March 31,
2017
December 31,
2016
Finished products and parts
$
1,448

$
1,388

Raw materials and supplies
713

778

Work in process
134

109

Total
$
2,295

$
2,275


All amounts in the table above are reported net of obsolescence reserves of $265 million as of March 31, 2017 and $263 million as of December 31, 2016.

Note 4. Debt

In March 2017, we used cash on hand to redeem an aggregate principal amount of $1.4 billion of senior notes, which consisted of $400 million of 5.90% senior notes due September 2018 and $1.0 billion of 6.15% senior notes due September 2019. In conjunction with this redemption, we terminated a series of interest rate swaps associated with these senior notes. As a result, we recorded $104 million in costs related to the early extinguishment of debt, which included the redemption premium and a write-off of the remaining original debt issuance costs and debt discount, partially offset by a gain from the termination of the related interest rate swap agreements. These debt extinguishment costs are included in interest expense on our condensed consolidated statement of operations for the three months ended March 31, 2017.


6

Note 5. 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, 2016
$
9,448

$
9,409

$
39

Retained earnings adjustment for new accounting standard (a)
(384
)
(384
)
—

Payments of dividends to shareholders
(156
)
(156
)
—

Stock plans
120

120

—

Other
(9
)
(8
)
(1
)
Comprehensive loss
(30
)
(30
)
—

Balance at March 31, 2017
$
8,989

$
8,951

$
38

(a) Represents a cumulative-effect adjustment to retained earnings upon our adoption of a new accounting standards update on the income tax consequences of intra-entity transfers of assets other than inventory which was effective January 1, 2017. See Note 9 for further information.
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
(154
)
(154
)
—

Stock plans
126

126

—

Other
12

(6
)
18

Comprehensive loss
(2,419
)
(2,413
)
(6
)
Balance at March 31, 2016
$
13,060

$
13,015

$
45


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 March 31, 2017. From the inception of this program in February 2006 through March 31, 2017, 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 three months ended March 31, 2017.
        
Accumulated other comprehensive loss consisted of the following:
Millions of dollars
March 31,
2017
December 31,
2016
Defined benefit and other postretirement liability adjustments
$
(314
)
$
(313
)
Cumulative translation adjustments
(80
)
(80
)
Other
(58
)
(61
)
Total accumulated other comprehensive loss
$
(452
)
$
(454
)

Note 6. 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. 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.
    

7

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. 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 well incident 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 eliminating our exposure in the MDL for punitive damages.

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) for an aggregate of $1.1 billion. Certain conditions had to be satisfied before our MDL Settlement became effective. These conditions included, among others, the issuance of a final order of the MDL court approving our MDL Settlement and the resolution of any appeals therefrom. The Court has issued that final approval of our MDL Settlement and the period for appeal has expired. 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. We have also entered into an agreement with Transocean to dismiss all claims made against each other. During the first quarter of 2017, we made our third and final installment payment of $335 million, and in April 2017, we made our third and final legal fees payment of $33 million. All of our payments with respect to our MDL Settlement have now been made. We believe that there is no additional material financial exposure to us in relation to the Macondo well incident.

Securities and related litigation
In June 2002, a class action lawsuit was commenced against us in federal court alleging violations of the federal securities laws 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).

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. and our disclosures and reserves relating to our 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 and in March 2007 the court ordered that the case proceed against our CEO and us.

In September 2007, the Fund filed a motion for class certification. 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 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 affirmed the district court's order. In June 2014, the Supreme Court reversed the Fifth Circuit and held that we were 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 July 2015, the district court denied certification for the plaintiff class with respect to five of the six dates upon which the plaintiff 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. We appealed the ruling to the Fifth

8

Circuit. The Fifth Circuit heard oral argument on the appeal in August 2016 and its consideration of the appeal is suspended pending finalization of the settlement discussed below.

In December 2016, we reached an agreement in principle to settle this lawsuit, without any admission of liability and subject to approval by the district court. We will fund approximately $54 million of the $100 million settlement fund, and our insurer will fund the balance. As of March 31, 2017, we have accrued a liability of $100 million with an offsetting $46 million insurance receivable on our condensed consolidated balance sheets. Plaintiff’s counsel fees and costs will be awarded from the settlement fund. On March 31, 2017, the district court granted its order preliminarily approving the settlement. The settlement remains subject to final approval of the district court following notice to class members.

The settlement resolves all pending cases other than Magruder v. Halliburton Co., et. al. (the Magruder case). The allegations arise out of the same general events described above, but for a later class period, December 8, 2001 to May 28, 2002. There has been limited activity in the Magruder case. In March 2009, our motion to dismiss was granted, with leave to re-plead; in March 2012, plaintiffs filed an amended complaint and in May 2012, we filed another motion to dismiss, which remains pending. We cannot predict the outcome or consequences of this case, which we intend to vigorously defend.

Investigations
We have conducted 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. We have engaged outside counsel and independent forensic accountants to assist us with these investigations.

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 to satisfy local content requirements. The e-mail also alleged conflicts of interest, self-dealing, and the failure to act on alleged violations of our COBC and the FCPA. We contacted the Department of Justice (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.

Our counsel has engaged in discussions with the SEC staff concerning a potential resolution of the investigations. Any potential resolution will be subject not only to an agreement with the SEC staff on specific terms and specific language in the settlement documentation, but also to approval of the Commissioners of the SEC and agreement with the DOJ. Accordingly, there can be no assurance that the discussions with the SEC will result in a final resolution of the investigations or, if a resolution is achieved, the timing of such resolution. In the event a resolution is not agreed to and approved, we cannot predict the ultimate outcome of the investigations 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 we are

9

involved in 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 $49 million as of March 31, 2017 and $50 million as of December 31, 2016. 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.

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 March 31, 2017, those eight sites accounted for approximately $4 million of our $49 million total environmental reserve. Despite attempts to resolve these Superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount accrued. With respect to some Superfund sites, we have been named a potentially responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims with respect to environmental matters for which we have been named as a potentially responsible party.

Guarantee arrangements
In the normal course of business, we have agreements with financial institutions under which approximately $2.0 billion of letters of credit, bank guarantees or surety bonds were outstanding as of March 31, 2017. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization. None of these off balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements.

Note 7. 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 shares represent potential common shares 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
March 31
Millions of shares
2017
2016
Basic weighted average common shares outstanding
867

858

Dilutive effect of awards granted under our stock incentive plans
—

—

Diluted weighted average common shares outstanding
867

858

 
 
 
Antidilutive shares:
 
 
Options with exercise price greater than the average market price
4

17

Options which are antidilutive due to net loss position
3

1

Total antidilutive shares
7

18


Note 8. Fair Value of Financial Instruments

At March 31, 2017, we held $92 million of investments in fixed income securities with maturities ranging from less than one year to May 2019, of which $54 million are classified as “Other current assets” and $38 million are classified as “Other assets” on our condensed consolidated balance sheets. At December 31, 2016, we also held $92 million of investments in fixed income securities. These securities consist primarily of corporate bonds and other debt instruments, are accounted for as available-for-sale and are recorded at fair value on quoted prices for identical assets in less active markets, which are categorized within level 2 on the fair value hierarchy.

At March 31, 2017 and December 31, 2016, we held an interest-bearing promissory note with our primary customer in Venezuela with a par value of $200 million. The carrying amount of this promissory note was $83 million as of March 31, 2017, which consists of a current portion of $47 million and non-current portion of $36 million, and are classified as “Receivables” and “Other assets,” respectively, on our condensed consolidated balance sheets. The carrying amount as of December 31, 2016 was $70 million. The carrying amounts for both periods approximate fair value. Initial fair value of the promissory note was based on pricing data points for similar assets in an illiquid market and is categorized within level 3 on the fair value hierarchy. We are using an effective interest method to accrete the carrying amount to its par value as it matures. This

10

accretion income is being recorded through “Interest expense, net of interest income” on our condensed consolidated statements of operations.

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 use interest rate swaps to effectively convert a portion of our fixed rate debt to floating LIBOR-based rates. Our interest rate swaps, which expire when the underlying debt matures, are designated as fair value hedges of the underlying debt and are determined to be highly effective. These derivative instruments are marked to market with gains and losses recognized currently in interest expense to offset the respective gains and losses recognized on changes in the fair value of the hedged debt. During the first quarter of 2017, we terminated a series of our interest rate swaps with a notional amount of $1.4 billion in conjunction with our early redemption of senior notes. We included the gain from the swap termination in our calculation of early debt extinguishment costs. See Note 4 for further information. As of March 31, 2017, we had one remaining interest rate swap relating to one of our debt instruments with a total notional amount of $100 million. The fair value of our interest rate swaps are included in “Other assets” in our condensed consolidated balance sheets and were immaterial as of March 31, 2017 and December 31, 2016. The fair value of our interest rate swaps are categorized within level 2 on the fair value hierarchy and were 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.

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:
 
March 31, 2017
 
December 31, 2016
Millions of dollars
Level 1
Level 2
Total fair value
Carrying value
 
Level 1
Level 2
Total fair value
Carrying value
Long-term debt
$
753

$
11,209

$
11,962

$
10,909

 
$
753

$
12,812

$
13,565

$
12,377


Our debt categorized within level 1 on the fair value hierarchy is calculated using quoted prices in active markets for identical liabilities with transactions occurring on the last two days of period-end. Our debt categorized within level 2 on the fair value hierarchy is 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. Our total fair value and carrying value of debt decreased in the first quarter of 2017 due to the early extinguishment of $1.4 billion of senior notes. We have no debt categorized within level 3 on the fair value hierarchy based on unobservable inputs.

Note 9. New Accounting Pronouncements
    
Standards adopted in 2017

Stock-Based Compensation
On January 1, 2017, we adopted an accounting standards update issued by the Financial Accounting Standards Board (FASB) which simplifies 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, the update allows an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur. The element of the update that will have the most impact on our financial statements will be income tax consequences. Excess tax benefits and tax deficiencies on stock-based compensation awards are now included in our tax provision within our condensed consolidated statement of operations as discrete items in the reporting period in which they occur, rather than previous accounting of recording in additional paid-in capital on our condensed consolidated balance sheets. We have also elected to continue our current policy of estimating forfeitures of stock-based compensation awards at the time of grant and revising in subsequent periods to reflect actual forfeitures. We applied the update prospectively beginning January 1, 2017, and the adoption did not have a material impact on our condensed consolidated financial statements.

11


Intra-Entity Transfers of Assets
On January 1, 2017, we adopted an accounting standards update issued by the FASB to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. The update requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs, rather than the previous requirement to defer recognition of current and deferred income taxes for an intra-entity asset transfer until the asset had been sold to an outside party. Two common examples of assets included in the scope of this update are intellectual property and property, plant and equipment. The update was applied on a modified retrospective basis resulting in a cumulative-effect adjustment of $384 million recorded directly to retained earnings as of January 1, 2017.

Inventory
On January 1, 2017, we adopted an accounting standards update issued by the FASB which simplifies the measurement of inventory. The update now requires inventory measured using the first in, first out 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. The update eliminated the requirement to subsequently measure inventory at the lower of cost or market, which could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The adoption of this update did not impact our condensed consolidated financial statements.

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 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. This new revenue recognition standard will be effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.

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.

We are currently determining the impacts of the new standard on our contract portfolio. Our approach includes performing a detailed review of key contracts representative of our different businesses and comparing historical accounting policies and practices to the new standard. Because the standard will impact our business processes, systems and controls, we are also developing a comprehensive change management project plan to guide the implementation. Our services are primarily short-term in nature, and our assessment at this stage is that we do not expect the new revenue recognition standard will have a material impact on our financial statements upon adoption. We are still evaluating software contracts within our Landmark Software and Services product service line and long-term contracts requiring integrated project management services within our Consulting and Project Management product service line for potential impact from the new accounting guidance. We currently intend on adopting the new standard utilizing the modified retrospective method that will result in a cumulative effect adjustment as of January 1, 2018.

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 condensed consolidated financial statements.

12

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 primary geographic regions: North America, Latin America, Europe/Africa/CIS and Middle East/Asia. We have manufacturing operations in various locations, the most significant of which are located in the United States, Canada, 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.

Financial results
Market conditions continued to impact our business during the first quarter of 2017 marked by the rapid increase in North American land rig count, while continued cyclical headwinds and seasonal pressures affected the international markets. The North America market continues to improve, with the United States land rig count for the first quarter of 2017 having increased 27% from the fourth quarter of 2016, which resulted in sequential revenue growth of 24% in the North America region. However, the international markets have been slower to recover and continue to face pricing pressure and activity declines, while customers defer new projects and focus on lowering costs. We believe the cost challenges are part of the evolution of the cycle and believe that we are positioned to provide long-term profitable opportunities with our margin-focused strategy.

We generated total company revenue of $4.3 billion during the first quarter of 2017, a 2% increase from the $4.2 billion of revenue generated in the first quarter of 2016. This slight increase resulted from rising pressure pumping services and drilling activity in the United States land market offset by lower pricing and activity across the international markets. We reported operating income of $203 million in the first quarter of 2017, compared to operating loss of $3.1 billion in the first quarter of 2016, which included $2.8 billion of company-wide impairments and other charges and $538 million of merger-related costs. Our operating results are now benefiting from the structural global cost savings initiatives implemented during the market downturn.

We made the decision to bring back cold-stacked equipment more rapidly than originally planned because of customer demand, thus forgoing short-term margin increases to maintain our market share. However, we are not pursuing market share at the cost of pricing. We believe that maximizing our profitability in the long term starts with stabilizing our market share. Given the significant level of customer demand we are experiencing, we are able to add equipment and improve our margins by putting this equipment to work at leading edge pricing. As a result of this reactivation of equipment, we hired approximately 2,000 employees in the United States in the first quarter, incurring additional personnel and training costs. We believe we are well-positioned to see an acceleration of our margins towards the end of 2017 because of our strategy to preserve the market share we gained during the downturn.

Business outlook
While the past two years were challenging as we navigated through this historic industry downturn, we believe our results have begun to reflect our successful execution in a difficult environment and that our strategy has positioned us for the challenges and opportunities ahead. Commodity prices and the North America rig count have improved substantially from first half 2016 lows, and we believe we are well positioned to benefit from the impending market recovery given our improved market share, delivery platform and cost containment strategies.

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In North America, stabilizing commodity prices and growing rig counts have resulted in a rapidly recovering market, particularly in United States unconventionals. Our customers remain focused on lowering cost and producing more barrels of oil equivalent. We are continuing to collaborate and engineer solutions to maximize asset value for our customers and will continue to take advantage of the recent rig count growth by focusing on increasing equipment utilization, managing costs and expanding our surface efficiency model. Additionally, we gained significant North America market share through the downturn by demonstrating to our customers the benefits of our efficiency and technology, coming out of the downturn with our highest North America market share in history. We have been utilizing this increased market share to drive margin improvement. The historically high level of market share we built in the downturn gives us the ability to focus our work with the most efficient customers and, as such, we continued to execute our strategy of high grading the profitability of our portfolio with customers that value our services. We will continue to reactivate our equipment at leading edge pricing and maintain our focus on execution and service quality.

While the North America market has begun to recover, the international downswing continues to persist. The international markets have been more resilient than North America through most of the downturn, particularly in the Eastern Hemisphere, but pricing and activity levels remain under pressure. Low commodity prices have stressed customer budgets and have impacted economics across deepwater and mature field markets, which led to decreased activity and pricing in the first quarter of 2017, coupled with seasonal and cyclical headwinds, leading to revenue declines and stressed margins in all of our international regions. While we are working with our customers to improve project economics through technology and improved operating efficiency, we continue to anticipate headwinds, and we do not expect to see an inflection point for revenue and margin improvements in the international markets until the latter part of 2017. Due to the longer investment cycles and contractual nature of the international markets, we expect revenue and margins to continue to be under pressure throughout 2017 until the markets fully stabilize. While we believe the first quarter of 2017 represents the bottom in the Eastern Hemisphere rig count, the full year average rig count for 2017 will likely be only marginally higher than the full year average rig count for 2016. In Latin America, we experienced sequential improvement in revenue from activity in Brazil and Mexico. This region is slowly showing signs of improvement but there are significant headwinds that must be overcome for a full recovery. Venezuela continues to experience significant political and economic turmoil.

We have maintained capital discipline and adjusted to market conditions during the market downturn over the past two years. During the first quarter of 2017, we had $265 million of capital expenditures, an increase of 13% from the first quarter of 2016. We plan to continue adjusting capital spending during 2017 to align with market conditions. We will continue executing our deployment strategy of converting our hydraulic fracturing fleet to Q10 pumps to support our surface efficiency model and reactivating our cold-stacked pressure pumping equipment to respond to customer demand as long as the economics make sense. While near-term production increases could moderate the pace of activity increases in the second half of the year, we believe there is sufficient demand for the equipment we are bringing into the market. As we look at the second half of the year, we are assessing our options for continued redeployment beyond our current plans but have made no decisions.
    
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 2017:
- directing capital and resources into strategic growth markets, including unconventional plays and mature fields;
-
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 and engineering solutions to maximize asset value for our customers.

Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations.”


14

Financial markets, liquidity, and capital resources
We believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations from adverse market conditions. In the first quarter of 2017, we redeemed an aggregate principal amount of $1.4 billion of senior notes, which consisted of $400 million due in 2018 and $1.0 billion due in 2019. We also made the final installment payment of $335 million related to the settlement reached for the Macondo well incident, closing the quarter at $2.1 billion of cash and equivalents. This represents a $1.9 billion reduction in our cash position from December 31, 2016. 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.”


15

LIQUIDITY AND CAPITAL RESOURCES

As of March 31, 2017, we had $2.1 billion of cash and equivalents, compared to $4.0 billion at December 31, 2016. Additionally, we held $92 million of investments in fixed income securities at March 31, 2017 and December 31, 2016. These securities are reflected in "Other current assets" and "Other assets" in our condensed consolidated balance sheets. Approximately $1.7 billion of our total cash position as of March 31, 2017 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
Sources of cash:
- Cash flows from operating activities were $5 million during the first three months of 2017.
- We improved working capital (receivables, inventories and accounts payable) by a net $32 million during the first three months of 2017, driven by efficient working capital management.
Uses of cash:
- We early redeemed $1.4 billion of senior notes during the first three months of 2017, which resulted in a payment of approximately $1.5 billion, inclusive of the redemption premium.
- We made the final installment settlement payment related to the Macondo well incident in the amount of $335 million during the first three months of 2017.
- Capital expenditures were $265 million in the first three months of 2017, and were predominantly made in our Production Enhancement, Production Solutions, Sperry Drilling, Baroid, and Wireline and Perforating product service lines.
- We paid $156 million in dividends to our shareholders during the first three months of 2017.

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. The capital expenditures plan for 2017 is primarily directed towards our Production Enhancement, Sperry Drilling, Production Solutions, Wireline and Perforating, and Baroid product service lines. This includes reactivating some of our cold-stacked pressure pumping equipment and continuing to convert our hydraulic fracturing fleet to Q10 pumps to support our surface efficiency strategy. While near term production increases could moderate the pace of activity increases in the second half of the year, we believe there is sufficient demand for the equipment we are bringing into the market.     

Currently, our quarterly dividend rate is $0.18 per common share, or approximately $156 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 March 31, 2017 and may be used for open market and other share purchases. There were no repurchases made under the program during the three months ended March 31, 2017.

We expect to receive a United States tax refund in the amount of approximately $534 million during the second half of 2017, primarily related to the carryback of our net operating losses recognized in 2016.

Other factors affecting liquidity
Financial position in current market. As of March 31, 2017, we had $2.1 billion of cash and equivalents, $92 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 2017, including capital expenditures, scheduled debt maturities, working capital investments, dividends, if any, and contingent liabilities.

Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which approximately $2.0 billion of letters of credit, bank guarantees or surety bonds were outstanding as of March 31, 2017. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.


16

Credit ratings. Our credit ratings with Standard & Poor’s (S&P) remain BBB+ for our long-term debt and A-2 for our short-term debt, with a stable outlook. 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.

17

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 70 countries throughout the world to provide a comprehensive range of services and products to the energy industry. 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 three months of 2017, based upon the location of the services provided and products sold, 49% of our consolidated revenue was from the United States, compared to 41% of consolidated revenue from the United States in the first three months of 2016. 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
March 31
Year Ended
December 31
 
2017
2016
2016
Oil price - WTI (1)
$
51.77

$
33.18

$
43.14

Oil price - Brent (1)
53.68

33.70

43.55

Natural gas price - Henry Hub (2)
3.01

2.00

2.52

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


18

The historical average rig counts based on the weekly Baker Hughes Incorporated rig count information were as follows:
 
Three Months Ended
March 31
Year Ended
December 31
Land vs. Offshore
2017
2016
2016
United States:
 
 
 
Land
722

524

486

Offshore (incl. Gulf of Mexico)
20

27

23

Total
742

551

509

Canada:
 

 

 

Land
294

170

128

Offshore
1

3

2

Total
295

173

130

International (excluding Canada):
 

 

 

Land
738

790

734

Offshore
201

226

221

Total
939

1,016

955

Worldwide total
1,976

1,740

1,594

Land total
1,754

1,484

1,348

Offshore total
222

256

246

 
 
 
 
 
Three Months Ended
March 31
Year Ended
December 31
Oil vs. Natural Gas
2017
2016
2016
United States (incl. Gulf of Mexico):
 
 

 
Oil
594

441

409

Natural gas
148

110

100

Total
742

551

509

Canada:
 

 

 

Oil
162

82

63

Natural gas
133

91

67

Total
295

173

130

International (excluding Canada):
 

 

 

Oil
718

770

726

Natural gas
221

246

229

Total
939

1,016

955

Worldwide total
1,976

1,740

1,594

Oil total
1,474

1,293

1,198

Natural gas total
502

447

396

 
Three Months Ended
March 31
Year Ended
December 31
Drilling Type
2017
2016
2016
United States (incl. Gulf of Mexico):
 
 
 
Horizontal
610

435

400

Vertical
69

63

60

Directional
63

53

49

Total
742

551

509


19

        
Crude oil prices have been extremely volatile during the past few years. WTI oil spot prices declined significantly beginning in 2014 from a peak price of $108 per barrel in June 2014 to a low of $26 per barrel in February 2016, a level which had not been experienced since 2003. Brent crude oil spot prices declined from a high of $115 per barrel in June 2014 to $26 per barrel in January 2016. Commodity prices have increased from the low point experienced in early 2016 to highs of $54 per barrel and $55 per barrel in December 2016 for WTI and Brent, respectively.

WTI and Brent crude oil spot prices had a monthly average in March 2017 of $49 per barrel and $52 per barrel, respectively. As crude oil production rose in the United States in early March, crude oil prices declined as crude oil inventories increased to a multi-decade high. The price declined even though the Organization of the Petroleum Exporting Countries (OPEC) and some non-OPEC producers voluntarily cut crude oil production in the first quarter of 2017. However, the United States Energy Information Administration (EIA) does predict the market to maintain balance in 2017, forecasting the average Brent crude oil spot price at $54 per barrel in their April 2017 "Short Term Energy Outlook," while WTI prices are projected to average about $2 less per barrel. Crude oil production in the United States is now projected to average 9.2 million barrels per day in 2017, a 3% increase from 2016. The International Energy Agency's (IEA) April 2017 "Oil Market Report" forecasts the 2017 global demand to average approximately 97.9 million barrels per day, which is up 1% from 2016, driven by an increase in the Asia Pacific region, while all other regions remain approximately the same.

The average Henry Hub natural gas price in the United States was $2.88 per MMBtu in March 2017, a decrease of $0.71 per MMBtu, or 20%, from December 2016, driven by unseasonably warm temperatures during January and February. However, natural gas prices have risen approximately 66% since March 2016 due to increased demand for natural gas to fuel electricity generation in addition to lower inventory levels, which was caused by production declines and higher exports. The EIA April 2017 “Short Term Energy Outlook” expects exports to increase more than production, which would move inventories closer to the five-year average, resulting in rising natural gas prices to a projected EIA average of $3.10 per MMBtu in 2017.

North America operations
While the United States land average rig count for the first quarter has dropped 62% since its peak in November 2014, the rig count has begun to rebound in line with the commodity price environment. The United States land rig count continued its rapid increase in the first quarter of 2017, with a 27% improvement over the fourth quarter of 2016 and 38% improvement over the first quarter of 2016. North America oil-directed rig count increased 233 rigs, or 45%, in the first quarter of 2017 as compared to the first quarter of 2016, while the natural gas-directed rig count in North America increased 80 rigs, or 40%, during the same period. As a result of the recent uptick in activity and the structural changes to our delivery platform we made during this down cycle, we returned to operating profitability in North America in the fourth quarter of 2016 and first quarter of 2017 after recording operating losses in the first three quarters of 2016.

In the Gulf of Mexico, the average offshore rig count for the first quarter of 2017 was down 26% compared to the first quarter of 2016. Low commodity prices have stressed budgets and have impacted economics across the deepwater market, which has led to decreased activity and pricing throughout 2016. These headwinds still persist today. We believe there will continue to be challenges in 2017 on deepwater project economics. Additionally, activity in the Gulf of Mexico is dependent on, among the factors described above, governmental approvals for permits, our customers' actions, and the entry and exit of deepwater rigs in the market.

International operations
The average international rig count for the first quarter of 2017 decreased by 8% compared to the first quarter of 2016. 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 hit a 15-year low across the region during 2016, and Venezuela continues to experience significant political and economic turmoil. Latin America is slowly showing signs of improvement, but there are significant headwinds that must be overcome to obtain a full recovery. For the Eastern Hemisphere, while we believe the first quarter represents the bottom of the rig count, the full year average rig count for 2017 will likely be only marginally higher than the full year average rig count for 2016. Further, due to the longer term contractual nature of international markets and the level of continuing price pressure, we expect discounts will offset activity gains over the near term.


20

Venezuela. The Venezuelan government currently has a dual-rate foreign exchange system: (i) the DIPRO, which represents a protected rate of 10.0 Bolívares per United States dollar made available for vital imports such as food, medicine and raw materials for production; and (ii) the DICOM, 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 708 Bolívares per United States dollar at March 31, 2017. We are utilizing the DICOM to remeasure our net monetary assets denominated in Bolívares. The continued devaluation of the Bolívar under the DICOM did not materially affect our financial statements for the three months ended March 31, 2017.

As of March 31, 2017, our total net investment in Venezuela was approximately $834 million, with only $6 million of net monetary liabilities denominated in Bolívares, and we had an additional $39 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.

Our total outstanding net trade receivables in Venezuela were $636 million as of March 31, 2017, compared to $610 million as of December 31, 2016, which represents 15% of total company trade receivables for both periods. The majority of our Venezuela receivables are United States dollar-denominated receivables. Of the $636 million of receivables in Venezuela as of March 31, 2017, $441 million have been classified as long-term and included within “Other assets” on our condensed consolidated balance sheets.

In addition, we currently hold an interest-bearing promissory note with our primary customer in Venezuela with a par value of $200 million. 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 have been receiving quarterly interest payments on this note in accordance with the dates outlined in the agreement, and the carrying amount of the note was $83 million as of March 31, 2017. 

For additional information, see Part I, Item 1(a), “Risk Factors” in our 2016 Annual Report on Form 10-K.



21

Three Months Ended March 31, 2017 Compared with Three Months Ended March 31, 2016
REVENUE:
Three Months Ended
March 31
Favorable
Percentage
Millions of dollars
2017
2016
(Unfavorable)
Change
Completion and Production
$
2,604

$
2,324

$
280

12
 %
Drilling and Evaluation
1,675

1,874

(199
)
(11
)
Total revenue
$
4,279

$
4,198

$
81

2
 %
 
 
 
 
 
By geographic region:
 
 
 
 
North America
$
2,231

$
1,794

$
437

24
 %
Latin America
463

541

(78
)
(14
)
Europe/Africa/CIS
604

778

(174
)
(22
)
Middle East/Asia
981

1,085

(104
)
(10
)
Total revenue
$
4,279

$
4,198

$
81

2
 %

OPERATING INCOME:
Three Months Ended
March 31
Favorable
Percentage
Millions of dollars
2017
2016
(Unfavorable)
Change
Completion and Production
$
147

$
30

$
117

390
 %
Drilling and Evaluation
122

241

(119
)
(49
)
Total
269

271

(2
)
(1
)%
Corporate and other
(66
)
(584
)
518

89

Impairments and other charges
—

(2,766
)
2,766

—

Total operating income (loss)
$
203

$
(3,079
)
$
3,282

—


Consolidated revenue was $4.3 billion in the first three months of 2017, an increase of $81 million, or 2%, as compared to the first three months of 2016, primarily due to increased North America stimulation activity, partially offset by reduced drilling activity on a global basis. Revenue from North America was 52% of consolidated revenue in the first three months of 2017, compared to 43% of consolidated revenue in the first three months of 2016, which reflects the rapid increase in activity our North America operations are experiencing as it relates to the recovery of the energy market.

Consolidated operating income was $203 million in the first three months of 2017 driven by significant increases in pressure pumping activity in North America and consulting and project management in Latin America. This compares to an operating loss of $3.1 billion during the first three months of 2016, in part due to the negative impact of $2.8 billion of impairments and other charges and $538 million of merger-related costs.

OPERATING SEGMENTS

Completion and Production
Completion and Production revenue in the first three months of 2017 was $2.6 billion, an increase of $280 million, or 12%, from the first three months of 2016. Operating income in the first three months of 2017 was $147 million, compared to $30 million in the first three months of 2016. These increases were primarily due to improved pressure pumping pricing and utilization in the United States land market. International revenue declined as a result of reduced completion tool sales across all regions.

Drilling and Evaluation
Drilling and Evaluation revenue in the first three months of 2017 was $1.7 billion, a decrease of $199 million, or 11%, from the first three months of 2016. Operating income in the first three months of 2017 was $122 million, a decrease of $119 million, or 49%, compared to the first three months of 2016. These reductions were experienced globally across the majority of our product service lines, particularly reduced drilling services, logging services, software sales and offshore activity in the international regions, partially offset by an increase in project management in Latin America.


22

GEOGRAPHIC REGIONS

North America
North America revenue in the first three months of 2017 was $2.2 billion, a 24% increase compared to the first three months of 2016, relative to a 43% increase in average North America rig count. These results were driven by improved customer demand in our United States land sector with increased pricing and utilization, primarily related to pressure pumping services.

Latin America
Latin America revenue in the first three months of 2017 was $463 million, a 14% reduction compared to the first three months of 2016, primarily due to decreased activity in production solutions and drilling activity in Mexico, Argentina and Venezuela, and reduced stimulation activity in Argentina.

Europe/Africa/CIS
Europe/Africa/CIS revenue in the first three months of 2017 was $604 million, a 22% decrease from the first three months of 2016, primarily from reduced drilling and logging activity in Angola and a decline in well completion services in Angola, Algeria and the North Sea as a result of continued cyclical headwinds for both activity and pricing across the area.
 
Middle East/Asia
Middle East/Asia revenue in the first three months of 2017 was $981 million, a 10% decrease from the first three months of 2016, due to decreased drilling activity and pressure pumping services across the region, and reduced logging services in Asia Pacific.

OTHER OPERATING ITEMS

Corporate and other expenses were $66 million in the first three months of 2017 compared to $584 million in the first three months of 2016. During the first three months of 2016, we incurred $538 million of merger-related costs, of which $464 million related to the reversal of assets held for sale accounting.

NONOPERATING ITEMS

Interest expense, net was $242 million in the first three months of 2017, as compared to $165 million in the first three months of 2016. This increase was primarily due to $104 million in costs related to the early extinguishment of $1.4 billion of senior notes. See Note 4 to the condensed consolidated financial statements for further information.

Effective tax rate. Our effective tax rate on continuing operations for the quarter ended March 31, 2017 and March 31, 2016 was 44.2% and 26.6%, respectively. The effective tax rates in both periods were impacted by the geographic mix of earnings for the respective period. The effective tax rate for March 31, 2016 was also impacted by the establishment of a valuation allowance on certain deferred tax assets equaling $112 million as well as the tax effects of impairments and other charges recorded during the period.

23

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 6 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 2016 Annual Report on Form 10-K. Our exposure to market risk has not changed materially since December 31, 2016.

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 Interim 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 Interim Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2017 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 Interim 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 March 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

24

PART II. OTHER INFORMATION
 
Item 1. Legal Proceedings

Information related to Item 1. Legal Proceedings is included in Note 6 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 March 31, 2017, 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, 2016.

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 March 31, 2017.
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)
January 1 - 31
122,557

$54.94
—
$5,700,004,373
February 1 - 28
19,146

$54.41
—
$5,700,004,373
March 1 - 31
9,250

$49.34
—
$5,700,004,373
Total
150,953

$54.53
—
 

(a)
All of the 150,953 shares purchased during the three-month period ended March 31, 2017 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 March 31, 2017. From the inception of this program in February 2006 through March 31, 2017, 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.


25

Item 6. Exhibits

*†
10.1
Executive Agreement (Anne Lyn Beaty).
 
 
 
*
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 Interim 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 Interim 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

26

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/ Robb L. Voyles
/s/ Charles E. Geer, Jr.
Robb L. Voyles
Charles E. Geer, Jr.
Executive Vice President, Interim Chief Financial Officer,
Vice President and
Secretary and General Counsel
Corporate Controller


Date: April 28, 2017


27

HALLIBURTON CO Reports