Edgar Filing: HALLIBURTON CO

edjune200910q_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, 2009

[ ] 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

5 Houston Center

1401 McKinney, Suite 2400

Houston, Texas 77010

(Address of Principal Executive Offices)

Telephone Number – Area Code (713) 759-2600

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes _____ No _____

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [X]

Non-accelerated filer [ ]

Accelerated filer [ ]

Smaller reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes No X

As of July 17, 2009, 901,714,840 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	18
	Results of Operations

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38

Item 4.	Controls and Procedures	38

PART II.	OTHER INFORMATION	39

Item 1.	Legal Proceedings	39

Item 1(a).	Risk Factors	39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 3.	Defaults Upon Senior Securities	39

Item 4.	Submission of Matters to a Vote of Security Holders	39

Item 5.	Other Information	41

Item 6.	Exhibits	42

Signatures		43

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	2009			2008			2009			2008
Revenue:
Services	$	2,542		$	3,292		$	5,492		$	6,256
Product sales		952			1,195			1,909			2,260
Total revenue		3,494			4,487			7,401			8,516
Operating costs and expenses:
Cost of services		2,164			2,480			4,575			4,753
Cost of sales		807			1,012			1,635			1,885
General and administrative		48			71			100			143
Gain on sale of assets, net		(1	)		(25	)		(1	)		(61	)
Total operating costs and expenses		3,018			3,538			6,309			6,720
Operating income		476			949			1,092			1,796
Interest expense		(82	)		(42	)		(135	)		(84	)
Interest income		3			9			5			29
Other, net		(14	)		(2	)		(19	)		(3	)
Income from continuing operations before income taxes
and noncontrolling interest		383			914			943			1,738
Provision for income taxes		(117	)		(288	)		(296	)		(526	)
Income from continuing operations		266			626			647			1,212
Loss from discontinued operations, net of income
tax benefit of $1, $1, $1, and $0		(1	)		(116	)		(2	)		(115	)
Net income	$	265		$	510		$	645		$	1,097
Noncontrolling interest in net income of subsidiaries		(3	)		(6	)		(5	)		(13	)
Net income attributable to company	$	262		$	504		$	640		$	1,084
Amounts attributable to company shareholders:
Income from continuing operations	$	263		$	620		$	642		$	1,199
Loss from discontinued operations, net		(1	)		(116	)		(2	)		(115	)
Net income attributable to company	$	262		$	504		$	640		$	1,084
Basic income per share attributable to company shareholders:
Income from continuing operations	$	0.29		$	0.71		$	0.71		$	1.37
Loss from discontinued operations, net		−			(0.13	)		−			(0.13	)
Net income per share	$	0.29		$	0.58		$	0.71		$	1.24
Diluted income per share attributable to company shareholders:
Income from continuing operations	$	0.29		$	0.68		$	0.71		$	1.31
Loss from discontinued operations, net		−			(0.13	)		−			(0.13	)
Net income per share	$	0.29		$	0.55		$	0.71		$	1.18

Cash dividends per share	$	0.09		$	0.09		$	0.18		$	0.18
Basic weighted average common shares outstanding		898			875			898			877
Diluted weighted average common shares outstanding		900			918			899			916

See notes to condensed consolidated financial statements.

HALLIBURTON COMPANY

Condensed Consolidated Balance Sheets

(Unaudited)

	June 30,			December 31,
Millions of dollars and shares except per share data	2009			2008
Assets
Current assets:
Cash and equivalents	$	1,568		$	1,124
Receivables (less allowance for bad debts of $76 and $60)		3,152			3,795
Inventories		1,832			1,828
Investments in marketable securities		753			–
Current deferred income taxes		179			246
Other current assets		524			418
Total current assets		8,008			7,411
Property, plant, and equipment, net of accumulated depreciation of $4,935 and $4,566		5,357			4,782
Goodwill		1,068			1,072
Investments in marketable securities		763			–
Other assets		1,019			1,120
Total assets	$	16,215		$	14,385
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	755		$	898
Accrued employee compensation and benefits		454			643
Deferred revenue		226			231
Department of Justice (DOJ) and Securities and Exchange Commission (SEC) settlement
and indemnity, current		190			373
Current maturities of long-term debt		27			26
Other current liabilities		568			610
Total current liabilities		2,220			2,781
Long-term debt		4,573			2,586
Employee compensation and benefits		521			539
Other liabilities		577			735
Total liabilities		7,891			6,641
Shareholders’ equity:
Common shares, par value $2.50 per share – authorized 2,000 shares, issued 1,067 shares		2,667			2,666
Paid-in capital in excess of par value		395			484
Accumulated other comprehensive loss		(198	)		(215	)
Retained earnings		10,521			10,041
Treasury stock, at cost – 167 and 172 shares		(5,084	)		(5,251	)
Company shareholders’ equity		8,301			7,725
Noncontrolling interest in consolidated subsidiaries		23			19
Total shareholders’ equity		8,324			7,744
Total liabilities and shareholders’ equity	$	16,215		$	14,385

See notes to condensed consolidated financial statements.

HALLIBURTON COMPANY

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	June 30
Millions of dollars	2009			2008
Cash flows from operating activities:
Net income	$	645		$	1,097
Adjustments to reconcile net income to net cash from operations:
Depreciation, depletion, and amortization		439			342
Payments of DOJ and SEC settlement and indemnity		(322	)		–
Provision for deferred income taxes, continuing operations		153			155
Other changes:
Receivables		639			(410	)
Accounts payable		(150	)		180
Inventories		(2	)		(277	)
Other		(384	)		(102	)
Total cash flows from operating activities		1,018			985
Cash flows from investing activities:
Sales (purchases) of investments in marketable securities		(1,518	)		388
Capital expenditures		(950	)		(837	)
Acquisitions of assets, net of cash acquired		(14	)		(150	)
Other investing activities		62			58
Total cash flows from investing activities		(2,420	)		(541	)
Cash flows from financing activities:
Proceeds from long-term borrowings, net of offering costs		1,975			–
Payments of dividends to shareholders		(162	)		(158	)
Payments to reacquire common stock		(11	)		(381	)
Other financing activities		58			124
Total cash flows from financing activities		1,860			(415	)
Effect of exchange rate changes on cash		(14	)		4
Increase in cash and equivalents		444			33
Cash and equivalents at beginning of period		1,124			1,847
Cash and equivalents at end of period	$	1,568		$	1,880
Supplemental disclosure of cash flow information:
Cash payments during the period for:
Interest from continuing operations	$	91		$	72
Income taxes from continuing operations	$	344		$	473

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 2008 Annual Report on Form 10-K.

Our accounting policies are in accordance with generally accepted accounting principles in the United States of America. 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, 2009, the results of our operations for the three and six months ended June 30, 2009 and 2008, and our cash flows for the six months ended June 30, 2009 and 2008. Such adjustments are of a normal recurring nature. The results of operations for the three and six months ended June 30, 2009 may not be indicative of results for the full year.

We have evaluated subsequent events through July 24, 2009, the date of issuance of the condensed consolidated financial statements.

In the first quarter of 2009, we reclassified certain services between our operating segments to re-establish a new service offering. In addition, during the first six months of 2009, we adopted the provisions of new accounting standards. See Notes 3, 8, and 11 for further information. All prior periods presented have been restated to reflect these changes.

Note 2. 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 and guarantees provided to KBR as described below. Since the separation, we have recorded adjustments to our liability for indemnities and guarantees to reflect changes to our estimation of our remaining obligation. All such adjustments are recorded in “Loss from discontinued operations, net of income tax.”

We entered into various agreements relating to the separation of KBR, including, among others, a master separation agreement, a registration rights agreement, a tax sharing agreement, transition services agreements, and an employee matters agreement. The master separation agreement provides for, among other things, KBR’s responsibility for liabilities related to its business and our responsibility for liabilities unrelated to KBR’s business. We provide indemnification in favor of KBR under the master separation agreement for certain contingent liabilities, including our indemnification of KBR and any of its greater than 50%-owned subsidiaries as of November 20, 2006, the date of the master separation agreement, for:

fines or other monetary penalties or direct monetary damages, including disgorgement, as a result of a claim made or assessed by a governmental authority in the United States, the United Kingdom, France, Nigeria, Switzerland, and/or Algeria, or a settlement thereof, related to alleged or actual violations occurring prior to November 20, 2006 of the United States Foreign Corrupt Practices Act (FCPA) or particular, analogous applicable foreign statutes, laws, rules, and regulations in connection with investigations pending as of that date, including with respect to the construction and subsequent expansion 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) of a natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria; and

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.

Additionally, we provide indemnities, performance guarantees, surety bond guarantees, and letter of credit guarantees that are currently in place in favor of KBR’s customers or lenders under project contracts, credit agreements, letters of credit, and other KBR credit instruments. These indemnities and guarantees will continue until they expire at the earlier of: (1) the termination of the underlying project contract or KBR obligations thereunder; (2) the expiration of the relevant credit support instrument in accordance with its terms or release of such instrument by the customer; or (3) the expiration of the credit agreements. Further, KBR and we have agreed that, until December 31, 2009, we will issue additional guarantees, indemnification, and reimbursement commitments for KBR’s benefit in connection with: (a) letters of credit necessary to comply with KBR’s Egypt Basic Industries Corporation ammonia plant contract, KBR’s Allenby & Connaught project, and all other KBR project contracts that were in place as of December 15, 2005; (b) surety bonds issued to support new task orders pursuant to the Allenby & Connaught project, two job order contracts for KBR’s Government and Infrastructure segment, and all other KBR project contracts that were in place as of December 15, 2005; and (c) performance guarantees in support of these contracts. KBR is compensating us for these guarantees. We have also provided a limited indemnity, with respect to FCPA and anti-trust governmental and third-party claims, to the lender parties under KBR’s revolving credit agreement expiring in December 2010. KBR has agreed to indemnify us, other than for the FCPA and Barracuda-Caratinga bolts matter, if we are required to perform under any of the indemnities or guarantees related to KBR’s revolving credit agreement, letters of credit, surety bonds, or performance guarantees described above.

In February 2009, the United States Department of Justice (DOJ) and Securities and Exchange Commission (SEC) FCPA investigations were resolved. The total of fines and disgorgement was $579 million, of which KBR consented to pay $20 million. As of June 30, 2009, we had paid $322 million, consisting of $145 million as a result of the DOJ settlement and the indemnity we provided to KBR upon separation and $177 million as a result of the SEC settlement. Our KBR indemnities and guarantees are primarily included in “Department of Justice (DOJ) and Securities and Exchange Commission (SEC) settlement and indemnity, current” and “Other liabilities” on the condensed consolidated balance sheets and totaled $309 million at June 30, 2009 and $631 million at December 31, 2008. Excluding the remaining amounts necessary to resolve the DOJ and SEC investigations and under the indemnity we provided to KBR, our estimation of the remaining obligation for other indemnities and guarantees provided to KBR upon separation was $72 million at June 30, 2009. See Note 7 for further discussion of the FCPA and Barracuda-Caratinga matters.

The tax sharing agreement provides for allocations of United States and certain other jurisdiction tax liabilities between us and KBR.

Note 3. 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. In the first quarter of 2009, we moved a portion of our completion tools and services from the Completion and Production segment to the Drilling and Evaluation segment to re-establish our testing and subsea services offering, which resulted in a change to our operating segments. Testing and subsea services provide acquisition and analysis of dynamic reservoir information and reservoir optimization solutions to the oil and gas industry utilizing downhole test tools, data acquisition services using telemetry and electronic memory recording, fluid sampling, surface well testing, subsea safety systems, and reservoir engineering services. All periods presented reflect reclassifications related to the change in operating segments.

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	2009			2008			2009			2008
Revenue:
Completion and Production	$	1,752		$	2,357		$	3,780		$	4,479
Drilling and Evaluation		1,742			2,130			3,621			4,037
Total revenue	$	3,494		$	4,487		$	7,401		$	8,516

Operating income:
Completion and Production	$	243		$	537		$	606		$	1,041
Drilling and Evaluation		284			504			588			913
Total operations		527			1,041			1,194			1,954
Corporate and other		(51	)		(92	)		(102	)		(158	)
Total operating income	$	476		$	949		$	1,092		$	1,796
Interest expense		(82	)		(42	)		(135	)		(84	)
Interest income		3			9			5			29
Other, net		(14	)		(2	)		(19	)		(3	)
Income from continuing operations before
income taxes and noncontrolling interest	$	383		$	914		$	943		$	1,738

Receivables

As of June 30, 2009, 24% of our gross trade receivables were from customers in the United States. As of December 31, 2008, 34% of our gross trade receivables were from customers in the United States.

Note 4. Inventories

Inventories are stated at the lower of cost or market. In the United States, we manufacture certain finished products and have parts inventories for drill bits, completion products, bulk materials, and other tools that are recorded using the last-in, first-out method totaling $79 million at June 30, 2009 and $92 million at December 31, 2008. If the average cost method was used, total inventories would have been $33 million higher than reported at June 30, 2009 and $31 million higher than reported at December 31, 2008. 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	2009		2008
Finished products and parts	$	1,227	$	1,312
Raw materials and supplies		568		446
Work in process		37		70
Total	$	1,832	$	1,828

Finished products and parts are reported net of obsolescence reserves of $95 million at June 30, 2009 and $81 million at December 31, 2008.

Note 5. Debt

Senior unsecured indebtedness

In the first quarter of 2009, we issued $1 billion aggregate principal amount of senior notes due September 2039 bearing interest at a fixed rate of 7.45% and $1 billion aggregate principal amount of senior notes due September 2019 bearing interest at a fixed rate of 6.15%. We may redeem some of the notes of each series from time to time or all of the notes of each series at any time at the redemption prices, plus accrued and unpaid interest. The notes are general, senior unsecured indebtedness and rank equally with all of our existing and future senior unsecured indebtedness.

Revolving credit facility

In March 2009, we terminated the $400 million unsecured, six-month revolving credit facility established in October 2008 to provide additional liquidity and for other general corporate purposes.

Note 6. 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, 2008	$	7,744		$	7,725		$	19
Transactions with shareholders		80			81			(1	)
Comprehensive income:
Net income		645			640			5
Other comprehensive income		17			17			–
Total comprehensive income		662			657			5
Dividends paid on common stock		(162	)		(162	)		–
Balance at June 30, 2009	$	8,324		$	8,301		$	23

							Noncontrolling
	Total			Company			interest in
	shareholders’			shareholders’			consolidated
Millions of dollars	equity			equity			subsidiaries
Balance at December 31, 2007	$	6,966		$	6,873		$	93
Share repurchases		(360	)		(360	)		–
Other transactions with shareholders		136			142			(6	)
Comprehensive income:
Net income		1,097			1,084			13
Other comprehensive income		4			4			–
Total comprehensive income		1,101			1,088			13
Dividends paid on common stock		(158	)		(158	)		–
Balance at June 30, 2008	$	7,685		$	7,585		$	100

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

	Three Months Ended
	June 30
Millions of dollars	2009		2008
Net income	$	265	$	510
Other comprehensive income		26		2
Total comprehensive income	$	291	$	512
Comprehensive income attributable to noncontrolling interest		3		6
Comprehensive income attributable to company		288		506

Accumulated other comprehensive loss consisted of the following:

	June 30,			December 31,
Millions of dollars	2009			2008
Defined benefit and other postretirement liability adjustments	$	(132	)	$	(151	)
Cumulative translation adjustments		(63	)		(60	)
Unrealized losses on investments		(3	)		(4	)
Total accumulated other comprehensive loss	$	(198	)	$	(215	)

Note 7. Commitments and Contingencies

Foreign Corrupt Practices Act investigations

Background. As a result of an ongoing FCPA investigation at the time of the KBR separation, we provided indemnification in favor of KBR under the master separation agreement for certain contingent liabilities, including our indemnification of KBR and any of its greater than 50%-owned subsidiaries as of November 20, 2006, the date of the master separation agreement, for fines or other monetary penalties or direct monetary damages, including disgorgement, as a result of a claim made or assessed by a governmental authority in the United States, the United Kingdom, France, Nigeria, Switzerland, and/or Algeria, or a settlement thereof, related to alleged or actual violations occurring prior to November 20, 2006 of the FCPA or particular, analogous applicable foreign statutes, laws, rules, and regulations in connection with investigations pending as of that date, including with respect to the construction and subsequent expansion by TSKJ of a multibillion dollar natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria.

TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip SA of France, Snamprogetti Netherlands B.V. (a subsidiary of Saipem SpA of Italy), JGC Corporation of Japan, and Kellogg Brown & Root LLC (a subsidiary of KBR), each of which had an approximate 25% interest in the venture. TSKJ and other similarly owned entities entered into various contracts to build and expand the liquefied natural gas project for Nigeria LNG Limited, which is owned by the Nigerian National Petroleum Corporation, Shell Gas B.V., Cleag Limited (an affiliate of Total), and Agip International B.V. (an affiliate of ENI SpA of Italy).

DOJ and SEC investigations resolved. In February 2009, the FCPA investigations by the DOJ and the SEC were resolved with respect to KBR and us. The DOJ and SEC investigations resulted from allegations of improper payments to government officials in Nigeria in connection with the construction and subsequent expansion by TSKJ of the Bonny Island project.

The DOJ investigation was resolved with respect to us with a non-prosecution agreement in which the DOJ agreed not to bring FCPA or bid coordination-related charges against us with respect to the matters under investigation, and in which we agreed to continue to cooperate with the DOJ’s ongoing investigation and to refrain from and self-report certain FCPA violations. The DOJ agreement does not provide a monitor for us.

As part of the resolution of the SEC investigation, we retained an independent consultant to conduct a 60-day review and evaluation of our internal controls and record-keeping policies as they relate to the FCPA, and we agreed to adopt any necessary anti-bribery and foreign agent internal controls and record-keeping procedures recommended by or agreed upon with the independent consultant. The review and evaluation were completed during the second quarter of 2009, and we have implemented the consultant’s immediate recommendations and will implement the remaining long-term recommendations over the next year. As a result of the substantial enhancement of our anti-bribery and foreign agent internal controls and record-keeping procedures prior to the review of the independent consultant, we do not expect the implementation of the consultant’s recommendations to materially impact our long-term strategy to grow our international operations. In 2010, the independent consultant will perform a 30-day, follow-up review to confirm that we have implemented the recommendations and continued the application of our current policies and procedures, and to recommend any additional improvements.

KBR has agreed that our indemnification obligations with respect to the DOJ and SEC FCPA investigations have been fully satisfied.

Other matters. In addition to the DOJ and the SEC investigations, we are aware of other investigations in France, Nigeria, the United Kingdom, and Switzerland regarding the Bonny Island project.

The settlements and the other ongoing investigations could result in third-party claims against us, which may include claims for special, indirect, derivative or consequential damages, damage to our business or reputation, loss of, or adverse effect on, cash flow, assets, goodwill, results of operations, business prospects, profits or business value or claims by directors, officers, employees, affiliates, advisors, attorneys, agents, debt holders, or other interest holders or constituents of us or our current or former subsidiaries.

Our indemnity of KBR continues with respect to other investigations within the scope of our indemnity. Our indemnification obligation to KBR does not include losses resulting from third-party claims against KBR, including claims for special, indirect, derivative or consequential damages, nor does our indemnification apply to damage to KBR’s business or reputation, loss of, or adverse effect on, cash flow, assets, goodwill, results of operations, business prospects, profits or business value or claims by directors, officers, employees, affiliates, advisors, attorneys, agents, debt holders, or other interest holders or constituents of KBR or KBR’s current or former subsidiaries.

At this time, no claims by governmental authorities in foreign jurisdictions have been asserted against KBR. Therefore, we are unable to estimate the maximum potential amount of future payments that could be required to be made under our indemnity to KBR related to these matters. See Note 2 for additional information.

Barracuda-Caratinga arbitration

We also 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. Estimates indicate that costs of these various solutions range 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. We understand KBR is vigorously defending and pursuing recovery of the costs incurred to date through the arbitration process and to that end has submitted a counterclaim in the arbitration seeking the recovery of $22 million. 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 and the arbitration panel are now in discussion regarding the future course of the arbitration proceedings with respect to the issues of liability and damages. 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, 2009 and December 31, 2008. See Note 2 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. 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 AMSF 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 AMSF to re-plead some of those claims to correct deficiencies in its earlier complaint. In April 2006, AMSF 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, AMSF 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 AMSF’s motion for class certification. AMSF then filed a motion with the Fifth Circuit Court of Appeals requesting permission to appeal the district court’s order denying class certification. The Fifth Circuit granted AMSF’s motion and the order denying class certification is currently on appeal. The case will remain stayed in the district court pending the outcome of the appeal. As of June 30, 2009, 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 petitions contain various allegations of resulting wrongdoing, including violations of the FCPA and claimed KBR offenses under United States government contracts. As of June 30, 2009, 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.

Asbestos insurance settlements

At December 31, 2004, we resolved all open and future asbestos- and silica-related claims in the prepackaged Chapter 11 proceedings of DII Industries LLC, Kellogg Brown & Root LLC, and our other affected subsidiaries that had previously been named as defendants in a large number of asbestos- and silica-related lawsuits. During 2004, we settled insurance disputes with substantially all the insurance companies for asbestos- and silica-related claims and all other claims under the applicable insurance policies and terminated all the applicable insurance policies.

Under the insurance settlements entered into as part of the resolution of our Chapter 11 proceedings, we have agreed to indemnify our insurers under certain historic general liability insurance policies in certain situations. We have concluded that the likelihood of any claims triggering the indemnity obligations is remote, and we believe any potential liability for these indemnifications will be immaterial. Further, an estimate of possible loss or range of loss related to this matter cannot be made. At June 30, 2009, we had not recorded any liability associated with these indemnifications.

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. On occasion, we are involved in specific 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. Our Health, Safety and Environment group has several programs in place to maintain environmental leadership and to prevent the occurrence of environmental contamination.

We do not expect costs related to these remediation requirements to have a material adverse effect on our consolidated financial position or our results of operations. Our accrued liabilities for environmental matters were $53 million as of June 30, 2009 and $64 million as of December 31, 2008. 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 9 federal and state superfund sites for which we have established a liability. As of June 30, 2009, those 9 sites accounted for approximately $14 million of our total $53 million liability. 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.

Letters of credit

In the normal course of business, we have agreements with banks under which approximately $2 billion of letters of credit, surety bonds, or bank guarantees were outstanding as of June 30, 2009, including approximately $400 million of surety bonds related to Venezuela. In addition, $627 million of the total $2 billion relates to KBR letters of credit, surety bonds, or bank guarantees that are being guaranteed by us in favor of KBR’s customers and lenders. KBR has agreed to compensate us for these guarantees and indemnify us if we are required to perform under any of these guarantees. 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.

On January 1, 2009, we adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. According to the provisions of FSP EITF 03-6-1, we restated prior periods’ basic and diluted earnings per share to include such outstanding unvested restricted shares of our common stock in the basic weighted average shares outstanding calculation. Upon adoption, both basic and diluted income per share for the first six months of 2008 and full year 2008 decreased by $0.01 for continuing operations and net income attributable to company shareholders.

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	2009		2008		2009		2008
Basic weighted average common shares outstanding		898		875		898		877
Dilutive effect of:
Convertible senior notes premium		–		38		–		34
Stock options		2		5		1		5
Diluted weighted average common shares outstanding		900		918		899		916

Excluded from the computation of diluted income per share are options to purchase eight million and nine million shares of common stock that were outstanding during the three and six months ended June 30, 2009 and one million shares during both the three and six months ended June 30, 2008. 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

During the second quarter of 2009, we purchased $1.5 billion in United States Treasury securities with maturities that extend through September 2010. These securities are accounted for as available-for-sale and recorded at fair value and classified by maturity date in “Investments in marketable securities” on the condensed consolidated balance sheet at June 30, 2009.

The fair value of $399 million and $412 million of our long-term debt at June 30, 2009 and December 31, 2008 was calculated based on the fair value of other actively-traded, Halliburton debt. The carrying amount of cash and equivalents, receivables, short-term notes payable, and accounts payable, as reflected in the condensed consolidated balance sheets, approximates fair market value due to the short maturities of these instruments. The following table presents the fair values of our other financial assets and liabilities and the basis for determining their fair values:

					Quoted prices
					in active		Significant
					markets for		observable inputs
	Carrying				identical assets		for similar assets or
Millions of dollars	Value		Fair value		or liabilities		liabilities
June 30, 2009
Marketable securities	$	1,516	$	1,516	$	1,516	$	–
Long-term debt		4,600		5,044		4,645		399
December 31, 2008
Long-term debt	$	2,612	$	2,826	$	2,414	$	412

Note 10. Retirement Plans

The components of net periodic benefit cost related to pension benefits for the three and six months ended June 30, 2009 and June 30, 2008 were as follows:

	Three Months Ended June 30
	2009		2008
Millions of dollars	United States	International	United States	International
Service cost	$ –	$ 7	$ –	$ 6
Interest cost	1	11	1	13
Expected return on plan assets	(2)	(9)	(2)	(12)
Settlements/curtailments	1	1	–	–
Recognized actuarial loss	1	1	1	2
Net periodic benefit cost	$ 1	$ 11	$ –	$ 9

	Six Months Ended June 30
	2009		2008
Millions of dollars	United States	International	United States	International
Service cost	$ –	$ 13	$ –	$ 13
Interest cost	3	21	3	26
Expected return on plan assets	(4)	(17)	(4)	(23)
Settlements/curtailments	1	1	–	–
Recognized actuarial loss	1	2	2	3
Net periodic benefit cost	$ 1	$ 20	$ 1	$ 19

During the six months ended June 30, 2009, we contributed $9 million to our international pension plans. We currently expect to contribute an additional $82 million to our international pension plans in 2009, of which $66 million represents discretionary contributions to our United Kingdom pension plan made in July 2009. We expect to make discretionary contributions of approximately $11 million to our United States pension plans in 2009.

Effective June 30, 2009, we amended our United Kingdom pension plan to cease benefit accruals related to service thereafter, resulting in a $32 million decrease in the projected benefit obligation and a $24 million decrease, net of tax, in other comprehensive loss.

Note 11. New Accounting Standards

In May 2009, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 165 “Subsequent Events,” which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events. SFAS No. 165 is effective for interim and annual reporting periods ending after June 15, 2009. We adopted the new disclosure requirements in our June 30, 2009 condensed consolidated financial statements.

On June 30, 2009, we adopted FSP SFAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP, which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” requires publicly-traded companies, as defined in APB Opinion No. 28, “Interim Financial Reporting,” to provide disclosures on the fair value of financial instruments in interim financial statements.

On January 1, 2009, we adopted the provisions of SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51.” SFAS No. 160 establishes new accounting, reporting, and disclosure standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement requires the recognition of a noncontrolling interest as equity in the condensed consolidated financial statements and separate from the parent’s equity. Noncontrolling interest has been presented as a separate component of shareholders’ equity for the current reporting period and prior comparative period in our condensed consolidated financial statements.

On January 1, 2009, we adopted the provisions of SFAS No. 141 (Revised 2007), “Business Combinations” (SFAS No. 141(R)), which retains the underlying concepts of SFAS No. 141 in that all business combinations are still required to be accounted for at fair value under the acquisition method of accounting, but changes the method of applying the acquisition method in a number of ways. Acquisition costs are no longer considered part of the fair value of an acquisition and will generally be expensed as incurred, noncontrolling interests are valued at fair value at the acquisition date, in-process research and development is recorded at fair value as an indefinite-lived intangible asset at the acquisition date, restructuring costs associated with a business combination are generally expensed subsequent to the acquisition date, and changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally will affect income tax expense. In April 2009, the FASB issued FSP SFAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” which amends the guidance in SFAS No. 141(R) to require contingent assets acquired and liabilities assumed in a business combination to be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the measurement period. If fair value cannot be reasonably estimated during the measurement period, the contingent asset or liability would be recognized in accordance with SFAS No. 5, “Accounting for Contingencies,” and FASB Interpretation (FIN) No. 14, “Reasonable Estimation of the Amount of a Loss.” Further, this FSP eliminated the specific subsequent accounting guidance for contingent assets and liabilities from Statement 141(R), without significantly revising the guidance in SFAS No. 141. However, contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination would still be initially and subsequently measured at fair value in accordance with SFAS No. 141(R). This FSP is effective for all business acquisitions occurring on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the provisions of SFAS No. 141(R) and FSP SFAS 141(R)-1 for business combinations with an acquisition date on or after January 1, 2009.

On January 1, 2009, we adopted FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).” This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Upon adopting the provisions of FSP APB 14-1, we retroactively applied its provisions and restated our condensed consolidated financial statements for prior periods.

In applying this FSP, $63 million of the carrying value of our 3.125% convertible senior notes due July 2023 was reclassified to equity as of the July 2003 issuance date. This amount represents the equity component of the proceeds from the notes, calculated assuming a 4.3% non-convertible borrowing rate. The discount was accreted to interest expense over the five-year term of the notes. Accordingly, $14 million of additional non-cash interest expense, or $0.01 per diluted share, was recorded in 2006 and 2007 and $7 million of additional non-cash interest expense was recorded in 2008, all during the first six months of the year. Furthermore, under this FSP, the $693 million loss to settle our convertible debt recorded in the third quarter of 2008 was reversed and recorded to additional paid-in capital. This resulted in a decrease of $7 million to income from continuing operations and net income attributable to company in the first six months of 2008, an increase of $686 million to income from continuing operations and net income attributable to company in 2008, and a net increase of $630 million to beginning retained earnings as of January 1, 2009. Diluted income per share for 2008 increased by $0.76 as a result of the adoption of FSP APB 14-1. These notes were converted and settled during the third quarter of 2008.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. In February 2008, the FASB issued FSP SFAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP SFAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active. On January 1, 2008, we adopted without material impact on our condensed consolidated financial statements the provisions of SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. On January 1, 2009, we adopted without material impact on our condensed consolidated financial statements the provisions of SFAS No. 157 related to nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in goodwill impairment testing, indefinite-lived intangible assets measured at fair value for impairment assessment, nonfinancial long-lived assets measured at fair value for impairment assessment, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination.

In April 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly. The scope of this FSP does not include assets and liabilities measured under level 1 inputs. We adopted FSP SFAS 157-4 on June 30, 2009 and will apply it prospectively to all fair value measurements where appropriate.

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R) Consolidation of Variable Interest Entities.” This statement clarifies the characteristics that identify a variable interest entity (VIE) and changes how a reporting entity identifies a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards calculation to a qualitative approach based on which variable interest holder has controlling financial interest and the ability to direct the most significant activities that impact the VIE’s economic performance. This statement requires the primary beneficiary assessment to be performed on a continuous basis. It also requires additional disclosures about an entity’s involvement with VIE, restrictions on the VIE’s assets and liabilities that are included in the reporting entity’s consolidated balance sheet, significant risk exposures due to the entity’s involvement with the VIE, and how its involvement with a VIE impacts the reporting entity’s consolidated financial statements. SFAS No.167 is effective for fiscal years beginning after November 15, 2009. We will adopt SFAS No. 167 on January 1, 2010 and have not yet determined the impact on our condensed consolidated financial statements.

In December 2008, the FASB issued FSP SFAS 132(R)-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP amends the disclosure requirements for employer’s disclosure of plan assets for defined benefit pensions and other postretirement plans. The objective of this FSP is to provide users of financial statements with an understanding of how investment allocation decisions are made, the major categories of plan assets held by the plans, the inputs and valuation techniques used to measure the fair value of plan assets, significant concentration of risk within the company’s plan assets, and for fair value measurements determined using significant unobservable inputs a reconciliation of changes between the beginning and ending balances. FSP SFAS 132(R)-1 is effective for fiscal years ending after December 15, 2009. We will adopt the new disclosure requirements in the 2009 annual reporting period.

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 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, and completion services. The segment consists of production enhancement services, completion tools and services, and cementing services; 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 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, Continental Europe, Malaysia, Mexico, Brazil, and Singapore. With approximately 52,000 employees, we operate in approximately 70 countries around the world, and our corporate headquarters are in Houston, Texas and Dubai, United Arab Emirates.

Financial results

During the first half of 2009, we produced revenue of $7.4 billion and operating income of $1.1 billion, reflecting an operating margin of 15%. Revenue decreased $1.1 billion or 13% from the first half of 2008, while operating income decreased $704 million or 39% from the first half of 2008. These decreases were caused by a decline in our customers’ capital spending as a result of the global recession and its impact on commodity prices, which resulted in severe margin contraction.

Business outlook

We continue to believe in the strength of the long-term fundamentals of our business. However, due to the financial crisis that developed in mid-2008, the ensuing negative impact on credit availability, and the current excess supply of oil and natural gas, the near- and mid-term outlook for our business and the industry remains uncertain. Forecasting the depth and length of the current cycle is challenging as it is different from past cycles due to the overlay of the financial crisis in combination with broad demand weakness.

In North America, the industry experienced an unprecedented decline in drilling activity during the first half of 2009. United States rig counts have continued to fall and as of July 17, 2009 are approximately 55% below 2008 highs. Working natural gas storage continues to be ahead of its normal seasonal patterns, which suggests that despite reduced drilling activity, the supply curtailment in gas production has not yet caught up with lower demand levels. Further, the expectation that gas storage will potentially reach record levels by the end of the injection period indicates that any recovery in gas drilling activity is likely to be relatively modest for the remainder of 2009. We have also seen pricing erosion and severe margin contraction in all of our service offerings in North America, and we believe that pricing for our services will remain under pressure until drilling activity stabilizes.

Outside of North America, rig count has declined approximately 13% from 2008 highs, and there is still a risk of a further decline in activity. Although we are seeing some projects move forward and have recently won a number of contract awards, we still continue to see certain markets exhibit weakness in activity. The depth of the decline in international markets is unknown, and operators have maintained their focus on lowering project costs. Given the continued pricing negotiations, we expect to see margin compression over the remainder of 2009 and throughout 2010.

In 2009, we are focusing on:

	-	leveraging our technologies to deploy our packaged-services strategy to provide our customers with the ability to more efficiently drill and complete their wells, especially in service-intensive environments such as deepwater and shale plays;
	-	retaining key investments in technology and capital to accelerate growth opportunities;
	-	increasing our market share in unconventional markets by enhancing our technological position and leveraging our technical expertise and wide portfolio of products and services;
	-	lowering our input costs from vendors by negotiating price reductions for both materials used in our operations and those utilized in the manufacturing of capital equipment;
	-	negotiating with our customers to trade an expansion of scope and a lengthening of contract duration for price concessions;
	-	reducing headcount in locations experiencing significant activity declines;
	-	improving working capital, operating within our cash flow, and managing our balance sheet to maximize our financial flexibility;
	-	continuing the globalization of our manufacturing and supply chain processes, preserving work at our lower-cost manufacturing centers, and utilizing our international infrastructure to lower costs from our supply chain through delivery;
	-	expanding our business with national oil companies; and
	-	minimizing discretionary spending.

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

Financial markets, liquidity, and capital resources

In 2009, the equity, credit, and commodity markets continue to be 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- and mid-term negative impact on our operations. To provide additional liquidity and flexibility in the current environment, we issued $2 billion in senior notes during the first quarter of 2009 and invested $1.5 billion in United States Treasury securities during the second quarter of 2009. For additional information, see “Liquidity and Capital Resources,” “Risk Factors,” “Business Environment and Results of Operations,” and Notes 5 and 9 to the condensed consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES

We ended the second quarter of 2009 with cash and equivalents of $1.6 billion compared to $1.1 billion at December 31, 2008.

Significant sources of cash

Cash flows from operating activities contributed $1 billion to cash in the first six months of 2009.

In March 2009, we issued senior notes due 2039 totaling $1 billion and senior notes due 2019 totaling $1 billion. We intend to use the net proceeds of this offering for general corporate purposes.

We received payment of $79 million for our asbestos-related insurance settlements in July 2009.

Further available sources of cash. We have an unsecured $1.2 billion, five-year revolving credit facility to provide commercial paper support, general working capital, and credit for other corporate purposes. There were no cash drawings under the facility as of June 30, 2009. In addition, we have $1.5 billion in United States Treasury securities that will be maturing at various dates through September 2010.

Significant uses of cash

Capital expenditures were $950 million in the first six months of 2009 and were predominantly made in the drilling services, production enhancement, wireline and perforating, and cementing product service lines.

We purchased $1.5 billion in United States Treasury securities with both short- and long-term maturity dates during the second quarter of 2009.

We paid $322 million to the Department of Justice (DOJ) and Securities and Exchange Commission (SEC) in the first six months of 2009 related to the settlements with them and under the indemnity provided to KBR, Inc. (KBR) upon separation.

We paid $162 million in dividends to our shareholders in the first six months of 2009.

We contributed an additional $66 million to an international pension plan in July 2009.

Future uses of cash. We have approximately $1.8 billion remaining available under our share repurchase authorization, which may be used for open market share purchases.

In 2009, we believe we will maintain our capital expenditures up to 2008 levels of $1.8 billion but will monitor our customers’ activity and make reductions as necessary. The capital expenditures plan for 2009 is primarily directed toward our drilling services, production enhancement, wireline and perforating, and cementing product service lines and toward retiring old equipment to replace it with new equipment to improve our fleet reliability and efficiency. 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.

As a result of the resolution of the DOJ and SEC Foreign Corrupt Practices Act (FCPA) investigations, we will pay a total of $237 million in equal installments over the next five quarters for the settlement with the DOJ and under the indemnity provided to KBR upon separation. See Notes 2 and 7 to our condensed consolidated financial statements for more information.

Subject to Board of Directors approval, we expect to pay dividends of approximately $80 million per quarter for the remainder of 2009.

Other factors affecting liquidity

Letters of credit. In the normal course of business, we have agreements with banks under which approximately $2 billion of letters of credit, surety bonds, or bank guarantees were outstanding as of June 30, 2009, including approximately $400 million of surety bonds related to Venezuela. In addition, $627 million of the total $2 billion relates to KBR letters of credit, surety bonds, or bank guarantees that are being guaranteed by us in favor of KBR’s customers and lenders. KBR has agreed to compensate us for these guarantees and indemnify us if we are required to perform under any of these guarantees. Some of the outstanding letters of credit have triggering events that would entitle a bank to require cash collateralization.

Financial position in current market. Our recent $2 billion long-term debt offering provides 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 $1.2 billion of committed bank credit under our revolving credit facility to support our operations and any commercial paper we may issue in the future. We have no financial covenants or material adverse change provisions in our bank agreements. Currently, there are no borrowings under the revolving credit facility.

In addition, we manage our cash investments by investing principally in United States Treasury securities and repurchase agreements collateralized by United States Treasury securities.

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 due to, among other reasons, a reduction in our customer’s cash flow from operations and their access to the credit markets. For example, we have seen an increased delay in receiving payment on our receivables from one of our primary customers in Venezuela. Recently, this customer requested a discount on the receivables. No agreement has been reached. 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 70 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 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 2009, based upon the location of the services provided and products sold, 37% of our consolidated revenue was from the United States. In the first six months of 2008, 42% 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 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 gas companies. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption. See “Risk Factors—Worldwide recession and effect on exploration and production activity” for further information related to the effect of the current recession.

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, 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)	2009		2008		2008
West Texas Intermediate	$	59.44	$	123.42	$	99.57
United Kingdom Brent		58.70		120.90		96.85

Average United States Gas Prices (dollars per thousand cubic
feet, or mcf)
Henry Hub	$	3.83	$	11.73	$	9.13

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	2009		2008		2009		2008
United States:
Land		886		1,799		1,078		1,755
Offshore		50		66		53		63
Total		936		1,865		1,131		1,818
Canada:
Land		90		168		209		337
Offshore		1		1		1		1
Total		91		169		210		338
International (excluding Canada):
Land		711		776		727		769
Offshore		271		308		277		296
Total		982		1,084		1,004		1,065
Worldwide total		2,009		3,118		2,345		3,221
Land total		1,687		2,743		2,014		2,861
Offshore total		322		375		331		360

	Three Months Ended				Six Months Ended
	June 30				June 30
Oil vs. Natural Gas	2009		2008		2009		2008
United States:
Oil		201		373		242		352
Natural Gas		735		1,492		889		1,466
Total		936		1,865		1,131		1,818
Canada:
Oil		40		81		82		147
Natural Gas		51		88		128		191
Total		91		169		210		338
International (excluding Canada):
Oil		757		842		783		822
Natural Gas		225		242		221		243
Total		982		1,084		1,004		1,065
Worldwide total		2,009		3,118		2,345		3,221
Oil total		998		1,296		1,107		1,321
Natural Gas total		1,011		1,822		1,238		1,900

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.

WTI oil spot prices have fallen from an average of $100 per barrel in 2008 to an average of $69.64 per barrel in the month of June 2009. As of July 21, 2009 the WTI oil spot price was $64.81 per barrel. According to the International Energy Agency’s (IEA) July 2009 “Oil Market Report,” growing concerns over the path of economic recovery and current weak demand contribute to an unlikely rebound in crude prices during the second half of 2009. The IEA’s forecasted world petroleum demand for the remainder of 2009 is 3% less than 2008 demand levels. In June 2009, the IEA reduced its five-year forecast for global crude demand, predicting that consumption may not regain 2008 levels until 2012. Despite the decline in oil and gas prices and reduction in our customers’ capital spending, we believe that, over the long term, any major macroeconomic disruptions may ultimately correct themselves as the underlying trends of smaller and more complex reservoirs, high depletion rates, and the need for continual reserve replacement should drive the long-term need for our services.

North America operations. Volatility in natural gas prices can impact our customers' drilling and production activities, particularly in North America. In the first six months of 2009, we experienced an unprecedented decline in drilling activity as the United States rig count, as of July 17, 2009, dropped approximately 55% from 2008 highs. Correlating with this decline, the Henry Hub spot price decreased from an average of $9.13 per mcf in 2008 to $3.91 per mcf in June 2009. As of July 21, 2009, the Henry Hub spot price had fallen to $3.59 per mcf. A high sequential decline in rig count from the first quarter of 2009 led to a more severe margin compression in the industry than previously anticipated. Working natural gas storage continues to be ahead of its normal seasonal patterns, which suggests that despite reduced drilling activity, the supply curtailment in gas production has not yet caught up with lower demand levels. Further, the expectation that gas storage will potentially reach record levels by the end of the injection period indicates that any recovery in gas drilling activity is likely to be relatively modest for the remainder of 2009. We have also seen pricing erosion and severe margin contraction in all of our service offerings in North America, and we anticipate that pricing for our services will remain under pressure until drilling activity stabilizes. When this stabilization may occur is uncertain, and we expect our customers to continue to adjust their spending plans until natural gas supply-demand fundamentals improve.

International operations. Consistent with our long-term strategy to grow our operations outside of North America, we expect to continue to invest capital related to our international operations. However, as of June 30, 2009, rig count had declined approximately 13% from 2008 highs, and there is a risk of a further decline in activity. Although we are seeing some projects move forward and have recently won a number of contract awards, we still continue to see certain markets exhibit weakness in activity. The depth of the decline in international markets is unknown, and operators have maintained their focus on lowering project costs. Given the continued pricing negotiations, we expect to see margin compression over the remainder of 2009 and throughout 2010.

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

	-	leveraging our technologies to deploy our packaged-services strategy to provide our customers with the ability to more efficiently drill and complete their wells, especially in service-intensive environments such as deepwater and shale plays;
	-	retaining key investments in technology and capital to accelerate growth opportunities;
	-	increasing our market share in unconventional markets by enhancing our technological position and leveraging our technical expertise and wide portfolio of products and services;
	-	lowering our input costs from vendors by negotiating price reductions for both materials used in our operations and those utilized in the manufacturing of capital equipment;
	-	negotiating with our customers to trade an expansion of scope and a lengthening of contract duration for price concessions;
	-	reducing headcount in locations experiencing significant activity declines;
	-	improving working capital, operating within our cash flow, and managing our balance sheet to maximize our financial flexibility;
	-	continuing the globalization of our manufacturing and supply chain processes, preserving work at our lower-cost manufacturing centers, and utilizing our international infrastructure to lower costs from our supply chain through delivery;
	-	expanding our business with national oil companies; and
	-	minimizing discretionary spending.

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

	-	a five-year, $1.5 billion contract to provide a broad base of products and services to an international oil company for its work associated with North America;
	-	several wins totaling $1 billion, including $700 million to provide deepwater drilling fluid services in the Gulf of Mexico, Brazil, Indonesia, Angola, and other countries, which solidifies our position in the deepwater drilling fluids market and $300 million for shelf- and land-related work;
	-	a two-year contract extension, estimated to be valued at $450 million, to provide cementing services and completion and drilling fluids for StatoilHydro in offshore fields on the Norwegian continental shelf;
	-	a five-year, $190 million contract to provide drilling fluid, completion fluid, and drilling waste management services for Petrobras in the offshore markets of Brazil;
	-	a five-year, $100 million contract to provide directional-drilling and logging-while-drilling services in the Middle East;
	-	a contract award in Algeria to provide integrated project management services for a number of delineation wells initially with the potential to expand to 120 wells for full field development.
	-	a four-year contract to provide directional-drilling, measurement-while-drilling, and logging-while-drilling, along with drilling fluids and cementing services in Russia; and
	-	a multi-year contract scheduled to commence in 2010 to provide completion products and services and drilling and completion fluids in the deepwater, offshore fields of Angola.

RESULTS OF OPERATIONS IN 2009 COMPARED TO 2008

Three Months Ended June 30, 2009 Compared with Three Months Ended June 30, 2008

	Three Months Ended
REVENUE:	June 30				Increase			Percentage
Millions of dollars	2009		2008		(Decrease)			Change
Completion and Production	$	1,752	$	2,357	$	(605	)		(26	)%
Drilling and Evaluation		1,742		2,130		(388	)		(18	)
Total revenue	$	3,494	$	4,487	$	(993	)		(22	)%

By geographic region:
Completion and Production:
North America	$	795	$	1,265	$	(470	)	(37	)%
Latin America		227		232		(5	)	(2	)
Europe/Africa/CIS		439		509		(70	)	(14	)
Middle East/Asia		291		351		(60	)	(17	)
Total		1,752		2,357		(605	)	(26	)
Drilling and Evaluation:
North America		464		725		(261	)	(36	)
Latin America		317		365		(48	)	(13	)
Europe/Africa/CIS		532		607		(75	)	(12	)
Middle East/Asia		429		433		(4	)	(1	)
Total		1,742		2,130		(388	)	(18	)
Total revenue by region:
North America		1,259		1,990		(731	)	(37	)
Latin America		544		597		(53	)	(9	)
Europe/Africa/CIS		971		1,116		(145	)	(13	)
Middle East/Asia		720		784		(64	)	(8	)

	Three Months Ended
OPERATING INCOME:	June 30						Increase			Percentage
Millions of dollars	2009			2008			(Decrease)			Change
Completion and Production	$	243		$	537		$	(294	)		(55	)%
Drilling and Evaluation		284			504			(220	)		(44	)
Corporate and other		(51	)		(92	)		41			45
Total operating income	$	476		$	949		$	(473	)		(50	)%

By geographic region:
Completion and Production:
North America	$	52	$	317	$	(265	)	(84	)%
Latin America		53		51		2		4
Europe/Africa/CIS		69		93		(24	)	(26	)
Middle East/Asia		69		76		(7	)	(9	)
Total		243		537		(294	)	(55	)
Drilling and Evaluation:
North America		28		189		(161	)	(85	)
Latin America		53		77		(24	)	(31	)
Europe/Africa/CIS		86		124		(38	)	(31	)
Middle East/Asia		117		114		3		3
Total		284		504		(220	)	(44	)
Total operating income by region
(excluding Corporate and other):
North America		80		506		(426	)	(84	)
Latin America		106		128		(22	)	(17	)
Europe/Africa/CIS		155		217		(62	)	(29	)
Middle East/Asia		186		190		(4	)	(2	)

Note

–

All periods presented reflect the movement of certain operations from the Completion and Production segment to the Drilling and Evaluation segment during the first quarter of 2009.

The 22% decline in consolidated revenue in the second quarter of 2009 compared to the second quarter of 2008 was primarily due to pricing declines and lower demand for our products and services in North America as the result of a significant reduction in rig count. Despite an approximate 50% reduction in average rig count in North America from the second quarter of 2008, we only experienced a 37% decline in North America revenue from the second quarter of 2008. International revenue was 66% of consolidated revenue in the second quarter of 2009 and 58% of consolidated revenue in the second quarter of 2008.

The decrease in consolidated operating income compared to the second quarter of 2008 primarily stemmed from an 84% decrease in North America due to a decline in rig count and severe margin contraction and a $17 million charge associated with employee separation costs partially offset by savings from cost reductions. Operating income in the second quarter of 2008 was positively impacted by a combined $25 million gain related to the sale of two investments in the United States and was adversely affected by a $30 million charge related to a drill bits patent dispute settlement.

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

Completion and Production decrease in revenue compared to the second quarter of 2008 was a result of pricing declines in North America and lower demand for our products and services in North America. North America revenue fell 37% on a drop in demand for production enhancement services and cementing services in the United States. In addition, Canada experienced declines in demand for production enhancement services. Latin America revenue decreased 2% with increased demand for all products and services in Mexico being offset by declines for cementing and production enhancement services in the rest of the region. Europe/Africa/CIS revenue decreased 14% on a decline in demand for completion tools in Africa and production enhancement services in both Africa and the North Sea. Europe was also negatively impacted by foreign exchange losses in the second quarter of 2009. Middle East/Asia revenue fell 17% largely due to a decrease in demand for all products and services in the Middle East. International revenue was 56% of total segment revenue in the second quarter of 2009 and 48% of total segment revenue in the second quarter of 2008.

The Completion and Production segment operating income decrease compared to the second quarter of 2008 was led by the North America region, where operating income fell 84% largely due to pricing declines and significant reductions in rig count resulting in lower demand for our products and services. Latin America operating income increased 4% due to higher demand and lower costs for completion tools and services offsetting declines in production enhancement services. Europe/Africa/CIS operating income declined 26% due to lower demand and higher costs for completion tools and production enhancement services in Africa and decreased production enhancement services in Europe. Middle East/Asia operating income decreased 9% with increased production enhancement in Asia Pacific outweighed by declines in demand for all products and services in the Middle East, mainly due to reductions in rig count.

Drilling and Evaluation revenue decrease compared to the second quarter of 2008 was a result of pricing declines in North America and lower demand for our products and services in North America, Latin America, and Europe/Africa. North America revenue fell 36% on pricing declines and a reduction in rig count. Latin America revenue declined 13% primarily due to lower demand for software and consulting services and drilling fluid services across the region. Europe/Africa/CIS revenue decreased 12% with increased drilling fluid services in the North Sea outweighed by pricing pressure and decreased demand for drilling services in Europe and drilling fluid services in Africa. Middle East/Asia revenue remained relatively flat due to increased demand for drilling and testing and subsea services in Asia Pacific offset by decreased demand for all products and services in the Middle East. International revenue was 76% of total segment revenue in the second quarter of 2009 and 68% of total segment revenue in the second quarter of 2008.

The decrease in segment operating income compared to the second quarter of 2008 was primarily derived from pricing declines and rig count reductions across all regions but most notably in North America where operating income fell 85%. North America benefited from a combined $25 million gain related to the sale of two investments in the second quarter of 2008. Latin America operating income decreased 31% due to declining demand across all products and services. The Europe/Africa/CIS region operating income fell 31% largely due to decreased demand and pricing declines for drilling services in the North Sea. Middle East/Asia operating income increased 3% over the second quarter of 2008 with increased demand for drilling services in Asia Pacific outweighing activity declines across most product service lines in the Middle East.

Corporate and other expenses were $51 million in the second quarter of 2009 compared to $92 million in the second quarter of 2008. The 45% reduction was primarily related to a $30 million charge related to a drill bits patent dispute settlement in the second quarter of 2008.

NONOPERATING ITEMS

Interest expense increased $40 million in the second quarter of 2009 compared to the second quarter of 2008 primarily related to the issuance of the $2 billion in senior notes during the first quarter of 2009.

Other, net in the second quarter of 2009 included a $13 million loss on foreign exchange.

Provision for income taxes on continuing operations of $117 million in the second quarter of 2009 resulted in an effective tax rate of 31% compared to an effective tax rate on continuing operations of 32% in the second quarter of 2008.

Loss from discontinued operations, net of income tax in the second quarter of 2008 included a $117 million charge related to adjustments to the indemnities and guarantees provided to KBR upon separation.

RESULTS OF OPERATIONS IN 2009 COMPARED TO 2008

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

	Six Months Ended
REVENUE:	June 30				Increase			Percentage
Millions of dollars	2009		2008		(Decrease)			Change
Completion and Production	$	3,780	$	4,479	$	(699	)		(16	)%
Drilling and Evaluation		3,621		4,037		(416	)		(10	)
Total revenue	$	7,401	$	8,516	$	(1,115	)		(13	)%

By geographic region:
Completion and Production:
North America	$	1,866	$	2,429	$	(563	)	(23	)%
Latin America		459		449		10		2
Europe/Africa/CIS		865		922		(57	)	(6	)
Middle East/Asia		590		679		(89	)	(13	)
Total		3,780		4,479		(699	)	(16	)
Drilling and Evaluation:
North America		1,076		1,423		(347	)	(24	)
Latin America		641		657		(16	)	(2	)
Europe/Africa/CIS		1,074		1,152		(78	)	(7	)
Middle East/Asia		830		805		25		3
Total		3,621		4,037		(416	)	(10	)
Total revenue by region:
North America		2,942		3,852		(910	)	(24	)
Latin America		1,100		1,106		(6	)	(1	)
Europe/Africa/CIS		1,939		2,074		(135	)	(7	)
Middle East/Asia		1,420		1,484		(64	)	(4	)

	Six Months Ended
OPERATING INCOME:	June 30						Increase			Percentage
Millions of dollars	2009			2008			(Decrease)			Change
Completion and Production	$	606		$	1,041		$	(435	)		(42	)%
Drilling and Evaluation		588			913			(325	)		(36	)
Corporate and other		(102	)		(158	)		56			35
Total operating income	$	1,092		$	1,796		$	(704	)		(39	)%

By geographic region:
Completion and Production:
North America	$	218	$	638	$	(420	)	(66	)%
Latin America		107		104		3		3
Europe/Africa/CIS		146		157		(11	)	(7	)
Middle East/Asia		135		142		(7	)	(5	)
Total		606		1,041		(435	)	(42	)
Drilling and Evaluation:
North America		92		359		(267	)	(74	)
Latin America		107		131		(24	)	(18	)
Europe/Africa/CIS		177		235		(58	)	(25	)
Middle East/Asia		212		188		24		13
Total		588		913		(325	)	(36	)
Total operating income by region
(excluding Corporate and other):
North America		310		997		(687	)	(69	)
Latin America		214		235		(21	)	(9	)
Europe/Africa/CIS		323		392		(69	)	(18	)
Middle East/Asia		347		330		17		5

Note

–

All periods presented reflect the movement of certain operations from the Completion and Production segment to the Drilling and Evaluation segment during the first quarter of 2009.

The 13% decline in consolidated revenue in the first six months of 2009 compared to the first six months of 2008 was primarily due to pricing declines and lower demand for our products and services in North America due to a significant reduction in rig count. Despite an approximate 37% reduction in average rig count in North America during the first six months of 2009 compared to the first six months of 2008, we experienced only a 24% decline in North America revenue from the first half of 2008. International revenue was 63% of consolidated revenue in the first six months of 2009 and 58% of consolidated revenue in the first six months of 2008.

The decrease in consolidated operating income compared to the first six months of 2008 primarily stemmed from a 69% decrease in North America due to a decline in rig count and severe margin contraction and a $45 million charge associated with employee separation costs. Operating income in the first six months of 2008 was favorably impacted by a $35 million gain on the sale of a joint venture interest in the United States and a combined $25 million gain related to the sale of two investments in the United States. Operating income in the first six months of 2008 was adversely impacted by a $23 million impairment charge related to an oil and gas property in Bangladesh and a $30 million charge related to a drill bits patent dispute settlement.

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

Completion and Production decrease in revenue compared to the first six months of 2008 was a result of pricing declines in North America and lower demand for our products and services in North America and Middle East/Asia. North America revenue fell 23% on a drop in demand for production enhancement services, cementing services, and completion tools services in the United States land market. In addition, Canada experienced declines in demand for all products and services. Latin America revenue grew 2% driven by increased activity for all products and services in Mexico, Brazil, and Colombia, partially offset by activity declines in Argentina and Venezuela. Europe/Africa/CIS revenue decreased 6% on lower demand for completion tools and sales and services and production enhancement services in Africa. Production enhancement services in Europe were negatively impacted by job delays in the North Sea and foreign exchange losses. Middle East/Asia revenue fell 13% largely due to a decrease in demand for all products and services in the Middle East. Increased production enhancement services and intelligent completion systems in Asia Pacific were outweighed by declines in cementing and completion tools services throughout the region. International revenue was 53% of total segment revenue in the first six months of 2009 and 48% of total segment revenue in the first six months of 2008.

The Completion and Production segment operating income decrease compared to the first six months of 2008 was led by the North America region, where operating income fell 66% largely due to pricing declines and significant reductions in rig count resulting in lower demand for our products and services. North America benefited from a $35 million gain on the sale of a joint venture interest in the first half of 2008. Latin America operating income increased 3% due to higher demand and lower costs for completion tools and services in Brazil and Mexico. Europe/Africa/CIS operating income decreased 7% mainly due to decreased demand for completion tools and production enhancement services in Africa. Middle East/Asia operating income decreased 5% despite higher demand for production enhancement services and intelligent completions systems in Asia Pacific due to lower demand across all other products and services throughout the region.

Drilling and Evaluation revenue decrease compared to the first six months of 2008 was primarily a result of pricing declines and decreased demand for our products and services stemming from a reduction in rig count in North America, where revenue fell 24%. Latin America revenue fell 2% mainly due to decreased demand for drilling fluid services and software sales and consulting services. Europe/Africa/CIS revenue decreased 7% as a result of decreased demand for drilling fluids services in Africa and drilling services in Europe. Pricing pressure also had a significant impact on revenue in Europe. Middle East/Asia revenue increased 3% as increased demand for drilling fluid services, testing and subsea services, and drilling services in Asia Pacific outweighed activity declines in drilling and wireline and perforating services in the Middle East. International revenue was 73% of total segment revenue in the first six months of 2009 and 68% of total segment revenue in the first six months of 2008.

The decrease in segment operating income compared to the first six months of 2008 was primarily derived from pricing declines and rig count reductions in North America and Europe. North America operating income decreased 74% from pricing declines and rig count reductions. This region’s results also reflect $25 million of gains related to the sale of two investments in the United States in the first six months of 2008. Latin America operating income fell 18% primarily due to higher costs and lower demand for wireline and perforating and testing and subsea services. The Europe/Africa/CIS region operating income fell 25% on pricing pressures and decreased demand primarily for drilling services in Europe, which outweighed the slight increase in Africa drilling services and wireline and perforating services. Middle East/Asia operating income grew 13% over the first six months of 2008 mainly due to increased drilling activity in Asia Pacific. This region was negatively impacted by the impairment charge related to an oil and gas property in Bangladesh in the first half of 2008.

Corporate and other expenses were $102 million in the first six months of 2009 compared to $158 million in the first six months of 2008. The 35% reduction was primarily related to a $30 million charge related to a drill bits patent dispute settlement in the first six months of 2008. Lower legal and corporate planning and development expenses also contributed to the decrease.

NONOPERATING ITEMS

Interest expense increased $51 million in the first six months of 2009 compared to the first six months of 2008 primarily due to the issuance of $2 billion in senior notes during the first half of 2009.

Interest income decreased $24 million in the first six months of 2009 compared to the first six months of 2008 due to a general decline in market interest rates and lower investment balances for a portion of the first half of 2009.

Other, net in the first six months of 2009 included a $19 million loss on foreign exchange.

Provision for income taxes on continuing operations of $296 million in the first six months of 2009 resulted in an effective tax rate of 31% compared to an effective tax rate on continuing operations of 30% in the first six months of 2008. The lower effective tax rate in the first six months of 2008 was partially attributable to favorable settlements with foreign tax jurisdictions and by the ability to recognize additional foreign tax credits that had been substantiated.

Loss from discontinued operations, net of income tax in the first six months of 2008 included a $117 million charge related to adjustments to the indemnities and guarantees provided to KBR upon separation.

ENVIRONMENTAL MATTERS

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.

NEW ACCOUNTING STANDARDS

In May 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 165 “Subsequent Events,” which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events. SFAS No. 165 is effective for interim and annual reporting periods ending after June 15, 2009. We adopted the new disclosure requirements in our June 30, 2009 condensed consolidated financial statements.

On June 30, 2009, we adopted FASB Staff Position (FSP) SFAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” requires publicly-traded companies, as defined in APB Opinion No. 28, “Interim Financial Reporting,” to provide disclosures on the fair value of financial instruments in interim financial statements.

On January 1, 2009, we adopted FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. According to the provisions of FSP EITF 03-6-1, we restated prior periods’ basic and diluted earnings per share to include such outstanding unvested restricted shares of our common stock in the basic weighted average shares outstanding calculation. Upon adoption, both basic and diluted income per share for the first six months of 2008 and full year 2008 decreased by $0.01 for continuing operations and net income attributable to company shareholders.

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R) Consolidation of Variable Interest Entities.” This statement clarifies the characteristics that identify a variable interest entity (VIE) and changes how a reporting entity identifies a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards calculation to a qualitative approach based on which variable interest holder has controlling financial interest and the ability to direct the most significant activities that impact the VIE’s economic performance. This statement requires the primary beneficiary assessment to be performed on a continuous basis. It also requires additional disclosures about an entity’s involvement with VIE, restrictions on the VIE’s assets and liabilities that are included in the reporting entity’s consolidated balance sheet, significant risk exposures due to the entity’s involvement with the VIE, and how its involvement with a VIE impacts the reporting entity’s consolidated financial statements. SFAS No. 167 is effective for fiscal years beginning after November 15, 2009. We will adopt SFAS No. 167 on January 1, 2010 and have not yet determined the impact on our condensed consolidated financial statements.

FORWARD-LOOKING INFORMATION

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

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

While it is not possible to identify all factors, we continue to face many risks and uncertainties that could cause actual results to differ from our forward-looking statements and potentially materially and adversely affect our financial condition and results of operations.

The risk factors discussed below update the risk factors previously disclosed in our 2008 Annual Report on Form 10-K.

RISK FACTORS

Worldwide recession and effect on exploration and production activity

The worldwide recession has reduced the levels of economic activity and the expansion of industrial business operations worldwide. This recession could continue for an extended period of time. The slowdown in economic activity has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. This reduction in demand could continue through 2009 and beyond. Crude oil prices declined from record levels in July 2008 of approximately $145 per barrel to levels as low as $30 per barrel toward the end of 2008. As of July 21, 2009, crude oil prices were $64.81 per barrel. Natural gas spot prices peaked at $13.72 per mcf in 2008 and then fell to an average of $6.02 per mcf toward the end of 2008. As of July 21, 2009, natural gas spot prices had fallen even further to $3.59 per mcf. Demand for our services and products depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices. Demand for our services and products is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies, including national oil companies. Any prolonged reduction in oil and natural gas prices will depress the immediate levels of exploration, development, and production activity. Perceptions of longer-term lower oil and natural gas prices by oil and gas companies can similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. Lower levels of activity result in a corresponding decline in the demand for our oil and natural gas well services and products, which could have a material adverse effect on our revenue and profitability.

Foreign Corrupt Practices Act investigations

KBR has agreed that our indemnification obligations with respect to the DOJ and SEC FCPA investigations have been fully satisfied.

Other matters. In addition to the DOJ and the SEC investigations, we are aware of other investigations in France, Nigeria, the United Kingdom, and Switzerland regarding the Bonny Island project.

Barracuda-Caratinga arbitration

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. Estimates indicate that costs of these various solutions range 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. We understand KBR is vigorously defending and pursuing recovery of the costs incurred to date through the arbitration process and to that end has submitted a counterclaim in the arbitration seeking the recovery of $22 million. 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 and the arbitration panel are now in discussion regarding the future course of the arbitration proceedings with respect to the issues of liability and damages. 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, 2009 and December 31, 2008. See Note 2 to our condensed consolidated financial statements for additional information regarding the KBR indemnification.

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 due to, among other reasons, a reduction in our customer’s cash flow from operations and their access to the credit markets. 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.

Risks related to our business in Venezuela

We believe there are risks associated with our operations in Venezuela. For example, the Venezuela National Assembly enacted legislation that allows the Venezuelan government, directly or through its state-owned oil company, to assume control over the operations and assets of certain oil service providers in exchange for reimbursement of the book value of the assets adjusted for certain liabilities. Venezuelan government officials have stated this recent legislation is not applicable to our company.

However, we continue to see an increased delay in receiving payment on our receivables from our primary customer in Venezuela. Recently, this customer requested a discount on the receivables. No agreement has been reached. If our customer delays in paying or fails to pay us a significant amount of our outstanding receivables, it could have a material effect on our liquidity, consolidated results of operations, and consolidated financial condition.

As of June 30, 2009, our total net investment in Venezuela was approximately $265 million. In addition to this amount, we also have approximately $400 million of surety bond guarantees outstanding relating to our Venezuelan operations.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk from changes in foreign currency exchange rates, interest rates, and commodity prices. We selectively manage these exposures through the use of derivative instruments to mitigate our market risk from these exposures. The objective of our risk management strategy is to minimize the volatility from fluctuations in foreign currency rates. Our use of derivative instruments entails the following types of market risk:

	-	volatility of the currency rates;
	-	counterparty credit risk;
	-	time horizon of the derivative instruments; and
	-	the type of derivative instruments used.

We do not use derivative instruments for trading purposes. We do not consider any of these risk management activities to be material.

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, 2009 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, 2009 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

Information related to various commitments and contingencies is described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations---Forward-Looking Information and Risk Factors,” and in Notes 2 and 7 to the condensed consolidated financial statements.

Item 1(a). Risk Factors

Information related to risk factors is described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations---Forward-Looking Information and Risk Factors.”

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, 2009.

Total Number

of Shares

Purchased as

Total Number

Average

Part of Publicly

of Shares

Price Paid

Announced Plans

Period

Purchased (a)

per Share

or Programs

April 1-30

185,964

18.50

–

May 1-31

116,404

21.20

–

June 1-30

72,928

23.85

–

Total

375,296

20.38

–

(a) All of the 375,296 shares purchased during the three-month period ended June 30, 2009 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.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

At our Annual Meeting of Stockholders held on May 20, 2009, stockholders were asked to consider and act upon:

	(1)	the election of Directors for the ensuing year;
	(2)	a proposal to ratify the appointment of KPMG LLP as independent accountants to examine the financial statements and books and records of Halliburton for the year 2009;
	(3)	a proposal to amend and restate the 1993 Stock and Incentive Plan;
	(4)	a proposal to amend and restate the 2002 Employee Stock Purchase Plan;
	(5)	a stockholder proposal regarding a human rights policy;
	(6)	a stockholder proposal regarding political contributions;
	(7)	a stockholder proposal regarding low carbon energy report;
	(8)	a stockholder proposal regarding additional compensation and analysis report;
	(9)	a stockholder proposal regarding special shareholder meetings; and
	(10)	a stockholder proposal regarding Iraq operations.

The votes for, votes against, abstentions, and broker non-votes, where applicable, for each matter are set out below.

(1)

Election of Directors:

Name of Nominee	Votes For		Votes Against		Votes Abstain

Alan M. Bennett		742,363,584		10,722,173		2,410,102
James R. Boyd		696,130,996		17,536,236		41,801,628
Milton Carroll		690,652,268		23,101,081		41,742,511
S. Malcolm Gillis		734,264,053		18,537,855		2,693,952
James T. Hackett		686,614,268		26,930,429		41,950,804
Robert A. Malone		734,483,717		18,817,999		2,194,145
David J. Lesar		743,124,932		10,181,552		2,189,376
J. Landis Martin		707,527,133		45,514,616		2,454,111
Jay A. Precourt		711,711,104		41,537,009		2,247,748
Debra L. Reed		695,336,807		17,776,895		42,382,159

(2)

Proposal for ratification of the selection of auditors:

	Number of Votes For	748,054,475
	Number of Votes Against	5,791,157
	Number of Votes Abstain	1,650,218

(3)

Proposal to amend and restate the 1993 Stock and Incentive Plan:

	Number of Votes For	508,631,947
	Number of Votes Against	132,660,637
	Number of Votes Abstain	2,265,733
	Number of Broker Non-Votes	111,937,544

(4)

Proposal to amend and restate the 2002 Employee Stock Purchase Plan:

	Number of Votes For	633,639,197
	Number of Votes Against	7,847,669
	Number of Votes Abstain	2,071,450
	Number of Broker Non-Votes	111,937,545

(5)

Stockholder proposal regarding a human rights policy:

	Number of Votes For	132,863,228
	Number of Votes Against	424,699,979
	Number of Votes Abstain	85,995,110
	Number of Broker Non-Votes	111,937,544

(6)

Stockholder proposal regarding political contributions:

	Number of Votes For	154,187,515
	Number of Votes Against	410,785,556
	Number of Votes Abstain	78,585,245
	Number of Broker Non-Votes	111,937,545

(7)

Stockholder proposal regarding low carbon energy report:

	Number of Votes For	35,739,015
	Number of Votes Against	523,825,598
	Number of Votes Abstain	83,993,704
	Number of Broker Non-Votes	111,937,544

(8)

Stockholder proposal regarding additional compensation and analysis report:

	Number of Votes For	303,532,626
	Number of Votes Against	331,098,423
	Number of Votes Abstain	8,927,268
	Number of Broker Non-Votes	111,937,544

(9)

Stockholder proposal regarding special shareowner meetings:

	Number of Votes For	342,970,452
	Number of Votes Against	292,125,354
	Number of Votes Abstain	8,462,510
	Number of Broker Non-Votes	111,937,545

(10)

Stockholder proposal regarding Iraq operations:

	Number of Votes For	123,471,874
	Number of Votes Against	423,145,816
	Number of Votes Abstain	85,810,968
	Number of Broker Non-Votes	123,067,203

Item 5. Other Information

None.

Item 6. Exhibits

10.1	Halliburton Company Stock and Incentive Plan, as amended and restated effective
	February 11, 2009 (incorporated by reference to Appendix B of Halliburton’s proxy
	statement filed April 6, 2009, File No. 1-3492).

10.2	Halliburton Company Employee Stock Purchase Plan, as amended and restated effective
	February 11, 2009 (incorporated by reference to Appendix C of Halliburton’s proxy
	statement filed April 6, 2009, File No. 1-3492).

10.3	Form of Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 99.2
	of Halliburton’s Form S-8 filed May 21, 2009, Registration No. 333-159394).

10.4	Form of Restricted Stock Agreement (incorporated by reference to Exhibit 99.3 of
	Halliburton’s Form S-8 filed May 21, 2009, Registration No. 333-159394).

10.5	Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 99.4 of
	Halliburton’s Form S-8 filed May 21, 2009, Registration No. 333-159394).

10.6	Form of Non-Employee Director Restricted Stock Agreement (incorporated by reference
	to Exhibit 99.5 of Halliburton’s Form S-8 filed May 21, 2009, Registration No. 333-
	159394).

* 12.1	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.

*	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	Vice President, Corporate Controller, and
Chief Financial Officer	Principal Accounting Officer

Date: July 24, 2009