SEC Filing - Halliburton

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HAL_6.30.2012-10Q

Table of Contents

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 June 30, 2012

[ ] 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 July 20, 2012, 927,750,281 shares of Halliburton Company common stock, $2.50 par value per share, were outstanding.

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HALLIBURTON COMPANY

Index



		Page No.
PART I.	FINANCIAL INFORMATION	1

Item 1.	Financial Statements	1

	- Condensed Consolidated Statements of Operations	1
	- Condensed Consolidated Statements of Comprehensive Income	2
	- Condensed Consolidated Balance Sheets	3
	- Condensed Consolidated Statements of Cash Flows	4
	- Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33

Item 4.	Controls and Procedures	33

PART II.	OTHER INFORMATION	34

Item 1.	Legal Proceedings	34

Item 1(a).	Risk Factors	46

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50

Item 3.	Defaults Upon Senior Securities	50

Item 4.	Mine Safety Disclosures	50

Item 5.	Other Information	50

Item 6.	Exhibits	51

SIGNATURES		52

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HALLIBURTON COMPANY

Condensed Consolidated Statements of Operations

(Unaudited)



	Three Months Ended June 30						Six Months Ended June 30
Millions of dollars and shares except per share data	2012			2011			2012			2011
Revenue:
Services	$	5,670		$	4,727		$	11,094		$	8,918
Product sales	1,564			1,208			3,008			2,299
Total revenue	7,234			5,935			14,102			11,217
Operating costs and expenses:
Cost of services	4,638			3,659			9,171			7,087
Cost of sales	1,328			1,050			2,572			2,020
General and administrative	67			65			135			135
Total operating costs and expenses	6,033			4,774			11,878			9,242
Operating income	1,201			1,161			2,224			1,975
Interest expense, net of interest income of $2, $2, $4, and $3	(80		)	(63		)	(154		)	(132		)
Other, net	(17		)	(5		)	(24		)	(9		)
Income from continuing operations before income taxes	1,104			1,093			2,046			1,834
Provision for income taxes	(357		)	(352		)	(661		)	(581		)
Income from continuing operations	747			741			1,385			1,253
Income (loss) from discontinued operations, net of income tax (provision) benefit of $(3), $1, $2, and $1	(8		)	—			(16		)	(1		)
Net income	$	739		$	741		$	1,369		$	1,252
Noncontrolling interest in net income of subsidiaries	(2		)	(2		)	(5		)	(2		)
Net income attributable to company	$	737		$	739		$	1,364		$	1,250
Amounts attributable to company shareholders:
Income from continuing operations	$	745		$	739		$	1,380		$	1,251
Loss from discontinued operations, net	(8		)	—			(16		)	(1		)
Net income attributable to company	$	737		$	739		$	1,364		$	1,250
Basic income per share attributable to company shareholders:
Income from continuing operations	$	0.81		$	0.81		$	1.50		$	1.37
Loss from discontinued operations, net	(0.01		)	—			(0.02		)	—
Net income per share	$	0.80		$	0.81		$	1.48		$	1.37
Diluted income per share attributable to company shareholders:
Income from continuing operations	$	0.80		$	0.80		$	1.49		$	1.36
Loss from discontinued operations, net	(0.01		)	—			(0.02		)	—
Net income per share	$	0.79		$	0.80		$	1.47		$	1.36
Cash dividends per share	$	0.09		$	0.09		$	0.18		$	0.18
Basic weighted average common shares outstanding	924			916			923			915
Diluted weighted average common shares outstanding	926			921			926			920
See notes to condensed consolidated financial statements.

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HALLIBURTON COMPANY

Condensed Consolidated Statements of Comprehensive Income

(Unaudited)



	Three Months Ended June 30						Six Months Ended June 30
Millions of dollars	2012			2011			2012			2011
Net income	$	739		$	741		$	1,369		$	1,252
Other comprehensive income, net of income taxes:
Defined benefit and other postretirement plans adjustments	$	6		$	(1	)	$	14		$	(1	)
Other	(1		)	2			(2		)	4
Other comprehensive income, net of income taxes	5			1			12			3
Comprehensive income	$	744		$	742		$	1,381		$	1,255
Comprehensive income attributable to noncontrolling interest	(2		)	(2		)	(5		)	(2		)
Comprehensive income attributable to company shareholders	$	742		$	740		$	1,376		$	1,253
See notes to condensed consolidated financial statements.

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HALLIBURTON COMPANY

Condensed Consolidated Balance Sheets



	June 30, 2012			December 31, 2011
Millions of dollars and shares except per share data	(Unaudited)
Assets
Current assets:
Cash and equivalents	$	2,172		$	2,698
Receivables (less allowance for bad debts of $117 and $137)	5,674			5,084
Inventories	3,297			2,570
Other current assets	1,391			1,225
Total current assets	12,534			11,577
Property, plant, and equipment, net of accumulated depreciation of $7,514 and $7,096	9,363			8,492
Goodwill	1,986			1,776
Other assets	1,688			1,832
Total assets	$	25,571		$	23,677
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	2,113		$	1,826
Accrued employee compensation and benefits	789			862
Other current liabilities	1,538			1,433
Total current liabilities	4,440			4,121
Long-term debt	4,820			4,820
Employee compensation and benefits	512			534
Other liabilities	1,238			986
Total liabilities	11,010			10,461
Shareholders’ equity:
Common shares, par value $2.50 per share - authorized 2,000 shares, issued 1,073 shares	2,683			2,683
Paid-in capital in excess of par value	424			455
Accumulated other comprehensive loss	(261		)	(273		)
Retained earnings	16,077			14,880
Treasury stock, at cost - 147 and 152 shares	(4,383		)	(4,547		)
Company shareholders’ equity	14,540			13,198
Noncontrolling interest in consolidated subsidiaries	21			18
Total shareholders’ equity	14,561			13,216
Total liabilities and shareholders’ equity	$	25,571		$	23,677
See notes to condensed consolidated financial statements.

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HALLIBURTON COMPANY

Condensed Consolidated Statements of Cash Flows

(Unaudited)



	Six Months Ended June 30
Millions of dollars	2012			2011
Cash flows from operating activities:
Net income	$	1,369		$	1,252
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation, depletion, and amortization	791			651
Loss contingency for Macondo well incident	300			—
Other changes:
Inventories	(724		)	(290		)
Receivables	(602		)	(583		)
Accounts payable	289			397
Other	(288		)	(39		)
Total cash flows from operating activities	1,135			1,388
Cash flows from investing activities:
Capital expenditures	(1,651		)	(1,423		)
Sales of marketable securities	200			701
Purchases of marketable securities	(100		)	(501		)
Other investing activities	34			(20		)
Total cash flows from investing activities	(1,517		)	(1,243		)
Cash flows from financing activities:
Dividends to shareholders	(167		)	(165		)
Other financing activities	25			80
Total cash flows from financing activities	(142		)	(85		)
Effect of exchange rate changes on cash	(2		)	(20		)
Increase (decrease) in cash and equivalents	(526		)	40
Cash and equivalents at beginning of period	2,698			1,398
Cash and equivalents at end of period	$	2,172		$	1,438
Supplemental disclosure of cash flow information:
Cash payments during the period for:
Interest	$	146		$	136
Income taxes	$	897		$	536
See notes to condensed consolidated financial statements.

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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 2011 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 June 30, 2012, the results of our operations for the three and six months ended June 30, 2012 and 2011, and our cash flows for the six months ended June 30, 2012 and 2011. Such adjustments are of a normal recurring nature. In addition, certain reclassifications of prior period balances have been made to conform to 2012 classifications. The results of operations for the three and six months ended June 30, 2012 may not be indicative of results for the full year.

Note 2. Business Segment and Geographic Information

We operate under two divisions, which form the basis for the two operating segments we report: the Completion and Production segment and the Drilling and Evaluation segment.

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, such as the $300 million loss contingency related to the Macondo well incident recorded in “Corporate and other” during the first quarter of 2012.

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 June 30						Six Months Ended June 30
Millions of dollars	2012			2011			2012			2011
Revenue:
Completion and Production	$	4,460		$	3,618		$	8,750		$	6,790
Drilling and Evaluation	2,774			2,317			5,352			4,427
Total revenue	$	7,234		$	5,935		$	14,102		$	11,217
Operating income:
Completion and Production	$	914		$	918		$	1,950		$	1,578
Drilling and Evaluation	393			324			761			554
Total operations	1,307			1,242			2,711			2,132
Corporate and other	(106		)	(81		)	(487		)	(157		)
Total operating income	$	1,201		$	1,161		$	2,224		$	1,975
Interest expense, net of interest income	(80		)	(63		)	(154		)	(132		)
Other, net	(17		)	(5		)	(24		)	(9		)
Income from continuing operations before income taxes	$	1,104		$	1,093		$	2,046		$	1,834

Receivables

As of June 30, 2012, 43% of our gross trade receivables were from customers in the United States. As of December 31, 2011, 45% of our gross trade receivables were from customers in the United States.

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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 $160 million as of both June 30, 2012 and December 31, 2011. If the average cost method had been used, total inventories would have been $42 million higher than reported as of June 30, 2012 and $36 million higher than reported as of December 31, 2011. The cost of the remaining inventory was recorded on the average cost method. Inventories consisted of the following:



Millions of dollars	June 30, 2012		December 31, 2011
Finished products and parts	$	2,405	$	1,801
Raw materials and supplies	773		673
Work in process	119		96
Total	$	3,297	$	2,570

Finished products and parts are reported net of obsolescence reserves of $110 million as of June 30, 2012 and $108 million as of December 31, 2011.

Note 4. Shareholders’ Equity

The following tables summarize our shareholders’ equity activity.



Millions of dollars	Total Shareholders' equity			Company shareholders' equity			Noncontrolling interest in consolidated subsidiaries
Balance at December 31, 2011	$	13,216		$	13,198		$	18
Transactions with shareholders	131			133			(2		)
Comprehensive income	1,381			1,376			5
Payments of dividends to shareholders	(167		)	(167		)	—
Balance at June 30, 2012	$	14,561		$	14,540		$	21



Millions of dollars	Total Shareholders' equity			Company shareholders' equity			Noncontrolling interest in consolidated subsidiaries
Balance at December 31, 2010	$	10,387		$	10,373		$	14
Transactions with shareholders	181			181			—
Comprehensive income	1,255			1,253			2
Payments of dividends to shareholders	(165		)	(165		)	—
Balance at June 30, 2011	$	11,658		$	11,642		$	16

The tax effects allocated to each component of other comprehensive income for the three and six months ended June 30, 2012 and 2011 are not material.

Accumulated other comprehensive loss consisted of the following:



Millions of dollars	June 30, 2012			December 31, 2011
Defined benefit and other postretirement liability adjustments	$	(194	)	$	(208	)
Cumulative translation adjustments	(67		)	(66		)
Unrealized gains on investments	—			1
Total accumulated other comprehensive loss	$	(261	)	$	(273	)

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Note 5. 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 “Loss from discontinued operations, net of income tax 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.

The tax sharing agreement provides for the calculation and allocation of United States and certain other jurisdiction tax liabilities between us and KBR for the periods 2001 through the date of separation. 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.

During the second quarter of 2012, we sent a notice as required by the tax sharing agreement to KBR requesting the appointment of an arbitrator in accordance with the terms of the tax sharing agreement. This request asked the arbitrator to find that KBR owes us $256 million pursuant to the tax sharing agreement. KBR denied that it owes us any amount and asserted instead that we owe KBR certain amounts under the tax sharing agreement. KBR also asserted that they believe the master separation agreement controls this matter and demanded arbitration under that agreement. On July 10, 2012, we filed suit in the District Court of Harris County, Texas, seeking to compel KBR to arbitrate this dispute in accordance with the provisions of the tax sharing agreement, rather than the master separation agreement. No anticipated recovery amounts related to this matter have been recognized in the condensed consolidated financial statements.

Amounts accrued relating to our remaining KBR liabilities are primarily included in “Other liabilities” on the condensed consolidated balance sheets and totaled $215 million as of June 30, 2012 and $201 million as of December 31, 2011. See Note 6 for further discussion of the Barracuda-Caratinga matter.

Note 6. Commitments and Contingencies

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.

We are currently unable to fully estimate the impact the Macondo well incident will have on us. The beginning of the multi-district litigation (MDL) trial referred to below has been delayed to January 2013 in connection with the pending settlement between BP and the Plaintiffs’ Steering Committee (PSC) in the MDL. In addition, BP has settled litigation with several defendants in the MDL. We cannot predict the outcome of the many lawsuits and investigations relating to the Macondo well incident, including orders and rulings of the court that impact the MDL, whether the MDL will proceed to trial, the results of any such trial, the final settlement arrangement between BP and the PSC, the effect that settlement may have on claims against us, or whether we might settle with one or more of the parties to any lawsuit or investigation. At the request of the court, in late February 2012 we participated in a series of discussions with the Magistrate Judge in the MDL relating to whether the MDL could be settled. Although these discussions did not result in a settlement, we recorded a $300 million liability during the first quarter of 2012 for an estimated loss contingency relating to the MDL. This loss contingency, which is included in “Other liabilities” on the condensed consolidated balance sheet as of June 30, 2012 and in “Cost of services” on the condensed consolidated statement of operations for the six months ended June 30, 2012, represents a loss contingency that is probable and for which a reasonable estimate of a loss or range of loss can be made. Although we continue to believe that we have substantial legal arguments and defenses against any liability and that BP's indemnity obligation protects us, we cannot conclude that a probable loss associated with the MDL is zero. There are additional loss contingencies relating to the Macondo well incident that are reasonably possible but for which we cannot make a reasonable estimate. Given the numerous potential developments relating to the MDL and other lawsuits and investigations, which could occur at any time, we may adjust our estimated loss contingency in the future. Liabilities arising out of the Macondo well incident could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

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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 (BOEMRE) (formerly known as the Minerals Management Service (MMS) and which was replaced effective October 1, 2011 by two new, independent bureaus – the Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Ocean Energy Management (BOEM)), 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. The Marine Board Investigation, as well as investigations of the incident that were conducted by The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (National Commission) and the National Academy of Sciences, have been completed, and reports issued as a result of those investigations are discussed below. In addition, the Chemical Safety Board is conducting an investigation to examine the root causes of the accidental release of hydrocarbons from the Macondo well, including an examination of key technical factors, the safety cultures involved, and the effectiveness of relevant laws, regulations, and industry standards.

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). As part of its criminal investigation, the DOJ is examining certain aspects of our conduct after the incident, including with respect to record-keeping, record retention, post-incident testing and modeling, securities filings, and public statements by us or our employees, to evaluate whether there has been any violation of federal law.

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 (OCSLA) 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, onshore facility, or offshore facility from which oil or a hazardous substance is discharged” in violation of the CWA. 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 and real or personal property, 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.

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 such violations are misdemeanor crimes subject to 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, federal law provides for a variety of fines and penalties, the most significant of which is the Alternative Fines Act. In lieu of the express amount of the criminal fines that may be imposed under some of the statutes described above, the Alternative Fines Act provides for a fine in the amount of twice the gross economic loss suffered by third parties, which amount, although difficult to estimate, is significant.

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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), which had an approximate 25% interest in the Macondo well, 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 United States 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 United States shorelines and resulting in removal costs and damages to the United States far exceeding $75 million. BP Exploration 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 or another law and requested a judgment that the DOJ assert its claims for OPA financial liability directly against us. We filed a motion to dismiss BP Exploration’s claim, and that motion is pending.

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 are not included in the DOJ’s civil 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, and/or other statutes or regulations. In connection with the DOJ’s filing of the civil 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 fully with the DOJ’s criminal investigation. As of July 27, 2012, the DOJ has not commenced any criminal proceedings against us. We cannot predict the status or outcome of the DOJ’s criminal investigation or estimate the potential impact the investigation may have on us or our liability assessment, all of which may change as the investigation progresses.We have had and expect to continue to have discussions with the DOJ regarding the Macondo well incident and associated pre-incident and post-incident conduct.

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.

On January 11, 2011, the 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.

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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 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 BOEMRE 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 and the pipe being outside the cutting surface of the ram blades. The forensic examination report recommended further examination, investigation, and testing, which found that the redundant operating pods of the blowout preventer may not have timely activated the blind shear rams in the automatic mode function due to a depleted battery in one pod and a miswired solenoid in the other pod. We had no part in manufacturing or servicing the blowout preventer stack.

In September 2011, the BOEMRE released the final report of the Marine Board Investigation regarding the Macondo well incident (BOEMRE Report). A panel of investigators of the BOEMRE identified a number of causes of the Macondo well incident. According to the BOEMRE 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 BOEMRE 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 BOEMRE 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 BOEMRE 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 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 in effect at the time of the alleged violations provide for fines of up to $35,000 per day per violation. We have appealed the INCs to the Interior Board of Land Appeals (IBLA). In January 2012, the IBLA, in response to our and the BSEE’s joint request, has suspended the appeal and has ordered us and the BSEE to file notice within 15 days after the conclusion of the MDL and, within 60 days after the MDL court issues a final decision, to file a proposal for further action in the appeal. The BSEE has announced that the INCs will be reviewed for possible imposition of civil penalties once the appeal 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.

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In December 2011, the National Academy of Sciences released a pre-publication copy of its report examining the causes of the Macondo well incident and identifying measures for preventing similar incidents in the future (NAS Report). The NAS Report noted that it does not attempt to assign responsibility to specific individuals or entities or determine the extent that the parties involved complied with applicable regulations.

According to the NAS Report, the flow of hydrocarbons that led to the blowout began when drilling mud was displaced by seawater during the temporary abandonment process, which was commenced by the drilling team despite a failure to demonstrate the integrity of the cement job after multiple negative pressure tests and after incorrectly deciding that a negative pressure test indicated that the cement barriers were effective. In addition, the NAS Report found, among other things, that: the approach chosen for well completion failed to provide adequate safety margins considering the reservoir formation; the loss of well control was not noted until more than 50 minutes after hydrocarbon flow from the formation had started; the blowout preventer was not designed or tested for the dynamic conditions that most likely existed at the time attempts were made to recapture well control; and the entities involved did not provide an effective systems safety approach commensurate with the risks of the Macondo well. According to the NAS Report, a number of key decisions related to the design, construction, and testing of the barriers critical to the temporary abandonment process were flawed.

The NAS Report also found, among other things, that the heavier “tail” cement slurry, intended for placement in the Macondo well shoe track, was “gravitationally unstable” on top of the lighter foam cement slurry and that the heavier tail cement slurry probably fell into or perhaps through the lighter foam cement slurry during pumping into the well, which would have left a tail slurry containing foam cement in the shoe track. The NAS Report also found, among other things, that foam cement that may have been inadvertently left in the shoe track likely would not have had the strength to resist crushing when experiencing the differential pressures exerted on the cement during the negative pressure test. In addition, the NAS Report found, among other things, that evidence available before the blowout indicated that the flapper valves in the float collar probably failed to seal, but the evidence was not acted upon and, due to BP’s choice of a long-string production casing and the lack of minimum circulation of the well prior to the cement job, the possibility of mud-filled channels or poor cement bonding existed.

The NAS Report also set forth the following observations, among others: (1) there were alternative completion techniques and operational processes available that could have safely prepared the well for temporary abandonment; (2) post-incident static tests on a foam cement slurry similar to the slurry pumped into the Macondo well were performed under laboratory conditions and exhibited the settling of cement and nitrogen breakout, although because the tests were not conducted at bottom hole conditions “it is impossible to say whether the foam was stable at the bottom of the well”; (3) the “cap” cement slurry was subject to contamination by the spacer or the drilling mud that was placed ahead of the cap cement slurry and, if the cap cement slurry was heavily contaminated, it would not reach the strength of uncontaminated cement; (4) the numerous companies involved and the division of technical expertise among those companies affected their ability to perform and maintain an integrated assessment of the margins of safety for the Macondo well; (5) the regulatory regime was ineffective in addressing the risks of the Macondo well; and (6) training of key personnel and decision makers in the industry and regulatory agencies has been inadequate relative to the risks and complexities of deepwater drilling.

The NAS Report recommended, among other things: that all primary cemented barriers to flow should be tested to verify quality, quantity, and location of cement; that the integrity of mechanical barriers should be verified by using the best available test procedures; that blowout preventer systems should be redesigned for the drilling environment to which they are being applied; and that operating companies should have ultimate responsibility and accountability for well integrity, well design, well construction, and the suitability of the rig and associated safety equipment.

The Cementing Job and Reaction to Reports. We disagree with the BP Report, the National Commission, Transocean’s report, the BOEMRE Report, and the NAS Report regarding many of their findings and characterizations with respect to the cementing and surface data logging services, as applicable, 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 the BOEMRE 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 Transocean 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 tests, and with Transocean 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 BOEMRE Report, the NAS Report, or the conclusions of future reports of the Chemical Safety Board or others. We also cannot predict whether their investigations or any other report or investigation will have an influence on or result in us being named as a party in any action alleging liability or 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 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. We are 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 seven personal injury lawsuits involving four decedents and at least 11 allegedly injured persons who were on the drilling rig at the time of the incident. At least six additional 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. Except for certain lawsuits not yet consolidated, the Judicial Panel on Multi-District Litigation ordered all of the lawsuits against us consolidated in the MDL proceeding before Judge Carl Barbier in the United States 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 OCSLA, 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. Complaints brought against us by at least seven other parishes in Louisiana were dismissed with prejudice, and the dismissal is being appealed by those parishes. 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. In February 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 is scheduled to occur in at least two phases beginning in January 2013. The initial two phases of this portion of the trial are scheduled to cover issues arising out of the conduct of various parties allegedly relevant to the loss of well control, the ensuing fire and explosion on and sinking of the Deepwater Horizon, the initiation of the release of hydrocarbons from the Macondo well, the actions relating to the attempts to control the flow of hydrocarbons from the well, and the quantification of hydrocarbons discharged from the well. Subsequent proceedings would be held to the extent triable issues remain unsolved by the first two phases of the trial, settlements, motion practice, or stipulation. We do not believe that a single apportionment of liability in the Limitation Action is properly applied, particularly with respect to gross negligence and punitive damages, to the hundreds of lawsuits pending in the MDL proceeding.

Damages for the cases tried in the MDL proceeding, including punitive damages, are expected to be tried following the portion of the trial described above. 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 ongoing. It is unclear how the judge will address the DOJ’s civil action for alleged violations of the CWA and the OPA.

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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 direct damages, 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, Anadarko, and Cameron. We also understand that BP and M-I Swaco have agreed to dismiss all claims between them.

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, although the court has since issued orders dismissing all claims asserted against Dril-Quip and Weatherford in the MDL and we have dismissed our contractual indemnification claim against M-I Swaco. 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.

Judge Barbier has issued an order, among others, clarifying certain aspects of law applicable to the lawsuits pending in his court. The court ruled that: (1) general maritime law will apply and therefore dismissed all claims brought under state law causes of action; (2) general maritime law claims may be brought directly against defendants who are non-“responsible parties” under the OPA with the exception of pure economic loss claims by plaintiffs other than commercial fishermen; (3) all claims for damages, including pure economic loss claims, may be brought under the OPA directly against responsible parties; and (4) punitive damage claims can be brought against both responsible and non-responsible parties under general maritime law. As discussed above, with respect to the ruling that claims for damages may be brought under the OPA against responsible parties, we have not been named as a responsible party under the OPA, but BP Exploration has filed a claim against us for contribution with respect to liabilities incurred by BP Exploration under the OPA.

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 the BP Defendants disclosed the hydrocarbon zone to us, we would not have proceeded with the cement program unless it was redesigned, which likely would have required a redesign of the production casing. In addition, we believe that the BP Defendants 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.

In December 2011, BP filed a motion for sanctions against us alleging, among other things, that we destroyed evidence relating to post-incident testing of the foam cement slurry on the Deepwater Horizon and requesting adverse findings against us. A magistrate judge in the MDL proceeding denied BP’s motion. BP appealed that ruling, and Judge Barbier affirmed the magistrate judge’s decision.

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In April 2012, BP announced that it had reached definitive settlement agreements with the PSC to resolve the substantial majority of eligible private economic loss and medical claims stemming from the Macondo well incident. The PSC acts on behalf of individuals and business plaintiffs in the MDL. BP has estimated that the cost of the pending settlement would be approximately $7.8 billion, including administration costs and plaintiffs’ attorneys’ fees and expenses, and stated that it is possible the actual cost could be higher or lower. According to BP, the proposed settlement does not include claims against BP made by the DOJ or other federal agencies or by states and local governments. In addition, BP has stated that the proposed settlement provides that, to the extent permitted by law, BP will assign to the PSC certain of its claims, rights and recoveries against Transocean and us for damages not recoverable from BP. We do not believe that our contract with BP Exploration permits the assignment of certain claims to the PSC without our consent. In April and May, 2012, BP and the PSC filed two settlement agreements and amendments with the MDL court, one agreement addressing economic claims and one agreement addressing medical claims, as well as numerous supporting documents and motions requesting that the court approve, among other things, the certification of the classes for both settlements and a schedule for holding a fairness hearing and approving the settlements. In May 2012, the MDL court preliminarily and conditionally certified the classes for both settlements and preliminarily approved the proposed settlements. The MDL court has ordered that any objections to the settlements be filed by the end of August 2012, with hearings on the certification of the classes and fairness of the settlements to begin in November 2012 and with the initial phase of the MDL trial to commence in January 2013. We intend to object to the settlement and take other appropriate actions to protect our interests. We are unable to predict at this time the effect that the settlements may have on claims against us.

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.

Indemnification and Insurance. Our contract with BP Exploration relating to the Macondo well generally provides for our indemnification by BP Exploration for certain 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. We have entered into separate indemnity agreements with Transocean and M-I Swaco, under which we have agreed to indemnify those parties for claims for personal injury of our employees and subcontractors and they have agreed to indemnify us for claims for personal injury of their employees and subcontractors.

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. We filed a motion to remand the case to Harris County, Texas, and the lawsuit was transferred 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.

In January 2012, the court in the MDL proceeding entered an order in response to our and BP’s motions for summary judgment regarding certain indemnification matters. The court held that BP is required to indemnify us for third-party compensatory claims, or actual damages, that arise from pollution or contamination that did not originate from our property or equipment located above the surface of the land or water, even if we are found to be grossly negligent. The court did not express an opinion as to whether our conduct amounted to gross negligence, but we do not believe the performance of our services on the Deepwater Horizon constituted gross negligence. The court also held, however, that BP does not owe us indemnity for punitive damages or for civil penalties under the CWA, if any, and that fraud could void the indemnity on public policy grounds, although the court stated that it was mindful that mere failure to perform contractual obligations as promised does not constitute fraud. As discussed above, the DOJ is not seeking civil penalties from us under the CWA. The court in the MDL proceeding deferred ruling on whether our indemnification from BP covers penalties or fines under the OCSLA, whether our alleged breach of our contract with BP Exploration would invalidate the indemnity, and whether we committed an act that materially increased the risk to or prejudiced the rights of BP so as to invalidate the indemnity. We do not believe that we breached our contract with BP Exploration or committed an act that would otherwise invalidate the indemnity. The court’s rulings will be subject to appeal at the appropriate time.

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In responding to similar motions for summary judgment between Transocean and BP, the court also held that public policy would not bar Transocean’s claim for indemnification of compensatory damages, even if Transocean was found to be grossly negligent. The court also held, among other things, that Transocean’s contractual right to indemnity does not extend to punitive damages or civil penalties under the CWA.

The rulings in the MDL proceeding regarding the indemnities are based on maritime law and may not bind the determination of similar issues in lawsuits not comprising a part of the MDL proceedings. Accordingly it is possible that different conclusions with respect to indemnities will be reached by other courts.

Indemnification for criminal fines or penalties, if any, may not be available if a court were to find such indemnification unenforceable as against public policy. In addition, certain state laws, if deemed to apply, would not allow for enforcement of indemnification for gross negligence, and may not allow for enforcement of indemnification of persons who are found to be negligent with respect to personal injury claims.

BP’s public filings indicate that BP has recognized in excess of $40 billion in pre-tax charges, excluding offsets for settlement payments received from certain defendants in the proceedings described above under “Litigation,” as a result of the Macondo well incident. BP’s public filings also indicate that the amount of, among other things, certain natural resource damages with respect to certain OPA claims, some of which may be included in such charges, cannot be reliably estimated as of the dates of those filings.

In addition to the contractual indemnities discussed above, 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. Through June 2012, we have incurred legal fees and related expenses of approximately $117 million that have been reimbursed under or that are expected to be covered by our insurance program. 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. In addition, we may not be insured with respect to civil or criminal fines or penalties, if any, pursuant to the terms of our insurance policies. 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.

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. During the third quarter of 2011, the arbitration panel issued an award against KBR in the amount of $201 million, which, along with accrued interest, is reflected as a liability in our condensed consolidated financial statements. Costs related to this matter are reflected as discontinued operations in our condensed consolidated financial statements. KBR filed a motion to vacate the arbitration award with the United States District Court for the Southern District of New York, and that motion is pending. See Note 5 for additional information regarding the KBR indemnification as well as an unrelated dispute with KBR related to the allocation of certain tax liabilities.

Securities and related litigation

In June 2002, a class action lawsuit was filed against us in federal court alleging violations of the federal securities laws after the Securities and Exchange Commission (SEC) initiated an investigation in connection with our change in accounting for revenue on long-term construction projects and related disclosures. In the weeks that followed, approximately twenty similar class actions were filed against us. Several of those lawsuits also named as defendants several of our present or former officers and directors. The class action cases were later consolidated, and the amended consolidated class action complaint, styled Richard Moore, et al. v. Halliburton Company, et al., was filed and served upon us in April 2003. As a result of a substitution of lead plaintiffs, the case was styled Archdiocese of Milwaukee Supporting Fund (AMSF) v. Halliburton Company, et al. AMSF has changed its name to Erica P. John Fund, Inc. (the Fund). We settled with the SEC in the second quarter of 2004.

In June 2003, the lead plaintiffs filed a motion for leave to file a second amended consolidated complaint, which was granted by the court. In addition to restating the original accounting and disclosure claims, the second amended consolidated complaint included claims arising out of our 1998 acquisition of Dresser Industries, Inc., including that we failed to timely disclose the resulting asbestos liability exposure.

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In April 2005, the court appointed new co-lead counsel and named the Fund the new lead plaintiff, directing that it file a third consolidated amended complaint and that we file our motion to dismiss. The court held oral arguments on that motion in August 2005. In March 2006, the court entered an order in which it granted the motion to dismiss with respect to claims arising prior to June 1999 and granted the motion with respect to certain other claims while permitting the Fund to re-plead some of those claims to correct deficiencies in its earlier complaint. In April 2006, the Fund filed its fourth amended consolidated complaint. We filed a motion to dismiss those portions of the complaint that had been re-pled. A hearing was held on that motion in July 2006, and in March 2007 the court ordered dismissal of the claims against all individual defendants other than our Chief Executive Officer (CEO). The court ordered that the case proceed against our CEO and us.

In September 2007, the Fund filed a motion for class certification, and our response was filed in November 2007. The district court held a hearing in March 2008, and issued an order November 3, 2008 denying the motion for class certification. The 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, the Fund filed a writ of certiorari in the United States Supreme Court. In early January 2011, the Supreme Court granted the 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 the 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, and in January 2012 the court issued an order certifying the class. We filed a Petition for Leave to Appeal with the Fifth Circuit, which was granted and the case is stayed at the district court pending this appeal. In spite of its age, the case is at an early stage, and we cannot predict the outcome or consequences thereof. As of June 30, 2012, 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. We intend to vigorously defend this case.

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 United States Foreign Corrupt Practices Act (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 certain independent and disinterested directors to oversee the investigation of the allegations made in the lawsuits and shareholder demand. Upon receipt of the special committee’s findings and recommendations, the independent and disinterested members of the Board determined that the shareholder claims were without merit and not otherwise in our best interest to pursue. The Board directed our counsel to report its determinations to the plaintiffs and demanding shareholder.

We have agreed in principle, subject to approval by the court, to settle the consolidated lawsuit and the process for seeking that approval is now underway. Under the terms of the proposed settlement, we have agreed to implement certain changes to our corporate governance policies and agreed to pay the plaintiffs’ legal fees. As of June 30, 2012, we have accrued for the plaintiffs’ legal fees, which are not material.

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 certain independent and disinterested directors to oversee the investigation of the allegations made in the lawsuit and shareholder demand. Upon receipt of the special committee’s findings and recommendations, the independent and disinterested members of the Board determined that the shareholder claims were without merit and not otherwise in our best interest to pursue. The Board directed our counsel to report its determinations to the plaintiffs and demanding shareholder.

We have agreed in principle, subject to approval by the court, to settle this lawsuit and the process for seeking that approval is now underway. Under the terms of the proposed settlement, we have agreed to implement certain changes to our corporate governance and health, safety, and environmental policies and agreed to pay the plaintiffs’ legal fees. As of June 30, 2012, we have accrued for the plaintiffs’ legal fees, which are not material.

Investigations

We are conducting internal investigations of certain areas of our operations in Angola and Iraq, focusing on compliance with certain company policies, including our Code of Business Conduct (COBC), and the FCPA and other applicable laws.

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In December 2010, we received an anonymous e-mail alleging that certain current and former personnel violated our COBC and the FCPA, principally through the use of an Angolan vendor. The e-mail also alleges conflicts of interest, self-dealing, and the failure to act on alleged violations of our COBC and the FCPA. We contacted the DOJ to advise them that we were initiating an internal investigation.

Since the third quarter of 2011, we have been participating in meetings with the DOJ and the SEC to brief them on the status of our investigation and have been producing documents to them both voluntarily and as a result of SEC subpoenas to the company and certain of our current and former officers and employees.

During the second quarter of 2012, in connection with a meeting with the DOJ and the SEC regarding the above investigation, we advised the DOJ and the SEC that we were initiating unrelated, internal investigations into payments made to a third-party agent relating to certain customs matters in Angola and to third-party agents relating to certain customs and visa matters in Iraq.

We expect to continue to have discussions with the DOJ and the SEC regarding the Angola and Iraq matters described above and have indicated that we would further update them as our investigations progress. We have engaged outside counsel and independent forensic accountants to assist us with the investigations. We intend to continue to cooperate with the DOJ's and the SEC's inquiries and requests in these investigations. Because these investigations are ongoing, we cannot predict their outcome or the consequences thereof.

Environmental

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:



	-	the Comprehensive Environmental Response, Compensation, and Liability Act;
	-	the Resource Conservation and Recovery Act;
	-	the Clean Air Act;
	-	the Federal Water Pollution Control Act;
	-	the Toxic Substances Control Act; and
	-	the Oil Pollution Act 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 and the Duncan, Oklahoma matter described below, 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. Excluding our loss contingency for the Macondo well incident, our accrued liabilities for environmental matters were $75 million as of June 30, 2012 and $81 million as of December 31, 2011. Because our estimated liability is typically within a range and our accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in excess of the amount accrued. Our total liability related to environmental matters covers numerous properties.

Between approximately 1965 and 1991, one or more former Halliburton units performed work (as a contractor or subcontractor) for the U.S. Department of Defense cleaning solid fuel from missile motor casings at a semi-rural facility on the north side of Duncan, Oklahoma. In addition, from approximately November 1983 through December 1985, a discrete portion of the site was used to conduct a recycling project on stainless steel nuclear fuel rod racks from Omaha Public Power District’s Fort Calhoun Station. We closed the site in coordination with the Oklahoma Department of Environmental Quality (DEQ) in the mid-1990s, but continued to monitor the groundwater at the DEQ’s request. A principal component of the missile fuel was ammonium perchlorate, a salt that is highly soluble in water, which has been discovered in the soil and groundwater on our site and in certain residential water wells near our property. In August 2011, we entered into the DEQ’s Voluntary Cleanup Program and executed a voluntary Memorandum of Agreement and Consent Order for Site Characterization and Risk Based Remediation with the DEQ relating to the remediation of this site.

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Commencing in October 2011, a number of lawsuits were filed against us, including a putative class action case in federal court in the Western District of Oklahoma and other lawsuits filed in Oklahoma state courts. The lawsuits generally allege, among other things, that operations at our Duncan facility caused releases of pollutants, including ammonium perchlorate and, in the case of the federal lawsuit, nuclear or radioactive waste, into the groundwater, and that we knew about those releases and did not take corrective actions to address them. It is also alleged that the plaintiffs have suffered from certain health conditions, including hypothyroidism, a condition that has been associated with exposure to perchlorate at sufficiently high doses over time. These cases seek, among other things, damages, including punitive damages, and the establishment of a fund for future medical monitoring. The cases allege, among other things, strict liability, trespass, private nuisance, public nuisance, and negligence and, in the case of the federal lawsuit, violations of the U.S. Resource Conservation and Recovery Act (RCRA), resulting in personal injuries, property damage, and diminution of property value.

The lawsuits generally allege that the cleaning of the missile casings at the Duncan facility contaminated the surrounding soils and groundwater, including certain water wells used in a number of residential homes, through the migration of, among other things, ammonium perchlorate. The federal lawsuit also alleges that our processing of radioactive waste from a nuclear power plant over 25 years ago resulted in the release of “nuclear/radioactive” waste into the environment. In April 2012, the judge in the federal lawsuit dismissed the plaintiffs’ RCRA claim. The other claims brought in that lawsuit remain pending.

To date, soil and groundwater sampling relating to the allegations discussed above has confirmed that the alleged nuclear or radioactive material is confined to the soil in a discrete area of the onsite operations and is not presently believed to be in the groundwater onsite or in any areas offsite. The radiological impacts from this discrete area are not believed to present any health risk for offsite exposure. With respect to ammonium perchlorate, we have made arrangements to supply affected residents with bottled drinking water and, if needed, with access to temporary public water supply lines, at no cost to the residents. We have worked with the City of Duncan and the DEQ to expedite expansion of the city water supply to the relevant areas at our expense.

The lawsuits described above are at an early stage, and additional lawsuits and proceedings may be brought against us. We cannot predict their outcome or the consequences thereof. As of June 30, 2012, we had accrued $29 million related to our initial estimate of response efforts, third-party property damage, and remediation related to the Duncan, Oklahoma matter. We intend to vigorously defend the lawsuits and do not believe that these lawsuits will have a material adverse effect on our liquidity, consolidated results of operations, or consolidated financial condition.

Additionally, 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 June 30, 2012, those 10 sites accounted for approximately $6 million of our $75 million total environmental reserve. Despite attempts to resolve these superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount accrued. With respect to some superfund sites, we have been named a potentially responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims with respect to environmental matters for which we have been named as a potentially responsible party.

Guarantee arrangements

In the normal course of business, we have agreements with financial institutions under which approximately $1.8 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of June 30, 2012, including $284 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 7. 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 June 30		Six Months Ended June 30
Millions of shares	2012	2011	2012	2011
Basic weighted average common shares outstanding	924	916	923	915
Dilutive effect of employee stock plans	2	5	3	5
Diluted weighted average common shares outstanding	926	921	926	920

Excluded from the computation of diluted income per share are options to purchase ten million and seven million shares of common stock that were outstanding during the three and six months ended June 30, 2012 and two million and one million shares that were outstanding during the three and six months ended June 30, 2011. 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 8. Fair Value of Financial Instruments

At June 30, 2012, we held $50 million of non-cash equivalents in United States Treasury securities with maturities that extend through July 2012 classified as short-term marketable securities. These securities are accounted for as available-for-sale and recorded at fair value, based on quoted market prices. The carrying amount of cash and equivalents, receivables, and accounts payable, as reflected in the condensed consolidated balance sheets, approximates fair value due to the short maturities of these instruments. We have no financial instruments measured at fair value using unobservable inputs.

The fair value of our long-term debt was $6.3 billion as of June 30, 2012 and $6.2 billion as of December 31, 2011, which differs from the carrying amount of $4.8 billion as of both June 30, 2012 and December 31, 2011, 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 hold a series of interest rate swaps relating to two of our debt instruments with a total notional amount of $1.0 billion at a weighted-average, LIBOR-based, floating rate of 3.5% as of June 30, 2012. We utilize interest rate swaps to effectively convert a portion of our fixed rate debt to floating 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. The fair value of our interest rate swaps is included in “Other assets” in our condensed consolidated balance sheets as of June 30, 2012 and December 31, 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, settlement terms, and counterparty credit risk, that are observable in the market or can be derived from or corroborated by observable data. 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. At June 30, 2012, we had fixed rate debt aggregating $3.8 billion and variable rate debt aggregating $1.0 billion, after taking into account the effects of the interest rate swaps. The fair value of our interest rate swaps was not material as of June 30, 2012.

Note 9. Accounting Standards Recently Adopted

On January 1, 2012, we adopted an update issued by the Financial Accounting Standards Board (FASB) to existing guidance on the presentation of comprehensive income. This update requires 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. The requirement to present reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statement has been deferred by the FASB. Net income and other comprehensive income has been presented in two separate but consecutive statements for the current reporting period and prior comparative period in our condensed consolidated financial statements.

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

EXECUTIVE OVERVIEW

Organization

We are a leading provider of services and products to the energy industry. We serve the upstream oil and natural gas industry throughout the lifecycle of the reservoir, from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Activity levels within our operations are significantly impacted by spending on upstream exploration, development, and production programs by major, national, and independent oil and natural gas companies. We report our results under two segments, Completion and Production and Drilling and Evaluation:



	-	our Completion and Production segment delivers cementing, stimulation, intervention, pressure control, specialty chemicals, artificial lift, and completion services. The segment consists of Halliburton Production Enhancement, Cementing, Completion Tools, Boots & Coots, and Multi-Chem; 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 Halliburton Drill Bits and Services, Wireline and Perforating, Testing and Subsea, Baroid, Sperry Drilling, Landmark Software and Services, and Consulting and Project Management.

The business operations of our segments are organized around four primary geographic regions: North America, Latin America, Europe/Africa/CIS, and Middle East/Asia. We have significant manufacturing operations in various locations, including, but not limited to, the United States, Canada, the United Kingdom, Malaysia, Mexico, Brazil, and Singapore. With over 70,000 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 first half of 2012, we produced revenue of $14.1 billion and operating income of $2.2 billion, reflecting an operating margin of approximately 16%. Revenue increased $2.9 billion, or 26%, from the first half of 2011, while operating income increased $249 million, or 13%. These results were attributable to higher drilling activity in the oil and liquids-rich basins in North America, as well as increased activity in all our international regions, compared to the first half of 2011. The first half of 2012 results, however, were moderated by escalating costs associated with guar gum, a blending additive used in our hydraulic fracturing processes, decreasing activity in natural gas basins, and pricing pressure in certain basins in North America due to an over-supply of hydraulic fracturing equipment. The first half of 2012 results included a $300 million, pre-tax, loss contingency for the Macondo well incident. The first half of 2011 results were negatively impacted by an $11 million, pre-tax, charge for employee separation costs in the Eastern Hemisphere and a $59 million, pre-tax, charge in Libya, primarily related to reserves for certain assets.

Business outlook

We continue to believe in the strength of the long-term fundamentals of our business. Energy demand is expected to increase in the long term driven by economic growth in developing countries despite current underlying downside risks in the industry, such as sluggish growth in developed countries and supply uncertainties associated with geopolitical tensions in the Middle East. Furthermore, development of new resources is expected to be more complex resulting in increasing service intensity.

In North America, the industry is experiencing a shift from natural gas shale plays to oil and liquids-rich shale plays due to low natural gas prices resulting from continued strong natural gas production despite peak natural gas storage levels. We believe we will continue to see a modest reduction in natural gas drilling over the remainder of the year as operators optimize their budgets by focusing on basins with better economics. While oil and liquids-rich drilling has mostly offset the decline in the first half of 2012, we believe the recent volatility in oil prices and softness in natural gas liquids prices may prompt certain customers to adopt a more cautious tone for the remainder of 2012. We anticipate near-term pricing pressure for our production enhancement services in certain markets and continued cost inflation related to guar gum.

Our Gulf of Mexico business continues to recover due to an increase in the level of permit approvals for deepwater drilling. We remain optimistic about the recovery of activity in the Gulf of Mexico as our customers adapt to new regulations and new permit approvals are issued. In addition, more deepwater rigs are expected to arrive in the Gulf of Mexico over the course of this year. We believe that an increasing pace of permit applications and approvals needs to be sustained 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.”

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Outside of North America, revenue and operating income increased in the first half of 2012 compared to the first half of 2011.We believe competitive pricing for large, long-term international projects will continue throughout 2012. However, for the remainder of the year, we expect to see gradual activity improvements as new rigs, particularly in deepwater, enter the international markets. We also believe that new international unconventional oil and natural gas projects may contribute to activity improvements this year. Recently, our operations in Egypt have recovered from the turmoil experienced in the first quarter of 2011. Although some minor work has been performed in Libya, we are still awaiting well-defined operational plans from our customers. We do not expect activity levels in Libya to recover to pre-2011 levels until late 2012 or 2013.

We are continuing to execute several key initiatives in 2012. These initiatives include increasing manufacturing production in the Eastern Hemisphere and reinventing our service delivery platform to lower our delivery costs.

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

Financial markets, liquidity, and capital resources

The global financial markets continue to be 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.”

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LIQUIDITY AND CAPITAL RESOURCES

We ended the second quarter of 2012 and the year ended December 31, 2011 with cash and equivalents of $2.2 billion and $2.7 billion. As of June 30, 2012, approximately $416 million of the $2.2 billion of cash and equivalents was held by our foreign subsidiaries that would be subject to tax if repatriated. If these funds are needed for our operations in the United States, we would be required to accrue and pay United States taxes to repatriate these funds. However, our intent is to permanently reinvest these funds outside of the United States and our current plans do not demonstrate a need to repatriate them to fund our United States operations. We also held $50 million of short-term, United States Treasury securities at June 30, 2012 compared to $150 million at December 31, 2011 included in “Other current assets” on our condensed consolidated balance sheets.

Significant sources of cash

Cash flows from operating activities contributed $1.1 billion to cash in the first half of 2012.

During the first half of 2012, we sold or redeemed approximately $200 million of short-term marketable securities.

Significant uses of cash

Capital expenditures were $1.7 billion in the first half of 2012, and were predominantly made in Halliburton Production Enhancement, Sperry Drilling, Cementing, and Wireline and Perforating. We have also invested additional working capital to support the growth of our business.

During the first six months of 2012, inventories increased by $727 million, primarily because we procured a large reserve of guar gum when market prices were relatively high. See further discussion in "North America operations."

We paid $167 million in dividends to our shareholders in the first half of 2012.

During the first half of 2012, we purchased $100 million in short-term marketable securities.

Future uses of cash. Capital spending for 2012 is expected to range between $3.6 billion to $3.8 billion. The capital expenditures plan for 2012 is primarily directed toward Halliburton Production Enhancement, Sperry Drilling, Cementing, and Wireline and Perforating.

We are continuing to explore opportunities for acquisitions that will enhance or augment our current portfolio of services and products, including those with unique technologies or distribution networks in areas where we do not already have large operations.

Subject to Board of Directors approval, we expect to pay dividends of approximately $80 million per quarter during 2012. 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 an aggregate of approximately $1.8 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of June 30, 2012, including $284 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 have $2.2 billion of cash and equivalents and $50 million in investments in marketable securities as of June 30, 2012 and a total of $2.0 billion of available committed bank credit under our revolving credit facility. Furthermore, we have no financial covenants or material adverse change provisions in our bank agreements and our debt maturities extend over a long period of time. Although a portion of earnings from our foreign subsidiaries is reinvested outside the United States indefinitely, we do not consider this to have a significant impact on our liquidity. We currently believe that our capital expenditures, working capital investments, and dividends, if any, in 2012 can be fully funded through cash from operations.

As a result, we believe we have a reasonable amount of liquidity and, if necessary, additional financing flexibility given the current market environment to fund our potential contingent liabilities, if any. However, as discussed above in Note 6 to the condensed consolidated financial statements, there are numerous future developments that may arise as a result of the Macondo well incident that could have a material adverse effect 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 continue to see delays 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 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 first half of 2012, based upon the location of the services provided and products sold, 56% of our consolidated revenue was from the United States. In the first half of 2011, 54% 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, foreign currency exchange restrictions, 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 measures 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
	June 30				December 31
Average Oil Prices (dollars per barrel)	2012		2011		2011
West Texas Intermediate	$	93.73	$	102.61	$	95.13
United Kingdom Brent	108.92		117.78		111.53

Average United States Natural Gas Prices (dollars per thousand cubic feet, or Mcf)
Henry Hub	$	2.26	$	4.38	$	4.09

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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 June 30		Six Months Ended June 30
Land vs. Offshore	2012	2011	2012	2011
United States:
Land	1,924	1,798	1,936	1,744
Offshore (incl. Gulf of Mexico)	46	32	44	29
Total	1,970	1,830	1,980	1,773
Canada:
Land	171	187	381	386
Offshore	2	1	2	1
Total	173	188	383	387
International (excluding Canada):
Land	923	847	901	854
Offshore	306	299	308	302
Total	1,229	1,146	1,209	1,156
Worldwide total	3,372	3,164	3,572	3,316
Land total	3,018	2,832	3,218	2,984
Offshore total	354	332	354	332

	Three Months Ended June 30		Six Months Ended June 30
Oil vs. Natural Gas	2012	2011	2012	2011
United States (incl. Gulf of Mexico):
Oil	1,372	946	1,317	879
Natural gas	598	884	663	894
Total	1,970	1,830	1,980	1,773
Canada:
Oil	118	114	271	258
Natural gas	55	74	112	129
Total	173	188	383	387
International (excluding Canada):
Oil	980	894	961	902
Natural gas	249	252	248	254
Total	1,229	1,146	1,209	1,156
Worldwide total	3,372	3,164	3,572	3,316
Oil total	2,470	1,954	2,549	2,039
Natural gas total	902	1,210	1,023	1,277



	Three Months Ended June 30		Six Months Ended June 30
Drilling Type	2012	2011	2012	2011
United States (incl. Gulf of Mexico):
Horizontal	1,169	1,039	1,170	1,009
Vertical	569	561	585	538
Directional	232	230	225	226
Total	1,970	1,830	1,980	1,773

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Our customers’ cash flows, in most instances, depend upon the revenue they generate from the sale of oil and natural gas. Lower oil and natural gas prices usually translate into lower exploration and production budgets. The opposite is true for higher oil and natural gas prices.

WTI oil spot prices fluctuated throughout 2011 between a low of approximately $75 per barrel to a high of approximately $113 per barrel. Brent oil spot prices fluctuated between a low of approximately $94 per barrel to a high of approximately $127 per barrel during this same period. During the first half of 2012, WTI and Brent oil spot prices averaged approximately $98 and $113 per barrel, respectively, consistent with prices experienced in the first half of 2011. Significant decreases, however, have occurred in the second quarter of 2012 as geopolitical tension in the Middle East, global economic uncertainty surrounding the European debt crisis, and the threat of a slowdown in the Chinese economy have impacted demand. The outlook for world petroleum demand for the remainder of 2012 remains mixed, with the International Energy Agency’s July 2012 “Oil Market Report” continuing to forecast 2012 demand to increase approximately 1% over 2011 levels.

Natural gas prices in the United States have declined approximately 45% from the first half of 2011 due to the resiliency of natural gas production coupled with natural gas inventories above five-year historical levels. In response, our customers have curtailed natural gas drilling activity. Despite recent improvement in spot prices, we believe that downward pressure on natural gas prices will continue through the summer injection season. The United States Energy Information Administration's July 2012 “Short Term Energy Outlook” forecast a continued shift in electricity generation from coal to natural gas, but we foresee significant price constraints in the near-term as natural gas competes as a fuel source in the power generation market.

In spite of this tempered outlook, we believe that, over the long term, hydrocarbon demand will generally increase. Increased demand, combined with the underlying trends of smaller and more complex reservoirs, high depletion rates, and the need for continual reserve replacement, should drive the long-term need for our services and products.

North America operations

Depressed natural gas prices can impact our customers’ drilling and production activities, particularly in North America. The decline in natural gas prices compared to the first half of 2011 has accelerated the shift from natural gas shale plays to oil and liquids-rich shale plays. For the first half of 2012, the average natural gas directed rig count fell by 248 rigs, or 24%, from the first half of 2011, while the average oil directed rig count has increased by 460 rigs, or 41%, over the same period. This transition has resulted in additional relocation costs and inefficiencies, which negatively impacted our margins in the first half of 2012. Increased costs for certain raw materials, particularly for guar gum, also adversely affected our margins in the second quarter of 2012. The seasonal Canadian spring break-up, a period when road conditions hinder the movement of heavy equipment, had a negative impact on our results in the second quarter of 2012 due to the growth we have experienced in this market in recent years. We anticipate that this market will recover in the second half of the year as road conditions improve. In the long run, we believe the shift to oil and liquids-rich shale basins will continue to drive increased service intensity, but also in fluid chemistry and other technologies required for these complex reservoirs. Production enhancement pricing, however, may be challenging as competition increases in these oil and liquids-rich plays and our contracts come up for renewal.

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, but permits were not issued for an extended period of time, and we experienced a significant reduction in our Gulf of Mexico operations. In the first quarter of 2011, the issuance of drilling permits resumed. Deepwater drilling activity in the Gulf of Mexico continues to recover due to an increase in drilling permit approvals. We believe we will see an increase in the level of permit approvals through the remainder of 2012, leading to additional deepwater rigs arriving in the Gulf of Mexico. Over the long term, our results in the Gulf of Mexico 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

In 2011, pricing pressures from over capacity and geopolitical disruptions in North Africa had a negative impact on international operating income. In the second half of 2012 and into 2013, we continue to anticipate that the industry will experience steady volume increases as macroeconomic trends support a more favorable operator spending outlook and new rigs are scheduled to enter the market. We believe these trends will eventually lead to meaningful absorption of equipment supply. The average international rig count has improved by 53 rigs, or 5%, since the first half of 2011. Despite this increased volume, we continue to believe that international pricing will remain competitive, particularly for larger projects. We also believe that international unconventional oil and natural gas and deepwater projects will contribute to activity improvements, and we plan to leverage our extensive experience in North America to optimize these opportunities. Consistent with our long-term strategy to grow our operations outside of North America, we also expect to continue to invest capital in our international operations.

Venezuela. As of June 30, 2012, our total net investment in Venezuela was approximately $247 million. In addition to this amount, we have $284 million of surety bond guarantees outstanding relating to our Venezuelan operations.

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Initiatives

Following is a brief discussion of some of our recent and current initiatives:



-	increasing our market share in the more economic, unconventional plays, mature fields, 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 services and products, 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;
-	improving working capital, and managing our balance sheet to maximize our financial flexibility. We are deploying 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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RESULTS OF OPERATIONS IN 2012 COMPARED TO 2011

Three Months Ended June 30, 2012 Compared with Three Months Ended June 30, 2011



REVENUE:	Three Months Ended June 30				Favorable		Percentage
Millions of dollars	2012		2011		(Unfavorable)		Change
Completion and Production	$	4,460	$	3,618	$	842	23	%
Drilling and Evaluation	2,774		2,317		457		20
Total revenue	$	7,234	$	5,935	$	1,299	22	%



By geographic region:
Completion and Production:
North America	$	3,167	$	2,588	$	579	22	%
Latin America	340		268		72		27
Europe/Africa/CIS	551		415		136		33
Middle East/Asia	402		347		55		16
Total	4,460		3,618		842		23
Drilling and Evaluation:
North America	973		857		116		14
Latin America	539		419		120		29
Europe/Africa/CIS	605		554		51		9
Middle East/Asia	657		487		170		35
Total	2,774		2,317		457		20
Total revenue by region:
North America	4,140		3,445		695		20
Latin America	879		687		192		28
Europe/Africa/CIS	1,156		969		187		19
Middle East/Asia	1,059		834		225		27

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OPERATING INCOME:	Three Months Ended June 30						Favorable			Percentage
Millions of dollars	2012			2011			(Unfavorable)			Change
Completion and Production	$	914		$	918		$	(4	)	—	%
Drilling and Evaluation	393			324			69			21
Corporate and other	(106		)	(81		)	(25		)	31
Total operating income	$	1,201		$	1,161		$	40		3	%



By geographic region:
Completion and Production:
North America	$	691	$	827	$	(136	)	(16	)%
Latin America	54		29		25			86
Europe/Africa/CIS	95		15		80			533
Middle East/Asia	74		47		27			57
Total	914		918		(4		)	—
Drilling and Evaluation:
North America	166		170		(4		)	(2	)
Latin America	84		52		32			62
Europe/Africa/CIS	64		53		11			21
Middle East/Asia	79		49		30			61
Total	393		324		69			21
Total operating income by region
(excluding Corporate and other):
North America	857		997		(140		)	(14	)
Latin America	138		81		57			70
Europe/Africa/CIS	159		68		91			134
Middle East/Asia	153		96		57			59

The 22% increase in consolidated revenue in the second quarter of 2012 compared to the second quarter of 2011 was primarily attributable to increased activity in the United States, as the demand for production enhancement, completion tools, and cementing work continued to rise. On a consolidated basis, all product service lines experienced revenue growth from the second quarter of 2011. Revenue outside of North America was 43% of consolidated revenue in the second quarter of 2012 and 42% of consolidated revenue in the second quarter of 2011.

The 3% increase in consolidated operating income during the second quarter of 2012 compared to the second quarter of 2011 was driven by strong international results, particularly in the Europe/Africa/CIS region, which were offset by rising costs and pricing pressure for production enhancement services in the more service intensive, unconventional oil and liquids-rich basins in the United States land market. Operating income in the second quarter of 2011 was adversely impacted by $11 million, pre-tax, of employee separation costs in the Eastern Hemisphere.

Following is a discussion of our results of operations by reportable segment.

Completion and Production consolidated revenue increased 23% and North America revenue increased 22% compared to the second quarter of 2011, led by production enhancement services as higher activity in unconventional basins generally resulted in increased demand for pressure-pumping services. Latin America revenue grew 27%, with higher demand for production enhancement services in Mexico and cementing services in Brazil. Europe/Africa/CIS revenue increased 33%, driven by strong demand for completion tools and pressure-pumping services in Angola, additional work in Mozambique, and higher cementing activity in Norway. Middle East/Asia revenue grew 16%, driven by higher activity levels in Oman, Australia, and Southeast Asia, which were partially offset by lower product sales in China. Revenue outside of North America was 29% of total segment revenue in the second quarter of 2012 and 28% of total segment revenue in the second quarter of 2011.

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Completion and Production segment operating income was essentially flat compared to the second quarter of 2011, as increased costs and price erosion for production enhancement services in the United States land market were offset by higher demand for cementing services and completion tools worldwide. The second quarter of 2011 results were negatively impacted by $6 million, pre-tax, of employee separation costs in the Eastern Hemisphere. In North America, operating income decreased 16% compared to the second quarter of 2011 due to increased costs, particularly for guar gum, and pricing pressure in production enhancement services in the United States land market. Latin America operating income grew 86% as a result of increased demand for production enhancement services in Mexico and cementing services in Brazil, as well as higher activity levels in Venezuela. Europe/Africa/CIS operating income improved by $80 million due to higher activity levels in Nigeria and the Caspian, as well as additional completion tools sales in Angola. Middle East/Asia operating income increased 57% due to cost controls in Iraq, higher cementing activity in Oman, and increased completion tools activity in Southeast Asia.

Drilling and Evaluation revenue increased 20% compared to the second quarter of 2011, with all regions experiencing revenue growth. North America revenue increased 14%, primarily due to higher drilling fluids demand in the United States. Latin America revenue was up 29%, driven by higher activity in Brazil, Mexico, and Colombia. Europe/Africa/CIS revenue increased 9% due to higher activity levels in Tanzania, direct sales in Poland, and increased demand for drilling services in Angola. Middle East/Asia revenue grew 35%, primarily due to increased activity levels in Malaysia, Iraq, and China and direct sales in Saudi Arabia, which were partially offset by lower drilling activity in Indonesia. Revenue outside of North America was 65% of total segment revenue in the second quarter of 2012 and 63% of total segment revenue in the second quarter of 2011.

Drilling and Evaluation operating income increased 21% compared to the second quarter of 2011, as profitability improved in all international regions. The second quarter of 2011 results were negatively impacted by $5 million, pre-tax, of employee separation costs in the Eastern Hemisphere. North America operating income was essentially flat, as increases in drill bit services were offset by increased costs in the United States land market. Latin America operating income improved 62%, driven by strong demand for testing and subsea services in Brazil, higher activity levels in Colombia and Venezuela. Europe/Africa/CIS operating income increased 21% as a result of higher activity in Nigeria and the Caspian region, which more than offset increased costs in Norway. Middle East/Asia operating income grew 61%, primarily due to increased wireline activity in Saudi Arabia and higher product sales and cost reductions in China.

Corporate and other expenses increased $25 million in the second quarter of 2012 compared to the second quarter of 2011, primarily due to higher legal 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 increased $17 million in the second quarter of 2012 compared to the second quarter of 2011, primarily due to the issuance of $1.0 billion senior notes in November 2011.

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Six Months Ended June 30, 2012 Compared with Six Months Ended June 30, 2011



REVENUE:	Six Months Ended June 30				Favorable		Percentage
Millions of dollars	2012		2011		(Unfavorable)		Change
Completion and Production	$	8,750	$	6,790	$	1,960	29	%
Drilling and Evaluation	5,352		4,427		925		21
Total revenue	$	14,102	$	11,217	$	2,885	26	%



By geographic region:
Completion and Production:
North America	$	6,349	$	4,809	$	1,540	32	%
Latin America	646		508		138		27
Europe/Africa/CIS	1,007		816		191		23
Middle East/Asia	748		657		91		14
Total	8,750		6,790		1,960		29
Drilling and Evaluation:
North America	1,959		1,618		341		21
Latin America	1,013		791		222		28
Europe/Africa/CIS	1,161		1,064		97		9
Middle East/Asia	1,219		954		265		28
Total	5,352		4,427		925		21
Total revenue by region:
North America	8,308		6,427		1,881		29
Latin America	1,659		1,299		360		28
Europe/Africa/CIS	2,168		1,880		288		15
Middle East/Asia	1,967		1,611		356		22

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OPERATING INCOME:	Six Months Ended June 30						Favorable			Percentage
Millions of dollars	2012			2011			(Unfavorable)			Change
Completion and Production	$	1,950		$	1,578		$	372		24	%
Drilling and Evaluation	761			554			207			37
Corporate and other	(487		)	(157		)	(330		)	210
Total operating income	$	2,224		$	1,975		$	249		13	%



By geographic region:
Completion and Production:
North America	$	1,562	$	1,441		$	121	8	%
Latin America	109		65			44		68
Europe/Africa/CIS	152		(11		)	163		1,482
Middle East/Asia	127		83			44		53
Total	1,950		1,578			372		24
Drilling and Evaluation:
North America	356		288			68		24
Latin America	151		92			59		64
Europe/Africa/CIS	104		75			29		39
Middle East/Asia	150		99			51		52
Total	761		554			207		37
Total operating income by region
(excluding Corporate and other):
North America	1,918		1,729			189		11
Latin America	260		157			103		66
Europe/Africa/CIS	256		64			192		300
Middle East/Asia	277		182			95		52

The 26% increase in consolidated revenue in the first six months of 2012 compared to the first six months of 2011 was due to higher activity across all regions, especially increased demand for Completion and Production services and drilling activity in the United States. Revenue outside North America was 41% of consolidated revenue in the first six months of 2012 and 43% of consolidated revenue in the first six months of 2011.

The 13% increase in consolidated operating income in the first six months of 2012 compared to the first six months of 2011 was primarily due to improved Completion and Production activities in Europe/Africa/CIS and North America regions, partially offset by the impact of cost inflation for guar gum and pricing pressures for production enhancement services in North America. Operating income in the first six months of 2011 was adversely impacted by $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.

Completion and Production revenue increased by 29% driven by North America revenue growth of 32% compared to the first six months of 2011. The activity increase in North America was led by production enhancement services in United States land resulting from higher activity in unconventional basins. Latin America revenue grew 27% due to increased activity across Mexico and Venezuela as well as additional cementing work in Brazil. Europe/Africa/CIS revenue increased 23% due to higher activity in the region, especially completion tools in Angola, cementing in Norway and Mozambique, and all services in Nigeria. Middle East/Asia revenue grew 14%, with higher demand for cementing in Oman and Australia, higher completion tools activities in Indonesia and Brunei, and increased Boots & Coots services in India and Saudi Arabia. Revenue outside North America was 27% of total segment revenue in the first six months of 2012 and 29% of total segment revenue in the first six months of 2011.

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Completion and Production operating income increased 24% compared to the first six months of 2011. This increase reflected higher profitability in all our regions, especially in the Europe/Africa/CIS region. North America operating income increased 8% due to higher cementing and completion tools activity in the United States, which was partially offset by pricing pressures in production enhancement and cost inflation for guar gum in the United States land market. Latin America operating income grew 68%, primarily due to a combination of higher cementing activity in Brazil and lower cementing costs in Argentina, as well as increased production enhancement services in Mexico. Europe/Africa/CIS operating income increased $163 million, primarily due to increased activity for all services in Nigeria and the North Sea, in addition to recovery in North Africa after activity disruptions in the first quarter of 2011. Middle East/Asia operating income grew 53% due to higher cementing activity in Oman, increased Boots & Coots services in Iraq, and higher completion tools sales in Indonesia and Brunei.

Drilling and Evaluation revenue increased 21% compared to the first six months of 2011 as fluids and wireline activity improved across all regions, most significantly in North America. North America revenue increased 21% on substantial fluids and wireline activity increases in the United States and increased drilling services in Canada. Latin America revenue grew 28% as a result of increased demand for all services in Brazil and Colombia and most services in Mexico, Ecuador, and Venezuela. Europe/Africa/CIS revenue increased 9% due to higher fluids and drilling activity in Angola and Tanzania and direct sales in Poland, which were partially offset by reduced activity in the North Sea. Middle East/Asia revenue grew 28% due to direct sales in Saudi Arabia, higher fluids and drilling activity in Malaysia, and increased activity in Iraq, partially offset by reduced drilling services in Indonesia. Revenue outside North America was 63% of total segment revenue in the first six months of 2012 and 2011.

Drilling and Evaluation operating income increased 37% compared to the first six months of 2011 due to higher profitability in all our regions, particularly in the Western Hemisphere. North America operating income increased 24% due to higher fluids and wireline services, as well as increased wireline profitability in Canada. Latin America operating income grew 64%, primarily due to higher fluids and testing activity in Brazil and increased drilling services in Colombia, Ecuador, and Venezuela, which were partially offset by reduced consulting services and higher costs in Mexico. Europe/Africa/CIS region operating income increased 39%, primarily due to higher drilling activity in Nigeria, Angola, and Tanzania and the recovery of first quarter 2011 disruptions in North Africa, which were partially offset by a decrease in activity and profitability in Norway. Middle East/Asia operating income grew 52% mainly due to increased fluids and wireline activity in Saudi Arabia and direct sales in China, partially offset by losses in Iraq and lower drilling activity in Indonesia.

Corporate and other expenses were $487 million in the first six months of 2012 compared to $157 million in the first six months of 2011. The increase was primarily due to a $300 million, pre-tax, loss contingency related to the Macondo well incident that was recorded in the first quarter of 2012. The remaining increase is due to higher legal 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 increased $22 million in the first six months of 2012 compared to the first six months of 2011 primarily due to the issuance of $1.0 billion senior notes in November 2011.

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ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. For information related to environmental matters, see Note 6 to the condensed consolidated financial statements, Part II, Item 1, “Legal Proceedings—Environmental,” and Part II, Item 1(a), “Risk Factors.”

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,” “plans,” “estimates,” “intends,” “expects,” “do not expect,” “anticipates,” “do not anticipate,” “should,” “likely,” and other expressions. We may also provide oral or written forward-looking information in other materials we release to the public. Forward-looking information involves risk and uncertainties and reflects our best judgment based on current information. Our results of operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and the results of operations may vary materially.

We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether factors change as a result of new information, future events, or for any other reason. You should review any additional disclosures we make in our press releases and Forms 10-K, 10-Q, and 8-K filed with or furnished to the SEC. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk, see Part II, Item 7(a), “Quantitative and Qualitative Disclosures About Market Risk,” in our 2011 Annual Report on Form 10-K. Our exposure to market risk has not changed materially since December 31, 2011.

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 June 30, 2012 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 June 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Macondo well incident

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We have had and expect to continue to have discussions with the DOJ regarding the Macondo well incident and associated pre-incident and post-incident conduct.

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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. We are 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 seven personal injury lawsuits involving four decedents and at least 11 allegedly injured persons who were on the drilling rig at the time of the incident. At least six additional 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. Except for certain lawsuits not yet consolidated , the Judicial Panel on Multi-District Litigation ordered all of the lawsuits against us consolidated in the MDL proceeding before Judge Carl Barbier in the United States 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 OCSLA, the Longshoremen and Harbor Workers Compensation Act, general maritime law, state common law, and various state environmental and products liability statutes.

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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. During the third quarter of 2011, the arbitration panel issued an award against KBR in the amount of $201 million. KBR filed a motion to vacate the arbitration award with the United States District Court for the Southern District of New York, and that motion is pending.

Securities and related litigation

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Shareholder derivative cases

Investigations

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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 and the Duncan, Oklahoma matter described below, 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. Because our estimated liability is typically within a range and our accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in excess of the amount accrued.

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Item 1(a). Risk Factors

The statements in this section describe the known material risks to our business and should be considered carefully. The risk factors discussed below update the risk factors previously discussed in our 2011 Annual Report on Form 10-K.

We, among others, have been named as a defendant in numerous lawsuits and there have been numerous investigations relating to the Macondo well incident that could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

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, an indirect wholly owned subsidiary of BP. There were eleven fatalities and a number of injuries as a result of the Macondo well incident. Crude oil escaping from the Macondo well site spread across thousands of square miles of the Gulf of Mexico and reached the United States Gulf Coast. We performed a variety of services for BP Exploration, including cementing, mud logging, directional drilling, measurement-while-drilling, and rig data acquisition services.

We are 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 seven personal injury lawsuits involving four decedents and at least 11 allegedly injured persons who were on the drilling rig at the time of the incident. At least six additional lawsuits naming us and others relate to alleged personal injuries sustained by those responding to the explosion and oil spill. BP Exploration and one of its affiliates have filed claims against us seeking subrogation and contribution, including with respect to liabilities under the OPA, and direct damages, and alleging negligence, gross negligence, fraudulent conduct and fraudulent concealment. Certain other defendants in the lawsuits have filed claims against us seeking, among other things, indemnification and contribution, including with respect to liabilities under the OPA, and alleging, among other things, negligence and gross negligence. See Part II, Item 1, “Legal Proceedings.” Additional lawsuits may be filed against us, including criminal and civil charges under federal and state statutes and regulations. Those statutes and regulations could result in criminal penalties, including fines and imprisonment, as well as civil fines, and the degree of the penalties and fines may depend on the type of conduct and level of culpability, including strict liability, negligence, gross negligence, and knowing violations of the statute or regulation.

In addition to the claims and lawsuits described above, numerous industry participants, governmental agencies and Congressional committees have investigated or are investigating the cause of the explosion, fire, and resulting oil spill. According to the January 11, 2011 Investigation Report of the National Commission, 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 also identified the failure of BP’s and our processes for cement testing and communication failures among BP, Transocean, and us with respect to the difficulty of the cement job as examples of systemic failures by industry management.

In September 2011, the BOEMRE released the BOEMRE Report. A panel of investigators of the BOEMRE identified a number of causes of the Macondo well incident. According to the BOEMRE 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.

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The BOEMRE 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 BOEMRE 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 BSEE issued a notification of 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 in effect at the time of the alleged violations provide for fines of up to $35,000 per day per violation. We have appealed the INCs to the IBLA. In January 2012, the IBLA, in response to our and the BSEE’s joint request, has suspended the appeal and has ordered us and the BSEE to file notice within 15 days after the conclusion of the MDL and, within 60 days after the MDL court issues a final decision, to file a proposal for further action in the appeal. The BSEE has announced that the INCs will be reviewed for possible imposition of civil penalties once the appeal 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.

Various other investigations have or may be critical of the services we provided on the Deepwater Horizon. In addition, as part of its criminal investigation, the DOJ is examining certain aspects of our conduct after the incident, including with respect to record-keeping, record retention, post-incident testing and modeling, securities filings, and public statements by us or our employees, to evaluate whether there has been any violation of federal law.

Our contract with BP Exploration relating to the Macondo well generally provides for our indemnification by BP Exploration for certain potential claims and expenses relating to the Macondo well incident. 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 have generally denied any obligation to contribute to any liabilities arising from the Macondo well incident. In January 2012, the court in the MDL proceeding entered an order in response to our and BP’s motions for summary judgment regarding certain indemnification matters. The court held that BP is required to indemnify us for third-party compensatory claims, or actual damages, that arise from pollution or contamination that did not originate from our property or equipment located above the surface of the land or water, even if we are found to be grossly negligent. The court also held that BP does not owe us indemnity for punitive damages or for civil penalties under the CWA, if any, and that fraud could void the indemnity on public policy grounds. The court in the MDL proceeding deferred ruling on whether our indemnification from BP covers penalties or fines under the OCSLA, whether our alleged breach of our contract with BP Exploration would invalidate the indemnity, and whether we committed an act that materially increased the risk to or prejudiced the rights of BP so as to invalidate the indemnity.

BP’s public filings indicate that BP has recognized in excess of $40 billion in pre-tax charges, excluding offsets for settlement payments received from certain defendants in the MDL, as a result of the Macondo well incident. BP’s public filings also indicate that the amount of, among other things, certain natural resource damages with respect to certain OPA claims, some of which may be included in such charges, cannot be reliably estimated as of the dates of those filings. We may not be insured with respect to civil or criminal fines or penalties, if any, pursuant to the terms of our insurance policies.

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We are currently unable to fully estimate the impact the Macondo well incident will have on us. We cannot predict the outcome of the many lawsuits and investigations relating to the Macondo well incident, including orders and rulings of the court that impact the MDL, whether the MDL will proceed to trial, the results of any such trial, the final settlement arrangement between BP and the PSC, the effect that settlement may have on claims against us, or whether we might settle with one or more of the parties to any lawsuit or investigation. At the request of the court, in late February 2012 we participated in a series of discussions with the Magistrate Judge in the MDL relating to whether the MDL could be settled. Although these discussions did not result in a settlement, we recorded a $300 million liability during the first quarter of 2012, for an estimated loss contingency relating to the MDL. This loss contingency, which is included in “Other liabilities” on the condensed consolidated balance sheet as of June 30, 2012 and in “Cost of services” on the condensed consolidated statement of operations for the six months ended June 30, 2012, represents a loss contingency that is probable and for which a reasonable estimate of loss or range of loss can be made. There are additional loss contingencies relating to the Macondo well incident that are reasonably possible but for which we cannot make a reasonable estimate. Given the numerous potential developments relating to the MDL and other lawsuits and investigations, which could occur at any time, we may adjust our estimated loss contingency in the future. Liabilities arising out of the Macondo well incident could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

We are a leading provider of hydraulic fracturing services. Various federal legislative and regulatory initiatives have been undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. For example, the Department of Interior is preparing to issue proposed regulations that would apply to hydraulic fracturing operations on wells that are subject to federal oil and gas leases and that could result in requirements regarding the disclosure of chemicals used in the hydraulic fracturing process as well as requirements to obtain certain federal approvals before proceeding with hydraulic fracturing at a well site. These regulations, if adopted, could establish additional levels of regulation at the federal level that could lead to operational delays and increased operating costs. At the same time, legislation and/or regulations have been adopted in several states that require additional disclosure regarding chemicals used in the fracturing process but that include protections for proprietary information. Legislation and/or regulations are being considered in other states that could impose further chemical disclosure or other regulatory requirements (such as restrictions on the use of certain types of chemicals or prohibitions on hydraulic fracturing operations in certain areas) that could affect our operations. In addition, governmental authorities in various foreign countries where we have provided or may provide hydraulic fracturing services have imposed or are considering imposing various restrictions or conditions that may affect hydraulic fracturing operations.

We are one of several unrelated companies who received a subpoena from the Office of the New York Attorney General, dated June 17, 2011. The subpoena sought information and documents relating to, among other things, natural gas development and hydraulic fracturing. We have provided information in response to the Attorney General’s requests.

The adoption of any future federal, state, or foreign laws or implementing regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

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Our operations are subject to political and economic instability, risk of government actions, and cyber attacks that could have a material adverse effect on our consolidated results of operations and consolidated financial condition.

We are exposed to risks inherent in doing business in each of the countries in which we operate. Our operations are subject to various risks unique to each country that could have a material adverse effect on our consolidated results of operations and consolidated financial condition. With respect to any particular country, these risks may include:



-	political and economic instability, including:
	•	civil unrest, acts of terrorism, force majeure, war, or other armed conflict;
	•	inflation; and
	•	currency fluctuations, devaluations, and conversion restrictions; and
-	governmental actions that may:
	•	result in expropriation and nationalization of our assets in that country;
	•	result in confiscatory taxation or other adverse tax policies;
	•	limit or disrupt markets, restrict payments, or limit the movement of funds;
	•	result in the deprivation of contract rights; and
	•	result in the inability to obtain or retain licenses required for operation.

For example, due to the unsettled political conditions in many oil-producing countries, our operations, revenue, and profits are subject to the adverse consequences of war, the effects of terrorism, civil unrest, strikes, currency controls, and governmental actions. These and other risks described above could result in the loss of our personnel or assets, cause us to evacuate our personnel from certain countries, cause us to increase spending on security worldwide, disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographic areas in which we operate. Areas where we operate that have significant risk include, but are not limited to: the Middle East, North Africa, Azerbaijan, Colombia, Indonesia, Kazakhstan, Mexico, Nigeria, Russia, and Venezuela. In addition, any possible reprisals as a consequence of military or other action, such as acts of terrorism in the United States or elsewhere, could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

Our operations are also subject to the risk of cyber attacks. If our systems for protecting against cybersecurity risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data, having our business operations interrupted, and increased costs to prevent, respond to, or mitigate cybersecurity attacks. These risks could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Following is a summary of our repurchases of our common stock during the three months ended June 30, 2012.



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that may yet be Purchased Under the Program (b)
April 1 - 30	100,907	$33.41	—	$	—
May 1 - 31	543,084	$30.78	—	$	—
June 1 - 30	8,622	$30.09	—	$	—
Total	652,613	$31.18	—	$	1,731,208,803



(a)		All of the 652,613 shares purchased during the three months ended June 30, 2012, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common shares.
(b)		Our Board of Directors has authorized a plan to repurchase our common stock from time to time. During the second quarter of 2012, we did not repurchase shares of our common stock pursuant to that plan. We had authorization remaining to repurchase up to a total of approximately $1.7 billion of our common stock.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

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

Item 5. Other Information

None.

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Item 6. Exhibits



	10.1	Halliburton Company Stock and Incentive Plan, as amended and restated effective February 16, 2012
		(incorporated by reference to Appendix B of Halliburton's proxy statement filed April 3, 2012, File
		No. 1-3492).
	10.2	Form of Non-Employee Director Restricted Stock Unit Agreement (Director Plan) (incorporated by
		reference to Exhibit 99.8 of Halliburton's Form S-8 filed June 22, 2012, Registration No. 333-182284).
	10.3	Form of Non-Employee Director Restricted Stock Unit Agreement (Stock and Incentive Plan)
		(incorporated by reference to Exhibit 99.9 of Halliburton's Form S-8 filed June 22, 2012, Registration
		No. 333-182284).
*	10.4	Second Amendment to Restricted Stock Plan for Non-Employee Directors of Halliburton Company.
*	10.5	Halliburton Company Directors' Deferred Compensation Plan, as amended and restated effective as of
		May 16, 2012.
*	12.1	Statement Regarding the Computation of Ratio of Earnings to Fixed Charges.
*	31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
		of 2002.
*	31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
		of 2002.
**	32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act
		of 2002.
**	32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act
		of 2002.
*	95	Mine Safety Disclosures
*	101.INS	XBRL Instance Document
*	101.SCH	XBRL Taxonomy Extension Schema Document
*	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*	101.LAB	XBRL Taxonomy Extension Label Linkbase Document
*	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
*	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
	*	Filed with this Form 10-Q
	**	Furnished with this Form 10-Q

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SIGNATURES

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

HALLIBURTON COMPANY



/s/ Mark A. McCollum	/s/ Evelyn M. Angelle
Mark A. McCollum	Evelyn M. Angelle
Executive Vice President and	Senior Vice President and
Chief Financial Officer	Chief Accounting Officer

Date: July 27, 2012

HAL-6.30.2012-Ex 10.4

SECOND AMENDMENT TO

RESTRICTED STOCK PLAN FOR NON-EMPLOYEE DIRECTORS

HALLIBURTON COMPANY

WHEREAS, Halliburton Company (the “Company”) has previously adopted the Restricted Stock Plan for Non-Employee Directors of Halliburton Company, as amended (the “Plan”), to promote the long-term, continuing success of the Company by providing a portion of the compensation for non-employee directors in shares of Common Stock pursuant to the terms of the Plan;

WHEREAS, Section 6.3 of the Plan reserves the right to amend, modify, suspend or terminate the Plan at any time by action of the Board of Directors of the Company (the “Board”);

WHEREAS, the Board desires to amend the Plan to provide that future awards under the Plan will be made in the form of restricted stock units, with each unit being equal to one share of Common Stock;

NOW, THEREFORE, the Board does hereby amend the Plan as follows, effective as of May 16, 2012:

(1) The following new sentences shall be added to the end of Article IV of the Plan to read as follows:

“Effective on and after August 1, 2012, annual Awards may be made in the form of restricted stock units, with each such unit representing the right to receive one share of Common Stock. An annual Award in the form of restricted stock units shall be made to Participants effective on or about August 1, 2012. No other Award in the form of restricted stock units or restricted shares of Common Stock shall be made to Participants in calendar year 2012. Awards in 2013 and subsequent calendar years shall be made on August 1st of each calendar year and shall be made in the form of restricted stock units unless the Committee, in its discretion, determines that such awards shall be made in the form of restricted shares of Common Stock.”

(2) The first sentence of Section 5.7 shall be amended to read as follows:

“All of the shares of Common Stock issued pursuant to the Plan shall become free of restrictions imposed by this Article V and shall become non-forfeitable upon the earliest to occur of a “separation from service” (within the meaning of Section 409A of the Internal Revenue Code and related guidance) due to the following:”

(3) A new Section 5.9 shall be added to the Plan to read as follows:

“5.9 Restricted Stock Units

Notwithstanding any other provision of the Plan to the contrary, the terms of this Section 5.9 shall apply to Awards under the Plan made in the form of restricted stock units.

(a) Registration. Each Award of restricted stock units under the plan shall be evidenced by book entry registration or in such other manner as the Committee may determine.

(b) Dividend Equivalents. Each Participant shall have the right to dividend equivalents with respect to Awards of restricted stock units for the period beginning on the date the Award was granted and ending on the date shares of Common Stock are delivered to the Participant in settlement of such Award. Such dividend equivalents shall be paid in cash as soon as practicable after the dividend is paid with respect to the Common Stock; provided, however, that if the Award has been deferred, any dividend equivalents shall be subject to the terms of the relevant deferral plan.

(c) Voting Rights. Participants shall not have the right to vote or execute proxies with respect to Awards in the form of restricted stock units.

(d) Vesting and Forfeiture. Awards in the form of restricted stock units shall be subject to vesting and forfeiture provisions. Awards of restricted stock units shall vest at the times and upon the circumstances specified in the relevant restricted stock unit agreement. Any termination from the Board of a Participant shall result in forfeiture of any restricted stock units that have not been or will not be vested and delivered pursuant to the terms of the relevant restricted stock unit agreement.

(e) Delivery. Unless an Award in the form of restricted stock units has been deferred as permitted in Section 5.9(f), no later than the date that is 60 days after the date a restricted stock unit vests, one share of Common Stock shall be delivered to the Participant for each such vested restricted stock unit held by such Participant. Notwithstanding the foregoing, the Company shall not be obligated to issue or deliver any such shares if the issuance or delivery thereof shall constitute a violation of any provision of any law or of any regulation of any governmental authority or any national securities exchange.

(f) Deferral. The Committee, in its sole discretion, may permit the deferral of an Award made in the form of restricted stock units.”

(4) All other provisions of the Plan shall remain the same and are hereby ratified.

Attested to by the Corporate Secretary of Halliburton Company as adopted by the Board of Directors effective as of the 16^th day of May, 2012.

_/s/ Christina M. Ibrahim____

Christina M. Ibrahim

Vice President & Corporate Secretary

Halliburton Company

HAL-6.30.2012-Ex 10.5

HALLIBURTON COMPANY

DIRECTORS' DEFERRED COMPENSATION PLAN

AS AMENDED AND RESTATED

EFFECTIVE AS OF MAY 16, 2012

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Page



ARTICLE I	PURPOSE OF PLAN	2
ARTICLE II	DEFINITIONS	3
ARTICLE III	ADMINISTRATION OF THE PLAN	5
ARTICLE IV	DEFERRED COMPENSATION	7
ARTICLE V	INTEREST	9
ARTICLE VI	STOCK EQUIVALENTS	10
ARTICLE VII	NATURE OF PLAN	12
ARTICLE VIII	TERMINATION OF THE PLAN	13
ARTICLE IX	AMENDMENT OF THE PLAN	14
ARTICLE X	GENERAL PROVISIONS	15
ARTICLE XI	EFFECTIVE DATE	16

HALLIBURTON COMPANY

DIRECTORS' DEFERRED COMPENSATION PLAN

AS AMENDED AND RESTATED

EFFECTIVE AS OF MAY 16, 2012

The Board of Directors of Halliburton Company having heretofore established the Directors' Deferred Compensation Plan, pursuant to the provisions of Article VII of said Plan, hereby amends and supplements said Plan to be effective in accordance with the provisions of ARTICLE XI hereof.

ARTICLE I

PURPOSE OF PLAN

The purpose of the Plan is to assist the Directors of the Company in planning for their retirement.

ARTICLE II

DEFINITIONS

Where the following words and phrases appear herein, they shall have the respective meanings set forth in this ARTICLE II, unless the context clearly indicates to the contrary.

Section 2.01 “Accounts” shall mean a Participant's Interest Bearing Account and/or Stock Equivalents Account.

Section 2.02 “Administrator” shall mean any administrator appointed by the Committee pursuant to Section 3.01 herein or, in the absence of any such appointment, the Committee.

Section 2.03 “Board of Directors” shall mean the Board of Directors of the Company.

Section 2.04 “Committee” shall mean the committee of those individuals (each of whom shall be a Director) appointed by the Board of Directors pursuant to Article III hereof.

Section 2.05 “Common Stock” means the common stock, par value $2.50 per share, of the Company.

Section 2.06 “Company” shall mean Halliburton Company.

Section 2.07 “Cash Compensation” shall mean a Participant's cash compensation for services as a Director.

Section 2.08 “Deferral Termination Date” shall mean the date a Participant has a “separation from service” from the Company within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations promulgated thereunder.

Section 2.09 “Deferred Compensation” shall mean Cash Compensation and Equity Compensation deferred pursuant to the provisions of this Plan.

Section 2.10 “Director” shall mean a member of the Board of Directors of the Company.

Section 2.11 “Earned” or any variant thereof, when used herein with respect to Cash Compensation, Equity Compensation or Deferred Compensation or interest accrued pursuant to Section 5.02, shall refer to the end of a calendar quarter and, when used with respect to a dividend, dividend equivalent right with respect to Equity Compensation or distribution on the Common Stock referenced in Section 6.02, shall refer to the date of payment of such dividend, dividend equivalent with respect to Equity Compensation or distribution by the Company.

Section 2.12 “Equity Compensation” shall mean a Participant's compensation denominated in the form of Common Stock under the Company's Incentive Plan for which deferrals are permitted.

Section 2.13 “Incentive Plan” shall mean (i) the Company's Stock and Incentive Plan, as amended and restated February 16, 2012, or as thereafter amended, (ii) the Restricted Stock Plan for Non-Employee Directors of Halliburton Company, as amended from time to time, or (iii) a successor plan to either of the plans in items (i) and (ii) above.

Section 2.14 “Interest Bearing Account” shall mean the Participant's Interest Bearing Account established pursuant to Section 4.03 herein with respect to Deferred Compensation that relates to Cash Compensation.

Section 2.15 “Market Price” of the Common Stock on any date shall mean the closing sales price per share for the Common Stock (or, if no closing sales price is reported, the average of the bid and ask prices per share on such date) on the New York Stock Exchange or, if the Common Stock is not then listed on such Exchange, such other national or regional securities exchange upon which the Common Stock is so listed, as reported in the composite transactions for the principal United States securities exchange on which the Common Stock is then listed or, if the Common Stock is not then listed on any such exchange, as reported by The NASDAQ Stock Market, Inc.

Section 2.16 “Participant” shall mean any Director of the Company who has elected to have all or a part of his Cash Compensation or Equity Compensation deferred pursuant to the Plan.

Section 2.17 “Plan” shall mean the Halliburton Company Directors' Deferred Compensation Plan, as amended and restated effective as of May 16, 2012, and as the same may thereafter be amended from time to time.

Section 2.18 “Plan Earnings” shall mean amounts of interest to which reference is made in Section 5.01 herein and of dividends and distributions to which reference is made in Section 6.02 herein.

Section 2.19 “Stock Equivalent” shall mean a measure of value equal to one share of the Common Stock.

Section 2.20 “Stock Equivalents Account” shall mean the Participant's Stock Equivalents Account established pursuant to Section 4.03 herein with respect to Deferred Compensation that relates to Cash Compensation or Equity Compensation.

ARTICLE III

ADMINISTRATION OF THE PLAN

Section 3.01 Committee. The Board of Directors shall appoint a Committee to administer, construe and interpret the Plan. Such Committee, or such successor Committee as may be duly appointed by the Board of Directors, shall serve at the pleasure of the Board of Directors. Decisions of the Committee with respect to any matter involving the Plan shall be final and binding on the Company and all Participants. The Committee may designate an Administrator to aid the Committee in its administration of the Plan. Such Administrator shall maintain complete and adequate records pertaining to the Plan, including but not limited to Participants' Interest Bearing Accounts, Participants' Stock Equivalent Accounts and any subaccounts the Administrator deems appropriate or necessary to reflect the source of deferrals, and shall serve at the pleasure of the Committee.

Section 3.02 Indemnity.

(a) Indemnification. The Company (the “Indemnifying Party”) hereby agrees to indemnify and hold harmless the members of the Committee and any Administrator designated by the Committee (the “Indemnified Parties”) against any losses, claims, damages or liabilities to which any of the Indemnified Parties may become subject to the extent that such losses, claims, damages or liabilities or actions in respect thereof arise out of or are based upon any act or omission of such Indemnified Party in connection with the administration of this Plan (including any act or omission constituting negligence on the part of such Indemnified Party, but excluding any act or omission constituting gross negligence or willful misconduct on the part of such Indemnified Party), and will reimburse the Indemnified Party for any legal or other expenses reasonably incurred by him or her in connection with investigating or defending against any such loss, claim, damage, liability or action.

(b) Actions. Promptly after receipt by the Indemnified Party under Section 3.02(a) herein of notice of the commencement of any action or proceeding with respect to any loss, claim, damage or liability against which the Indemnified Party believes he or she is indemnified under Section 3.02(a), the Indemnified Party shall, if a claim with respect thereto is to be made against the Indemnifying Party under such Section, notify the Indemnifying Party in writing of the commencement thereof; provided, however, that the omission so to notify the Indemnifying Party shall not relieve it from any liability which it may have to the Indemnified Party to the extent the Indemnifying Party is not prejudiced by such omission. If any such action or proceeding shall be brought against the Indemnified Party and it shall notify the Indemnifying Party of the commencement thereof, the Indemnifying Party shall be entitled to participate therein, and, to the extent that it shall wish, to assume the defense thereof, with counsel reasonably satisfactory to the Indemnified Party, and, after notice from the Indemnifying Party to the Indemnified Party of its election to assume the defense thereof, the Indemnifying Party shall not be liable to such Indemnified Party under Section 3.02(a) for any legal or other expenses subsequently incurred by the Indemnified Party in connection with the defense thereof other than reasonable costs of investigation or reasonable expenses of actions taken

at the written request of the Indemnifying Party. The Indemnifying Party shall not be liable for any compromise or settlement of any such action or proceeding effected without its consent, which consent will not be unreasonably withheld.

ARTICLE IV

DEFERRED COMPENSATION

Section 4.01 Initial Deferral Elections by Participants. Any Director of the Company may at any time elect to participate in the Plan and to have all, or such percentage as he may specify, of the Cash Compensation otherwise payable to him as a Director or Equity Compensation granted to him as a Director deferred and paid to him pursuant to the terms of Section 5.02 or Section 6.05, as applicable. Such deferral election shall be made by notice in writing in a manner and form acceptable to the Administrator and shall be applicable only with respect to Cash Compensation and Equity Compensation for services performed after the end of the calendar year in which such deferral election is made and prior to the earlier of the effective date of a further deferral election pursuant to Section 4.02 herein or such Participant's Deferral Termination Date. At the time of making such initial deferral election hereunder, a Director shall specify the portion, if any, of such Deferred Compensation that relates to Cash Compensation which will be (i) held subject to the interest payment provisions of ARTICLE V hereof or (ii) translated into Stock Equivalents in accordance with ARTICLE VI hereof.

Section 4.02 Subsequent Deferral Elections by Participants. Subsequent to the initial deferral election by a Participant provided for in Section 4.01, a Participant may at any time make a subsequent deferral election in like manner to increase or decrease the percentage of his Cash Compensation or Equity Compensation to be deferred pursuant to the Plan and, with respect to Deferred Compensation that relates to Cash Compensation, to elect the portion of such Deferred Compensation and any Plan Earnings to be (i) held subject to the interest payment provisions of ARTICLE V hereof or (ii) translated into Stock Equivalents in accordance with ARTICLE VI hereof. Any such subsequent deferral election shall be effective as of the first day of the calendar year following the calendar year in which such subsequent deferral election is made. Notwithstanding anything to the contrary herein, no such subsequent deferral election shall effect a transfer of any amount credited, as of the first day of such calendar year, to either the Interest Bearing Account or the Stock Equivalents Account from such account to the other account.

Section 4.03 Establishment of Interest Bearing Accounts and Stock Equivalents Accounts. For Participants who elect to defer Cash Compensation, there shall be established for each such Participant an account to be designated as such Participant's Interest Bearing Account and, where appropriate, an account to be designated as such Participant's Stock Equivalents Account.

Section 4.04 Allocations to Accounts. Any Deferred Compensation relating to Cash Compensation earned by a Participant during a calendar quarter shall be credited to the Interest Bearing Account and/or Stock Equivalents Account of such Participant, as applicable, on the date any such amount is otherwise payable. Any Deferred Compensation relating to a Participant's Equity Compensation shall be credited to the Stock Equivalents Account of such Participant on the date any such Equity Compensation would otherwise be payable to the Participant and no longer subject to forfeiture; provided, however, that any dividend equivalents to which a Participant is entitled under such Equity Compensation prior to the date such Equity Compensation would otherwise be payable or be forfeited shall be credited to the

Participant's Stock Equivalents Account. Any Plan Earnings shall be credited in accordance with the provisions of Section 5.01 and 6.02, as applicable.

Section 4.05 Distribution Elections. A Participant may elect, subject to the provisions of this Section and Sections 5.02 and 6.05, the form of distribution with respect to the Cash Compensation, Equity Compensation and Plan Earnings attributable thereto, deferred by the Participant and allocated to the Participant's Interest Bearing Account and Stock Equivalents Account, as applicable. The distribution election is not required to be the same for each Account. A Participant's distribution election under this Section shall be made in writing in a form authorized by the Administrator and shall be made at the time the Participant makes an initial deferral election under Section 4.01 or a subsequent deferral election under Section 4.02. A Participant may elect distribution in the form of a lump sum, five equal annual installments or ten equal annual installments. Absent any such distribution election by a Participant, the Participant's Interest Bearing Account and Stock Equivalents Account will be distributed in the form of a lump sum distribution.

ARTICLE V

INTEREST

Section 5.01 Interest. A Participant's Interest Bearing Account shall be credited as of the end of each calendar quarter with an amount equivalent to interest for the number of days in such quarter (based on a calendar year of 365 days) at Citibank, N.A.'s prime rate for major corporate borrowers in effect on the first day of such calendar quarter applied to the balance of such account at the beginning of such calendar quarter. (No amount credited to a Participant's Interest Bearing Account subsequent to the beginning of a calendar quarter shall bear interest during that calendar quarter.)

Section 5.02 Distribution of Interest Bearing Accounts. When a Participant's Deferral Termination Date occurs, the balance standing in such Participant's Interest Bearing Account at the end of the calendar quarter in which such date occurs (after crediting interest thereto in accordance with Section 5.01 herein) shall be distributed to such Participant in the form provided under Section 4.05 hereof.

Until payment is made, interest shall continue to accrue in the manner provided in Section 5.01. All Plan Earnings accrued to the date of payment of any lump-sum or annual installment shall be paid in conjunction with such payment. The lump-sum payment or the initial annual installment shall be distributed on the last business day of January next following the close of the calendar year in which the Participant's Deferral Termination Date occurs. The remaining installments, if any, shall be distributed at annual intervals thereafter.

If a Participant's Deferral Termination Date occurs by reason of his death or if he dies after his Deferral Termination Date, but prior to receipt of all distributions provided for in this Section, all cash distributable hereunder shall be distributed in a lump sum to such Participant's estate or personal representative as soon as administratively feasible following such Participant's death.

ARTICLE VI

STOCK EQUIVALENTS

Section 6.01 Stock Equivalents Accounts. With respect to Deferred Compensation that relates to Equity Compensation, the number of Stock Equivalents to be credited to a Participant's Stock Equivalents Account in accordance with Section 4.04 shall be equal to the number of shares of Common Stock relating to such Equity Compensation. With respect to Deferred Compensation that relates to Cash Compensation, the number of Stock Equivalents, or fractions thereof, to be credited to a Participant's Stock Equivalents Account in accordance with Section 4.04 shall be determined by dividing the amount of Deferred Compensation and Plan Earnings to be allocated to such account pursuant to the Participant's specifications given in accordance with Article IV by the Market Price of the Common Stock on the trading day next preceding the last business day of the calendar quarter specified in Section 4.04, and the number of Stock Equivalents, so determined, shall be credited to the Stock Equivalents Account established for the Participant.

Section 6.02 Cash and Property Dividend Credits. Additional credits shall be made to a Participant's Stock Equivalents Account throughout the period of such Participant's participation in the Plan, and thereafter until all distributions to which the Participant is entitled under Section 6.05 or ARTICLE VIII shall have been made, in amounts equal to the Plan Earnings consisting of the cash or fair market value of any dividends or distributions declared and made with respect to the Common Stock payable in cash, securities issued by the Company (other than the Common Stock but including any such securities convertible into Common Stock) or other property which the Participant would have received from time to time had he been the owner on the record dates for the payment of such dividends of the number of shares of the Common Stock equal to the number of Stock Equivalents in his Stock Equivalents Account on such dates. Each such credit shall be effected as of the payment date for such dividend or distribution.

Section 6.03 Stock Dividend Credits. Additional credits shall be made to a Participant's Stock Equivalents Account throughout the period of his participation in the Plan, and thereafter until all distributions to which the Participant is entitled under Section 6.05 or ARTICLE VIII shall have been made, of a number of Stock Equivalents equal to the number of shares (including fractional shares) of the Common Stock to which the Participant would have been entitled from time to time as Common Stock dividends had such Participant been the owner on the record dates for the payments of such stock dividends of the number of shares of the Common Stock equal to the number of Stock Equivalents credited to his Stock Equivalents Account on such dates. Such additional credits shall be effected as of the end of the calendar quarter in which payment of such stock dividend is made.

Section 6.04 Recapitalization. If, as a result of a split or combination of the outstanding Common Stock or other recapitalization or reorganization, the number of shares of the outstanding Common Stock is increased or decreased or all or a portion of the outstanding Common Stock is exchanged for or converted into other securities issued by the Company (including without limitation securities convertible into Common Stock) or other property, the number of Stock Equivalents credited to a Participant's Stock Equivalents Account shall, to the extent reasonably practicable, be

equitably adjusted to give effect to such recapitalization or reorganization (taking into account the fair market value of any securities or other property for which the Common Stock was exchanged or into which it was converted) as if the Participant had owned of record on the effective date of such recapitalization or reorganization a number of shares of the Common Stock equal to the number of Stock Equivalents credited to his Stock Equivalents Account immediately prior thereto. To the extent that any such adjustment is not reasonably practicable, the Board of Directors shall give consideration to amending the Plan pursuant to ARTICLE IX in order to give effect to the purpose of the Plan and, if no such amendments can be effected or are considered desirable, to terminating the Plan pursuant to ARTICLE VIII.

Section 6.05 Distributions from Stock Equivalent Account After Participant's Deferral Termination Date. When a Participant's Deferral Termination Date occurs, the Company shall become obligated to make the distributions prescribed in paragraphs (a) and (b) below. At the time of any distribution, each Stock Equivalent to be distributed shall be converted into one share of Common Stock and such share shall be distributed to the Participant. Any fraction of a Stock Equivalent to be distributed shall be converted into an amount in cash equal to the Market Price of one share of Common Stock on the trading day next preceding the date of distribution multiplied by such fraction and such cash shall be distributed to the Participant.

(a) Distribution shall be made in the form provided under Section 4.05 hereof. Until payment is made, Plan Earnings shall continue to be credited in the manner provided in Section 6.02. All Plan Earnings accrued to the date of any lump-sum distribution or annual installment shall be paid in conjunction with such payment. The lump-sum or the initial annual installment shall be distributed on the last business day of January next following the close of the calendar year in which the Participant's Deferral Termination Date occurs. The remaining installments, if any, shall be distributed at annual intervals thereafter.

(b) If a Participant's Deferral Termination Date shall occur by reason of his death or if he shall die after his Deferral Termination Date but prior to receipt of all distributions provided for in this Section, all Stock Equivalents, or the undistributed balance thereof, shall be distributed to such Participant's estate or personal representative as soon as administratively feasible following such Participant's death.

ARTICLE VII

NATURE OF PLAN

The adoption of this Plan and any setting aside of amounts by the Company with which to discharge its obligations hereunder shall not be deemed to create a trust. Legal and equitable title to any funds so set aside shall remain in the Company, and any recipient of benefits hereunder shall have no security or other interest in such funds. Any and all funds so set aside shall remain subject to the claims of the general creditors of the Company, present and future. This provision shall not require the Company to set aside any funds, but the Company may set aside such funds if it chooses to do so.

ARTICLE VIII

TERMINATION OF THE PLAN

The Board of Directors may terminate the Plan at any time. Upon termination of the Plan, distributions in respect of credits to Participants' Accounts as of the date of termination shall be made in the manner and at the time prescribed in Section 5.02 or 6.05, as applicable.

ARTICLE IX

AMENDMENT OF THE PLAN

The Board of Directors may, without the consent of Participants or their beneficiaries, amend the Plan at any time and from time to time; provided, however, that no amendment may deprive a Participant of the amounts allocated to his or her Accounts or be retroactive in effect to the prejudice of any Participant.

ARTICLE X

GENERAL PROVISIONS

Section 10.01 No Preference. No Participant shall have any preference over the general creditors of the Company in the event of the Company's insolvency.

Section 10.02 Authorized Payments.

(a) If the Committee receives evidence satisfactory to it that any person entitled to receive a periodic payment hereunder is, at the time the benefit is payable, physically, mentally or legally incompetent to receive such payment and to give a valid receipt therefor, and that an individual or institution is then maintaining or has custody of such person and that no guardian, committee or other representative of the estate of such person has been duly appointed, the Committee may direct that such periodic payment or portion thereof be paid to such individual or institution maintaining or having custody of such person, and the receipt of such individual or institution shall be valid and a complete discharge for the payment of such benefit.

(b) Payments to be made hereunder may, at the written request of the Participant, be made to a bank account designated by such Participant, provided that deposits to the credit of such Participant in any bank or trust company shall be deemed payment into his hands.

(c) Notwithstanding any other provisions of the Plan, if any amounts payable under the Plan are found in a “determination” (within the meaning of Section 1313(a) of the Internal Revenue Code of 1986) to have been includible in gross income of a Participant prior to payment of such amounts hereunder, such amounts shall be paid to such Participant as soon as practicable after the Committee is advised of such determination. For purposes of this paragraph, the Committee shall be entitled to rely on an affidavit by a Participant and a copy of the determination to the effect that a determination described in the preceding sentence has occurred.

Section 10.03 Gender Words. Wherever any words are used herein in the masculine, feminine or neuter gender, they shall be construed as though they were also used in another gender in all cases where they would so apply, and whenever any words are used herein in the singular or plural form, they shall be construed as though they were also used in the other form in all cases where they would so apply.

Section 10.04 Assignment of Benefits. Benefits provided under the Plan may not be assigned or alienated, either voluntarily or involuntarily, other than by will or the applicable laws of descent and distribution.

Section 10.05 Conflicts of Laws. THE LAWS OF THE STATE OF TEXAS SHALL CONTROL THE INTERPRETATION AND PERFORMANCE OF THE TERMS OF THE PLAN. THE PLAN IS NOT INTENDED TO QUALIFY UNDER SECTION 401(a) OF THE INTERNAL REVENUE CODE OF 1986, AS AMENDED, OR TO COMPLY WITH THE EMPLOYEE RETIREMENT INCOME SECURITY ACT OF 1974, AS AMENDED.

ARTICLE XI

EFFECTIVE DATE

This amendment and restatement of the Plan shall be effective as of May 16, 2012, and shall continue in force during subsequent years unless amended or revoked by action of the Board of Directors.

HALLIBURTON COMPANY

By /s/ David J. Lesar_______________

David J. Lesar

Chairman of the Board, President

and Chief Executive Officer

HAL-6.30.2012-Ex 12.1

EXHIBIT 12.1

HALLIBURTON COMPANY

Computation of Ratio of Earnings to Fixed Charges

(Unaudited)

(Millions of dollars, except ratios)



	Six Months Ended June 30,		Year Ended December 31
	2012		2011		2010		2009		2008		2007
Earnings available for fixed charges:
Income from continuing operations before income taxes	$	2,046	$	4,449	$	2,655	$	1,682	$	3,849	$	3,447
Add:
Distributed earnings from equity in unconsolidated affiliates	3		13		13		17		30		43
Fixed charges	216		384		402		361		232		222
Subtotal	2,265		4,846		3,070		2,060		4,111		3,712
Less:
Equity in earnings of unconsolidated affiliates	7		20		20		16		50		57
Total earnings available for fixed charges	$	2,258	$	4,826	$	3,050	$	2,044	$	4,061	$	3,655

Fixed charges:
Interest expense	$	158	$	268	$	308	$	297	$	167	$	168
Rental expense representative of interest	58		116		94		64		65		54
Total fixed charges	$	216	$	384	$	402	$	361	$	232	$	222

Ratio of earnings to fixed charges	10.5		12.6		7.6		5.7		17.5		16.5

HAL-6.30.2012-Ex 31.1

Exhibit 31.1

Section 302 Certification

I, David J. Lesar, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2012 of Halliburton Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: July 27, 2012

/s/ David J. Lesar

David J. Lesar

Chief Executive Officer

Halliburton Company

HAL-6.30.2012-Ex 31.2

Exhibit 31.2

Section 302 Certification

I, Mark A. McCollum, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2012 of Halliburton Company;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: July 27, 2012

/s/ Mark A. McCollum

Mark A. McCollum

Chief Financial Officer

Halliburton Company

HAL-6.30.2012-Ex 32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is provided pursuant to § 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. § 1350, and accompanies the Quarterly Report on Form 10-Q for the period ended June 30, 2012 of Halliburton Company (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”).

I, David J. Lesar, Chief Executive Officer of the Company, certify that:


(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David J. Lesar

David J. Lesar

Chief Executive Officer

Date: July 27, 2012

HAL-6.30.2012-Ex 32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark A. McCollum, Chief Financial Officer of the Company, certify that:


(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Mark A. McCollum

Mark A. McCollum

Chief Financial Officer

Date: July 27, 2012

HAL-6.30.2012-Ex 95

EXHIBIT 95

Mine Safety Disclosures

Under the Dodd-Frank Wall Street Reform and Consumer Protection Act, each operator of a mine is required to include certain mine safety results in its periodic reports filed with the SEC. The operation of our mines is subject to regulation by the federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act). Below, we present the following items regarding certain mining safety and health matters for the three months ended June 30, 2012:


▪	total number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA;

▪

total number of orders issued under section 104(b) of the Mine Act, which covers violations that had previously been cited under section 104(a) that, upon follow-up inspection by MSHA, are found not to have been totally abated within the prescribed time period, which results in the issuance of an order requiring the mine operator to immediately withdraw all persons (except certain authorized persons) from the mine;


▪	total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under Section 104(d) of the Mine Act;


▪	total number of flagrant violations (i.e., reckless or repeated failure to make reasonable efforts to eliminate a known violation of a mandatory health or safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury) under section 110(b)(2) of the Mine Act;


▪	total number of imminent danger orders (i.e., the existence of any condition or practice in a mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated) issued under section 107(a) of the Mine Act;


▪	total dollar value of proposed assessments from MSHA under the Mine Act;


▪	total number of mining-related fatalities; and


▪	total number of pending legal actions before the Federal Mine Safety and Health Review Commission involving such mine.



HALLIBURTON COMPANY
Mine Safety Disclosures
Three Months Ended June 30, 2012
(Unaudited)
(Whole dollars)

Operation/ MSHA Identification Number⁽¹⁾	Section 104 Citations	Section 104(b)Orders	104(d)Citations and Orders	Section 110(b)(2)Violations	Section 107(a)Orders	Proposed MSHA Assessments⁽²⁾		Fatalities	Pending Legal Actions
BPM Colony Mill/4800070	1	—	—	—	—	$	—	—	—
BPM Colony Mine/4800889	—	—	—	—	—	—		—	—
BPM Lovell Mill/4801405	—	—	—	—	—	—		—	—
BPM Lovell Mine/4801016	—	—	—	—	—	—		—	—
Corpus Christi Grinding Plant/4104010	—	—	—	—	—	—		—	—
Dunphy Mill/2600412	—	—	—	—	—	—		—	—
Lake Charles Plant/1601032	—	—	—	—	—	—		—	—
Larose Grinding Plant/1601504	—	—	—	—	—	—		—	—
Rossi Jig Plant/2602239	3	—	—	—	—	1,470		—	—
Total	4	—	—	—	—	$	1,470	—	—



(1)	The definition of a mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools, and preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine.
(2)	Amounts included are the total dollar value of proposed or outstanding assessments received from MSHA on or before July 16, 2012 regardless of whether the assessment has been challenged or appealed, for citations and orders occurring during the three months ended June 30, 2012.

In addition, as required by the reporting requirements regarding mine safety included in §1503(a)(2) of the Dodd-Frank Act, the following is a list for the three months ended June 30, 2012, of each mine of which we or a subsidiary of ours is an operator, that has received written notice from MSHA of:

(a) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under

§104(e) of the Mine Act:

None; or

(b) the potential to have such a pattern:

None.

Citations and orders can be contested and appealed, and as part of that process, are sometimes reduced in severity and amount, and are sometimes dismissed. The number of citations, orders, and proposed assessments vary by inspector and also vary depending on the size and type of the operation.