10-Q 1 edsept201110q_final.htm SEPTEMBER 30, 2011 FORM 10Q edsept201110q_final.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 September 30, 2011

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 14, 2011, 920,165,263 shares of Halliburton Company common stock, $2.50 par value per share, were outstanding.

 
 

 

HALLIBURTON COMPANY

Index

   
Page No.
PART I.
FINANCIAL INFORMATION
  3
     
Item 1.
Financial Statements
  3
     
 
-       Condensed Consolidated Statements of Operations
  3
 
-       Condensed Consolidated Balance Sheets
  4
 
-       Condensed Consolidated Statements of Cash Flows
  5
 
-       Notes to Condensed Consolidated Financial Statements
  6
     
Item 2.
Management’s Discussion and Analysis of Financial Condition and
 
 
Results of Operations
23
     
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
37
     
Item 4.
Controls and Procedures
39
     
PART II.
OTHER INFORMATION
40
     
Item 1.
Legal Proceedings
40
     
Item 1(a).
Risk Factors
50
     
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
55
     
Item 3.
Defaults Upon Senior Securities
55
     
Item 4.
Specialized Disclosures
55
     
Item 5.
Other Information
55
     
Item 6.
Exhibits
56
     
Signatures
 
57

 
 

 

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

HALLIBURTON COMPANY
Condensed Consolidated Statements of Operations
(Unaudited)

   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
Millions of dollars and shares except per share data
 
2011
   
2010
   
2011
   
2010
 
Revenue:
                       
Services
  $ 5,246     $ 3,598     $ 14,164     $ 9,814  
Product sales
    1,302       1,067       3,601       2,999  
Total revenue
    6,548       4,665       17,765       12,813  
Operating costs and expenses:
                               
Cost of services
    4,030       2,891       11,117       8,075  
Cost of sales
    1,107       894       3,127       2,542  
General and administrative
    79       62       214       167  
Total operating costs and expenses
    5,216       3,847       14,458       10,784  
Operating income
    1,332       818       3,307       2,029  
Interest expense, net of interest income of $1, $3, $4, and $9
    (62 )     (76 )     (194 )     (228 )
Other, net
    (9 )     (7 )     (18 )     (56 )
Income from continuing operations before income taxes
    1,261       735       3,095       1,745  
Provision for income taxes
    (411 )     (249 )     (992 )     (570 )
Income from continuing operations
    850       486       2,103       1,175  
Income (loss) from discontinued operations, net of income
                               
tax (provision) benefit of $(19), $64, $(18), and $63
    (165 )     59       (166 )     60  
Net income
  $ 685     $ 545     $ 1,937     $ 1,235  
Noncontrolling interest in net income of subsidiaries
    (2 )     (1 )     (4 )     (5 )
Net income attributable to company
  $ 683     $ 544     $ 1,933     $ 1,230  
Amounts attributable to company shareholders:
                               
Income from continuing operations
  $ 848     $ 485     $ 2,099     $ 1,170  
Income (loss) from discontinued operations, net
    (165 )     59       (166 )     60  
Net income attributable to company
  $ 683     $ 544     $ 1,933     $ 1,230  
Basic income per share attributable to company shareholders:
                               
Income from continuing operations
  $ 0.92     $ 0.53     $ 2.29     $ 1.29  
Income (loss) from discontinued operations, net
    (0.18 )     0.07       (0.18 )     0.07  
Net income per share
  $ 0.74     $ 0.60     $ 2.11     $ 1.36  
Diluted income per share attributable to company shareholders:
                               
Income from continuing operations
  $ 0.92     $ 0.53     $ 2.28     $ 1.29  
Income (loss) from discontinued operations, net
    (0.18 )     0.07       (0.18 )     0.06  
Net income per share
  $ 0.74     $ 0.60     $ 2.10     $ 1.35  
                                 
Cash dividends per share
  $ 0.09     $ 0.09     $ 0.27     $ 0.27  
Basic weighted average common shares outstanding
    920       910       917       907  
Diluted weighted average common shares outstanding
    925       912       922       910  
See notes to condensed consolidated financial statements.

 
3

 

HALLIBURTON COMPANY
Condensed Consolidated Balance Sheets


   
September 30,
   
December 31,
 
   
2011
   
2010
 
Millions of dollars and shares except per share data
 
(Unaudited)
       
Assets
 
Current assets:
           
Cash and equivalents
  $ 1,775     $ 1,398  
Receivables (less allowance for bad debts of $141 and $91)
    4,769       3,924  
Inventories
    2,412       1,940  
Investments in marketable securities
    400       653  
Current deferred income taxes
    238       257  
Other current assets
    712       714  
Total current assets
    10,306       8,886  
Property, plant, and equipment, net of accumulated depreciation of $6,842 and $6,064
    7,993       6,842  
Goodwill
    1,373       1,315  
Other assets
    1,532       1,254  
Total assets
  $ 21,204     $ 18,297  
Liabilities and Shareholders’ Equity
 
Current liabilities:
               
Accounts payable
  $ 1,733     $ 1,139  
Accrued employee compensation and benefits
    733       716  
Deferred revenue
    269       266  
Other current liabilities
    921       636  
Total current liabilities
    3,656       2,757  
Long-term debt
    3,824       3,824  
Employee compensation and benefits
    477       487  
Other liabilities
    871       842  
Total liabilities
    8,828       7,910  
Shareholders’ equity:
               
Common shares, par value $2.50 per share – authorized 2,000 shares, issued
               
1,073 and 1,069 shares
    2,682       2,674  
Paid-in capital in excess of par value
    430       339  
Accumulated other comprehensive loss
    (240 )     (240 )
Retained earnings
    14,057       12,371  
Treasury stock, at cost – 153 and 159 shares
    (4,571 )     (4,771 )
Company shareholders’ equity
    12,358       10,373  
Noncontrolling interest in consolidated subsidiaries
    18       14  
Total shareholders’ equity
    12,376       10,387  
Total liabilities and shareholders’ equity
  $ 21,204     $ 18,297  
See notes to condensed consolidated financial statements.

 
4

 

HALLIBURTON COMPANY
Condensed Consolidated Statements of Cash Flows
(Unaudited)

   
Nine Months Ended
 
   
September 30
 
Millions of dollars
 
2011
   
2010
 
Cash flows from operating activities:
           
Net income
  $ 1,937     $ 1,235  
Adjustments to reconcile net income to net cash flows from operating activities:
               
Depreciation, depletion, and amortization
    991       817  
Payments related to KBR TSKJ matters
    (6 )     (142 )
(Income) loss from discontinued operations, net
    166       (60 )
Other changes:
               
Receivables
    (988 )     (716 )
Accounts payable
    598       286  
Inventories
    (468 )     (280 )
Other
    136       222  
Total cash flows from operating activities
    2,366       1,362  
Cash flows from investing activities:
               
Capital expenditures
    (2,164 )     (1,412 )
Sales of marketable securities
    751       1,600  
Purchases of marketable securities
    (501 )     (1,182 )
Acquisitions of business assets, net of cash acquired
    (70 )     (383 )
Other investing activities
    106       122  
Total cash flows from investing activities
    (1,878 )     (1,255 )
Cash flows from financing activities:
               
Dividends to shareholders
    (247 )     (245 )
Proceeds from exercises of stock options
    157       78  
Other financing activities
    2       (129 )
Total cash flows from financing activities
    (88 )     (296 )
Effect of exchange rate changes on cash
    (23 )     (18 )
Increase (decrease) in cash and equivalents
    377       (207 )
Cash and equivalents at beginning of period
    1,398       2,082  
Cash and equivalents at end of period
  $ 1,775     $ 1,875  
Supplemental disclosure of cash flow information:
               
Cash payments during the period for:
               
Interest
  $ 260     $ 289  
Income taxes
  $ 871     $ 529  
See notes to condensed consolidated financial statements.

 
5

 

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 2010 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, 2011, the results of our operations for the three and nine months ended September 30, 2011 and 2010, and our cash flows for the nine months ended September 30, 2011 and 2010. Such adjustments are of a normal recurring nature. In addition, certain reclassifications of prior period balances have been made to conform to 2011 classifications. The results of operations for the three and nine months ended September 30, 2011 may not be indicative of results for the full year.

 
6

 

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.
The following table presents information on our business segments. “Corporate and other” includes expenses related to support functions and corporate executives. Also included are certain gains and losses not attributable to a particular business segment.
Intersegment revenue was immaterial. Our equity in earnings and losses of unconsolidated affiliates that are accounted for by the equity method of accounting are included in revenue and operating income of the applicable segment.

   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
Millions of dollars
 
2011
   
2010
   
2011
   
2010
 
Revenue:
                       
Completion and Production
  $ 4,025     $ 2,655     $ 10,815     $ 7,012  
Drilling and Evaluation
    2,523       2,010       6,950       5,801  
Total revenue
  $ 6,548     $ 4,665     $ 17,765     $ 12,813  
                                 
Operating income:
                               
Completion and Production
  $ 1,068     $ 609     $ 2,646     $ 1,344  
Drilling and Evaluation
    369       271       923       859  
Total operations
    1,437       880       3,569       2,203  
Corporate and other
    (105 )     (62 )     (262 )     (174 )
Total operating income
  $ 1,332     $ 818     $ 3,307     $ 2,029  
Interest expense, net of interest income
    (62 )     (76 )     (194 )     (228 )
Other, net
    (9 )     (7 )     (18 )     (56 )
Income from continuing operations before
                               
income taxes
  $ 1,261     $ 735     $ 3,095     $ 1,745  

Receivables
As of September 30, 2011, 46% of our gross trade receivables were from customers in the United States. As of December 31, 2010, 36% of our gross trade receivables were from customers in the United States.

Note 3. 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 $145 million as of September 30, 2011 and $108 million as of December 31, 2010. If the average cost method had been used, total inventories would have been $42 million higher than reported as of September 30, 2011 and $34 million higher than reported as of December 31, 2010. The cost of the remaining inventory was recorded on the average cost method. Inventories consisted of the following:

   
September 30,
   
December 31,
 
Millions of dollars
 
2011
   
2010
 
Finished products and parts
  $ 1,675     $ 1,369  
Raw materials and supplies
    646       496  
Work in process
    91       75  
Total
  $ 2,412     $ 1,940  

Finished products and parts are reported net of obsolescence reserves of $107 million as of September 30, 2011 and $88 million as of December 31, 2010.

 
7

 

Note 4. Debt
On February 22, 2011, we entered into a new unsecured $2.0 billion five-year revolving credit facility that replaced our then existing $1.2 billion unsecured credit facility established in July 2007. The purpose of the facility is to provide commercial paper support, general working capital, and credit for other corporate purposes. The full amount of the revolving credit facility was available as of September 30, 2011.
During the second quarter of 2011, we entered into a series of interest rate swaps relating to two of our debt instruments. The first series of swaps were for a notional amount of $600 million in order to hedge a portion of the changes in the fair value of our 6.15% senior notes due 2019. Under the terms of these swaps, we will receive interest at a fixed rate of 6.15% and will pay interest at a floating rate of three-month LIBOR plus a spread semiannually. The second series of swaps were for a notional amount of $400 million in order to hedge changes in the fair value of our 5.9% senior notes due 2018. Under the terms of these swaps, we will receive interest at a fixed rate of 5.9% and will pay interest at a floating rate of three-month LIBOR plus a spread semiannually. These interest rate swaps are designated as fair value hedges of the underlying debt. 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. See Note 9 for further discussion of the fair value of our interest rate swaps.

 
8

 


Note 5. Shareholders’ Equity
The following tables summarize our shareholders’ equity activity.

               
Noncontrolling
 
   
Total
   
Company
   
interest in
 
   
shareholders’
   
shareholders’
   
consolidated
 
Millions of dollars
 
equity
   
equity
   
subsidiaries
 
Balance at December 31, 2010
  $ 10,387     $ 10,373     $ 14  
Transactions with shareholders
    299       299        
Comprehensive income:
                       
Net income
    1,937       1,933       4  
Total comprehensive income
    1,937       1,933       4  
Payments of dividends to shareholders
    (247 )     (247 )      
Balance at September 30, 2011
  $ 12,376     $ 12,358     $ 18  

               
Noncontrolling
 
   
Total
   
Company
   
interest in
 
   
shareholders’
   
shareholders’
   
consolidated
 
Millions of dollars
 
equity
   
equity
   
subsidiaries
 
Balance at December 31, 2009
  $ 8,757     $ 8,728     $ 29  
Transactions with shareholders
    111       131       (20 )
Treasury shares issued for acquisition of
                       
Boots & Coots, Inc.
    105       105        
Shares repurchased
    (114 )     (114 )      
Comprehensive income:
                       
Net income
    1,235       1,230       5  
Other comprehensive income
    4       5       (1 )
Total comprehensive income
    1,239       1,235       4  
Payments of dividends to shareholders
    (245 )     (245 )      
Balance at September 30, 2010
  $ 9,853     $ 9,840     $ 13  

The following table summarizes comprehensive income for the quarterly periods presented.

   
Three Months Ended
 
   
September 30
 
Millions of dollars
 
2011
   
2010
 
Net income
  $ 685     $ 545  
Total comprehensive income
  $ 685     $ 545  
Comprehensive income attributable to noncontrolling interest
    2       1  
Comprehensive income attributable to company
    683       544  

Accumulated other comprehensive loss consisted of the following:

   
September 30,
   
December 31,
 
Millions of dollars
 
2011
   
2010
 
Defined benefit and other postretirement liability adjustments
  $ (175 )   $ (175 )
Cumulative translation adjustments
    (66 )     (66 )
Unrealized gains on investments
    1       1  
Total accumulated other comprehensive loss
  $ (240 )   $ (240 )

 
9

 

Note 6. KBR Separation
During 2007, we completed the separation of KBR, Inc. (KBR) from us by exchanging KBR common stock owned by us for our common stock. In addition, we recorded a liability reflecting the estimated fair value of the indemnities provided to KBR as described below. Since the separation, we have recorded adjustments to reflect changes to our estimation of our remaining obligation. All such adjustments are recorded in “Income (loss) from discontinued operations, net of income tax (provision) benefit.”
We entered into various agreements relating to the separation of KBR, including, among others, a master separation agreement and a tax sharing agreement. We agreed to provide indemnification in favor of KBR under the master separation agreement for all out-of-pocket cash costs and expenses, or cash settlements or cash arbitration awards in lieu thereof, KBR may incur after the effective date of the master separation agreement as a result of the replacement of the subsea flowline bolts installed in connection with the Barracuda-Caratinga project. During the third quarter of 2011, an arbitration award of $201 million was issued against KBR. Also, under the master separation agreement, we have indemnified KBR for certain losses arising from investigations and charges brought under the United States Foreign Corrupt Practices Act (FCPA) or similar foreign statutes, laws, rules, or regulations in each case related to the construction of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria by a consortium of engineering firms comprised of Technip SA of France, Snamprogetti Netherlands B.V., JGC Corporation of Japan, and Kellogg Brown & Root LLC (TSKJ), each of which had an approximate 25% beneficial interest in the venture. Part of KBR’s ownership in TSKJ was held through M.W. Kellogg Limited, a United Kingdom joint venture and subcontractor on the Bonny Island project in which KBR beneficially owned a 55% interest at the time of the execution of the master separation agreement. The TSKJ investigations and charges have been resolved. At this time, no other claims by governmental authorities in any jurisdictions have been asserted against the indemnified parties.
The tax sharing agreement provides for allocations of United States and certain other jurisdiction tax liabilities between us and KBR. The tax sharing agreement is complex, and finalization of amounts owed between KBR and us under the tax sharing agreement can occur only after income tax audits are completed by the taxing authorities and both parties have had time to analyze the results. There can be no guarantee that the parties will agree on the allocations of tax liabilities, and the process may take several quarters or more to complete.
Amounts accrued relating to our remaining KBR liabilities are primarily included in “Other liabilities” on the condensed consolidated balance sheets and totaled $201 million as of September 30, 2011 and $63 million as of December 31, 2010. See Note 7 for further discussion of the Barracuda-Caratinga matter.

Note 7. Commitments and Contingencies
The Gulf of Mexico/Macondo well incident
Overview. 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 Transocean Ltd. and had been drilling the Macondo exploration well in Mississippi Canyon Block 252 in the Gulf of Mexico for the lease operator, BP Exploration & Production, Inc. (BP Exploration), an indirect wholly owned subsidiary of BP p.l.c. We performed a variety of services for BP Exploration, including cementing, mud logging, directional drilling, measurement-while-drilling, and rig data acquisition services. Crude oil flowing from the well site spread across thousands of square miles of the Gulf of Mexico and reached the United States Gulf Coast. Numerous attempts at estimating the volume of oil spilled have been made by various groups, and on August 2, 2010 the federal government published an estimate that approximately 4.9 million barrels of oil were discharged from the well. Efforts to contain the flow of hydrocarbons from the well were led by the United States government and by BP p.l.c., BP Exploration, and their affiliates (collectively, BP). The flow of hydrocarbons from the well ceased on July 15, 2010, and the well was permanently capped on September 19, 2010. There were eleven fatalities and a number of injuries as a result of the Macondo well incident.
As of September 30, 2011, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. We are currently unable to estimate the full impact the Macondo well incident will have on us. Further, an estimate of a reasonably possible loss or range of loss related to this matter cannot be made. Considering the complexity of the Macondo well, however, and the number of investigations being conducted and lawsuits pending or settled, as discussed below, new information or future developments may require us to adjust our liability assessment, and liabilities arising out of this matter could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

 
10

 

Investigations and Regulatory Action. The United States Coast Guard, a component of the United States Department of Homeland Security, and the Bureau of Ocean Energy Management, Regulation and Enforcement (BOE) (formerly known as the Minerals Management Service and which was replaced effective October 1, 2011 by two new, independent bureaus – the Bureau of Safety and Environmental Enforcement and the Bureau of Ocean Energy Management), a bureau of the United States Department of the Interior, shared jurisdiction over the investigation into the Macondo well incident and formed a joint investigation team that reviewed information and held hearings regarding the incident (Marine Board Investigation). We were named as one of the 16 parties-in-interest in the Marine Board Investigation. In addition, other investigations are underway by the Chemical Safety Board and the National Academy of Sciences to, among other things, examine the relevant facts and circumstances concerning the causes of the Macondo well incident and develop options for guarding against future oil spills associated with offshore drilling. We are assisting in efforts to identify the factors that led to the Macondo well incident and have participated and intend to continue participating in various hearings relating to the incident that are held by, among others, certain of the agencies referred to above and various committees and subcommittees of the House of Representatives and the Senate of the United States.
In May 2010, the United States Department of the Interior effectively suspended all offshore deepwater drilling projects in the United States Gulf of Mexico. The suspension was lifted in October 2010. Later, the Department of the Interior issued new guidance for drillers that intend to resume deepwater drilling activity and has recently proposed additional regulations. Despite the fact that the drilling suspension was lifted, the BOE did not issue permits for the resumption of drilling for an extended period of time, and we have experienced a significant reduction in our Gulf of Mexico operations since the Macondo well incident. In the first quarter of 2011, the BOE resumed the issuance of drilling permits, and activity began to slowly recover in the second and third quarters although there can be no assurance of whether or when operations in the Gulf of Mexico will return to pre-suspension levels. For additional information, see Part II, Item 1(a), “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Environment and Results of Operations.”
DOJ Investigations and Actions. On June 1, 2010, the United States Attorney General announced that the Department of Justice (DOJ) was launching civil and criminal investigations into the Macondo well incident to closely examine the actions of those involved, and that the DOJ was working with attorneys general of states affected by the Macondo well incident. The DOJ announced that it was reviewing, among other traditional criminal statutes, possible violations of and liabilities under The Clean Water Act (CWA), The Oil Pollution Act of 1990 (OPA), The Migratory Bird Treaty Act of 1918 (MBTA), and the Endangered Species Act of 1973 (ESA).
The CWA provides authority for civil and criminal penalties for discharges of oil into or upon navigable waters of the United States, adjoining shorelines, or in connection with the Outer Continental Shelf Lands Act in quantities that are deemed harmful. A single discharge event may result in the assertion of numerous violations under the CWA. Criminal sanctions under the CWA can be assessed for negligent discharges (up to $50,000 per day per violation), for knowing discharges (up to $100,000 per day per violation), and for knowing endangerment (up to $2 million per violation), and federal agencies could be precluded from contracting with a company that is criminally sanctioned under the CWA. Civil proceedings under the CWA can be commenced against an “owner, operator or person in charge of any vessel or offshore facility that discharged oil or a hazardous substance.”  The civil penalties that can be imposed against responsible parties range from up to $1,100 per barrel of oil discharged in the case of those found strictly liable to $4,300 per barrel of oil discharged in the case of those found to have been grossly negligent.
The OPA establishes liability for discharges of oil from vessels, onshore facilities, and offshore facilities into or upon the navigable waters of the United States. Under the OPA, the “responsible party” for the discharging vessel or facility is liable for removal and response costs as well as for damages, including recovery costs to contain and remove discharged oil and damages for injury to natural resources, lost revenues, lost profits and lost earning capacity. The cap on liability under the OPA is the full cost of removal of the discharged oil plus up to $75 million for damages, except that the $75 million cap does not apply in the event the damage was proximately caused by gross negligence or the violation of certain federal safety, construction or operating standards. The OPA defines the set of responsible parties differently depending on whether the source of the discharge is a vessel or an offshore facility. Liability for vessels is imposed on owners and operators; liability for offshore facilities is imposed on the holder of the permit or lessee of the area in which the facility is located.

 
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The MBTA and the ESA provide penalties for injury and death to wildlife and bird species. The MBTA provides that violators are strictly liable and provides for fines of up to $15,000 per bird killed and imprisonment of up to six months. The ESA provides for civil penalties for knowing violations that can range up to $25,000 per violation and, in the case of criminal penalties, up to $50,000 per violation.
In addition, the Alternative Fines Act may be applied in lieu of the express amount of the criminal fines that may be imposed under the statutes described above in the amount of twice the gross economic loss suffered by third parties (or twice the gross economic gain realized by the defendant, if greater).
On December 15, 2010, the DOJ filed a civil action seeking damages and injunctive relief against BP Exploration, Anadarko Petroleum Corporation and Anadarko E&P Company LP (together, Anadarko), certain subsidiaries of Transocean Ltd. and others for violations of the CWA and the OPA. The DOJ’s complaint seeks an action declaring that the defendants are strictly liable under the CWA as a result of harmful discharges of oil into the Gulf of Mexico and upon U.S. shorelines as a result of the Macondo well incident. The complaint also seeks an action declaring that the defendants are strictly liable under the OPA for the discharge of oil that has resulted in, among other things, injury to, loss of, loss of use of or destruction of natural resources and resource services in and around the Gulf of Mexico and the adjoining U.S. shorelines and resulting in removal costs and damages to the United States far exceeding $75 million. BP has been designated, and has accepted the designation, as a responsible party for the pollution under the CWA and the OPA. Others have also been named as responsible parties, and all responsible parties may be held jointly and severally liable for any damages under the OPA. A responsible party may make a claim for contribution against any other responsible party or against third parties it alleges contributed to or caused the oil spill. In connection with the proceedings discussed below under “Litigation,” in April 2011 BP Exploration filed a claim against us for contribution with respect to liabilities incurred by BP Exploration under the OPA and requested a judgment that the DOJ assert its claims for OPA financial liability directly against us.
We have not been named as a responsible party under the CWA or the OPA in the DOJ civil action, and we do not believe we are a responsible party under the CWA or the OPA. While we were not included in the DOJ’s complaint, there can be no assurance that the DOJ or other federal or state governmental authorities will not bring an action, whether civil or criminal, against us under the CWA, the OPA or other statutes or regulations. In connection with the DOJ’s filing of the action, it announced that its criminal and civil investigations are continuing and that it will employ efforts to hold accountable those who are responsible for the incident. A federal grand jury has been convened in Louisiana to investigate potential criminal conduct in connection with the Macondo well incident. We are cooperating with the DOJ's investigation. As of October 21, 2011, the DOJ has not commenced any civil or criminal proceedings against us.
In June 2010, we received a letter from the DOJ requesting thirty days advance notice of any event that may involve substantial transfers of cash or other corporate assets outside of the ordinary course of business. In our reply to the June 2010 DOJ letter, we conveyed our interest in briefing the DOJ on the services we provided on the Deepwater Horizon but indicated that we would not bind ourselves to the DOJ request. Subsequently, we have had and expect to continue to have discussions with the DOJ regarding the Macondo well incident and the request contained in the June 2010 DOJ letter.
Investigative Reports. On September 8, 2010, an incident investigation team assembled by BP issued the Deepwater Horizon Accident Investigation Report (BP Report). The BP Report outlined eight key findings of BP related to the possible causes of the Macondo well incident, including failures of cement barriers, failures of equipment provided by other service companies and the drilling contractor, and failures of judgment by BP and the drilling contractor. With respect to the BP Report’s assessment that the cement barrier did not prevent hydrocarbons from entering the wellbore after cement placement, the BP Report concluded that, among other things, there were “weaknesses in cement design and testing.”  According to the BP Report, the BP incident investigation team did not review its analyses or conclusions with us or any other entity or governmental agency conducting a separate or independent investigation of the incident. In addition, the BP incident investigation team did not conduct any testing using our cementing products.
On June 22, 2011, Transocean released its internal investigation report on the causes of the Macondo well incident. Transocean’s report, among other things, alleges deficiencies with our cementing services on the Deepwater Horizon. Like the BP Report, the Transocean incident investigation team did not review its analyses or conclusions with us and did not conduct any testing using our cementing products.

 
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On January 11, 2011, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (National Commission) released “Deep Water -- The Gulf Oil Disaster and the Future of Offshore Drilling,” its investigation report (Investigation Report) to the President of the United States regarding, among other things, the National Commission’s conclusions of the causes of the Macondo well incident. According to the Investigation Report, the “immediate causes” of the incident were the result of a series of missteps, oversights, miscommunications and failures to appreciate risk by BP, Transocean, and us, although the National Commission acknowledged that there were still many things it did not know about the incident, such as the role of the blowout preventer. The National Commission also acknowledged that it may never know the extent to which each mistake or oversight caused the Macondo well incident, but concluded that the immediate cause was “a failure to contain hydrocarbon pressures in the well,” and pointed to three things that could have contained those pressures: “the cement at the bottom of the well, the mud in the well and in the riser, and the blowout preventer.”  In addition, the Investigation Report stated that “primary cement failure was a direct cause of the blowout” and that cement testing performed by an independent laboratory “strongly suggests” that the foam cement slurry used on the Macondo well was unstable. The Investigation Report, however, acknowledges a fact widely accepted by the industry that cementing wells is a complex endeavor utilizing an inherently uncertain process in which failures are not uncommon and that, as a result, the industry utilizes the negative-pressure test and cement bond log test, among others, to identify cementing failures that require remediation before further work on a well is performed.
The Investigation Report also sets forth the National Commission’s findings on certain missteps, oversights and other factors that may have caused, or contributed to the cause of, the incident, including BP’s decision to use a long string casing instead of a liner casing, BP’s decision to use only six centralizers, BP’s failure to run a cement bond log, BP’s reliance on the primary cement job as a barrier to a possible blowout, BP’s and Transocean’s failure to properly conduct and interpret a negative-pressure test, BP’s temporary abandonment procedures, and the failure of the drilling crew and our surface data logging specialist to recognize that an unplanned influx of oil, gas or fluid into the well (known as a “kick”) was occurring. With respect to the National Commission’s finding that our surface data logging specialist failed to recognize a kick, the Investigation Report acknowledged that there were simultaneous activities and other monitoring responsibilities that may have prevented the surface data logging specialist from recognizing a kick.
The Investigation Report also identified two general root causes of the Macondo well incident: systemic failures by industry management, which the National Commission labeled “the most significant failure at Macondo,” and failures in governmental and regulatory oversight. The National Commission cited examples of failures by industry management such as BP’s lack of controls to adequately identify or address risks arising from changes to well design and procedures, the failure of BP’s and our processes for cement testing, communication failures among BP, Transocean, and us, including with respect to the difficulty of our cement job, Transocean’s failure to adequately communicate lessons from a recent near-blowout, and the lack of processes to adequately assess the risk of decisions in relation to the time and cost those decisions would save. With respect to failures of governmental and regulatory oversight, the National Commission concluded that applicable drilling regulations were inadequate, in part because of a lack of resources and political support of the Minerals Management Service (MMS), and a lack of expertise and training of MMS personnel to enforce regulations that were in effect.
As a result of the factual and technical complexity of the Macondo well incident, the Chief Counsel of the National Commission issued a separate, more detailed report regarding the technical, managerial and regulatory causes of the Macondo well incident in February 2011.
In March 2011, a third party retained by the BOE to undertake a forensic examination and evaluation of the blowout preventer stack, its components and associated equipment, released a report detailing its findings. The forensic examination report found, among other things, that the blowout preventer stack failed primarily because the blind sheer rams did not fully close and seal the well due to a portion of drill pipe that had become trapped between the blocks. The forensic examination report recommended further examination, investigation and testing, which we understand is underway. We had no part in manufacturing or servicing the blowout preventer stack.

 
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In September 2011, the BOE released the final report of the Marine Board Investigation regarding the Macondo well incident (BOE report). A panel of investigators of the BOE identified a number of causes of the Macondo well incident. According to the BOE Report, “a central cause of the blowout was failure of a cement barrier in the production casing string.”  The panel was unable to identify the precise reasons for the failure but concluded that it was likely due to: “(1) swapping of cement and drilling mud in the shoe track (the section of casing near the bottom of the well); (2) contamination of the shoe track cement; or (3) pumping the cement past the target location in the well, leaving the shoe track with little or no cement.” Generally, the panel concluded that the Macondo well incident was the result of, among other things, poor risk management, last-minute changes to drilling plans, failure to observe and respond to critical indicators and inadequate well control response by the companies and individuals involved. In particular, the BOE Report stated that BP made a series of decisions that complicated the cement job and may have contributed to the failure of the cement job, including the use of only one cement barrier, the location of the production casing and the failure to follow industry-accepted recommendations.
The BOE Report also stated, among other things, that BP failed to properly communicate well design and cementing decisions and risks to Transocean, that BP and Transocean failed to correctly interpret the negative-pressure test, and that we, BP, and Transocean failed to detect the influx of hydrocarbons into the well. According to the BOE Report, the panel found evidence that we, among others, violated federal regulations relating to the failure to take measures to prevent the unauthorized release of hydrocarbons, the failure to take precautions to keep the well under control, and the failure to cement the well in a manner that would, among other things, prevent the release of fluids into the Gulf of Mexico. In October 2011, the Bureau of Safety and Environmental Enforcement (BSEE) issued a notification of Incidents of Noncompliance (INCs) to us for violating those regulations and a federal regulation relating to 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. According to the BSEE’s notice, we did not ensure an adequate barrier to hydrocarbon flow after cementing the production casing and did not detect the influx of hydrocarbons until they were above the blowout preventer stack. We understand that the regulations provide for fines of up to $35,000 per day per violation. There is an opportunity to appeal the INCs to the appropriate agency within a 60-day appeal period, during which and thereafter we may consult with the BSEE regarding the alleged INCs and related civil penalties, if any. The BSEE has announced that the INCs will be reviewed for possible imposition of civil penalties once the 60-day appeal period has ended. The BSEE has stated that this is the first time the Department of the Interior has issued INCs directly to a contractor that was not the well's operator. We have not accrued any amounts related to the INCs.
The Cementing Job and Reaction to Reports. We disagree with the BP Report, the National Commission, Transocean’s report, and the BOE Report regarding many of their findings and characterizations with respect to the cementing and surface data logging services on the Deepwater Horizon. We have provided information to the National Commission, its staff, and representatives of the joint investigation team for the Marine Board Investigation that we believe has been overlooked or selectively omitted from the Investigation Report and BOE Report, as applicable. We intend to continue to vigorously defend ourselves in any investigation relating to our involvement with the Macondo well that we believe inaccurately evaluates or depicts our services on the Deepwater Horizon.
The cement slurry on the Deepwater Horizon was designed and prepared pursuant to well condition data provided by BP. Regardless of whether alleged weaknesses in cement design and testing are or are not ultimately established, and regardless of whether the cement slurry was utilized in similar applications or was prepared consistent with industry standards, we believe that had BP and others properly interpreted a negative-pressure test, this test would have revealed any problems with the cement. In addition, had BP designed the Macondo well to allow a full cement bond log test or if BP had conducted even a partial cement bond log test, the test likely would have revealed any problems with the cement. BP, however, elected not to conduct any cement bond log test, and with others misinterpreted the negative-pressure test, both of which could have resulted in remedial action, if appropriate, with respect to the cementing services.
At this time we cannot predict the impact of the Investigation Report, the BOE Report, or the conclusions of future reports of the Chemical Safety Board, the National Academy of Sciences, Congressional committees, or any other governmental or private entity. We also cannot predict whether their investigations or any other report or investigation will have an influence on or result in our being named as a party in any action alleging violation of a statute or regulation, whether federal or state and whether criminal or civil.

 
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We intend to continue to cooperate fully with all governmental hearings, investigations, and requests for information relating to the Macondo well incident. We cannot predict the outcome of, or the costs to be incurred in connection with, any of these hearings or investigations, and therefore we cannot predict the potential impact they may have on us.
Litigation. Since April 21, 2010, plaintiffs have been filing lawsuits relating to the Macondo well incident. Generally, those lawsuits allege either (1) damages arising from the oil spill pollution and contamination (e.g., diminution of property value, lost tax revenue, lost business revenue, lost tourist dollars, inability to engage in recreational or commercial activities) or (2) wrongful death or personal injuries. To date, we have been named along with other unaffiliated defendants in more than 400 complaints, most of which are alleged class actions, involving pollution damage claims and at least 40 personal injury lawsuits involving seven decedents and at least 59 allegedly injured persons who were on the drilling rig at the time of the incident. Another six lawsuits naming us and others relate to alleged personal injuries sustained by those responding to the explosion and oil spill. Plaintiffs originally filed the lawsuits described above in federal and state courts throughout the United States, including Alabama, Delaware, Florida, Georgia, Kentucky, Louisiana, Mississippi, South Carolina, Tennessee, Texas, and Virginia. Except for certain lawsuits not yet consolidated (including one lawsuit that is proceeding in Louisiana state court, three lawsuits that are proceeding in Texas state court, and three lawsuits that are proceeding in Florida federal court), the Judicial Panel on Multi-District Litigation ordered all of the lawsuits against us consolidated in a multi-district litigation (MDL) proceeding before Judge Carl Barbier in the U.S. Eastern District of Louisiana. The pollution complaints generally allege, among other things, negligence and gross negligence, property damages, taking of protected species, and potential economic losses as a result of environmental pollution and generally seek awards of unspecified economic, compensatory, and punitive damages, as well as injunctive relief. Plaintiffs in these pollution cases have brought suit under various legal provisions, including the OPA, the CWA, the MBTA, the ESA, the Outer Continental Shelf Lands Act, the Longshoremen and Harbor Workers Compensation Act, general maritime law, state common law, and various state environmental and products liability statutes.
Furthermore, the pollution complaints include suits brought against us by governmental entities, including the State of Alabama, the State of Louisiana, Plaquemines Parish, the City of Greenville, and three Mexican states. The wrongful death and other personal injury complaints generally allege negligence and gross negligence and seek awards of compensatory damages, including unspecified economic damages and punitive damages. We have retained counsel and are investigating and evaluating the claims, the theories of recovery, damages asserted, and our respective defenses to all of these claims.
Judge Barbier is also presiding over a separate proceeding filed by Transocean under the Limitation of Liability Act (Limitation Action). In the Limitation Action, Transocean seeks to limit its liability for claims arising out of the Macondo well incident to the value of the rig and its freight. Although the Limitation Action is not consolidated in the MDL, to this point the judge is effectively treating the two proceedings as associated cases. On February 18, 2011, Transocean tendered us, along with all other defendants, into the Limitation Action. As a result of the tender, we and all other defendants will be treated as direct defendants to the plaintiffs’ claims as if the plaintiffs had sued each of us and the other defendants directly. In the Limitation Action, the judge intends to determine the allocation of liability among all defendants in the hundreds of lawsuits associated with the Macondo well incident, including those in the MDL proceeding, that are pending in his court. Specifically, the judge will determine the liability, limitation, exoneration and fault allocation with regard to all of the defendants in a trial, which may occur in several phases, that is set to begin in the first quarter 2012. We do not believe, however, that a single apportionment of liability in the Limitation Action is properly applied to the hundreds of lawsuits pending in the MDL proceeding. Damages for the cases tried in the first quarter 2012, including punitive damages, are currently scheduled to be tried in a later phase of the Limitation Action. Under ordinary MDL procedures, such cases would, unless waived by the respective parties, be tried in the courts from which they were transferred into the MDL. It remains unclear, however, what impact the overlay of the Limitation Action will have on where these matters are tried. Document discovery and depositions among the parties to the MDL are underway.

 
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In April and May 2011, certain defendants in the proceedings described above filed numerous cross claims and third party claims against certain other defendants. BP Exploration and BP America Production Company filed claims against us seeking subrogation and contribution, including with respect to liabilities under the OPA, and alleging negligence, gross negligence, fraudulent conduct, and fraudulent concealment. Transocean filed claims against us seeking indemnification, and subrogation and contribution, including with respect to liabilities under the OPA and for the total loss of the Deepwater Horizon, and alleging comparative fault and breach of warranty of workmanlike performance. Anadarko filed claims against us seeking tort indemnity and contribution, and alleging negligence, gross negligence and willful misconduct, and MOEX Offshore 2007 LLC (MOEX), who has an approximate 10% interest in the Macondo well, filed a claim against us alleging negligence. Cameron International Corporation (Cameron) (the manufacturer and designer of the blowout preventer), M-I Swaco (provider of drilling fluids and services, among other things), Weatherford U.S. L.P. and Weatherford International, Inc. (together, Weatherford) (providers of casing components, including float equipment and centralizers, and services), and Dril-Quip, Inc. (Dril-Quip) (provider of wellhead systems), each filed claims against us seeking indemnification and contribution, including with respect to liabilities under the OPA in the case of Cameron, and alleging negligence. Additional civil lawsuits may be filed against us. In addition to the claims against us, generally the defendants in the proceedings described above filed claims, including for liabilities under the OPA and other claims similar to those described above, against the other defendants described above. BP has since announced that it has settled those claims between it and each of MOEX, Weatherford, and Anadarko.
In April 2011, we filed claims against BP Exploration, BP p.l.c. and BP America Production Company (BP Defendants), M-I Swaco, Cameron, Anadarko, MOEX, Weatherford, Dril-Quip, and numerous entities involved in the post-blowout remediation and response efforts, in each case seeking contribution and indemnification and alleging negligence. Our claims also alleged gross negligence and willful misconduct on the part of the BP Defendants, Anadarko, and Weatherford. We also filed claims against M-I Swaco and Weatherford for contractual indemnification, and against Cameron, Weatherford and Dril-Quip for strict products liability. We filed our answer to Transocean’s Limitation petition denying Transocean’s right to limit its liability, denying all claims and responsibility for the incident, seeking contribution and indemnification, and alleging negligence and gross negligence.
In September 2011, we filed claims in Harris County, Texas against the BP Defendants seeking damages, including lost profits and exemplary damages, and alleging negligence, grossly negligent misrepresentation, defamation, common law libel, slander and business disparagement. Our claims allege that the BP Defendants knew or should have known about an additional hydrocarbon zone in the well that the BP Defendants failed to disclose to us prior to our designing the cement program for the Macondo well. The location of the hydrocarbon zones is critical information required prior to performing cementing services and is necessary to achieve desired cement placement. We believe that had BP disclosed the hydrocarbon zone to us, we would not have executed the cement program unless and until changes were made to the cement program, changes that likely would have required a redesign of the production casing. In addition, we believe that BP withheld this information from the BP Report and from the various investigations discussed above. In connection with the foregoing, we also moved to amend our claims against the BP Defendants in the MDL proceeding to include fraud. The BP Defendants have denied all of the allegations relating to the additional hydrocarbon zone and filed a motion to prevent us from adding our fraud claim in the MDL. In October 2011, our motion to add the fraud claim against the BP Defendants in the MDL proceeding was denied. The court’s ruling does not, however, prevent us from using the underlying evidence in our pending claims against the BP Defendants.
We intend to vigorously defend any litigation, fines, and/or penalties relating to the Macondo well incident and to vigorously pursue any damages, remedies, or other rights available to us as a result of the Macondo well incident. We have incurred and expect to continue to incur significant legal fees and costs, some of which we expect to be covered by indemnity or insurance, as a result of the numerous investigations and lawsuits relating to the incident.
Macondo derivative case. In February 2011, a shareholder who had previously made a demand on our board of directors with respect to another derivative lawsuit filed a shareholder derivative lawsuit relating to the Macondo well incident. See “Shareholder derivative cases” below.

 
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Indemnification and Insurance. Our contract with BP Exploration relating to the Macondo well provides for our indemnification by BP Exploration for potential claims and expenses relating to the Macondo well incident, including those resulting from pollution or contamination (other than claims by our employees, loss or damage to our property, and any pollution emanating directly from our equipment). Also, under our contract with BP Exploration, we have, among other things, generally agreed to indemnify BP Exploration and other contractors performing work on the well for claims for personal injury of our employees and subcontractors, as well as for damage to our property. In turn, we believe that BP Exploration was obligated to obtain agreement by other contractors performing work on the well to indemnify us for claims for personal injury of their employees or subcontractors, as well as for damages to their property.
In addition to the contractual indemnity, we have a general liability insurance program of $600 million. Our insurance is 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. We have received and expect to continue to receive payments from our insurers with respect to covered legal fees incurred in connection with the Macondo well incident. To the extent we incur any losses beyond those covered by indemnification, there can be no assurance that our insurance policies will cover all potential claims and expenses relating to the Macondo well incident. Insurance coverage can be the subject of uncertainties and, particularly in the event of large claims, potential disputes with insurance carriers, as well as other potential parties claiming insured status under our insurance policies.
In April 2011, we filed a lawsuit against BP Exploration in Harris County, Texas to enforce BP Exploration’s contractual indemnity and alleging BP Exploration breached certain terms of the contractual indemnity provision. BP Exploration removed that lawsuit to federal court in the Southern District of Texas, Houston Division, and the lawsuit was transferred to the MDL. We have filed a motion to remand the case to Harris County, Texas and will continue to take actions to oppose the removal and the transfer to the MDL.
BP Exploration, in connection with filing its claims with respect to the MDL proceeding, asked that court to declare that it is not liable to us in contribution, indemnification or otherwise with respect to liabilities arising from the Macondo well incident. Other defendants in the litigation discussed above have generally denied any obligation to contribute to any liabilities arising from the Macondo well incident.
Indemnification for criminal or civil fines or penalties, if any, may not be available if a court were to find such indemnification unenforceable as against public policy. We do not expect, however, public policy to limit substantially the enforceability of our contractual right to indemnification with respect to liabilities other than criminal fines and penalties, if any. We may not be insured with respect to civil or criminal fines or penalties, if any, pursuant to the terms of our insurance policies.
We believe the law likely to be held applicable to matters relating to the Macondo well incident may not allow for enforcement of indemnification of persons who are found to be grossly negligent, although we do not believe the performance of our services on the Deepwater Horizon constituted gross negligence. In addition, certain state laws, if deemed to apply, may not allow for enforcement of indemnification of persons who are found to be negligent with respect to personal injury claims. Also, financial analysts and the press have speculated about the financial capacity of BP, and whether it might seek to avoid indemnification obligations in bankruptcy proceedings. BP’s public filings indicate that BP has recognized $40.7 billion in pre-tax charges as a result of the Macondo well incident and that the amount of, among other things, certain natural resource damages with respect to OPA claims by the United States and by state, tribal and foreign trustees, some of which may be included in such charges, cannot be reliably estimated as of the date of those filings. We consider, however, the likelihood of a BP bankruptcy to be remote.

 
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Barracuda-Caratinga arbitration
We provided indemnification in favor of KBR under the master separation agreement for all out-of-pocket cash costs and expenses (except for legal fees and other expenses of the arbitration so long as KBR controls and directs it), or cash settlements or cash arbitration awards, KBR may incur after November 20, 2006 as a result of the replacement of certain subsea flowline bolts installed in connection with the Barracuda-Caratinga project. At Petrobras’ direction, KBR replaced certain bolts located on the subsea flowlines that failed through mid-November 2005, and KBR informed us that additional bolts have failed thereafter, which were replaced by Petrobras. These failed bolts were identified by Petrobras when it conducted inspections of the bolts. In March 2006, Petrobras commenced arbitration against KBR claiming $220 million plus interest for the cost of monitoring and replacing the defective bolts and all related costs and expenses of the arbitration, including the cost of attorneys’ fees. The arbitration panel held an evidentiary hearing in March 2008 to determine which party is responsible for the designation of the material used for the bolts. On May 13, 2009, the arbitration panel held that KBR and not Petrobras selected the material to be used for the bolts. Accordingly, the arbitration panel held that there is no implied warranty by Petrobras to KBR as to the suitability of the bolt material and that the parties' rights are to be governed by the express terms of their contract. The parties presented evidence and witnesses to the panel in May 2010, and final arguments were presented in August 2010. During the third quarter of 2011, the arbitration panel issued an award against KBR in the amount of $201 million, which is reflected as a liability and a component of loss from discontinued operations in our condensed consolidated financial statements. See Note 6 for additional information regarding the KBR indemnification.
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. (Erica P. John 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 Erica P. John 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 Erica P. John Fund to re-plead some of those claims to correct deficiencies in its earlier complaint. In April 2006, Erica P. John Fund filed its fourth amended consolidated complaint. We filed a motion to dismiss those portions of the complaint that had been re-pled. A hearing was held on that motion in July 2006, and in March 2007 the court ordered dismissal of the claims against all individual defendants other than our Chief Executive Officer (CEO). The court ordered that the case proceed against our CEO and us.

 
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In September 2007, Erica P. John Fund filed a motion for class certification, and our response was filed in November 2007. The court held a hearing in March 2008, and issued an order November 3, 2008 denying Erica P. John Fund’s motion for class certification. Erica P. John Fund appealed the district court’s order to the Fifth Circuit Court of Appeals. The Fifth Circuit affirmed the district court’s order denying class certification. On May 13, 2010, Erica P. John Fund filed a writ of certiorari in the United States Supreme Court. In early January 2011, the Supreme Court granted Erica P. John Fund’s writ of certiorari and accepted the appeal. The Court heard oral arguments in April 2011 and issued its decision in June 2011, reversing the Fifth Circuit ruling that Erica P. John Fund needed to prove loss causation in order to obtain class certification. The Court’s ruling was limited to the Fifth Circuit’s loss causation requirement, and the case was returned to the Fifth Circuit for further consideration of our other arguments for denying class certification. The Fifth Circuit returned the case to the District Court for further action. As of September 30, 2011, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot be made.
Shareholder derivative cases
In May 2009, two shareholder derivative lawsuits involving us and KBR were filed in Harris County, Texas, naming as defendants various current and retired Halliburton directors and officers and current KBR directors. These cases allege that the individual Halliburton defendants violated their fiduciary duties of good faith and loyalty, to our detriment and the detriment of our shareholders, by failing to properly exercise oversight responsibilities and establish adequate internal controls. The District Court consolidated the two cases, and the plaintiffs filed a consolidated petition against only current and former Halliburton directors and officers containing various allegations of wrongdoing including violations of the FCPA, claimed KBR offenses while acting as a government contractor in Iraq, claimed KBR offenses and fraud under United States government contracts, Halliburton activity in Iran, and illegal kickbacks. Subsequently, a shareholder made a demand that the board take remedial action respecting the FCPA claims in the pending lawsuit. Our Board of Directors designated a special committee of independent directors to oversee the investigation of the allegations made in the lawsuits and shareholder demand. Upon receipt of its special committee’s findings and recommendations, the Board determined that the shareholder claims were without merit and not otherwise in the best interest of the company to pursue. The Board directed company counsel to report its determinations to the plaintiffs and demanding shareholder. As of September 30, 2011, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot be made.
In February 2011, the same shareholder who had made the demand on our board of directors in connection with one of the derivative lawsuits discussed above filed a shareholder derivative lawsuit in Harris County, Texas naming us as a nominal defendant and certain of our directors and officers as defendants. This case alleges that these defendants, among other things, breached fiduciary duties of good faith and loyalty by failing to properly exercise oversight responsibilities and establish adequate internal controls, including controls and procedures related to cement testing and the communication of test results, as they relate to the Macondo well incident. Our Board of Directors designated a special committee of independent directors to oversee the investigation of the allegations made in the lawsuit and shareholder demand. That investigation is in progress. As of September 30, 2011, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot be made.
Angola Investigations
We are conducting an internal investigation of certain areas of our operations in Angola, focusing on compliance with certain company policies, including our Code of Business Conduct (COBC), and the FCPA and other applicable laws. In December 2010, we received an anonymous email alleging that certain current and former personnel violated our COBC and the FCPA, principally through the use of an Angolan vendor. The email 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 with the assistance of outside counsel and independent forensic accountants.
During the third quarter of 2011, we met with the DOJ and the SEC to brief them on the status of our investigation and provided them documents. We expect to continue to have discussions with the DOJ and the SEC, and we intend to continue to cooperate with their inquiries and requests as they investigate this matter.
Because these investigations are at an early stage, we cannot predict their outcome or the consequences thereof.

 
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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 of 1990.
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 remediation requirements to have a material adverse effect on our consolidated financial position or our results of operations. Our accrued liabilities for those environmental matters were $58 million as of September 30, 2011 and $47 million as of December 31, 2010. Our total liability related to environmental matters covers numerous properties.
We have subsidiaries that have been named as potentially responsible parties along with other third parties for 10 federal and state superfund sites for which we have established reserves. As of September 30, 2011, those 10 sites accounted for approximately $7 million of our total $58 million reserve. For any particular federal or state superfund site, since 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. 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 $1.6 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of September 30, 2011, including $276 million of surety bonds related to Venezuela. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

 
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Note 8. Income per Share
Basic income 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.
A reconciliation of the number of shares used for the basic and diluted income per share calculations is as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
Millions of shares
 
2011
   
2010
   
2011
   
2010
 
Basic weighted average common shares outstanding
    920       910       917       907  
Dilutive effect of stock options
    5       2       5       3  
Diluted weighted average common shares outstanding
    925       912       922       910  

Excluded from the computation of diluted income per share are options to purchase four million and one million shares of common stock that were outstanding during the three and nine months ended September 30, 2011 and six million shares that were outstanding during both the three and nine months ended September 30, 2010. These options were outstanding during these periods but were excluded because they were antidilutive, as the option exercise price was greater than the average market price of the common shares.

Note 9. Fair Value of Financial Instruments
At September 30, 2011, we held $400 million of non-cash equivalents in United States Treasury securities with maturities that extend through February 2012. These securities are accounted for as available-for-sale and recorded at fair value, based on quoted market prices, in “Investments in marketable securities” on our condensed consolidated balance sheets. The carrying amount of cash and equivalents, investments in marketable securities, receivables, and accounts payable, as reflected in the condensed consolidated balance sheets, approximates fair value due to the short maturities of these instruments. We have no financial instruments measured at fair value using unobservable inputs.
The fair value of our long-term debt was $5.0 billion as of September 30, 2011 and $4.6 billion as of December 31, 2010, which differs from the carrying amount of $3.8 billion as of both September 30, 2011 and December 31, 2010, on our condensed consolidated balance sheets. The fair value of our long-term debt was calculated using either quoted market prices or significant observable inputs for similar liabilities for the respective periods.
We maintain an interest rate management strategy that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. We utilize interest rate swaps to effectively convert a portion of our fixed rate debt to floating rates. The fair value of our interest rate swaps are included in “Other assets” in our consolidated condensed balance sheets as of September 30, 2011. 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. We did not have any interest rate swaps outstanding as of December 31, 2010.
At September 30, 2011, we had fixed rate debt aggregating $2.8 billion and variable rate debt aggregating $1 billion, after taking into account the effects of the interest rate swaps.

 
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Note 10. Accounting Standards Recently Adopted
In September 2011, the FASB issued an update to existing guidance on the assessment of goodwill impairment. This update simplifies the assessment of goodwill for impairment by allowing companies to consider qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before performing the two step impairment review process. It also amends the examples of events or circumstances that would be considered in a goodwill impairment evaluation. We have elected to early adopt this update to be effective for the fiscal year beginning January 1, 2011. The adoption of this update did not have a material impact on our condensed consolidated financial statements.
On January 1, 2011, we adopted an update issued by the Financial Accounting Standards Board (FASB) to existing guidance on revenue recognition for arrangements with multiple deliverables. This update allows companies to allocate consideration for qualified separate deliverables using estimated selling price for both delivered and undelivered items when vendor-specific objective evidence or third-party evidence is unavailable. It also requires additional disclosures on the nature of multiple element arrangements, the types of deliverables under the arrangements, the general timing of their delivery, and significant factors and estimates used to determine estimated selling prices. The update is effective for fiscal years beginning after June 15, 2010. The adoption of this update did not have a material impact on our condensed consolidated financial statements or existing revenue recognition policies.
 
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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 products and services 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, Completion and Production and Drilling and Evaluation:
-
our Completion and Production segment delivers cementing, stimulation, intervention, pressure control, and completion services. The segment consists of production enhancement services, completion tools and services, cementing services, and Boots & Coots; and
-
our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and precise wellbore placement solutions that enable customers to model, measure, and optimize their well construction activities. The segment consists of fluid services, drilling services, drill bits, wireline and perforating services, testing and subsea, software and asset solutions, and integrated project management and consulting services.
The business operations of our segments are organized around four primary geographic regions: North America, Latin America, Europe/Africa/CIS, and Middle East/Asia. We have significant manufacturing operations in various locations, including, but not limited to, the United States, Canada, the United Kingdom, Malaysia, Mexico, Brazil, and Singapore. With over 60,000 employees, we operate in approximately 80 countries around the world, and our corporate headquarters are in Houston, Texas and Dubai, United Arab Emirates.
Financial results
During the nine months of 2011, we produced revenue of $17.8 billion and operating income of $3.3 billion, reflecting an operating margin of 19%. Revenue increased $5.0 billion, or 39%, from the nine months of 2010, while operating income increased $1.3 billion, or 63%, from the nine months of 2010. These increases were due mainly to increased drilling activity and pricing improvements in North America as well as increased activity in Latin America. Partially offsetting these results were operational disruptions in North Africa and project delays in the Middle East.
Business outlook
We continue to believe in the strength of the long-term fundamentals of our business. Despite concerns about the global economy, energy demand is expected to continue to increase driven by growth in developing countries. Furthermore, development of new resources is expected to be more complex resulting in increasing service intensity.
In North America, the United States land rig count and horizontal drilling activity continues to grow, led by a shift to oil and liquids-rich shale basins. We believe that natural gas drilling activity could be under pressure in the near-term until the oversupply situation is corrected; however, any reduction in natural gas drilling may be more than offset by an increase in liquids-directed activity. Our third quarter 2011 Gulf of Mexico business has continued to improve compared to the first half of the 2011 due to the higher level of drilling permits issued in recent months. However, the pace of permit applications and approvals needs to be sustained at higher levels in order for the Gulf of Mexico business to recover to activity levels experienced before the Macondo well incident. See “Business Environment and Results of Operations,” Note 7 to the consolidated financial statements, Part II, Item 1. “Legal Proceedings,” and Part II, Item 1(a), “Risk Factors.” Despite uncertainty about natural gas fundamentals and the Gulf of Mexico recovery, we believe our current North America revenue and margins will be sustainable through the remainder of 2011.

 
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Outside of North America, revenue during the nine months of 2011 increased from the prior year, while our operating income declined due to highly competitive service pricing in several markets. Recently, our operations in Egypt recovered from the turmoil experienced in the first quarter of 2011while our activity in Libya remains mostly shut down. Any meaningful recovery in Libya will depend on our customers’ ability to reestablish operations. Despite the events that have transpired and the impact of lower service pricing negotiated during the worldwide recession, we expect gradual margin improvement by the end of the year or early part of 2012 as activity continues to increase and new technologies are introduced.
We are executing several key initiatives in 2011. These initiatives involve increasing manufacturing production in the Eastern Hemisphere and reinventing our service delivery platform to lower our delivery costs. Costs related to these efforts, which are included under “Corporate and other” on our condensed consolidated statements of operations, impacted our results by approximately $0.01-$0.02 per diluted share in each quarter of 2011. We expect that costs associated with these initiatives will impact fourth quarter 2011 results by approximately $0.02 per diluted share.
Our operating performance and business outlook are described in more detail in “Business Environment and Results of Operations.”
Financial markets, liquidity, and capital resources
Since mid-2008, the global financial markets have been somewhat volatile. While this has created additional risks for our business, we believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations. For additional information, see “Liquidity and Capital Resources” and “Business Environment and Results of Operations.”

LIQUIDITY AND CAPITAL RESOURCES

We ended the third quarter of 2011 with cash and equivalents of $1.8 billion compared to $1.4 billion at December 31, 2010. We also held $400 million of short-term, United States Treasury securities classified as marketable securities at September 30, 2011 compared to $653 million at December 31, 2010.
Significant sources of cash
Cash flows from operating activities contributed $2.4 billion to cash in the nine months of 2011.
During the nine months of 2011, we sold approximately $751 million of short-term marketable securities.
Further available sources of cash. On February 22, 2011, we entered into an unsecured $2.0 billion five-year revolving credit facility that replaced our then existing $1.2 billion unsecured credit facility established in July 2007. The purpose of the facility is to provide commercial paper support, general working capital, and credit for other corporate purposes.
Significant uses of cash
Capital expenditures were $2.2 billion in the nine months of 2011 and were predominantly made in the production enhancement, drilling services, cementing, and wireline and perforating product service lines. We have also invested additional working capital to support the growth of our business.
During the nine months of 2011, we purchased $501 million in short-term marketable securities.
We paid $247 million in dividends to our shareholders in the nine months of 2011.
Future uses of cash. Capital spending for 2011 is expected to be approximately $3.1 billion. The capital expenditures plan for 2011 is primarily directed toward our production enhancement, drilling services, wireline and perforating, cementing, and completion tools product service lines to support the expansion of our North America business.
In October 2011, we completed the acquisition of Multi-Chem Group LLC (Multi-Chem) in an all cash transaction. Multi-Chem is the fourth-largest provider of production chemicals in North America, delivering specialty chemicals, services and solutions. Beginning October 2011, Multi-Chem’s results of operations will be included in our Completion and Production segment. We anticipate fourth quarter 2011 uses of cash related to Multi-Chem and other acquisitions to total approximately $800 million.
We are currently exploring opportunities for acquisitions that will enhance or augment our current portfolio of products and services, including those with unique technologies or distribution networks in areas where we do not already have large operations.
 
 
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Subject to Board of Directors approval, we expect to pay dividends of approximately $83 million during the remainder of 2011. We also have approximately $1.7 billion remaining available under our share repurchase authorization, which may be used for open market share purchases.
Other factors affecting liquidity
Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which approximately $1.6 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of September 30, 2011, including $276 million of surety bonds related to Venezuela. See “Business Environment and Results of Operations – International Operations” for further discussion related to Venezuela. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.
Financial position in current market. We believe our $1.8 billion of cash and equivalents, $400 million in investments in marketable securities, and $2.0 billion of available bank credit as of September 30, 2011 provide us with sufficient liquidity and flexibility, given the current market environment. Our debt maturities extend over a long period of time. We currently have a total of $2.0 billion of committed bank credit under our revolving credit facility to support our operations and any commercial paper we may issue in the future. The full amount of the revolving credit facility was available as of September 30, 2011. We have no financial covenants or material adverse change provisions in our bank agreements. Although a portion of earnings from our foreign subsidiaries is reinvested overseas indefinitely, we do not consider this to have a significant impact on our liquidity.
Credit ratings. Credit ratings for our long-term debt remain A2 with Moody’s Investors Service and A with Standard & Poor’s. The credit ratings on our short-term debt remain P-1 with Moody’s Investors Service and A-1 with Standard & Poor’s.
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. For example, we have seen a delay in receiving payment on our receivables from one of our primary customers in Venezuela. If our customers delay in 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.

 
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BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 80 countries throughout the world to provide a comprehensive range of discrete and integrated services and products to the energy industry. The majority of our consolidated revenue is derived from the sale of services and products to major, national, and independent oil and natural gas companies worldwide. 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 throughout the life of the field. Our two business segments are the Completion and Production segment and the Drilling and Evaluation segment. The industries we serve are highly competitive with many substantial competitors in each segment. In the nine months of 2011, based upon the location of the services provided and products sold, 55% of our consolidated revenue was from the United States. In the nine months of 2010, 45% of our consolidated revenue was from the United States. 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, expropriation or other governmental actions, inflation, exchange control problems, and highly inflationary currencies. 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 levels within our business segments are significantly impacted by spending on upstream exploration, development, and production programs by major, national, and independent oil and natural gas companies. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption.
Some of the more significant barometers of current and future spending levels of oil and natural gas companies are oil and natural gas prices, the world economy, the availability of credit, government regulation, and global stability, which together drive worldwide drilling activity. Our financial performance is significantly affected by oil and natural gas prices and worldwide rig activity, which are summarized in the following tables.
This 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
   
Year Ended
 
   
September 30
   
December 31
 
Average Oil Prices (dollars per barrel)
 
2011
   
2010
   
2010
 
West Texas Intermediate
  $ 90.37     $ 75.92     $ 79.36  
United Kingdom Brent
    113.98       77.44       79.66  
                         
Average United States Natural Gas Prices (dollars per
                       
thousand cubic feet, or Mcf)
                       
Henry Hub
  $ 4.28     $ 4.41     $ 4.52  

 
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The quarterly and year-to-date average rig counts based on the Baker Hughes Incorporated rig count information were as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
Land vs. Offshore
 
2011
   
2010
   
2011
   
2010
 
United States:
                       
Land
    1,911       1,604       1,800       1,457  
Offshore (incl. Gulf of Mexico)
    34       18       30       35  
Total
    1,945       1,622       1,830       1,492  
Canada:
                               
Land
    442       360       404       330  
Offshore
    1       1       2       2  
Total
    443       361       406       332  
International (excluding Canada):
                               
Land
    859       798       856       783  
Offshore
    310       312       304       305  
Total
    1,169       1,110       1,160       1,088  
Worldwide total
    3,557       3,093       3,396       2,912  
Land total
    3,212       2,762       3,060       2,570  
Offshore total
    345       331       336       342  

   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
Oil vs. Natural Gas
 
2011
   
2010
   
2011
   
2010
 
United States (incl. Gulf of Mexico):
                       
Oil
    1,048       640       935       547  
Natural Gas
    897       982       895       945  
Total
    1,945       1,622       1,830       1,492  
Canada:
                               
Oil
    305       219       274       189  
Natural Gas
    138       142       132       143  
Total
    443       361       406       332  
International (excluding Canada):
                               
Oil
    924       858       910       833  
Natural Gas
    245       252       250       255  
Total
    1,169       1,110       1,160       1,088  
Worldwide total
    3,557       3,093       3,396       2,912  
Oil total
    2,277       1,717       2,119       1,569  
Natural Gas total
    1,280       1,376       1,277       1,343  

   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
Drilling Type
 
2011
   
2010
   
2011
   
2010
 
United States (incl. Gulf of Mexico):
                       
Horizontal
    1,114       885       1,042       777  
Vertical
    590       515       557       490  
Directional
    241       222       231       225  
Total
    1,945       1,622       1,830       1,492  

 
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Our customers’ cash flows, in many instances, depend upon the revenue they generate from the sale of oil and natural gas. Lower oil and natural gas prices usually translate into lower exploration and production budgets. The opposite is true for higher oil and natural gas prices.
Crude oil prices were relatively stable for most of 2010. Towards the end of 2010 and through the first six months of 2011, oil prices rose dramatically. However, during the third quarter of 2011, oil prices experienced a great deal of volatility, primarily due to concerns about the global economic recovery. According to the International Energy Agency’s (IEA) October 2011 “Oil Market Report,” despite lower than expected demand levels during the nine months of 2011, the 2012 world petroleum demand is forecasted to increase 1% over 2011 levels. Despite the recent market volatility and decline in crude oil prices, we believe that any major macroeconomic disruptions may ultimately correct themselves as the underlying trends of significant demand growth for developing countries, smaller and more complex reservoirs, higher depletion rates, and the need for continual reserve replacement should drive the long-term need for our services.
North America operations
Volatility in oil and natural gas prices can impact our customers’ drilling and production activities. The shift in 2010 to oil and liquids-rich shale basins has helped to drive increased service intensity, not only in terms of horsepower required per job, but also in fluid chemistry and other technologies required for these complex reservoirs. This trend has continued through the nine months of 2011, with horizontal oil-directed drilling activity representing the fastest growing segment of the market. As of September 30, 2011, horizontal-directed rig activity represented over 57% of the total rigs in the United States, about 75% higher than peak levels in 2008. These trends have led to increased demand and improved pricing for most of our products and services in our United States land operations. In the third quarter of 2011, North America revenue increased 13% and operating income increased 14% sequentially. Going forward, we believe there will be an increase in overall activity in the United States land market, and this is reinforcing our confidence that margins for North America will be sustainable; however, growing cost pressure could moderate the extent of any further margin improvements for the remainder of 2011.
Deepwater drilling activity in the Gulf of Mexico is continuing to recover due to the issuance of a number of drilling permits. Despite some improvement in the third quarter, we believe risks remain for further growth in the Gulf of Mexico unless the pace of permit issuance is sustained at higher levels for a period of time. Our business in the Gulf of Mexico represented approximately 16% of our North America revenue in the nine months of 2009, approximately 10% in the nine months of 2010, and approximately 6% in the nine months of 2011. In addition, the Gulf of Mexico represented approximately 6% of our consolidated revenue in the nine months of 2009, approximately 5% in the nine months of 2010, and approximately 3% in the nine months of 2011. Longer term, we do not know the extent to which the Macondo well incident or resulting drilling regulations will impact revenue or earnings, as they are dependent on, among other things, governmental approvals for permits, our customers’ actions, and the potential movement of deepwater rigs to or from other markets.
International operations
During the third quarter of 2011, revenue outside North America increased 7% and operating income outside of North America increased 23% from the prior quarter, reflecting typical seasonality. This seasonality more than offset activity disruptions caused by the political unrest and sanctions in North Africa and the continued impact of over capacity leading to pricing pressure. The first quarter of 2011 results were impacted by a $59 million, pre-tax, charge in Libya, to reserve for certain doubtful accounts receivable and inventory. Additionally, the second quarter of 2011 results were impacted by a $11 million, pre-tax, charge for employee separation costs, primarily related to our Europe/Africa/CIS regional operations. The third quarter of 2011 results were impacted by a $25 million, pre-tax, impairment charge on an asset held for sale in our Europe/Africa/CIS regional operations.

 
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The pace of international recovery is lagging that of previous cycles at this stage, despite international rig counts exceeding the prior peak reached in September of 2008. One of the contributory factors for the difference is the decline in offshore rig counts that we have seen with the current cycle. Given the service intensity of offshore work, we believe this resulted in a more extensive impact on the industry’s revenues, a more significant capacity overhang, and consequently, a more pronounced drop off in pricing. However, we are anticipating that the industry will experience steady volume increases through the remainder of the year and 2012 as macroeconomic trends support a more favorable operator spending outlook, which we believe will eventually lead to meaningful absorption of equipment supply and result in the ability to begin to improve pricing for our services sometime in the fourth quarter of 2011 and into 2012. We continue to believe in the long-term prospects of the international market and will align our business accordingly. Consistent with our long-term strategy to grow our operations outside of North America, we also expect to continue to invest capital in our international operations.
Venezuela. In December 2010, the Venezuelan government set the fixed exchange rate at 4.3 Bolívar Fuerte to one United States dollar effective January 1, 2011, eliminating the dual exchange rate scheme implemented in early 2010. This change had no impact on us because we have applied the 4.3 Bolívar Fuerte fixed exchange rate since the previously disclosed January 2010 devaluation. We continue to work with our primary customer in Venezuela to resolve outstanding issues regarding the payment of invoices in relation to exchange rates and discounts.
On May 24, 2011, the United States government imposed sanctions on the state-owned oil company of Venezuela. The sanctions do not, however, apply to that company’s subsidiaries and do not prohibit the export of crude oil to the United States. We do not expect these sanctions to have a material impact on our operations in Venezuela.
As of September 30, 2011, our total net investment in Venezuela was approximately $191 million. In addition to this amount, we have $276 million of surety bond guarantees outstanding relating to our Venezuelan operations.

Initiatives and recent contract awards
Following is a brief discussion of some of our recent and current initiatives:
-
increasing our market share in the more economic, unconventional plays and deepwater markets by leveraging our broad technology offerings to provide value to our customers through integrated solutions and the ability to more efficiently drill and complete their wells;
-
exploring opportunities for acquisitions that will enhance or augment our current portfolio of products and services, including those with unique technologies or distribution networks in areas where we do not already have large operations;
-
making key investments in technology and capital to accelerate growth opportunities. To that end, we are continuing to push our technology and manufacturing development, as well as our supply chain, closer to our customers in the Eastern Hemisphere, and we are building a new, world class technology center in Houston, Texas;
-
improving working capital, and managing our balance sheet to maximize our financial flexibility. In early 2011, we launched a global project to improve service delivery that we expect to result in, among other things, additional investments in our systems and significant improvements to our current order-to-cash and purchase-to-pay processes;
-
continuing to seek ways to be one of the most cost efficient service providers in the industry by using our scale and breadth of operations; and
-
expanding our business with national oil companies.

 
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Contract wins positioning us to grow our operations over the long term include:
-
a three-year contract award by Chevron, with extension opportunities, to provide integrated services for shale natural gas exploration in Poland. Under this contract, we will provide drilling services, mud logging, cementing, coiled tubing, slickline services, well testing, completion and hydraulic fracturing, and project management services;
-
contract awards by Statoil, with the potential to exceed more than $200 million in value, to provide directional drilling, logging-while-drilling, cementing, drilling fluids, and completion equipment and services for two high-pressure and high-temperature (HP/HT) fields offshore Norway;
-
contract awards for equipment and services on two offshore blocks in the South China Sea as part of the first ultra-HP/HT oil and gas drilling project in Asia. Under these contracts, we will provide several-HP/HT technologies for drilling, completions,  cementing, and testing, including two industry-first technologies;
-
a three-year contract extension by Chevron Thailand, which includes provisions for directional drilling, logging- and measurement- while-drilling services for the ongoing offshore developments in the Gulf of Thailand;
-
a contract by Exxon Mobil Iraq Limited to provide drilling services for 15 wells in the West Qurna (Phase I) oil field located in southern Iraq. This is in addition to work awarded in this field by the same customer in 2010. Under this contract, we will provide a complete range of well construction services, utilizing three drilling rigs to deliver the wells; and
-
a contract by Statoil to provide integrated drilling and well services in offshore Norway with options up to eight years in duration with extended scope and activity. We will provide directional drilling services, logging- and measurement-while-drilling services, surface data logging, drill bits, hole enlargement and coring services, cementing and pumping services, drilling and completion fluids, completion services, and project management.

 
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RESULTS OF OPERATIONS IN 2011 COMPARED TO 2010

Three Months Ended September 30, 2011 Compared with Three Months Ended September 30, 2010

   
Three Months Ended
             
REVENUE:
 
September 30
   
Increase
   
Percentage
 
Millions of dollars
 
2011
   
2010
   
(Decrease)
   
Change
 
Completion and Production
  $ 4,025     $ 2,655     $ 1,370       52 %
Drilling and Evaluation
    2,523       2,010       513       26  
Total revenue
  $ 6,548     $ 4,665     $ 1,883       40 %

By geographic region:
 
Completion and Production:
                       
North America
  $ 2,950     $ 1,706     $ 1,244       73 %
Latin America
    297       208       89       43  
Europe/Africa/CIS
    433       437       (4 )     (1 )
Middle East/Asia
    345       304       41       13  
Total
    4,025       2,655       1,370       52  
Drilling and Evaluation:
                               
North America
    926       675       251       37  
Latin America
    509       360       149       41  
Europe/Africa/CIS
    558       510       48       9  
Middle East/Asia
    530       465       65       14  
Total
    2,523       2,010       513       26  
Total revenue by region:
                               
North America
    3,876       2,381       1,495       63  
Latin America
    806       568       238       42  
Europe/Africa/CIS
    991       947       44       5  
Middle East/Asia
    875       769       106       14  

 
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Three Months Ended
             
OPERATING INCOME:
 
September 30
   
Increase
   
Percentage
 
Millions of dollars
 
2011
   
2010
   
(Decrease)
   
Change
 
Completion and Production
  $ 1,068     $ 609     $ 459       75 %
Drilling and Evaluation
    369       271       98       36  
Corporate and other
    (105 )     (62 )     (43 )     69  
Total operating income
  $ 1,332     $ 818     $ 514       63 %

By geographic region:
 
Completion and Production:
                       
North America
  $ 960     $ 458     $ 502       110 %
Latin America
    43       28       15       54  
Europe/Africa/CIS
    15       73       (58 )     (79 )
Middle East/Asia
    50       50              
Total
    1,068       609       459       75  
Drilling and Evaluation:
                               
North America
    175       115       60       52  
Latin America
    94       49       45       92  
Europe/Africa/CIS
    51       66       (15 )     (23 )
Middle East/Asia
    49       41       8       20  
Total
    369       271       98       36  
Total operating income by region
                               
(excluding Corporate and other):
                               
North America
    1,135       573       562       98  
Latin America
    137       77       60       78  
Europe/Africa/CIS
    66       139       (73 )     (53 )
Middle East/Asia
    99       91       8       9  

The 40% increase in consolidated revenue in the third quarter of 2011 compared to the third quarter of 2010 was primarily attributable to increased activity in North America, as the shift to unconventional oil and liquids-rich basins in the United States land market more than offset geopolitical issues in North Africa. On a consolidated basis, all product service lines experienced revenue growth from the third quarter of 2010. Revenue outside of North America was 41% of consolidated revenue in the third quarter of 2011 and 49% of consolidated revenue in the third quarter of 2010.
The 63% increase in consolidated operating income during the third quarter of 2011 compared to the third quarter of 2010 was attributable to capacity additions, Completion and Production’s higher utilization rates, and a more favorable pricing environment associated with the activity growth in the more service intensive, unconventional oil and liquids-rich basins in the United States land market. However, operating income in the third quarter of 2011 was adversely impacted by a $25 million, pre-tax, impairment charge on an asset held for sale in the Europe/Africa/CIS region.
Following is a discussion of our results of operations by reportable segment.
Completion and Production consolidated revenue increased 52% and North America revenue increased 73% compared to the third quarter of 2010, led by production enhancement services as higher activity in unconventional basins generally resulted in increased demand for hydraulic fracturing. Latin America revenue increased 43%, with Brazil and Mexico leading higher demand throughout the region for all product service lines. Europe/Africa/CIS revenue remained flat, as increased Boots & Coots activity in Norway and Angola was offset by geopolitical disruptions in North Africa and lower completion tools sales in Nigeria. Middle East/Asia revenue increased 13%, due to a weather-related rebound in Australia and completion tools sales improving in both Indonesia and Malaysia while declining in China. Revenue outside of North America was 27% of total segment revenue in the third quarter of 2011 and 36% of total segment revenue in the third quarter of 2010.

 
32

 

Completion and Production segment operating income increased 75% compared to the third quarter of 2010, primarily driven by production enhancement services in the United States land market. The results were negatively impacted by a $25 million, pre-tax, impairment charge on an asset held for sale in the Europe/Africa/CIS region. In North America, operating income grew 110%, due to higher activity, improved equipment utilization, and a more favorable pricing environment for production enhancement services in the United States land market. Latin America operating income improved 54%, as a result of heightened demand for cementing services in Brazil, Colombia, and Argentina and completion tools throughout the region, which were offset by increased production enhancement costs in Mexico. Europe/Africa/CIS operating income declined 79%, due to an impairment charge on an asset held for sale and the effect of geopolitical disruptions in North Africa. Middle East /Asia operating income stayed flat, as a weather-related rebound in Australia and higher margin completion tools sales in Indonesia and Malaysia were offset by lower direct sales in China.
Drilling and Evaluation revenue increased 26% compared to the third quarter of 2010, with all regions experiencing revenue growth from the third quarter of 2010. North America revenue grew 37%, primarily due to higher activity and improved pricing in the United States land market and a recovery of activity in the United States Gulf of Mexico. Latin America revenue increased 41%, driven by higher drilling activities in Mexico and Brazil. Europe/Africa/CIS revenue increased 9%, as higher drilling activities in Norway and Algeria were offset by geopolitical disruptions in North Africa. Middle East/Asia revenue grew 14%, primarily due to the commencement of activity in Iraq, which was offset by lower demand for drilling services in Indonesia and Malaysia. Revenue outside of North America was 63% of total segment revenue in the third quarter of 2011 and 66% of total segment revenue in the third quarter of 2010.
Drilling and Evaluation operating income increased 36% compared to the third quarter of 2010, as strong results in North America and Latin America were partially offset by startup costs from the commencement of work in Iraq. In addition, operating income increased significantly compared to the third quarter of 2010 due to a $50 million impairment charge for an oil and gas property in Bangladesh in the prior year. North America operating income increased 52%, due to higher wireline activity in the United States land market and increased demand for drilling activities throughout the region. Latin America operating income increased 92%, driven by strong demand for drilling activities in Mexico, software sales in Colombia, and testing and subsea activity in Brazil. Europe/Africa/CIS region operating income decreased 23%, primarily due to increased wireline costs throughout the region and geopolitical disruptions in North Africa. Middle East/Asia operating income increased 20%, as the 2010 results were impacted by the impairment charge. This was partially offset by 2011 startup costs associated with the commencement of work in Iraq.
Corporate and other expenses were $105 million in the third quarter of 2011 compared to $62 million in the third quarter of 2010. The increase was due to higher legal and environmental costs and approximately $18 million of costs associated with strategic investments in our operating model and creating competitive advantage by repositioning our technology, supply chain, and manufacturing infrastructure.

NONOPERATING ITEMS
Interest expense, net of interest income decreased $14 million in the third quarter of 2011 compared to the third quarter of 2010, primarily due to less interest expense as a result of the retirement of $750 million principal amount of our 5.5% senior notes in October 2010 and lower interest rates on a portion of our debt as a result of our interest rate swaps.
Income (loss) from discontinued operations, net in the third quarter of 2011 included a $163 million charge related to a ruling in an arbitration proceeding between Barracuda & Caratinga Leasing Company B.V. and our former subsidiary, KBR, whom we agreed to indemnify.

 
33

 

RESULTS OF OPERATIONS IN 2011 COMPARED TO 2010

Nine Months Ended September 30, 2011 Compared with Nine Months Ended September 30, 2010

   
Nine Months Ended
             
REVENUE:
 
September 30
   
Increase
   
Percentage
 
Millions of dollars
 
2011
   
2010
   
(Decrease)
   
Change
 
Completion and Production
  $ 10,815     $ 7,012     $ 3,803       54 %
Drilling and Evaluation
    6,950       5,801       1,149       20  
Total revenue
  $ 17,765     $ 12,813     $ 4,952       39 %

By geographic region:
 
Completion and Production:
                       
North America
  $ 7,759     $ 4,265     $ 3,494       82 %
Latin America
    805       622       183       29  
Europe/Africa/CIS
    1,249       1,281       (32 )     (2 )
Middle East/Asia
    1,002       844       158       19  
Total
    10,815       7,012       3,803       54  
Drilling and Evaluation:
                               
North America
    2,544       1,931       613       32  
Latin America
    1,300       1,008       292       29  
Europe/Africa/CIS
    1,622       1,567       55       4  
Middle East/Asia
    1,484       1,295       189       15  
Total
    6,950       5,801       1,149       20  
Total revenue by region:
                               
North America
    10,303       6,196       4,107       66  
Latin America
    2,105       1,630       475       29  
Europe/Africa/CIS
    2,871       2,848       23       1  
Middle East/Asia
    2,486       2,139       347       16  

 
34

 


   
Nine Months Ended
             
OPERATING INCOME:
 
September 30
   
Increase
   
Percentage
 
Millions of dollars
 
2011
   
2010
   
(Decrease)
   
Change
 
Completion and Production
  $ 2,646     $ 1,344     $ 1,302       97 %
Drilling and Evaluation
    923       859       64       7  
Corporate and other
    (262 )     (174 )     (88 )     51  
Total operating income
  $ 3,307     $ 2,029     $ 1,278       63 %

By geographic region:
 
Completion and Production:
                       
North America
  $ 2,401     $ 905     $ 1,496       165 %
Latin America
    108       91       17       19  
Europe/Africa/CIS
    4       207       (203 )     (98 )
Middle East/Asia
    133       141       (8 )     (6 )
Total
    2,646       1,344       1,302       97  
Drilling and Evaluation:
                               
North America
    463       339       124       37  
Latin America
    186       121       65       54  
Europe/Africa/CIS
    126       210       (84 )     (40 )
Middle East/Asia
    148       189       (41 )     (22 )
Total
    923       859       64       7  
Total operating income by region
                               
(excluding Corporate and other):
                               
North America
    2,864       1,244       1,620       130  
Latin America
    294       212       82       39  
Europe/Africa/CIS
    130       417       (287 )     (69 )
Middle East/Asia
    281       330       (49 )     (15 )

The 39% increase in consolidated revenue in the nine months of 2011 compared to the nine months of 2010 was primarily due to higher drilling activity and increased demand for Completion and Production services in North America. Revenue outside North America was 42% of consolidated revenue in the nine months of 2011 and 52% of consolidated revenue in the nine months of 2010.
The 63% increase in consolidated operating income in the nine months of 2011 compared to the nine months of 2010 was primarily due to higher demand and a more favorable pricing environment for Completion and Production services in North America as operators continued the shift towards the more service intensive oil and liquids-rich basins. Operating income in the nine months of 2011 was adversely impacted by a $25 million, pre-tax, impairment charge on an asset held for sale in the Europe/Africa/CIS region, $11 million, pre-tax, of employee separation costs in the Eastern Hemisphere during the second quarter of 2011, and a $59 million, pre-tax, charge in Libya, to reserve for certain doubtful accounts receivable and inventory during the first quarter of 2011. Operating income in the nine months of 2010 was adversely impacted by a $50 million impairment charge for an oil and gas property in Bangladesh in the third quarter of 2010.
Completion and Production revenue increased by 54% driven by North America revenue growth of 82% compared to the nine months of 2010. The activity increase in North America was led by production enhancement services in the United States land market as higher activity in unconventional basins resulted in increased demand for hydraulic fracturing. Latin America revenue rose 29% on higher activity for all product service lines across the region. Europe/Africa/CIS revenue was relatively flat, as the activity disruptions in North Africa and lower completions activity in Nigeria offset higher activity for our Boots & Coots product service line in Angola and Norway. Middle East/Asia revenue increased 19% with higher activity levels in Malaysia, Indonesia, and Australia. Revenue outside North America was 28% of total segment revenue in the nine months of 2011 and 39% of total segment revenue in the nine months of 2010.

 
35

 

Completion and Production operating income increased 97% compared to the nine months of 2010. This increase was driven by the North America region, where operating income grew $1.5 billion on higher activity for production enhancement services in unconventional basins located in the United States land market. Latin America operating income increased 19%, as higher demand for cementing services in the region offset higher costs in Mexico. Europe/Africa/CIS operating income declined 98% primarily due to an impairment charge on an asset held for sale in the third quarter of 2011 and activity disruptions in North Africa, including the reserve charge for certain account receivables and inventory recognized in the first quarter of 2011. Middle East/Asia operating income decreased 6% due to higher costs across most of the region and startup costs associated with the commencement of work in Iraq, which were partially offset by higher activity levels in Malaysia, Indonesia, and Australia.
Drilling and Evaluation revenue increased 20% compared to the nine months of 2010 as drilling activity improved across all regions, most significantly in North America. North America revenue grew 32% on substantial activity increases in the United States land market. Latin America revenue rose 29% as a result of increased demand for most product service lines in Brazil, Venezuela, and Colombia. Europe/Africa/CIS revenue was relatively flat, as higher drilling activity in Norway and Angola was offset by lower activity in Libya and Kazakhstan. Middle East/Asia revenue increased 15% due to the commencement of work in Iraq, increased fluids demand in Indonesia, and higher wireline direct sales in China. Revenue outside North America was 63% of total segment revenue in the nine months of 2011 and 67% of total segment revenue in the nine months of 2010.
Drilling and Evaluation operating income increased 7% compared to the nine months of 2010, as activity increases in the United States land market offset lower activity associated with the disruptions in North Africa and less favorable pricing in the Eastern Hemisphere. North America operating income grew 37% on higher drilling activity and more favorable pricing, primarily in the United States land market. Latin America operating income rose 54% as a result of activity increases in Venezuela and Mexico and an improved product mix for fluid services in Brazil. Europe/Africa/CIS region operating income fell 40% primarily due to costs associated with activity disruptions in North Africa, including the reserve charge for certain account receivables and inventory recognized in the first quarter of 2011. Middle East/Asia operating income decreased 22% mainly due to lower activity and higher costs in Saudi Arabia, Oman, and Malaysia and startup costs associated with the commencement of work in Iraq.
Corporate and other expenses were $262 million in the nine months of 2011 compared to $174 million in the nine months of 2010. The increase was primarily due to higher legal and environmental costs and additional expenses associated with strategic investments in our operating model and creating competitive advantage by repositioning our technology, supply chain, and manufacturing infrastructure.

NONOPERATING ITEMS
Interest expense, net of interest income decreased $34 million in the nine months of 2011 compared to the nine months of 2010 primarily due to less interest expense as a result of the retirement of $750 million principal amount of our 5.5% senior notes in October 2010 and lower interest rates on a portion of our debt as a result of our interest rate swaps.
Other, net decreased $38 million in the nine months of 2011 compared to the nine months of 2010 primarily due to a $31 million loss on foreign exchange recognized in the first quarter of 2010 in connection with the devaluation of the Venezuelan Bolívar Fuerte.
Income (loss) from discontinued operations, net for the nine months of 2011 included a $163 million charge related to a ruling in an arbitration proceeding between Barracuda & Caratinga Leasing Company B.V. and our former subsidiary, KBR, whom we agreed to indemnify.

 
36

 

ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. For information related to environmental matters, see Note 7 to the condensed consolidated financial statements, Part II, Item 1, “Legal Proceedings—Environmental,” and Part II, Item 1(a), “Risk Factors.”

NEW ACCOUNTING PRONOUNCEMENTS

In June 2011, the Financial Accounting Standards Board (FASB) issued an update to existing guidance on the presentation of comprehensive income. This update will require the presentation of the components of net income and other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In addition, companies are also required to present reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The update is effective for fiscal years and interim periods beginning after December 15, 2011. We will adopt the new disclosure requirements for comprehensive income beginning January 1, 2012 and are currently evaluating the provisions of this update.

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,” “believes,” “do not believe,” “expects,” “do not expect,” “anticipates,” “do not anticipate,” “should,” 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 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 Securities and Exchange Commission (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
We are exposed to market risk from changes in foreign currency exchange rates and interest rates. We selectively manage these exposures through the use of derivative instruments, including forward exchange contracts and interest rate swaps. The objective of our risk management strategy is to minimize the volatility from fluctuations in foreign currency and interest rates. We do not use derivative instruments for trading purposes. The counterparties to our forward exchange contracts and interest rate swaps are global commercial banks.
There are certain limitations inherent in the sensitivity analyses presented, primarily due to the assumption that interest rates and exchange rates change instantaneously in an equally adverse fashion. In addition, the analyses are unable to reflect the complex market reactions that normally would arise from the market shifts modeled. While this is our best estimate of the impact of the various scenarios, these estimates should not be viewed as forecasts.

 
37

 

Foreign exchange risk
We have operations in many international locations and are involved in transactions denominated in currencies other than the U.S. dollar, our functional currency, which exposes us to foreign currency exchange rate risk. Techniques in managing foreign exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency derivative instruments. We attempt to selectively manage significant exposures to potential foreign exchange losses based on current market conditions, future operating activities, and the associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management activities is to minimize the risk that our cash flows from the sale and purchase of services and products in foreign currencies will be adversely affected by changes in exchange rates.
We use forward exchange contracts to manage our exposure to fluctuations in the currencies of the countries in which we do the majority of our international business. These forward exchange contracts are not treated as hedges for accounting purposes, generally have an expiration date of one year or less, and are not exchange traded. While forward exchange contracts are subject to fluctuations in value, the fluctuations are generally offset by the value of the underlying exposures being managed. The use of some of these contracts may limit our ability to benefit from favorable fluctuations in foreign exchange rates.
Forward exchange contracts are not utilized to manage exposures in some currencies due primarily to the lack of available markets or cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency exposure in non-traded currencies and recognize that pricing for the services and products offered in these countries should account for the cost of exchange rate devaluations. We have historically incurred transaction losses in non-traded currencies.
The notional amounts of open forward exchange contracts were $207 million at September 30, 2011 and $356 million at December 31, 2010. The notional amounts of our forward exchange contracts do not generally represent amounts exchanged by the parties, and thus are not a measure of our exposure or of the cash requirements related to these contracts. As such, cash flows related to these contracts are typically not material. The amounts exchanged are calculated by reference to the notional amounts and by other terms of the contracts, such as exchange rates.
We use a sensitivity analysis model to measure the impact of a 10% adverse movement of foreign currency exchange rates against the U.S. dollar. A hypothetical 10% adverse change in the value of all our foreign currency positions relative to the U.S. dollar as of September 30, 2011 would result in a $58 million pre-tax loss for our net monetary assets denominated in currencies other than U.S. dollars.
Interest rate risk
We are subject to interest rate risk on our long-term debt. Our marketable securities and short-term borrowings do not give rise to significant interest rate risk due to their short-term nature. We had fixed rate long-term debt totaling $3.8 billion at September 30, 2011 and December 31, 2010, respectively, with none maturing before 2017.
During the second quarter of 2011, we entered into a series of interest rate swaps relating to two of our debt instruments with a total notional amount of $1 billion at a weighted-average, LIBOR-based, floating rate of 3.37% as of September 30, 2011. We use interest rate swaps to manage the economic effect of fixed rate obligations associated with certain senior notes so that the interest payable on the senior notes effectively becomes linked to variable 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.
After consideration of the impact from the interest rate swaps, a hypothetical 100 basis point increase in the LIBOR rate would result in approximately an additional $4 million of interest charges for the nine months ended September 30, 2011.

 
38

 

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, 2011 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
There has been no change in our internal control over financial reporting that occurred during the three months ended September 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 
39

 

PART II. OTHER INFORMATION