Edgar Filing: HALLIBURTON CO

edjune201110q_final.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] Quarterly Report Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

For the quarterly period ended June 30, 2011

[ ] 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]

[ ]

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]

[ ]

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

[ ]

[X]

As of July 15, 2011, 919,636,645 shares of Halliburton Company common stock, $2.50 par value per share, were outstanding.

HALLIBURTON COMPANY

Index

		Page No.
PART I.	FINANCIAL INFORMATION	3

Item 1.	Financial Statements	3

	- Condensed Consolidated Statements of Operations	3
	- Condensed Consolidated Balance Sheets	4
	- Condensed Consolidated Statements of Cash Flows	5
	- Notes to Condensed Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35

Item 4.	Controls and Procedures	37

PART II.	OTHER INFORMATION	38

Item 1.	Legal Proceedings	38

Item 1(a).	Risk Factors	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51

Item 3.	Defaults Upon Senior Securities	51

Item 4.	Specialized Disclosures	51

Item 5.	Other Information	51

Item 6.	Exhibits	52

Signatures		53

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HALLIBURTON COMPANY

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
Millions of dollars and shares except per share data	2011			2010			2011			2010
Revenue:
Services	$	4,727		$	3,371		$	8,918		$	6,216
Product sales		1,208			1,016			2,299			1,932
Total revenue		5,935			4,387			11,217			8,148
Operating costs and expenses:
Cost of services		3,659			2,716			7,087			5,184
Cost of sales		1,050			862			2,020			1,648
General and administrative		65			47			135			105
Total operating costs and expenses		4,774			3,625			9,242			6,937
Operating income		1,161			762			1,975			1,211
Interest expense, net of interest income of $2, $3, $3, and $6		(63	)		(76	)		(132	)		(152	)
Other, net		(5	)		(9	)		(9	)		(49	)
Income from continuing operations before income taxes		1,093			677			1,834			1,010
Provision for income taxes		(352	)		(200	)		(581	)		(321	)
Income from continuing operations		741			477			1,253			689
Income (loss) from discontinued operations, net of income
tax (provision) benefit of $1, $(3), $1, and $(0)		−			6			(1	)		1
Net income	$	741		$	483		$	1,252		$	690
Noncontrolling interest in net income of subsidiaries		(2	)		(3	)		(2	)		(4	)
Net income attributable to company	$	739		$	480		$	1,250		$	686
Amounts attributable to company shareholders:
Income from continuing operations	$	739		$	474		$	1,251		$	685
Income (loss) from discontinued operations, net		−			6			(1	)		1
Net income attributable to company	$	739		$	480		$	1,250		$	686
Basic income per share attributable to company shareholders:
Income from continuing operations	$	0.81		$	0.52		$	1.37		$	0.76
Income from discontinued operations, net		−			0.01			−			−
Net income per share	$	0.81		$	0.53		$	1.37		$	0.76
Diluted income per share attributable to company shareholders:
Income from continuing operations	$	0.80		$	0.52		$	1.36		$	0.75
Income from discontinued operations, net		−			0.01			−			0.01
Net income per share	$	0.80		$	0.53		$	1.36		$	0.76

Cash dividends per share	$	0.09		$	0.09		$	0.18		$	0.18
Basic weighted average common shares outstanding		916			906			915			906
Diluted weighted average common shares outstanding		921			909			920			908

See notes to condensed consolidated financial statements.

HALLIBURTON COMPANY

Condensed Consolidated Balance Sheets

	June 30,			December 31,
	2011			2010
Millions of dollars and shares except per share data	(Unaudited)
Assets
Current assets:
Cash and equivalents	$	1,438		$	1,398
Receivables (less allowance for bad debts of $128 and $91)		4,448			3,924
Inventories		2,235			1,940
Investments in marketable securities		451			653
Current deferred income taxes		258			257
Other current assets		710			714
Total current assets		9,540			8,886
Property, plant, and equipment, net of accumulated depreciation of $6,611 and $6,064		7,626			6,842
Goodwill		1,369			1,315
Other assets		1,421			1,254
Total assets	$	19,956		$	18,297
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	1,554		$	1,139
Accrued employee compensation and benefits		706			716
Deferred revenue		260			266
Other current liabilities		646			636
Total current liabilities		3,166			2,757
Long-term debt		3,824			3,824
Employee compensation and benefits		483			487
Other liabilities		825			842
Total liabilities		8,298			7,910
Shareholders’ equity:
Common shares, par value $2.50 per share – authorized 2,000 shares, issued
1,072 and 1,069 shares		2,680			2,674
Paid-in capital in excess of par value		360			339
Accumulated other comprehensive loss		(237	)		(240	)
Retained earnings		13,456			12,371
Treasury stock, at cost – 154 and 159 shares		(4,617	)		(4,771	)
Company shareholders’ equity		11,642			10,373
Noncontrolling interest in consolidated subsidiaries		16			14
Total shareholders’ equity		11,658			10,387
Total liabilities and shareholders’ equity	$	19,956		$	18,297

See notes to condensed consolidated financial statements.

HALLIBURTON COMPANY

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	June 30
Millions of dollars	2011			2010
Cash flows from operating activities:
Net income	$	1,252		$	690
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation, depletion, and amortization		651			533
Payments related to KBR TSKJ matters		(6	)		(94	)
Other changes:
Receivables		(583	)		(547	)
Accounts payable		397			296
Inventories		(290	)		(162	)
Other		(33	)		92
Total cash flows from operating activities		1,388			808
Cash flows from investing activities:
Capital expenditures		(1,423	)		(855	)
Sales of marketable securities		701			550
Purchases of marketable securities		(501	)		(1,182	)
Acquisitions of business assets, net of cash acquired		(70	)		(190	)
Other investing activities		50			82
Total cash flows from investing activities		(1,243	)		(1,595	)
Cash flows from financing activities:
Dividends to shareholders		(165	)		(163	)
Proceeds from exercises of stock options		93			40
Other financing activities		(13	)		5
Total cash flows from financing activities		(85	)		(118	)
Effect of exchange rate changes on cash		(20	)		(17	)
Increase (decrease) in cash and equivalents		40			(922	)
Cash and equivalents at beginning of period		1,398			2,082
Cash and equivalents at end of period	$	1,438		$	1,160
Supplemental disclosure of cash flow information:
Cash payments during the period for:
Interest	$	136		$	155
Income taxes	$	536		$	361

See notes to condensed consolidated financial statements.

HALLIBURTON COMPANY

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1. Basis of Presentation

The accompanying unaudited condensed consolidated financial statements were prepared using generally accepted accounting principles for interim financial information and the instructions to Form 10-Q and Regulation S-X. Accordingly, these financial statements do not include all information or notes required by generally accepted accounting principles for annual financial statements and should be read together with our 2010 Annual Report on Form 10-K.

Our accounting policies are in accordance with United States generally accepted accounting principles. The preparation of financial statements in conformity with these accounting principles requires us to make estimates and assumptions that affect:

	-	the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements; and
	-	the reported amounts of revenue and expenses during the reporting period.

Ultimate results could differ from our estimates.

In our opinion, the condensed consolidated financial statements included herein contain all adjustments necessary to present fairly our financial position as of June 30, 2011, the results of our operations for the three and six months ended June 30, 2011 and 2010, and our cash flows for the six months ended June 30, 2011 and 2010. Such adjustments are of a normal recurring nature. In addition, certain reclassifications of prior period balances have been made to conform to 2011 classifications. The results of operations for the three and six months ended June 30, 2011 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.

Intersegment revenue was immaterial. Our equity in earnings and losses of unconsolidated affiliates that are accounted for by the equity method are included in revenue and operating income of the applicable segment.

	Three Months Ended						Six Months Ended
	June 30						June 30
Millions of dollars	2011			2010			2011			2010
Revenue:
Completion and Production	$	3,618		$	2,393		$	6,790		$	4,357
Drilling and Evaluation		2,317			1,994			4,427			3,791
Total revenue	$	5,935		$	4,387		$	11,217		$	8,148

Operating income:
Completion and Production	$	918		$	497		$	1,578		$	735
Drilling and Evaluation		324			318			554			588
Total operations		1,242			815			2,132			1,323
Corporate and other		(81	)		(53	)		(157	)		(112	)
Total operating income	$	1,161		$	762		$	1,975		$	1,211
Interest expense, net of interest income		(63	)		(76	)		(132	)		(152	)
Other, net		(5	)		(9	)		(9	)		(49	)
Income from continuing operations before
income taxes	$	1,093		$	677		$	1,834		$	1,010

Receivables

As of June 30, 2011, 43% of our gross trade receivables were from customers in the United States. As of December 31, 2010, 36% of our gross trade receivables were from customers in the United States.

Note 3. Inventories

Inventories are stated at the lower of cost or market. 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 $129 million as of June 30, 2011 and $108 million as of December 31, 2010. If the average cost method had been used, total inventories would have been $40 million higher than reported as of June 30, 2011 and $34 million higher than reported as of December 31, 2010. The cost of the remaining inventory was recorded on the average cost method. Inventories consisted of the following:

	June 30,		December 31,
Millions of dollars	2011		2010
Finished products and parts	$	1,559	$	1,369
Raw materials and supplies		621		496
Work in process		55		75
Total	$	2,235	$	1,940

Finished products and parts are reported net of obsolescence reserves of $104 million as of June 30, 2011 and $88 million as of December 31, 2010.

Note 4. Debt

On February 22, 2011, we entered into a new unsecured $2.0 billion five-year revolving credit facility that replaced our then existing $1.2 billion unsecured credit facility established in July 2007. The purpose of the facility is to provide commercial paper support, general working capital, and credit for other corporate purposes. The full amount of the revolving credit facility was available as of June 30, 2011.

During the second quarter of 2011, we entered into a series of interest rate swaps relating to two of our debt instruments. The first series of swaps were for a notional amount of $600 million in order to hedge a portion of the changes in the fair value of our 6.15% senior notes due 2019. Under the terms of these swaps, we will receive interest at a fixed rate of 6.15% and will pay interest at a floating rate of three-month LIBOR plus a spread semiannually. The second series of swaps were for a notional amount of $400 million in order to hedge changes in the fair value of our 5.9% senior notes due 2018. Under the terms of these swaps, we will receive interest at a fixed rate of 5.9% and will pay interest at a floating rate of three-month LIBOR plus a spread semiannually. These interest rate swaps are designated as fair value hedges of the underlying debt. These derivative instruments are marked to market with gains and losses recognized currently in interest expense to offset the respective gains and losses recognized on changes in the fair value of the hedged debt.

Note 5. Shareholders’ Equity

The following tables summarize our shareholders’ equity activity.

							Noncontrolling
	Total			Company			interest in
	shareholders’			shareholders’			consolidated
Millions of dollars	equity			equity			subsidiaries
Balance at December 31, 2010	$	10,387		$	10,373		$	14
Transactions with shareholders		181			181			–
Comprehensive income:
Net income		1,252			1,250			2
Other comprehensive income		3			3			–
Total comprehensive income		1,255			1,253			2
Payments of dividends to shareholders		(165	)		(165	)		–
Balance at June 30, 2011	$	11,658		$	11,642		$	16

							Noncontrolling
	Total			Company			interest in
	shareholders’			shareholders’			consolidated
Millions of dollars	equity			equity			subsidiaries
Balance at December 31, 2009	$	8,757		$	8,728		$	29
Transactions with shareholders		96			98			(2	)
Comprehensive income:
Net income		690			686			4
Other comprehensive income		4			4			–
Total comprehensive income		694			690			4
Payments of dividends to shareholders		(163	)		(163	)		–
Balance at June 30, 2010	$	9,384		$	9,353		$	31

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

	Three Months Ended
	June 30
Millions of dollars	2011		2010
Net income	$	741	$	483
Other comprehensive income (loss)		1		(3	)
Total comprehensive income	$	742	$	480
Comprehensive income attributable to noncontrolling interest		2		3
Comprehensive income attributable to company		740		477

Accumulated other comprehensive loss consisted of the following:

	June 30,		December 31,
Millions of dollars	2011		2010
Defined benefit and other postretirement liability adjustments	$	(176)	$	(175)
Cumulative translation adjustments		(64)		(66)
Unrealized gains on investments		3		1
Total accumulated other comprehensive loss	$	(237)	$	(240)

Note 6. KBR Separation

During 2007, we completed the separation of KBR, Inc. (KBR) from us by exchanging KBR common stock owned by us for our common stock. In addition, we recorded a liability reflecting the estimated fair value of the indemnities provided to KBR as described below. Since the separation, we have recorded adjustments to reflect changes to our estimation of our remaining obligation. All such adjustments are recorded in “Income (loss) from discontinued operations, net of income tax 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. Also, under the master separation agreement, we have indemnified KBR for certain losses arising from investigations and charges brought under the United States Foreign Corrupt Practices Act (FCPA) or similar foreign statutes, laws, rules, or regulations in each case related to the construction of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria by a consortium of engineering firms comprised of Technip SA of France, Snamprogetti Netherlands B.V., JGC Corporation of Japan, and Kellogg Brown & Root LLC (TSKJ), each of which had an approximate 25% beneficial interest in the venture. Part of KBR’s ownership in TSKJ was held through M.W. Kellogg Limited, a United Kingdom joint venture and subcontractor on the Bonny Island project in which KBR beneficially owned a 55% interest at the time of the execution of the master separation agreement. The TSKJ investigations and charges have been resolved. At this time, no other claims by governmental authorities in any jurisdictions have been asserted against the indemnified parties.

The tax sharing agreement provides for allocations of United States and certain other jurisdiction tax liabilities between us and KBR. The tax sharing agreement is complex, and finalization of amounts owed between KBR and us under the tax sharing agreement can occur only after income tax audits are completed by the taxing authorities and both parties have had time to analyze the results. There can be no guarantee that the parties will agree on the allocations of tax liabilities, and the process may take several quarters or more to complete.

Amounts accrued relating to our remaining KBR liabilities are primarily included in “Other liabilities” on the condensed consolidated balance sheets and totaled $53 million as of June 30, 2011 and $63 million as of December 31, 2010. See Note 7 for further discussion of the Barracuda-Caratinga matter.

Note 7. Commitments and Contingencies

The Gulf of Mexico/Macondo well incident

Overview. The semisubmersible drilling rig, Deepwater Horizon, sank on April 22, 2010 after an explosion and fire onboard the rig that began on April 20, 2010. The Deepwater Horizon was owned by Transocean Ltd. and had been drilling the Macondo exploration well in Mississippi Canyon Block 252 in the Gulf of Mexico for the lease operator, BP Exploration & Production, Inc. (BP Exploration), an indirect wholly owned subsidiary of BP p.l.c. We performed a variety of services for BP Exploration, including cementing, mud logging, directional drilling, measurement-while-drilling, and rig data acquisition services. Crude oil flowing from the well site spread across thousands of square miles of the Gulf of Mexico and reached the United States Gulf Coast. Numerous attempts at estimating the volume of oil spilled have been made by various groups, and on August 2, 2010 the federal government published an estimate that approximately 4.9 million barrels of oil were discharged from the well. Efforts to contain the flow of hydrocarbons from the well were led by the United States government and by BP p.l.c., BP Exploration, and their affiliates (collectively, BP). The flow of hydrocarbons from the well ceased on July 15, 2010, and the well was permanently capped on September 19, 2010. There were eleven fatalities and a number of injuries as a result of the Macondo well incident.

As of June 30, 2011, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. We are currently unable to estimate the full impact the Macondo well incident will have on us. Further, an estimate of a reasonably possible loss or range of loss related to this matter cannot be made. Considering the complexity of the Macondo well, however, and the number of investigations being conducted and lawsuits pending, as discussed below, new information or future developments may require us to adjust our liability assessment, and liabilities arising out of this matter could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Investigations and Regulatory Action. The United States Coast Guard, a component of the United States Department of Homeland Security, and the Bureau of Ocean Energy Management, Regulation and Enforcement (BOE) (formerly known as the Minerals Management Service), a bureau of the United States Department of the Interior, share jurisdiction over the investigation into the Macondo well incident and have formed a joint investigation team that continues to review information and hold hearings regarding the incident (Marine Board Investigation). We are named as one of the 16 parties-in-interest in the Marine Board Investigation. In addition, other investigations are underway by the Chemical Safety Board and the National Academy of Sciences to, among other things, examine the relevant facts and circumstances concerning the causes of the Macondo well incident and develop options for guarding against future oil spills associated with offshore drilling. We are assisting in efforts to identify the factors that led to the Macondo well incident and have participated and intend to continue participating in various hearings relating to the incident that are held by, among others, certain of the agencies referred to above and various committees and subcommittees of the House of Representatives and the Senate of the United States.

In May 2010, the United States Department of the Interior effectively suspended all offshore deepwater drilling projects in the United States Gulf of Mexico. The suspension was lifted in October 2010. Later, the Department of the Interior issued new guidance for drillers that intend to resume deepwater drilling activity. Despite the fact that the drilling suspension was lifted, the BOE did not issue permits for the resumption of drilling for an extended period of time, and we have experienced a significant reduction in our Gulf of Mexico operations since the Macondo well incident. In the first quarter of 2011, the BOE resumed the issuance of drilling permits, and activity began to slowly recover in the second quarter although there can be no assurance of whether or when operations in the Gulf of Mexico will return to pre-suspension levels. For additional information, see Part II, Item 1(a), “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Environment and Results of Operations.”

DOJ Investigations and Actions. On June 1, 2010, the United States Attorney General announced that the Department of Justice (DOJ) was launching civil and criminal investigations into the Macondo well incident to closely examine the actions of those involved, and that the DOJ was working with attorneys general of states affected by the Macondo well incident. The DOJ announced that it was reviewing, among other traditional criminal statutes, possible violations of and liabilities under The Clean Water Act (CWA), The Oil Pollution Act of 1990 (OPA), The Migratory Bird Treaty Act of 1918 (MBTA), and the Endangered Species Act of 1973 (ESA).

The CWA provides authority for civil and criminal penalties for discharges of oil into or upon navigable waters of the United States, adjoining shorelines, or in connection with the Outer Continental Shelf Lands Act in quantities that are deemed harmful. A single discharge event may result in the assertion of numerous violations under the CWA. Criminal sanctions under the CWA can be assessed for negligent discharges (up to $50,000 per day per violation), for knowing discharges (up to $100,000 per day per violation), and for knowing endangerment (up to $2 million per violation), and federal agencies could be precluded from contracting with a company that is criminally sanctioned under the CWA. Civil proceedings under the CWA can be commenced against an “owner, operator or person in charge of any vessel or offshore facility that discharged oil or a hazardous substance.” The civil penalties that can be imposed against responsible parties range from up to $1,100 per barrel of oil discharged in the case of those found strictly liable to $4,300 per barrel of oil discharged in the case of those found to have been grossly negligent.

The OPA establishes liability for discharges of oil from vessels, onshore facilities, and offshore facilities into or upon the navigable waters of the United States. Under the OPA, the “responsible party” for the discharging vessel or facility is liable for removal and response costs as well as for damages, including recovery costs to contain and remove discharged oil and damages for injury to natural resources, lost revenues, lost profits and lost earning capacity. The cap on liability under the OPA is the full cost of removal of the discharged oil plus up to $75 million for damages, except that the $75 million cap does not apply in the event the damage was proximately caused by gross negligence or the violation of certain federal safety, construction or operating standards. The OPA defines the set of responsible parties differently depending on whether the source of the discharge is a vessel or an offshore facility. Liability for vessels is imposed on owners and operators; liability for offshore facilities is imposed on the holder of the permit or lessee of the area in which the facility is located.

The MBTA and the ESA provide penalties for injury and death to wildlife and bird species. The MBTA provides that violators are strictly liable and provides for fines of up to $15,000 per bird killed and imprisonment of up to six months. The ESA provides for civil penalties for knowing violations that can range up to $25,000 per violation and, in the case of criminal penalties, up to $50,000 per violation.

In addition, the Alternative Fines Act may be applied in lieu of the express amount of the criminal fines that may be imposed under the statutes described above in the amount of twice the gross economic loss suffered by third parties (or twice the gross economic gain realized by the defendant, if greater).

On December 15, 2010, the DOJ filed a civil action seeking damages and injunctive relief against BP Exploration, Anadarko Petroleum Corporation and Anadarko E&P Company LP (together, Anadarko), certain subsidiaries of Transocean Ltd. and others for violations of the CWA and the OPA. The DOJ’s complaint seeks an action declaring that the defendants are strictly liable under the CWA as a result of harmful discharges of oil into the Gulf of Mexico and upon U.S. shorelines as a result of the Macondo well incident. The complaint also seeks an action declaring that the defendants are strictly liable under the OPA for the discharge of oil that has resulted in, among other things, injury to, loss of, loss of use of or destruction of natural resources and resource services in and around the Gulf of Mexico and the adjoining U.S. shorelines and resulting in removal costs and damages to the United States far exceeding $75 million. BP has been designated, and has accepted the designation, as a responsible party for the pollution under the CWA and the OPA. Others have also been named as responsible parties, and all responsible parties may be held jointly and severally liable for any damages under the OPA. A responsible party may make a claim for contribution against any other responsible party or against third parties it alleges contributed to or caused the oil spill. In connection with the proceedings discussed below under “Litigation,” in April 2011 BP Exploration filed a claim against us for contribution with respect to liabilities incurred by BP Exploration under the OPA and requested a judgment that the DOJ assert its claims for OPA financial liability directly against us.

We were not named as a responsible party under the CWA or the OPA in the DOJ civil action, and we do not believe we are a responsible party under the CWA or the OPA. While we were not included in the DOJ’s complaint, there can be no assurance that the DOJ or other federal or state governmental authorities will not bring an action, whether civil or criminal, against us under the CWA, the OPA or other statutes or regulations. In connection with the DOJ’s filing of the action, it announced that its criminal and civil investigations are continuing and that it will employ efforts to hold accountable those who are responsible for the incident. The DOJ has convened a grand jury in Louisiana to investigate potential criminal conduct in connection with the Macondo well incident. As of July 21, 2011, the DOJ has not commenced any civil or criminal proceedings against us.

In June 2010, we received a letter from the DOJ requesting thirty days advance notice of any event that may involve substantial transfers of cash or other corporate assets outside of the ordinary course of business. In our reply to the June 2010 DOJ letter, we conveyed our interest in briefing the DOJ on the services we provided on the Deepwater Horizon but indicated that we would not bind ourselves to the DOJ request. Subsequently, we have had and expect to continue to have discussions with the DOJ regarding the Macondo well incident and the request contained in the June 2010 DOJ letter.

Investigative Reports. On September 8, 2010, an incident investigation team assembled by BP issued the Deepwater Horizon Accident Investigation Report (BP Report). The BP Report outlines 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 on the BP Deepwater Horizon Oil Spill and Offshore Drilling (National Commission) released “Deep Water -- The Gulf Oil Disaster and the Future of Offshore Drilling,” its investigation report (Investigation Report) to the President of the United States regarding, among other things, the National Commission’s conclusions of the causes of the Macondo well incident. According to the Investigation Report, the “immediate causes” of the incident were the result of a series of missteps, oversights, miscommunications and failures to appreciate risk by BP, Transocean, and us, although the National Commission acknowledged that there were still many things it did not know about the incident, such as the role of the blowout preventer. The National Commission also acknowledged that it may never know the extent to which each mistake or oversight caused the Macondo well incident, but concluded that the immediate cause was “a failure to contain hydrocarbon pressures in the well,” and pointed to three things that could have contained those pressures: “the cement at the bottom of the well, the mud in the well and in the riser, and the blowout preventer.” In addition, the Investigation Report stated that “primary cement failure was a direct cause of the blowout” and that cement testing performed by an independent laboratory “strongly suggests” that the foam cement slurry used on the Macondo well was unstable. The Investigation Report, however, acknowledges a fact widely accepted by the industry that cementing wells is a complex endeavor utilizing an inherently uncertain process in which failures are not uncommon and that, as a result, the industry utilizes the negative-pressure test and cement bond log test, among others, to identify cementing failures that require remediation before further work on a well is performed.

The Investigation Report also sets forth the National Commission’s findings on certain missteps, oversights and other factors that may have caused, or contributed to the cause of, the incident, including BP’s decision to use a long string casing instead of a liner casing, BP’s decision to use only six centralizers, BP’s failure to run a cement bond log, BP’s reliance on the primary cement job as a barrier to a possible blowout, BP’s and Transocean’s failure to properly conduct and interpret a negative-pressure test, BP’s temporary abandonment procedures, and the failure of the drilling crew and our surface data logging specialist to recognize that an unplanned influx of oil, gas or fluid into the well (known as a “kick”) was occurring. With respect to the National Commission’s finding that our surface data logging specialist failed to recognize a kick, the Investigation Report acknowledged that there were simultaneous activities and other monitoring responsibilities that may have prevented the surface data logging specialist from recognizing a kick.

The Investigation Report also identified two general root causes of the Macondo well incident: systemic failures by industry management, which the National Commission labeled “the most significant failure at Macondo,” and failures in governmental and regulatory oversight. The National Commission cited examples of failures by industry management such as BP’s lack of controls to adequately identify or address risks arising from changes to well design and procedures, the failure of BP’s and our processes for cement testing, communication failures among BP, Transocean, and us, including with respect to the difficulty of our cement job, Transocean’s failure to adequately communicate lessons from a recent near-blowout, and the lack of processes to adequately assess the risk of decisions in relation to the time and cost those decisions would save. With respect to failures of governmental and regulatory oversight, the National Commission concluded that applicable drilling regulations were inadequate, in part because of a lack of resources and political support of the Minerals Management Service (MMS), and a lack of expertise and training of MMS personnel to enforce regulations that were in effect.

As a result of the factual and technical complexity of the Macondo well incident, the Chief Counsel of the National Commission issued a separate, more detailed report regarding the technical, managerial and regulatory causes of the Macondo well incident in February 2011.

In March 2011, a third party retained by the BOE to undertake a forensic examination and evaluation of the blowout preventer stack, its components and associated equipment, released a report detailing its findings. The forensic examination report found, among other things, that the blowout preventer stack failed primarily because the blind sheer rams did not fully close and seal the well due to a portion of drill pipe that had become trapped between the blocks. The forensic examination report recommended further examination, investigation and testing, which we understand is underway. We had no part in manufacturing or servicing the blowout preventer stack.

The Cementing Job and Reaction to Reports. We disagree with the BP Report, the National Commission, and Transocean’s report regarding many of their findings and characterizations with respect to the cementing and surface data logging services on the Deepwater Horizon. We have provided information to the National Commission and its staff that we believe has been overlooked or selectively omitted from the Investigation Report. We intend to continue to vigorously defend ourselves in any investigation relating to our involvement with the Macondo well that we believe inaccurately evaluates or depicts our services on the Deepwater Horizon.

The cement slurry on the Deepwater Horizon was designed and prepared pursuant to well condition data provided by BP. Regardless of whether alleged weaknesses in cement design and testing are or are not ultimately established, and regardless of whether the cement slurry was utilized in similar applications or was prepared consistent with industry standards, we believe that had BP and others properly interpreted a negative-pressure test, this test would have revealed any problems with the cement. In addition, had BP designed the Macondo well to allow a full cement bond log test or if BP had conducted even a partial cement bond log test, the test likely would have revealed any problems with the cement. BP, however, elected not to conduct any cement bond log test, and with others misinterpreted the negative-pressure test, both of which could have resulted in remedial action, if appropriate, with respect to the cementing services.

At this time we cannot predict the impact of the Investigation Report or the conclusions of future reports of the Marine Board Investigation, the Chemical Safety Board, the National Academy of Sciences, Congressional committees, or any other governmental or private entity. We also cannot predict whether their investigations or any other report or investigation will have an influence on or result in our being named as a party in any action alleging violation of a statute or regulation, whether federal or state and whether criminal or civil.

We intend to continue to cooperate fully with all governmental hearings, investigations, and requests for information relating to the Macondo well incident. We cannot predict the outcome of, or the costs to be incurred in connection with, any of these hearings or investigations, and therefore we cannot predict the potential impact they may have on us.

Litigation. Since April 21, 2010, plaintiffs have been filing lawsuits relating to the Macondo well incident. Generally, those lawsuits allege either (1) damages arising from the oil spill pollution and contamination (e.g., diminution of property value, lost tax revenue, lost business revenue, lost tourist dollars, inability to engage in recreational or commercial activities) or (2) wrongful death or personal injuries. To date, we have been named along with other unaffiliated defendants in more than 400 complaints, most of which are alleged class actions, involving pollution damage claims and at least 40 personal injury lawsuits involving seven decedents and at least 59 allegedly injured persons who were on the drilling rig at the time of the incident. Another six lawsuits naming us and others relate to alleged personal injuries sustained by those responding to the explosion and oil spill. Plaintiffs originally filed the lawsuits described above in federal and state courts throughout the United States, including Alabama, Delaware, Florida, Georgia, Kentucky, Louisiana, Mississippi, South Carolina, Tennessee, Texas, and Virginia. Except for certain lawsuits not yet consolidated (including one lawsuit that is proceeding in Louisiana state court, nine lawsuits that are pending in Delaware federal court, two lawsuits that are pending in Texas federal court, and two lawsuits that are proceeding in Texas state court), the Judicial Panel on Multi-District Litigation ordered all of the lawsuits against us consolidated in a multi-district litigation (MDL) proceeding before Judge Carl Barbier in the U.S. Eastern District of Louisiana. The pollution complaints generally allege, among other things, negligence and gross negligence, property damages, taking of protected species, and potential economic losses as a result of environmental pollution and generally seek awards of unspecified economic, compensatory, and punitive damages, as well as injunctive relief. Plaintiffs in these pollution cases have brought suit under various legal provisions, including the OPA, the CWA, the MBTA, the ESA, the Outer Continental Shelf Lands Act, the Longshoremen and Harbor Workers Compensation Act, general maritime law, state common law, and various state environmental and products liability statutes.

Furthermore, the pollution complaints include suits brought against us by governmental entities, including the State of Alabama, the State of Louisiana, Plaquemines Parish, the City of Greenville, and three Mexican states. The wrongful death and other personal injury complaints generally allege negligence and gross negligence and seek awards of compensatory damages, including unspecified economic damages and punitive damages. We have retained counsel and are investigating and evaluating the claims, the theories of recovery, damages asserted, and our respective defenses to all of these claims.

Judge Barbier is also presiding over a separate proceeding filed by Transocean under the Limitation of Liability Act (Limitation Action). In the Limitation Action, Transocean seeks to limit its liability for claims arising out of the Macondo well incident to the value of the rig and its freight. Although the Limitation Action is not consolidated in the MDL, to this point the judge is effectively treating the two proceedings as associated cases. On February 18, 2011, Transocean tendered us, along with all other defendants, into the Limitation Action. As a result of the tender, we and all other defendants will be treated as direct defendants to the plaintiffs’ claims as if the plaintiffs had sued each of us and the other defendants directly. In the Limitation Action, the judge intends to determine the allocation of liability among all defendants in the hundreds of lawsuits associated with the Macondo well incident, including those in the MDL proceeding, that are pending in his court. Specifically, the judge will determine the liability, limitation, exoneration and fault allocation with regard to all of the defendants in a trial, which may occur in several phases, that is set to begin in the first quarter 2012. We do not believe, however, that a single apportionment of liability in the Limitation Action is properly applied to the hundreds of lawsuits pending in the MDL proceeding. Damages for the cases tried in the first quarter 2012, including punitive damages, are currently scheduled to be tried in a later phase of the Limitation Action. Under ordinary MDL procedures, such cases would, unless waived by the respective parties, be tried in the courts from which they were transferred into the MDL. It remains unclear, however, what impact the overlay of the Limitation Action will have on where these matters are tried. Document discovery and depositions among the parties to the MDL are underway.

In April and May 2011, certain defendants in the proceedings described above filed numerous cross claims and third party claims against certain other defendants. BP Exploration and BP America Production Company filed claims against us seeking subrogation and contribution, including with respect to liabilities under the OPA, and alleging negligence, gross negligence, fraudulent conduct, and fraudulent concealment. Transocean filed claims against us seeking indemnification, and subrogation and contribution, including with respect to liabilities under the OPA and for the total loss of the Deepwater Horizon, and alleging comparative fault and breach of warranty of workmanlike performance. Anadarko filed claims against us seeking tort indemnity and contribution, and alleging negligence, gross negligence and willful misconduct, and MOEX Offshore 2007 LLC (MOEX), who has an approximate 10% interest in the Macondo well, filed a claim against us alleging negligence. Cameron International Corporation (Cameron) (the manufacturer and designer of the blowout preventer), M-I Swaco (provider of drilling fluids and services, among other things), Weatherford U.S. L.P. and Weatherford International, Inc. (together, Weatherford) (providers of casing components, including float equipment and centralizers, and services), and Dril-Quip, Inc. (Dril-Quip) (provider of wellhead systems), each filed claims against us seeking indemnification and contribution, including with respect to liabilities under the OPA in the case of Cameron, and alleging negligence. Additional civil lawsuits may be filed against us. In addition to the claims against us, generally the defendants in the proceedings described above filed claims, including for liabilities under the OPA and other claims similar to those described above, against the other defendants described above. BP has since announced that it has settled those claims between it and each of Weatherford and MOEX.

In April 2011, we filed claims against BP Exploration, BP p.l.c. and BP America Production Company (BP Defendants), M-I Swaco, Cameron, Anadarko, MOEX, Weatherford, Dril-Quip, and numerous entities involved in the post-blowout remediation and response efforts, in each case seeking contribution and indemnification and alleging negligence. Our claims also alleged gross negligence and willful misconduct on the part of the BP Defendants, Anadarko, and Weatherford. We also filed claims against M-I Swaco and Weatherford for contractual indemnification, and against Cameron, Weatherford and Dril-Quip for strict products liability. We filed our answer to Transocean’s Limitation petition denying Transocean’s right to limit its liability, denying all claims and responsibility for the incident, seeking contribution and indemnification, and alleging negligence and gross negligence.

We intend to vigorously defend any litigation, fines, and/or penalties relating to 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 provides for our indemnification by BP Exploration for potential claims and expenses relating to the Macondo well incident, including those resulting from pollution or contamination (other than claims by our employees, loss or damage to our property, and any pollution emanating directly from our equipment). Also, under our contract with BP Exploration, we have, among other things, generally agreed to indemnify BP Exploration and other contractors performing work on the well for claims for personal injury of our employees and subcontractors, as well as for damage to our property. In turn, we believe that BP Exploration was obligated to obtain agreement by other contractors performing work on the well to indemnify us for claims for personal injury of their employees or subcontractors, as well as for damages to their property.

In addition to the contractual indemnity, we have a general liability insurance program of $600 million. Our insurance is designed to cover claims by businesses and individuals made against us in the event of property damage, injury or death and, among other things, claims relating to environmental damage, as well as legal fees incurred in defending against those claims. We have received and expect to continue to receive payments from our insurers with respect to covered legal fees incurred in connection with the Macondo well incident. To the extent we incur any losses beyond those covered by indemnification, there can be no assurance that our insurance policies will cover all potential claims and expenses relating to the Macondo well incident. Insurance coverage can be the subject of uncertainties and, particularly in the event of large claims, potential disputes with insurance carriers, as well as other potential parties claiming insured status under our insurance policies.

In April 2011, we filed a lawsuit against BP Exploration in Harris County, Texas to enforce BP Exploration’s contractual indemnity and alleging BP Exploration breached certain terms of the contractual indemnity provision. BP Exploration removed that lawsuit to federal court in the Southern District of Texas, Houston Division, where the judge has issued a stay order pending determination of a conditional order by the MDL panel to transfer the lawsuit to the MDL. We have taken and will continue to take actions to oppose the removal and the transfer to the MDL.

BP Exploration, in connection with filing its claims with respect to the MDL proceeding, asked that court to declare that it is not liable to us in contribution, indemnification or otherwise with respect to liabilities arising from the Macondo well incident. Other defendants in the litigation discussed above have generally denied any obligation to contribute to any liabilities arising from the Macondo well incident.

Indemnification for criminal or civil fines or penalties, if any, may not be available if a court were to find such indemnification unenforceable as against public policy. We do not expect, however, public policy to limit substantially the enforceability of our contractual right to indemnification with respect to liabilities other than criminal fines and penalties, if any. We may not be insured with respect to civil or criminal fines or penalties, if any, pursuant to the terms of our insurance policies.

We believe the law likely to be held applicable to matters relating to the Macondo well incident does not allow for enforcement of indemnification of persons who are found to be grossly negligent, although we do not believe the performance of our services on the Deepwater Horizon constituted gross negligence. In addition, certain state laws, if deemed to apply, may not allow for enforcement of indemnification of persons who are found to be negligent with respect to personal injury claims. Also, financial analysts and the press have speculated about the financial capacity of BP, and whether it might seek to avoid indemnification obligations in bankruptcy proceedings. BP’s public filings indicate that BP recognized a $40.9 billion pre-tax charge in 2010 and a $0.4 billion pre-tax charge in the first quarter of 2011 as a result of the Macondo well incident and that the amount of, among other things, any natural resource damages with respect to OPA claims by the United States and by state, tribal and foreign trustees, some of which may be included in such charges, cannot be reliably estimated as of the date of those filings. We consider, however, the likelihood of a BP bankruptcy to be remote.

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. Under the master separation agreement, KBR currently controls the defense, counterclaim, and settlement of the subsea flowline bolts matter. As a condition of our indemnity, for any settlement to be binding upon us, KBR must secure our prior written consent to such settlement’s terms. We have the right to terminate the indemnity in the event KBR enters into any settlement without our prior written consent.

At Petrobras’ direction, KBR replaced certain bolts located on the subsea flowlines that failed through mid-November 2005, and KBR has 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. We understand KBR believes several possible solutions may exist, including replacement of the bolts. Initial estimates by KBR indicated that costs of these various solutions ranged up to $148 million. In March 2006, Petrobras commenced arbitration against KBR claiming $220 million plus interest for the cost of monitoring and replacing the defective bolts and all related costs and expenses of the arbitration, including the cost of attorneys’ fees. The arbitration panel held an evidentiary hearing in March 2008 to determine which party is responsible for the designation of the material used for the bolts. On May 13, 2009, the arbitration panel held that KBR and not Petrobras selected the material to be used for the bolts. Accordingly, the arbitration panel held that there is no implied warranty by Petrobras to KBR as to the suitability of the bolt material and that the parties' rights are to be governed by the express terms of their contract. The parties presented evidence and witnesses to the panel in May 2010, and final arguments were presented in August 2010. We are awaiting a final decision from the arbitration panel. Our estimation of the indemnity obligation regarding the Barracuda-Caratinga arbitration is recorded as a liability in our condensed consolidated financial statements as of June 30, 2011. See Note 6 for additional information regarding the KBR indemnification.

Securities and related litigation

In June 2002, a class action lawsuit was filed against us in federal court alleging violations of the federal securities laws after the 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 is now styled Archdiocese of Milwaukee Supporting Fund (AMSF) v. Halliburton Company, et al. AMSF has changed its name to Erica P. John Fund, Inc. (Erica P. John Fund). We settled with the SEC in the second quarter of 2004.

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

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

In September 2007, Erica P. John Fund filed a motion for class certification, and our response was filed in November 2007. The court held a hearing in March 2008, and issued an order November 3, 2008 denying Erica P. John Fund’s motion for class certification. Erica P. John Fund appealed the district court’s order to the Fifth Circuit Court of Appeals. The Fifth Circuit affirmed the district court’s order denying class certification. On May 13, 2010, Erica P. John Fund filed a writ of certiorari in the United States Supreme Court. In early January 2011, the Supreme Court granted Erica P. John Fund’s writ of certiorari and accepted the appeal. The Court heard oral arguments in April 2011 and issued its decision in June 2011, reversing the Fifth Circuit ruling that Erica P. John Fund needed to prove loss causation in order to obtain class certification. The Court’s ruling was limited to the Fifth Circuit’s loss causation requirement, and the case was returned to the Fifth Circuit for further consideration of Halliburton’s other arguments for denying class certification. As of June 30, 2011, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot be made.

Shareholder derivative cases

In May 2009, two shareholder derivative lawsuits involving us and KBR were filed in Harris County, Texas, naming as defendants various current and retired Halliburton directors and officers and current KBR directors. These cases allege that the individual Halliburton defendants violated their fiduciary duties of good faith and loyalty, to the detriment of Halliburton and its shareholders, by failing to properly exercise oversight responsibilities and establish adequate internal controls. The District Court consolidated the two cases, and the plaintiffs filed a consolidated petition against only current and former Halliburton directors and officers containing various allegations of wrongdoing including violations of the FCPA, claimed KBR offenses while acting as a government contractor in Iraq, claimed KBR offenses and fraud under United States government contracts, Halliburton activity in Iran, and illegal kickbacks. Subsequently, a shareholder made a demand that the board take remedial action respecting the FCPA claims in the pending lawsuit. Our Board of Directors designated a special committee of independent directors to oversee the investigation of the allegations made in the lawsuits and shareholder demand. Upon receipt of its special committee’s findings and recommendations, the Board determined that the shareholder claims were without merit and not otherwise in the best interest of the company to pursue. The Board directed company counsel to report its determinations to the plaintiffs and demanding shareholder. As of June 30, 2011, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot be made.

In February 2011, the same shareholder who had made the demand on our board of directors in connection with one of the derivative lawsuits discussed above filed a shareholder derivative lawsuit in Harris County, Texas naming us as a nominal defendant and certain of our directors and officers as defendants. This case alleges that these defendants, among other things, breached fiduciary duties of good faith and loyalty by failing to properly exercise oversight responsibilities and establish adequate internal controls, including controls and procedures related to cement testing and the communication of test results, as they relate to the Deepwater Horizon incident. Due to the preliminary status of the lawsuit and uncertainties related to litigation, we are unable to evaluate the likelihood of either a favorable or unfavorable outcome.

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; and
		-	the Toxic Substances Control Act.

In addition to the federal laws and regulations, states and other countries where we do business often have numerous environmental, legal, and regulatory requirements by which we must abide. We evaluate and address the environmental impact of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with environmental, legal, and regulatory requirements. Our Health, Safety and Environment group has several programs in place to maintain environmental leadership and to help prevent the occurrence of environmental contamination. On occasion, in addition to the matters relating to the Macondo well incident described above, we are involved in other environmental litigation and claims, including the remediation of properties we own or have operated, as well as efforts to meet or correct compliance-related matters. We do not expect costs related to those remediation requirements to have a material adverse effect on our consolidated financial position or our results of operations. Our accrued liabilities for those environmental matters were $46 million as of June 30, 2011 and $47 million as of December 31, 2010. Our total liability related to environmental matters covers numerous properties.

We have subsidiaries that have been named as potentially responsible parties along with other third parties for 10 federal and state superfund sites for which we have established reserves. As of June 30, 2011, those 10 sites accounted for approximately $7 million of our total $46 million reserve. For any particular federal or state superfund site, since our estimated liability is typically within a range and our accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in excess of the amount accrued. Despite attempts to resolve these superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount accrued. With respect to some superfund sites, we have been named a potentially responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims with respect to environmental matters for which we have been named as a potentially responsible party.

Guarantee arrangements

In the normal course of business, we have agreements with financial institutions under which approximately $1.5 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of June 30, 2011, including $240 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.

Note 8. Income per Share

Basic income per share is based on the weighted average number of common shares outstanding during the period. Diluted income per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect had been issued.

A reconciliation of the number of shares used for the basic and diluted income per share calculations is as follows:

	Three Months Ended				Six Months Ended
	June 30				June 30
Millions of shares	2011		2010		2011		2010
Basic weighted average common shares outstanding		916		906		915		906
Dilutive effect of stock options		5		3		5		2
Diluted weighted average common shares outstanding		921		909		920		908

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

Note 9. Fair Value of Financial Instruments

At June 30, 2011, we held $451 million of non-cash equivalents in United States Treasury securities with maturities that extend through February 2012. These securities are accounted for as available-for-sale and recorded at fair value, based on quoted market prices, in “Investments in marketable securities” on our condensed consolidated balance sheets. The carrying amount of cash and equivalents, investments in marketable securities, receivables, and accounts payable, as reflected in the condensed consolidated balance sheets, approximates fair value due to the short maturities of these instruments. We have no financial instruments measured at fair value using unobservable inputs.

The fair value of our long-term debt was $4.6 billion as of both June 30, 2011 and December 31, 2010, which differs from the carrying amount of $3.8 billion as of both June 30, 2011 and December 31, 2010, on our condensed consolidated balance sheets. The fair value of our long-term debt was calculated using either quoted market prices or significant observable inputs for similar liabilities for the respective periods.

We maintain an interest rate management strategy that is intended to mitigate the exposure to changes in interest rates in the aggregate for our investment portfolio. We utilize interest rate swaps to effectively convert a portion of our fixed rate debt to floating rates. The fair value of the swap agreements was not material at June 30, 2011. See Note 4 for further discussion of our interest rate swaps.

At June 30, 2011, we had fixed rate debt aggregating $2.8 billion and variable rate debt aggregating $1 billion, after taking into account the effects of the interest rate swaps.

Note 10. Accounting Standards Recently Adopted

On January 1, 2011, we adopted an update issued by the Financial Accounting Standards Board (FASB) to existing guidance on revenue recognition for arrangements with multiple deliverables. This update allows companies to allocate consideration for qualified separate deliverables using estimated selling price for both delivered and undelivered items when vendor-specific objective evidence or third-party evidence is unavailable. It also requires additional disclosures on the nature of multiple element arrangements, the types of deliverables under the arrangements, the general timing of their delivery, and significant factors and estimates used to determine estimated selling prices. The update is effective for fiscal years beginning after June 15, 2010. The adoption of this update did not have a material impact on our condensed consolidated financial statements or existing revenue recognition policies.

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

EXECUTIVE OVERVIEW

Organization

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

		-	our Completion and Production segment delivers cementing, stimulation, intervention, pressure control, and completion services. The segment consists of production enhancement services, completion tools and services, cementing services, and Boots & Coots; and
		-	our Drilling and Evaluation segment provides field and reservoir modeling, drilling, evaluation, and precise wellbore placement solutions that enable customers to model, measure, and optimize their well construction activities. The segment consists of fluid services, drilling services, drill bits, wireline and perforating services, testing and subsea, software and asset solutions, and integrated project management and consulting services.

The business operations of our segments are organized around four primary geographic regions: North America, Latin America, Europe/Africa/CIS, and Middle East/Asia. We have significant manufacturing operations in various locations, including, but not limited to, the United States, Canada, the United Kingdom, Malaysia, Mexico, Brazil, and Singapore. With over 60,000 employees, we operate in approximately 80 countries around the world, and our corporate headquarters are in Houston, Texas and Dubai, United Arab Emirates.

Financial results

During the first half of 2011, we produced revenue of $11.2 billion and operating income of $2.0 billion, reflecting an operating margin of 18%. Revenue increased $3.1 billion, or 38%, from the first half of 2010, while operating income increased $764 million, or 63%, from the first half of 2010. Overall, these increases were due to increased drilling activity and pricing improvements in North America. Partially offsetting the strong North America results were operational disruptions in North Africa.

Business outlook

In North America, the United States land rig count and horizontal drilling activity have continued to grow, led by a shift to oil and liquids-rich shale basins because of supportive commodity prices and attractive economics for our customers. We believe that natural gas drilling activity could be under pressure in the near-term until the oversupply situation is corrected; however, any reduction in natural gas drilling may be more than offset by an increase in liquids-directed activity. Our second quarter 2011 Gulf of Mexico business has improved somewhat due to the recent issuances of drilling permits by the Bureau of Ocean Energy Management, Regulation and Enforcement (BOE); however, unless the pace of further permitting improves, there is risk the recovery in the Gulf of Mexico could stall in the second half of 2011. See “Business Environment and Results of Operations,” Note 7 to the consolidated financial statements, Part II, Item 1. “Legal Proceedings,” and Part II, Item 1(a), “Risk Factors.” Despite uncertainty about natural gas fundamentals and the Gulf of Mexico recovery, we believe our current North America revenue and margins are likely sustainable through the remainder of 2011.

Outside of North America, second quarter of 2011 revenue increased from the prior year, while our operating income declined due to highly competitive service pricing in several markets. Our operations in Egypt are recovering from the turmoil experienced in the first quarter, while all customer activity in Libya has ceased due to the recently imposed United States and European sanctions against Libya. The geopolitical outlook in North Africa remains uncertain. Some of our customers have indicated, however, that they plan to increase their production capabilities in areas outside of North Africa and we expect that this, driven by improved oil price and demand fundamentals, will contribute to activity increases in the second half of the year. Despite the events that have transpired and the impact of lower service pricing negotiated during the worldwide recession, we expect that activity increases throughout the year will lead to margin improvement by the latter half of 2011 or the early part of 2012.

We are executing several key initiatives in 2011. These initiatives involve increasing manufacturing production in the Eastern Hemisphere and improving service delivery in North America. Costs related to these efforts, which are included under “Corporate and other” on our condensed consolidated statements of operations, impacted our results by approximately $0.01 per diluted share in each of the first two quarters of 2011. We expect that costs associated with these initiatives will impact third quarter 2011 results by approximately $0.02 per diluted share.

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

Financial markets, liquidity, and capital resources

Since mid-2008, the global financial markets have been somewhat volatile. While this has created additional risks for our business, we believe we have invested our cash balances conservatively and secured sufficient financing to help mitigate any near-term negative impact on our operations. For additional information, see “Liquidity and Capital Resources” and “Business Environment and Results of Operations.”

LIQUIDITY AND CAPITAL RESOURCES

We ended the second quarter of 2011 and December 31, 2010 with cash and equivalents of $1.4 billion. We also held $451 million of short-term, United States Treasury securities classified as marketable securities at June 30, 2011 compared to $653 million at December 31, 2010.

Significant sources of cash

Cash flows from operating activities contributed $1.4 billion to cash in the first six months of 2011.

During the first six months of 2011, we sold approximately $701 million of short-term marketable securities.

Further available sources of cash. On February 22, 2011, we entered into an unsecured $2.0 billion five-year revolving credit facility that replaced our then existing $1.2 billion unsecured credit facility established in July 2007. The purpose of the facility is to provide commercial paper support, general working capital, and credit for other corporate purposes.

Significant uses of cash

Capital expenditures were $1.4 billion in the first six months of 2011 and were predominantly made in the production enhancement, drilling services, cementing, and wireline and perforating product service lines. We have also invested additional working capital to support the growth of our business.

During the first six months of 2011, we purchased $501 million in short-term marketable securities.

We paid $165 million in dividends to our shareholders in the first six months of 2011.

Future uses of cash. Capital spending for 2011 is expected to be approximately $3.2 billion. The capital expenditures plan for 2011 is primarily directed toward our production enhancement, drilling services, wireline and perforating, cementing, and completion tools product service lines to support the expansion of our North America business.

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

Subject to Board of Directors approval, we expect to pay quarterly dividends of approximately $83 million during 2011. We also have approximately $1.7 billion remaining available under our share repurchase authorization, which may be used for open market share purchases.

Other factors affecting liquidity

Guarantee agreements. In the normal course of business, we have agreements with financial institutions under which approximately $1.5 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of June 30, 2011, including $240 million of surety bonds related to Venezuela. See “Business Environment and Results of Operations – International Operations” for further discussion related to Venezuela. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

Financial position in current market. We believe our $1.4 billion of cash and equivalents and $451 million in investments in marketable securities as of June 30, 2011 provide us with sufficient liquidity and flexibility, given the current market environment. Our debt maturities extend over a long period of time. We currently have a total of $2.0 billion of committed bank credit under our revolving credit facility to support our operations and any commercial paper we may issue in the future. The full amount of the revolving credit facility was available as of June 30, 2011. We have no financial covenants or material adverse change provisions in our bank agreements. Although a portion of earnings from our foreign subsidiaries is reinvested overseas indefinitely, we do not consider this to have a significant impact on our liquidity.

Credit ratings. Credit ratings for our long-term debt remain A2 with Moody’s Investors Service and A with Standard & Poor’s. The credit ratings on our short-term debt remain P-1 with Moody’s Investors Service and A-1 with Standard & Poor’s.

Customer receivables. In line with industry practice, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets. For example, we have seen a delay in receiving payment on our receivables from one of our primary customers in Venezuela. If our customers delay in paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We operate in approximately 80 countries throughout the world to provide a comprehensive range of discrete and integrated services and products to the energy industry. The majority of our consolidated revenue is derived from the sale of services and products to major, national, and independent oil and natural gas companies worldwide. We serve the upstream oil and natural gas industry throughout the lifecycle of the reservoir, from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production throughout the life of the field. Our two business segments are the Completion and Production segment and the Drilling and Evaluation segment. The industries we serve are highly competitive with many substantial competitors in each segment. In the first six months of 2011, based upon the location of the services provided and products sold, 54% of our consolidated revenue was from the United States. In the first six months of 2010, 44% of our consolidated revenue was from the United States. No other country accounted for more than 10% of our revenue during these periods.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, force majeure, war or other armed conflict, expropriation or other governmental actions, inflation, exchange control problems, and highly inflationary currencies. We believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country, other than the United States, would be materially adverse to our consolidated results of operations.

Activity levels within our business segments are significantly impacted by spending on upstream exploration, development, and production programs by major, national, and independent oil and natural gas companies. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption.

Some of the more significant barometers of current and future spending levels of oil and natural gas companies are oil and natural gas prices, the world economy, the availability of credit, government regulation, and global stability, which together drive worldwide drilling activity. Our financial performance is significantly affected by oil and natural gas prices and worldwide rig activity, which are summarized in the following tables.

This table shows the average oil and natural gas prices for West Texas Intermediate (WTI), United Kingdom Brent crude oil, and Henry Hub natural gas:

	Three Months Ended				Year Ended
	June 30				December 31
Average Oil Prices (dollars per barrel)	2011		2010		2010
West Texas Intermediate	$	102.61	$	77.79	$	79.36
United Kingdom Brent		117.78		78.51		79.66

Average United States Natural Gas Prices (dollars per
thousand cubic feet, or mcf)
Henry Hub	$	4.38	$	4.45	$	4.52

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

	Three Months Ended				Six Months Ended
	June 30				June 30
Land vs. Offshore	2011		2010		2011		2010
United States:
Land		1,798		1,467		1,744		1,384
Offshore (incl. Gulf of Mexico)		32		41		29		43
Total		1,830		1,508		1,773		1,427
Canada:
Land		187		164		386		315
Offshore		1		2		1		3
Total		188		166		387		318
International (excluding Canada):
Land		847		782		854		775
Offshore		299		306		302		300
Total		1,146		1,088		1,156		1,075
Worldwide total		3,164		2,762		3,316		2,820
Land total		2,832		2,413		2,984		2,474
Offshore total		332		349		332		346

	Three Months Ended				Six Months Ended
	June 30				June 30
Oil vs. Natural Gas	2011		2010		2011		2010
United States (incl. Gulf of Mexico):
Oil		946		544		879		501
Natural Gas		884		964		894		926
Total		1,830		1,508		1,773		1,427
Canada:
Oil		114		92		258		174
Natural Gas		74		74		129		144
Total		188		166		387		318
International (excluding Canada):
Oil		894		829		902		820
Natural Gas		252		259		254		255
Total		1,146		1,088		1,156		1,075
Worldwide total		3,164		2,762		3,316		2,820
Oil total		1,954		1,465		2,039		1,495
Natural Gas total		1,210		1,297		1,277		1,325

	Three Months Ended				Six Months Ended
	June 30				June 30
Drilling Type	2011		2010		2011		2010
United States (incl. Gulf of Mexico):
Horizontal		1,039		781		1,009		725
Vertical		561		495		538		477
Directional		230		232		226		225
Total		1,830		1,508		1,773		1,427

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

In comparison to the previous two years, crude oil prices were relatively stable for most of 2010. Toward the end of 2010 and through the first six months of 2011, however, oil prices have risen dramatically, primarily due to uncertainty regarding the geopolitical issues in North Africa and demand growth from developing countries like China. In response, natural gas drilling activity continues to be curtailed. According to the International Energy Agency’s (IEA) July 2011 “Oil Market Report,” despite lower than expected demand levels during the first half of the year, the 2012 world petroleum demand is forecasted to increase 2% over 2011 levels. Though the global oil supply rose in the second quarter of 2011, continued political instability may lead to the further escalation of oil prices and subsequently lower demand, which could delay the current economic recovery. Despite this and the heightened geopolitical uncertainties, we believe that, over the long-term, any major macroeconomic disruptions may ultimately correct themselves as the underlying trends of significant demand growth for developing countries, smaller and more complex reservoirs, high depletion rates, and the need for continual reserve replacement should drive the long-term need for our services.

North America operations

Volatility in oil and natural gas prices can impact our customers’ drilling and production activities. The shift in 2010 to oil and liquids-rich shale basins has helped to drive increased service intensity, not only in terms of horsepower required per job, but also in fluid chemistry and other technologies required for these complex reservoirs. This trend has continued through the first half of 2011, with horizontal oil-directed drilling activity representing the fastest growing segment of the market. While rig counts increased modestly from the end of 2010, as of June 30, 2011, horizontal-directed rig activity represented over 57% of the total rigs in the United States, about 66% higher than peak levels in 2008. These trends have led to increased demand and improved pricing for most of our products and services in our United States land operations. In the second quarter of 2011, North America revenue increased 16% and operating income increased 36% sequentially. Going forward, we believe there will be an increase in overall activity in United States land, and this is reinforcing our confidence that margins for North America will be sustainable; however, growing cost pressure could moderate the extent of any further margin improvements for the remainder of 2011.

Deepwater drilling activity in the Gulf of Mexico is continuing to recover due to the issuance of a number of drilling permits by the BOE. Despite some improvement in the second quarter, we believe risks remain for further growth in the Gulf of Mexico given the pace of permit issuance. Our business in the Gulf of Mexico represented approximately 16% of our North America revenue in the first half of 2009, approximately 12% in the first half of 2010, and approximately 6% in the first half of 2011. In addition, the Gulf of Mexico represented approximately 6% of our consolidated revenue in the first half of 2009, approximately 6% in the first half of 2010, and approximately 3% in the first half of 2011. Longer term, we do not know the extent the Macondo well incident or resulting drilling regulations will impact revenue or earnings, as they are dependent on, among other things, governmental approvals for permits, our customers’ actions, and the potential movement of deepwater rigs to or from other markets.

International operations

During the second quarter of 2011, revenue outside North America increased 8% and operating income outside of North America increased 55% from the prior quarter, reflecting typical seasonality. This seasonality more than offset activity disruptions caused by the political unrest and sanctions in North Africa and the continued impact of over capacity leading to pricing pressure. The first quarter of 2011 results were impacted by a $59 million, pre-tax, charge in Libya, to reserve for certain doubtful accounts receivable and inventory. Additionally, the second quarter of 2011 results were impacted by a $11 million, pre-tax, charge for employee separation costs, primarily related to our Europe/Africa/CIS regional operations.

The pace of international recovery is lagging that of previous cycles at this stage, despite international rig counts exceeding the prior peak reached in September of 2008. One of the contributory factors for the difference is the decline in offshore rig counts that we have seen with the current cycle. Given the service intensity of offshore work, we believe this resulted in a more extensive impact on the industry’s revenues, a more significant capacity overhang, and consequently, a more pronounced drop off in pricing. However, we are anticipating that the industry will experience steady volume increases through the remainder of the year as macroeconomic trends support a more favorable operator spending outlook, which we believe will eventually lead to meaningful absorption of equipment supply and result in the ability to begin to improve pricing for our services sometime in the second half of 2011. We continue to believe in the long-term prospects of the international market and will align our business accordingly. Consistent with our long-term strategy to grow our operations outside of North America, we also expect to continue to invest capital in our international operations.

Venezuela. In December 2010, the Venezuelan government set the fixed exchange rate at 4.3 Bolívar Fuerte to one United States dollar effective January 1, 2011, eliminating the dual exchange rate scheme implemented in early 2010. This change had no impact on us because we have applied the 4.3 Bolívar Fuerte fixed exchange rate since the previously disclosed January 2010 devaluation. We continue to work with our primary customer in Venezuela to resolve outstanding issues regarding the payment of invoices in relation to exchange rates and discounts.

On May 24, 2011, the United States government imposed sanctions on the state-owned oil company of Venezuela. The sanctions do not, however, apply to that company’s subsidiaries and do not prohibit the export of crude oil to the United States. We do not expect these sanctions to have a material impact on our operations in Venezuela.

As of June 30, 2011, our total net investment in Venezuela was approximately $208 million. In addition to this amount, we have $240 million of surety bond guarantees outstanding relating to our Venezuelan operations.

Initiatives and recent contract awards

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

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

Contract wins positioning us to grow our operations over the long term include:

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

RESULTS OF OPERATIONS IN 2011 COMPARED TO 2010

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

	Three Months Ended
REVENUE:	June 30				Increase		Percentage
Millions of dollars	2011		2010		(Decrease)		Change
Completion and Production	$	3,618	$	2,393	$	1,225		51%
Drilling and Evaluation		2,317		1,994		323		16
Total revenue	$	5,935	$	4,387	$	1,548		35%

By geographic region:
Completion and Production:
North America	$	2,588	$	1,434	$	1,154		80%
Latin America		268		212		56		26
Europe/Africa/CIS		415		459		(44	)	(10)
Middle East/Asia		347		288		59		20
Total		3,618		2,393		1,225		51
Drilling and Evaluation:
North America		857		677		180		27
Latin America		419		355		64		18
Europe/Africa/CIS		554		522		32		6
Middle East/Asia		487		440		47		11
Total		2,317		1,994		323		16
Total revenue by region:
North America		3,445		2,111		1,334		63
Latin America		687		567		120		21
Europe/Africa/CIS		969		981		(12	)	(1)
Middle East/Asia		834		728		106		15

	Three Months Ended
OPERATING INCOME:	June 30						Increase			Percentage
Millions of dollars	2011			2010			(Decrease)			Change
Completion and Production	$	918		$	497		$	421			85%
Drilling and Evaluation		324			318			6			2
Corporate and other		(81	)		(53	)		(28	)		53
Total operating income	$	1,161		$	762		$	399			52%

By geographic region:
Completion and Production:
North America	$	827	$	310	$	517		167%
Latin America		29		34		(5	)	(15)
Europe/Africa/CIS		15		95		(80	)	(84)
Middle East/Asia		47		58		(11	)	(19)
Total		918		497		421		85
Drilling and Evaluation:
North America		170		131		39		30
Latin America		52		55		(3	)	(5)
Europe/Africa/CIS		53		53		–		–
Middle East/Asia		49		79		(30	)	(38)
Total		324		318		6		2
Total operating income by region
(excluding Corporate and other):
North America		997		441		556		126
Latin America		81		89		(8	)	(9)
Europe/Africa/CIS		68		148		(80	)	(54)
Middle East/Asia		96		137		(41	)	(30)

The 35% increase in consolidated revenue in the second quarter of 2011 compared to the second quarter of 2010 was primarily attributable to increased activity in North America, as the unabated shift to unconventional oil and liquids-rich basins in United States land more than offset geopolitical issues in North Africa and the effects of the suspension of deepwater drilling activity in the Gulf of Mexico. On a consolidated basis, all product service lines experienced revenue growth from the second quarter of 2010. Revenue outside of North America was 42% of consolidated revenue in the second quarter of 2011 and 52% of consolidated revenue in the second quarter of 2010.

The 52% increase in consolidated operating income during the second quarter of 2011 compared to the second quarter of 2010 was attributable to capacity additions, Completion and Production’s higher utilization rates, and a more favorable pricing environment associated with the activity growth in the more service intensive, unconventional oil and liquids-rich basins in United States land. However, 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 51% and North America revenue increased 80% compared to the second quarter of 2010, led by production enhancement services as higher activity in unconventional basins generally resulted in increased demand for hydraulic fracturing. Latin America revenue increased 26% with higher demand for all product service lines. Europe/Africa/CIS revenue decreased 10%, primarily due to the impact from the geopolitical disruptions in North Africa and also lower completions activity in Sub-Saharan Africa. Middle East/Asia revenue increased 20%, largely due to higher completions activity across the region and an activity rebound in Australia. Revenue outside of North America was 28% of total segment revenue in the second quarter of 2011 and 40% of total segment revenue in the second quarter of 2010.

Completion and Production segment operating income increased 85% compared to the second quarter of 2010, driven by production enhancement services in United States land. The results were negatively impacted by $6 million, pre-tax, of employee separation costs, primarily in Europe/Africa/CIS. In North America, operating income grew 167%, due to higher activity, utilization rates, and a more favorable pricing environment for production enhancement services in United States land. Latin America operating income decreased 15%, as less favorable pricing in Mexico and higher costs across the region offset higher demand for cementing services in Colombia. Europe/Africa/CIS operating income declined 84% due to the effect of geopolitical disruptions in North Africa and lower completions activity. Middle East /Asia operating income decreased 19% on lower intervention activity across Asia Pacific.

Drilling and Evaluation revenue increased 16% compared to the second quarter of 2010, with all regions experiencing revenue growth from the prior year. North America revenue grew 27%, with higher activity and improved pricing in United States land. Latin America revenue increased 18% with higher activity seen across South America. Europe/Africa/CIS revenue increased 6%, primarily due to higher demand for drilling services in the North Sea and higher activity in Angola. Middle East/Asia revenue grew 11% due to increased demand for most product service lines across the region. Revenue outside of North America was 63% of total segment revenue in the second quarter of 2011 and 66% of total segment revenue in the second quarter of 2010.

Drilling and Evaluation operating income was relatively flat compared to the second quarter of 2010, as strong results in United States land offset highly competitive pricing in several Eastern Hemisphere markets. The results were negatively impacted by $5 million, pre-tax, of employee separation costs, primarily in Europe/Africa/CIS. North America operating income increased 30%, as higher activity in United States land offset declines in the Gulf of Mexico. Latin America operating income decreased 5%, as higher activity in Venezuela and Ecuador and strong fluids demand in Brazil was offset by higher costs in Mexico. Europe/Africa/CIS region operating income was flat, as the effects of the geopolitical disruptions in North Africa offset increased drilling activity in the North Sea and improved pricing conditions in Angola. Middle East/Asia operating income decreased 38%, primarily due to lower drilling activity in Saudi Arabia and project delays in Iraq.

Corporate and other expenses were $81 million in the second quarter of 2011 compared to $53 million in the second quarter of 2010. The increase was primarily due to $12 million of costs associated with strategic investments in our operating model and creating competitive advantage by repositioning our technology, supply chain, and manufacturing infrastructure.

NONOPERATING ITEMS

Interest expense, net of interest income decreased $13 million in the second quarter of 2011 compared to the second quarter of 2010, primarily due to less interest expense as a result of the retirement of $750 million principal amount of our 5.5% senior notes in October 2010.

RESULTS OF OPERATIONS IN 2011 COMPARED TO 2010

Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

	Six Months Ended
REVENUE:	June 30				Increase		Percentage
Millions of dollars	2011		2010		(Decrease)		Change
Completion and Production	$	6,790	$	4,357	$	2,433		56%
Drilling and Evaluation		4,427		3,791		636		17
Total revenue	$	11,217	$	8,148	$	3,069		38%

By geographic region:
Completion and Production:
North America	$	4,809	$	2,559	$	2,250		88%
Latin America		508		414		94		23
Europe/Africa/CIS		816		844		(28	)	(3)
Middle East/Asia		657		540		117		22
Total		6,790		4,357		2,433		56
Drilling and Evaluation:
North America		1,618		1,256		362		29
Latin America		791		648		143		22
Europe/Africa/CIS		1,064		1,057		7		1
Middle East/Asia		954		830		124		15
Total		4,427		3,791		636		17
Total revenue by region:
North America		6,427		3,815		2,612		68
Latin America		1,299		1,062		237		22
Europe/Africa/CIS		1,880		1,901		(21	)	(1)
Middle East/Asia		1,611		1,370		241		18

	Six Months Ended
OPERATING INCOME:	June 30						Increase			Percentage
Millions of dollars	2011			2010			(Decrease)			Change
Completion and Production	$	1,578		$	735		$	843			115%
Drilling and Evaluation		554			588			(34	)		(6)
Corporate and other		(157	)		(112	)		(45	)		40
Total operating income	$	1,975		$	1,211		$	764			63%

By geographic region:
Completion and Production:
North America	$	1,441		$	447	$	994		222%
Latin America		65			63		2		3
Europe/Africa/CIS		(11	)		134		(145	)	(108)
Middle East/Asia		83			91		(8	)	(9)
Total		1,578			735		843		115
Drilling and Evaluation:
North America		288			224		64		29
Latin America		92			72		20		28
Europe/Africa/CIS		75			144		(69	)	(48)
Middle East/Asia		99			148		(49	)	(33)
Total		554			588		(34	)	(6)
Total operating income by region
(excluding Corporate and other):
North America		1,729			671		1,058		158
Latin America		157			135		22		16
Europe/Africa/CIS		64			278		(214	)	(77)
Middle East/Asia		182			239		(57	)	(24)

The 38% increase in consolidated revenue in the first six months of 2011 compared to the first six months of 2010 was primarily due to higher drilling activity and increased demand for Completion and Production services in North America. Revenue outside North America was 43% of consolidated revenue in the first six months of 2011 and 53% of consolidated revenue in the first six months of 2010.

The 63% increase in consolidated operating income in the first six months of 2011 compared to the first six months of 2010 was primarily due to higher demand and a more favorable pricing environment for Completion and Production services in North America as operators continued the shift towards the more service intensive oil and liquids-rich basins. Operating income in the 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 56% driven by North America revenue growth of 88% compared to the first six months of 2010. The activity increase in North America was led by production enhancement services in United States land as higher activity in unconventional basins resulted in increased demand for hydraulic fracturing. Latin America revenue rose 23% on increased demand for cementing services across the region and higher activity across all product service lines in Argentina and Brazil. Europe/Africa/CIS revenue was down 3%, as the activity disruptions in North Africa and lower completions activity in Nigeria and Angola offset higher vessel utilization in the North Sea. Middle East/Asia revenue increased 22% with higher activity across all product service lines in Malaysia and Australia and increased demand for cementing services across most of the region. Revenue outside North America was 29% of total segment revenue in the first six months of 2011 and 41% of total segment revenue in the first six months of 2010.

Completion and Production operating income increased 115% compared to the first six months of 2010. This increase was driven by the North America region, where operating income grew $994 million on higher activity and more favorable pricing for production enhancement services in unconventional basins located in United States land. Latin America operating income increased 3%, as higher demand for cementing services in the region offset higher costs across most of the region. Europe/Africa/CIS operating income declined 108% primarily due to the activity disruptions in North Africa, including the reserve charge for certain account receivables and inventory recognized in the first quarter of 2011. Middle East/Asia operating income decreased 9% due to higher costs and a less favorable product mix across most of the region.

Drilling and Evaluation revenue increased 17% compared to the first six months of 2010 as drilling activity improved across all regions, most significantly in North America. North America revenue grew 29% on substantial activity increases in United States land. Latin America revenue rose 22% as a result of increased demand for most product service lines in Venezuela, Brazil and Colombia. Europe/Africa/CIS revenue was relatively flat, as higher drilling activity in the United Kingdom and Angola was offset by lower activity in Libya and Kazakhstan. Middle East/Asia revenue increased 15% due to the commencement of work in Iraq and higher drilling activity in Indonesia. Revenue outside North America was 63% of total segment revenue in the first six months of 2011 and 67% of total segment revenue in the first six months of 2010.

Drilling and Evaluation operating income decreased 6% compared to the first six months of 2010, as lower activity associated with the disruptions in North Africa and less favorable pricing in the Eastern Hemisphere offset activity increases in United States land. North America operating income grew 29% on higher drilling activity and more favorable pricing in United States land. Latin America operating income rose 28%, as activity increases in Venezuela and an improved product mix for fluid services in Brazil. Europe/Africa/CIS region operating income fell 48% primarily due to costs associated with activity disruptions in North Africa, including the reserve charge for certain account receivables and inventory recognized in the first quarter of 2011. Middle East/Asia operating income decreased 33% mainly due to lower activity and higher costs for drilling services in Oman and Malaysia and startup costs associated with the commencement of work in Iraq.

Corporate and other expenses were $157 million in the first six months of 2011 compared to $112 million in the first six months of 2010. The increase was 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 decreased $20 million in the first six months of 2011 compared to the first six months of 2010 primarily due to less interest expense as a result of the retirement of $750 million principal amount of our 5.5% senior notes in October 2010.

Other, net decreased $40 million in the first six months of 2011 compared to the first six months of 2010 primarily due to a $31 million loss on foreign exchange recognized in the first quarter of 2010 in connection with the devaluation of the Venezuelan Bolívar Fuerte.

ENVIRONMENTAL MATTERS

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

NEW ACCOUNTING PRONOUNCEMENTS

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

FORWARD-LOOKING INFORMATION

The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Forward-looking information is based on projections and estimates, not historical information. Some statements in this Form 10-Q are forward-looking and use words like “may,” “may not,” “believes,” “do not believe,” “expects,” “do not expect,” “anticipates,” “do not anticipate,” “should,” and other expressions. We may also provide oral or written forward-looking information in other materials we release to the public. Forward-looking information involves risk and uncertainties and reflects our best judgment based on current information. Our results of operations can be affected by inaccurate assumptions we make or by known or unknown risks and uncertainties. In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and the results of operations may vary materially.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from changes in foreign currency exchange rates and interest rates. We selectively manage these exposures through the use of derivative instruments. The objective of our risk management strategy is to minimize the volatility from fluctuations in foreign currency and interest rates. We do not use derivative instruments for trading purposes.

Foreign exchange risk

Techniques in managing foreign exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency derivative instruments. We selectively manage significant exposures to potential foreign exchange losses considering current market conditions, future operating activities, and the associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management activities is to protect us from the risk that the eventual dollar cash flows resulting from the sale and purchase of services and products in foreign currencies will be adversely affected by changes in exchange rates.

We manage our currency exposure through the use of currency derivative instruments as it relates to the major currencies, which are generally the currencies of the countries in which we do the majority of our international business. These instruments are not treated as hedges for accounting purposes and generally have an expiration date of one year or less. Forward exchange contracts, which are commitments to buy or sell a specified amount of a foreign currency at a specified price and time, are generally used to manage identifiable foreign currency commitments. Forward exchange contracts are generally used to manage exposures related to assets and liabilities denominated in a foreign currency. None of the forward contracts are exchange traded. The counterparties to our forward exchange contracts are global commercial banks. While derivative instruments are subject to fluctuations in value, the fluctuations are generally offset by the value of the underlying exposures being managed. The use of some contracts may limit our ability to benefit from favorable fluctuations in foreign exchange rates.

Foreign currency contracts are not utilized to manage exposures in some currencies due primarily to the lack of available markets or cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency commitments in non-traded currencies and recognize that pricing for the services and products offered in these countries should cover the cost of exchange rate devaluations. We have historically incurred transaction losses in non-traded currencies.

Notional amounts and fair market values. The notional amounts of open foreign exchange forward contracts were $374 million at June 30, 2011 and $356 million at December 31, 2010. The notional amounts of our foreign exchange contracts do not generally represent amounts exchanged by the parties and, thus, are not a measure of our exposure or of the cash requirements related to these contracts. As such, cash flows related to these instruments are typically not material. The amounts exchanged are calculated by reference to the notional amounts and by other terms of the derivatives, such as exchange rates. The estimated fair market value of our foreign exchange contracts was not material at either June 30, 2011 or December 31, 2010.

Interest rate risk

The following table represents principal amounts of our long-term debt, all of which are at fixed rates, at June 30, 2011 and December 31, 2010 and related weighted average interest rates on the repayment amounts by year of maturity.

			2017 and
Millions of dollars	2011		Thereafter			Total
Repayment amount	$	–	$	3,834		$	3,834
Weighted average
interest rate on
repayment amount		–		6.85	%		6.85	%

The fair market value of long-term debt was $4.6 billion as of June 30, 2011 and December 31, 2010.

During the second quarter of 2011, we entered into a series of interest rate swaps relating to two of our debt instruments. The impacts of these swaps are not reflected in the table above. We use interest rate swaps to manage the economic effect of fixed rate obligations associated with certain senior notes so that the interest payable on the senior notes effectively becomes linked to variable rates. The counterparties to our interest rate swaps are global commercial banks.

Notional amounts and fair market values. The first series of swaps were for a notional amount of $600 million in order to hedge a portion of the changes in the fair value of our 6.15% senior notes due 2019. Under the terms of these swaps, we will receive interest at a fixed rate of 6.15% and will pay interest at a floating rate of three-month LIBOR plus a spread semiannually. The second series of swaps were for a notional amount of $400 million in order to hedge changes in the fair value of our 5.9% senior notes due 2018. Under the terms of these swaps, we will receive interest at a fixed rate of 5.9% and will pay interest at a floating rate of three-month LIBOR plus a spread semiannually. These interest rate swaps, 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 the swap agreements was not material at June 30, 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, 2011 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the three months ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Gulf of Mexico/Macondo well incident

Barracuda-Caratinga arbitration

Securities and related litigation

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

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; and
		-	the Toxic Substances Control Act.

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. For any particular federal or state superfund site, since our estimated liability is typically within a range and our accrued liability may be the amount on the low end of that range, our actual liability could eventually be well in excess of the amount accrued. Despite attempts to resolve these superfund matters, the relevant regulatory agency may at any time bring suit against us for amounts in excess of the amount accrued. With respect to some superfund sites, we have been named a potentially responsible party by a regulatory agency; however, in each of those cases, we do not believe we have any material liability. We also could be subject to third-party claims with respect to environmental matters for which we have been named as a potentially responsible party.

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 2010 Annual Report on Form 10-K.

We, among others, have been named as a defendant in numerous lawsuits and are the subject of 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 BP Exploration & Production, Inc. (BP Exploration), the lease operator and indirect wholly owned subsidiary of BP p.l.c. (BP p.l.c., BP Exploration, and their affiliates, collectively, 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.

To date, we have been named along with other unaffiliated defendants in more than 400 complaints, most of which are alleged class-actions, involving pollution damage claims and at least 40 personal injury lawsuits involving seven decedents and at least 59 allegedly injured persons who were on the drilling rig at the time of the incident. Another six lawsuits naming us and others relate to alleged personal injuries sustained by those responding to the explosion and oil spill. 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 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 are investigating or plan to investigate the cause of the explosion, fire, and resulting oil spill. According to the January 11, 2011 report (Investigation Report) of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (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 states 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.

Our contract with BP Exploration relating to the Macondo well provides for our indemnification for claims and expenses relating to the Macondo well incident. 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. BP Exploration, in connection with filing its claims with respect to the MDL proceeding, sought to avoid their indemnity obligations and asked the 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.

Indemnification for criminal or civil fines or penalties, if any, may not be available if a court were to find such indemnification unenforceable as against public policy. In addition, we believe the law likely to be held applicable to matters relating to the Macondo well incident does not allow for enforcement of indemnification of persons who are found to be grossly negligent. Certain state laws, if deemed to apply, also 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. In addition, financial analysts and the press have speculated about the financial capacity of BP, and whether it might seek to avoid indemnification obligations in bankruptcy proceedings. BP’s public filings indicate that BP recognized a $40.9 billion pre-tax charge in 2010 and a $0.4 billion pre-tax charge in the first quarter of 2011 as a result of the Macondo well incident and that the amount of, among other things, any natural resource damages with respect to OPA claims by the United States and by state, tribal and foreign trustees, some of which may be included in such charges, cannot be reliably estimated as of the date of those filings. If BP Exploration filed for bankruptcy protection, a bankruptcy judge could disallow our contract with BP Exploration, including the indemnification obligations thereunder. Also, we may not be insured with respect to civil or criminal fines or penalties, if any, pursuant to the terms of our insurance policies.

As of June 30, 2011, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. We are currently unable to estimate the full impact the Macondo well incident will have on us. Further, an estimate of possible loss or range of loss related to this matter cannot be made. However, considering the complexity of the Macondo well and the number of investigations being conducted and lawsuits pending, new information or future developments may require us to adjust our liability assessment. If proceedings and investigations are not resolved in our favor, resulting liabilities, fines, or penalties, if any, for which we are not indemnified or are not insured could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Certain matters relating to the Macondo well incident, including increased regulation of the United States offshore drilling industry, and similar catastrophic events could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Results of the Macondo well incident and the subsequent oil spill have included offshore drilling delays and increased federal regulation of our and our customers’ operations, and more delays and regulations are expected. For example, the Investigation Report recommended, among other things, a review of and numerous changes to drilling and environmental regulations and the creation of new, independent agencies to oversee the various aspects of offshore drilling. The BOE has announced the creation of two new, independent agencies to replace the BOE effective October 2011 and has issued guidance and regulations for drillers that intend to resume deepwater drilling activity. The BOE’s regulations focus in part on increased safety and environmental issues, drilling equipment, and the requirement that operators submit drilling applications demonstrating regulatory compliance with respect to, among other things, required independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout. The BOE has also indicated that it believes it has broad legal authority over all activities relating to offshore leases and has expressed an interest in exercising regulatory authority over contractors, like us, in addition to operators.

Any increased regulation of the exploration and production industry as a whole that arises out of the Macondo well incident could result in higher operating costs for us and our customers, extended permitting and drilling delays, and reduced demand for our services. We cannot predict to what extent increased regulation may be adopted in international or other jurisdictions or whether we and our customers will be required or may elect to implement responsive policies and procedures in jurisdictions where they may not be required.

In addition, the Macondo well incident has negatively impacted and could continue to negatively impact the availability and cost of insurance coverage for our customers and their service providers. Also, our relationships with BP and others involved in the Macondo well incident could be negatively affected. Our business may be adversely impacted by any negative publicity relating to the incident, any negative perceptions about us by our customers, any increases in insurance premiums or difficulty in obtaining coverage, and the diversion of management’s attention from our operations to focus on matters relating to the incident.

As illustrated by the Macondo well incident, the services we provide for our customers are performed in challenging environments that can be dangerous. Catastrophic events such as a well blowout, fire or explosion can occur, resulting in property damage, personal injury, death, pollution, and environmental damage. While we are typically indemnified by our customers for these types of events and the resulting damages and injuries (except in some cases, claims by our employees, loss or damage to our property, and any pollution emanating directly from our equipment), we will be exposed to significant potential losses should such catastrophic events occur if adequate indemnification provisions or insurance arrangements are not in place, if existing indemnity provisions are determined by a court to be unenforceable, in whole or in part, or if our customers are unable or unwilling to satisfy their indemnity obligations.

The matters discussed above relating to the Macondo well incident and similar catastrophic events could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

Our operations are subject to political and economic instability and risk of government actions 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;
-	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 revenue and profits are subject to the adverse consequences of war, the effects of terrorism, civil unrest, strikes, currency controls, and governmental actions, including the recently imposed United States and European sanctions against Libya that have caused us to stop all customer activity in Libya. Countries where we operate that have significant political risk include, but are not limited to: Algeria, Azerbaijan, Colombia, Egypt, Indonesia, Iraq, Kazakhstan, Mexico, Nigeria, Russia, and Venezuela. Our facilities and our employees are under threat of attack in certain countries. In addition, military action or continued unrest in the Middle East and North Africa could impact the supply of and pricing for oil and natural gas, disrupt our operations in the region and elsewhere, and increase our costs for security worldwide.

The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, 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, a process that creates fractures extending from the well bore through the rock formation to enable natural gas or oil to move more easily through the rock pores to a production well. Bills have been introduced in Congress based on assertions that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require federal regulation of hydraulic fracturing operations and the reporting and public disclosure of chemicals used in the fracturing process. This legislation, 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 has been adopted in several states that requires additional disclosure regarding chemicals used in the fracturing process but that includes protections for proprietary information. Legislation is being considered in other states that could impose further chemical disclosure or other regulatory requirements 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. The adoption of any future federal, state, or foreign laws or implementing regulations imposing reporting obligations on, or otherwise limiting, 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.

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-month period ended June 30, 2011.

Maximum

Total Number

Number (or

of Shares

Approximate

Purchased as

Dollar Value) of

Total Number

Average

Part of Publicly

Shares that may yet

of Shares

Price Paid

Announced Plans

be Purchased

Period

Purchased (a)

per Share

or Programs

Under the Program (b)

April 1-30

109,567

50.03

–

May 1-31

434,613

46.89

–

June 1-30

67,418

48.07

–

Total

611,598

47.58

–

1,731,208,803

(a)

All of the 611,598 shares purchased during the three-month period ended June 30, 2011, 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 2011, we did not repurchase shares of our common stock. 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. Specialized 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 (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act). 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 (Dodd-Frank Act) and the recently proposed Item 106 of Regulation S-K (17 CFR 229.106) is included in Exhibit 99.1 to this quarterly report.

Item 5. Other Information

None.

Item 6. Exhibits

* 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.

* 99.1	Mine Safety Disclosure.

** 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

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 21, 2011