edmarch201010q_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 March 31, 2010

[ ] Transition Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the transition period from _____ to _____

Commission File Number 001-03492

HALLIBURTON COMPANY

(a Delaware corporation)

75-2677995

3000 North Sam Houston Parkway East

Houston, Texas 77032

(Address of Principal Executive Offices)

Telephone Number – Area Code (281) 871-2699

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

Yes

[X]

[ ]

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

Yes

[X]

[ ]

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

Large accelerated filer [X]

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

[ ]

[X]

As of April 16, 2010, 905,275,293 shares of Halliburton Company common stock, $2.50 par value per share, were outstanding.

HALLIBURTON COMPANY

Index

		Page No.
PART I.	FINANCIAL INFORMATION	3

Item 1.	Financial Statements	3

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

Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30

Item 4.	Controls and Procedures	30

PART II.	OTHER INFORMATION	31

Item 1.	Legal Proceedings	31

Item 1(a).	Risk Factors	31

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31

Item 3.	Defaults Upon Senior Securities	31

Item 4.	[Removed and Reserved]	31

Item 5.	Other Information	31

Item 6.	Exhibits	32

Signatures		33

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HALLIBURTON COMPANY

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended
	March 31
Millions of dollars and shares except per share data	2010			2009
Revenue:
Services	$	2,845		$	2,950
Product sales		916			957
Total revenue		3,761			3,907
Operating costs and expenses:
Cost of services		2,473			2,411
Cost of sales		786			828
General and administrative		58			52
Gain on sale of assets, net		(5	)		−
Total operating costs and expenses		3,312			3,291
Operating income		449			616
Interest expense		(79	)		(53	)
Interest income		3			2
Other, net		(40	)		(5	)
Income from continuing operations before income taxes		333			560
Provision for income taxes		(121	)		(179	)
Income from continuing operations		212			381
Loss from discontinued operations, net of income
tax benefit of $3 and $0		(5	)		(1	)
Net income	$	207		$	380
Noncontrolling interest in net income of subsidiaries		(1	)		(2	)
Net income attributable to company	$	206		$	378
Amounts attributable to company shareholders:
Income from continuing operations	$	211		$	379
Loss from discontinued operations, net		(5	)		(1	)
Net income attributable to company	$	206		$	378
Basic income per share attributable to company
shareholders:
Income from continuing operations	$	0.23		$	0.42
Loss from discontinued operations, net		−			−
Net income per share	$	0.23		$	0.42
Diluted income per share attributable to company
shareholders:
Income from continuing operations	$	0.23		$	0.42
Loss from discontinued operations, net		−			−
Net income per share	$	0.23		$	0.42

Cash dividends per share	$	0.09		$	0.09
Basic weighted average common shares outstanding		905			897
Diluted weighted average common shares outstanding		908			899

See notes to condensed consolidated financial statements.

HALLIBURTON COMPANY

Condensed Consolidated Balance Sheets

(Unaudited)

	March 31,			December 31,
Millions of dollars and shares except per share data	2010			2009
Assets
Current assets:
Cash and equivalents	$	1,383		$	2,082
Receivables (less allowance for bad debts of $88 and $90)		3,176			2,964
Inventories		1,658			1,598
Investments in marketable securities		1,808			1,312
Current deferred income taxes		248			210
Other current assets		541			472
Total current assets		8,814			8,638
Property, plant, and equipment, net of accumulated depreciation
of $5,406 and $5,230		5,980			5,759
Goodwill		1,138			1,100
Other assets		1,048			1,041
Total assets	$	16,980		$	16,538
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	964		$	787
Current maturities of long-term debt		750			750
Accrued employee compensation and benefits		520			514
Deferred revenue		282			215
Department of Justice (DOJ) and Securities and Exchange Commission (SEC)
settlement and indemnity		95			142
Other current liabilities		534			481
Total current liabilities		3,145			2,889
Long-term debt		3,824			3,824
Employee compensation and benefits		425			462
Other liabilities		626			606
Total liabilities		8,020			7,781
Shareholders’ equity:
Common shares, par value $2.50 per share – authorized 2,000 shares, issued
1,068 and 1,067 shares		2,669			2,669
Paid-in capital in excess of par value		395			411
Accumulated other comprehensive loss		(206	)		(213	)
Retained earnings		10,988			10,863
Treasury stock, at cost – 162 and 165 shares		(4,915	)		(5,002	)
Company shareholders’ equity		8,931			8,728
Noncontrolling interest in consolidated subsidiaries		29			29
Total shareholders’ equity		8,960			8,757
Total liabilities and shareholders’ equity	$	16,980		$	16,538

See notes to condensed consolidated financial statements.

HALLIBURTON COMPANY

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	March 31
Millions of dollars	2010			2009
Cash flows from operating activities:
Net income	$	207		$	380
Adjustments to reconcile net income to net cash from operations:
Depreciation, depletion, and amortization		261			215
Payments of DOJ and SEC settlement and indemnity		(47	)		(274	)
Other changes:
Receivables		(264	)		372
Accounts payable		187			(18	)
Inventories		(54	)		(65	)
Other		27			(229	)
Total cash flows from operating activities		317			381
Cash flows from investing activities:
Purchases of investments in marketable securities		(500	)		−
Capital expenditures		(404	)		(518	)
Acquisitions of business assets, net of cash acquired		(113	)		−
Other investing activities		47			53
Total cash flows from investing activities		(970	)		(465	)
Cash flows from financing activities:
Proceeds from long-term borrowings, net of offering costs		−			1,976
Payments of dividends to shareholders		(81	)		(81	)
Other financing activities		44			42
Total cash flows from financing activities		(37	)		1,937
Effect of exchange rate changes on cash		(9	)		(10	)
Increase (decrease) in cash and equivalents		(699	)		1,843
Cash and equivalents at beginning of period		2,082			1,124
Cash and equivalents at end of period	$	1,383		$	2,967
Supplemental disclosure of cash flow information:
Cash payments during the period for:
Interest	$	133		$	66
Income taxes	$	96		$	128

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 2009 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 March 31, 2010 and the results of our operations and cash flows for the three months ended March 31, 2010 and 2009. Such adjustments are of a normal recurring nature. The results of operations for the three months ended March 31, 2010 may not be indicative of results for the full year.

Note 2. Business Segment and Geographic Information

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

The following table presents information on our business segments. “Corporate and other” includes expenses related to support functions and corporate executives. Also included are certain gains and losses not attributable to a particular business segment.

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

	Three Months Ended March 31
Millions of dollars	2010			2009
Revenue:
Completion and Production	$	1,964		$	2,028
Drilling and Evaluation		1,797			1,879
Total revenue	$	3,761		$	3,907

Operating income:
Completion and Production	$	238		$	363
Drilling and Evaluation		270			304
Total operations		508			667
Corporate and other		(59	)		(51	)
Total operating income	$	449		$	616
Interest expense		(79	)		(53	)
Interest income		3			2
Other, net		(40	)		(5	)
Income from continuing operations before income taxes	$	333		$	560

Receivables

As of March 31, 2010, 29% of our gross trade receivables were from customers in the United States. As of December 31, 2009, 26% of our gross trade receivables were from customers in the United States.

Note 3. Inventories

Inventories are stated at the lower of cost or market. In the United States, we manufacture certain finished products and parts inventories for drill bits, completion products, bulk materials, and other tools that are recorded using the last-in, first-out method, which totaled $77 million at March 31, 2010 and $68 million at December 31, 2009. If the average cost method had been used, total inventories would have been $31 million higher than reported at March 31, 2010 and $33 million higher than reported at December 31, 2009. The cost of the remaining inventory was recorded on the average cost method. Inventories consisted of the following:

	March 31,		December 31,
Millions of dollars	2010		2009
Finished products and parts	$	1,128	$	1,090
Raw materials and supplies		489		480
Work in process		41		28
Total	$	1,658	$	1,598

Finished products and parts are reported net of obsolescence reserves of $102 million at March 31, 2010 and $94 million at December 31, 2009.

Note 4. 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, 2009	$	8,757		$	8,728		$	29
Transactions with shareholders		70			71			(1	)
Comprehensive income:
Net income		207			206			1
Other comprehensive income		7			7			–
Total comprehensive income		214			213			1
Dividends paid on common stock		(81	)		(81	)		–
Balance at March 31, 2010	$	8,960		$	8,931		$	29

							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		61			61			–
Comprehensive income:
Net income		380			378			2
Other comprehensive loss		(9	)		(9	)		–
Total comprehensive income		371			369			2
Dividends paid on common stock		(81	)		(81	)		–
Balance at March 31, 2009	$	8,095		$	8,074		$	21

Accumulated other comprehensive loss consisted of the following:

	March 31,			December 31,
Millions of dollars	2010			2009
Defined benefit and other postretirement liability adjustments	$	(142	)	$	(149	)
Cumulative translation adjustments		(65	)		(65	)
Unrealized gains on investments		1			1
Total accumulated other comprehensive loss	$	(206	)	$	(213	)

Note 5. KBR Separation

During 2007, we completed the separation of KBR, Inc. (KBR) from us by exchanging KBR common stock owned by us for our common stock. In addition, we recorded a liability reflecting the estimated fair value of the indemnities 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 and a tax sharing 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 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, letters of credit, and other KBR credit instruments. These guarantees will continue until they expire at the earlier of: (1) the termination of the underlying project contract or KBR obligations thereunder; or (2) the expiration of the relevant credit support instrument in accordance with its terms or release of such instrument by the customer. 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 guarantees related to KBR’s 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 March 31, 2010, we had paid $464 million, consisting of $287 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” and “Other liabilities” on the condensed consolidated balance sheets and totaled $167 million at March 31, 2010 and $214 million at December 31, 2009. 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 March 31, 2010. See Note 6 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 6. Commitments and Contingencies

TSKJ matters

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. As a condition of our indemnity, we have control over the investigation, defense, and/or settlement of these matters. We have the right to terminate the indemnity in the event KBR elects to take control over the investigation, defense, and/or settlement or refuses to agree to a settlement negotiated and presented by us.

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% beneficial interest in the venture. Part of KBR’s ownership in TSKJ was held through M.W. Kellogg Limited (MWKL), a United Kingdom joint venture and subcontractor on the Bonny Island project, in which KBR beneficially owns a 55% interest. 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 did 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 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 by mid-year 2010. 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 August 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. In the United Kingdom, the Serious Fraud Office (SFO) is considering civil claims or criminal prosecution under various United Kingdom laws and appears to be focused on the actions of MWKL, among others. Violations of these laws could result in fines, restitution and confiscation of revenues, among other penalties, some of which could be subject to our indemnification obligations under the master separation agreement. Our indemnity for penalties under the master separation agreement with respect to MWKL is limited to 55% of such penalties, which is KBR’s beneficial ownership interest in MWKL. MWKL is cooperating with the SFO’s investigation. Whether the SFO pursues civil or criminal claims, and the amount of any fines, restitution, confiscation of revenues or other penalties that could be assessed would depend on, among other factors, the SFO’s findings regarding the amount, timing, nature and scope of any improper payments or other activities, whether any such payments or other activities were authorized by or made with knowledge of MWKL, the amount of revenue involved, and the level of cooperation provided to the SFO during the investigations. MWKL has informed the SFO that it intends to self-report corporate liability for corruption-related offenses arising out of the Bonny Island project, and discussions with the SFO are continuing.

The DOJ and SEC 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 and its majority-owned subsidiaries 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.

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. Initial estimates by KBR indicated that costs of these various solutions ranged up to $148 million. In March 2006, Petrobras commenced arbitration against KBR claiming $220 million plus interest for the cost of monitoring and replacing the defective bolts and all related costs and expenses of the arbitration, including the cost of attorneys’ fees. We understand KBR is vigorously defending this matter and 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 arbitration panel set the final hearing on liability and damages for early May 2010. Our estimation of the indemnity obligation regarding the Barracuda-Caratinga arbitration is recorded as a liability in our condensed consolidated financial statements as of March 31, 2010 and December 31, 2009. See Note 5 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. The district court issued an order on November 3, 2008 denying AMSF’s motion for class certification. AMSF then appealed to the United States Court of Appeals for the Fifth Circuit. On February 10, 2010, the Fifth Circuit affirmed the district court’s order denying class certification. AMSF has the opportunity to request additional review by the United States Supreme Court. Accordingly, the district court entered an order staying proceedings in that court until May 13, 2010, which is the deadline for AMSF to seek a writ of certiori in the United States Supreme Court. As of March 31, 2010, we had not accrued any amounts related to this matter because we do not believe that a loss is probable. Further, an estimate of possible loss or range of loss related to this matter cannot be made.

Shareholder derivative cases

In May 2009, two shareholder derivative lawsuits involving us and KBR were filed in Harris County, Texas naming as defendants various current and retired Halliburton directors and officers and current KBR directors. These cases allege that the individual Halliburton defendants violated their fiduciary duties of good faith and loyalty to the detriment of Halliburton and its shareholders by failing to properly exercise oversight responsibilities and establish adequate internal controls. The District Court consolidated the two cases and the plaintiffs filed a consolidated petition against current and former Halliburton directors and officers only containing various allegations of wrongdoing including violations of the FCPA, claimed KBR offenses while acting as a government contractor in Iraq, claimed KBR offenses and fraud under United States government contracts, Halliburton activity in Iran, and illegal kickbacks. As of March 31, 2010, 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.

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 $54 million as of March 31, 2010 and $53 million as of December 31, 2009. Our total liability related to environmental matters covers numerous properties.

We have subsidiaries that have been named as potentially responsible parties along with other third parties for 10 federal and state superfund sites for which we have established a liability. As of March 31, 2010, those 10 sites accounted for approximately $16 million of our total $54 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.

Guarantee arrangements

In the normal course of business, we have agreements with financial institutions under which approximately $1.6 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of March 31, 2010, including $214 million of surety bonds related to Venezuela. In addition, $303 million of the total $1.6 billion relates to KBR letters of credit, bank guarantees, or surety bonds 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 7. Income per Share

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

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

	Three Months Ended March 31
Millions of shares	2010		2009
Basic weighted average common shares outstanding		905		897
Dilutive effect of stock options		3		2
Diluted weighted average common shares outstanding		908		899

Excluded from the computation of diluted income per share are options to purchase six million shares of common stock that were outstanding during the three months ended March 31, 2010 and options to purchase nine million shares that were outstanding during the three months ended March 31, 2009. These options were outstanding during these periods but were excluded because they were antidilutive, as the option exercise price was greater than the average market price of the common shares.

Note 8. Fair Value of Financial Instruments

During the first quarter of 2010, we purchased $500 million of additional United States Treasury securities with maturities that extend through November 2010. These securities are accounted for as available-for-sale and recorded at fair value in “Investments in marketable securities.”

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
March 31, 2010
Marketable securities	$	1,808	$	1,808	$	1,808	$	–
Long-term debt		4,574		5,202		4,013		1,189 (a)
December 31, 2009
Marketable securities	$	1,312	$	1,312	$	1,312	$	–
Long-term debt		4,574		5,301		4,874		427 (a)

(a) Calculated based on the fair value of other actively-traded Halliburton debt.

Note 9. Retirement Plans

The components of net periodic benefit cost related to pension benefits for the three months ended March 31, 2010 and March 31, 2009 were as follows:

	Three Months Ended March 31
	2010				2009
Millions of dollars	United States		International		United States		International
Service cost	$	–	$	5	$	–	$	6
Interest cost		1		12		2		10
Expected return on plan assets		(2)		(11)		(2)		(8)
Recognized actuarial loss		1		1		–		1
Net periodic benefit cost	$	–	$	7	$	–	$	9

Note 10. Accounting Standards Recently Adopted

On January 1, 2010, we adopted the provisions of a new accounting standard which provides amendments to previous guidance on the consolidation of variable interest entities. This standard 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 standard requires the primary beneficiary assessment to be performed on a continuous basis. It also requires additional disclosures about an entity’s involvement with a VIE, restrictions on the VIE’s assets and liabilities that are included in the reporting entity’s condensed 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 condensed consolidated financial statements. The standard is effective for fiscal years beginning after November 15, 2009. The adoption of this standard did not have a material impact on our condensed consolidated financial statements.

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

EXECUTIVE OVERVIEW

Organization

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

our Completion and Production segment delivers cementing, stimulation, intervention, 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 integrated project management and consulting services.

The business operations of our segments are organized around four primary geographic regions: North America (includes Canada and the United States), Latin America, Europe/Africa/CIS, and Middle East/Asia. We have significant manufacturing operations in various locations, including, but not limited to, the United States, Canada, the United Kingdom, Malaysia, Mexico, Brazil, and Singapore. With approximately 53,000 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 quarter of 2010, we produced revenue of $3.8 billion and operating income of $449 million, reflecting an operating margin of 12%. Revenue decreased $146 million or 4% from the first quarter of 2009, while operating income decreased $167 million or 27% from the first quarter of 2009. These decreases were caused by a significant decline in our customers’ capital spending throughout 2009 and into the first quarter of 2010, primarily in our international operations, as a result of the global recession, which resulted in overall lower activity, lower pricing, and severe margin contraction. These decreases were partially offset by increased drilling activity and some pricing improvement in North America.

Business outlook

We continue to believe in the strength of the long-term fundamentals of our business. However, due to the financial crisis throughout 2009, the negative impact on credit availability and industry activity, and the current excess supply of oil and natural gas, the near-term outlook for our business and the industry still 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 and rig count during 2009. These declines, coupled with natural gas storage levels reaching record levels, resulted in severe margin contraction in 2009. Beginning in the fourth quarter of 2009 and continuing through the first quarter of 2010, we saw a rebound in rig count and drilling activity with the trend toward more service-intensive work, especially in shale plays, resulting in absorption of much of the industry’s excess oilfield equipment capacity. As a result of our improved equipment utilization, we achieved price and margin increases from the fourth quarter for most of our services. However, new production resulting from this increased activity, coupled with natural gas storage volumes exiting the heating season at levels above the five-year average, have weakened natural gas prices, which could negatively impact drilling activity in coming quarters.

Outside of North America, operating income declined in 2009 from 2008 levels due to a drop in rig count and the impact of pricing concessions that were renegotiated or given in the contract retendering process. During the first quarter of 2010, as expected, we experienced margin contraction due to declines related to this contract repricing, weather-related issues, project delays, and lower activity in certain key markets. However, despite tempered activity levels in the first quarter, our current visibility to multiple projects and some momentum in project activity lead us to believe that a resurgence may occur in the latter half of 2010 and into 2011.

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

Financial markets, liquidity, and capital resources

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

LIQUIDITY AND CAPITAL RESOURCES

We ended the first quarter of 2010 with cash and equivalents of $1.4 billion compared to $2.1 billion at December 31, 2009.

Significant sources of cash

Cash flows from operating activities contributed $317 million to cash in the first quarter of 2010.

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 March 31, 2010. In addition, we have $1.8 billion in United States Treasury securities that will be maturing at various dates through November 2010.

Significant uses of cash

Capital expenditures were $404 million in the first quarter of 2010 and were predominantly made in the production enhancement, drilling services, wireline and perforating, and cementing product service lines.

During the first quarter of 2010, we purchased approximately $500 million in United States Treasury securities, with varying maturity dates.

We paid $113 million to acquire various companies during the first quarter of 2010 that will enhance or augment our current portfolio of products and services.

We paid $81 million in dividends to our shareholders in the first quarter of 2010.

We paid $47 million to the Department of Justice (DOJ) in the first quarter of 2010 related to the settlement with them and under the indemnity provided to KBR, Inc. (KBR) upon separation.

Future uses of cash. Capital spending for 2010 is expected to be approximately $2.0 billion. The capital expenditures plan for 2010 is primarily directed toward our production enhancement, drilling services, 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.

In April 2010, we entered into a definitive merger agreement to acquire Boots & Coots, Inc. in a stock and cash transaction valued at approximately $250 million. Upon closing, we will combine our existing hydraulic workover and pipeline and coiled tubing services in our Completion and Production segment with Boots and Coots’ well intervention and pressure control capabilities. Under the merger agreement, Boots & Coots stockholders will receive $3.00 per share for each share of Boots & Coots common stock they hold, comprised of $1.73 in cash, which we will pay out of available cash and equivalents, and $1.27 in Halliburton common stock, subject to election, proration features, and an exchange ratio based on Halliburton’s five-day average share price prior to closing as further described in the merger agreement. The completion of the transaction will be subject to approval by Boots & Coots’ stockholders, regulatory approvals, and other customary closing conditions.

We are currently exploring other 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.

We currently intend to retire our $750 million principal amount of 5.5% senior notes at maturity in October 2010 with available cash and equivalents.

As a result of the resolution of the DOJ and Securities and Exchange Commission (SEC) Foreign Corrupt Practices Act (FCPA) investigations, we will pay a total of $95 million in equal installments during the second and third quarters of 2010 for the settlement with the DOJ and under the indemnity provided to KBR upon separation. See Notes 5 and 6 to our condensed consolidated financial statements for more information.

Subject to Board of Directors approval, we expect to pay quarterly dividends of approximately $80 million during 2010. We also have approximately $1.8 billion remaining available under our share repurchase authorization, which may be used for open market share purchases.

Other factors affecting liquidity

Guarantee arrangements. In the normal course of business, we have agreements with financial institutions under which approximately $1.6 billion of letters of credit, bank guarantees, or surety bonds were outstanding as of March 31, 2010, including $214 million of surety bonds related to Venezuela. In addition, $303 million of the total $1.6 billion relates to KBR letters of credit, bank guarantees, or surety bonds 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 $1.4 billion of cash and equivalents and $1.8 billion in investments in marketable securities as of March 31, 2010 provide 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. Although a portion of earnings from our foreign subsidiaries is reinvested overseas indefinitely, we do not consider this to have a significant impact on our liquidity.

In addition, we manage our cash investments by investing principally in United States Treasury securities and in investment funds that principally hold 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 a delay in receiving payment on our receivables from one of our primary customers in Venezuela. However, during the fourth quarter of 2009, we reached a settlement with this customer and received payment on approximately one-third of our outstanding receivables. 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 natural gas companies worldwide. We serve the upstream oil and natural gas industry throughout the lifecycle of the reservoir, from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production throughout the life of the field. Our two business segments are the Completion and Production segment and the Drilling and Evaluation segment. The industries we serve are highly competitive with many substantial competitors in each segment. In the first quarter of 2010, based upon the location of the services provided and products sold, 41% of our consolidated revenue was from the United States. In the first quarter of 2009, 40% 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 natural gas companies. Also impacting our activity is the status of the global economy, which impacts oil and natural gas consumption. See “Risk Factors—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
	March 31				December 31
Average Oil Prices (dollars per barrel)	2010		2009		2009
West Texas Intermediate	$	78.64	$	42.91	$	61.65
United Kingdom Brent		76.25		44.43		61.49

Average United States Gas Prices (dollars per thousand
cubic feet, or mcf)
Henry Hub	$	5.30	$	4.71	$	4.06

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

	Three Months Ended				Year Ended
	March 31				December 31
Land vs. Offshore	2010		2009		2009
United States:
Land		1,300		1,270		1,042
Offshore (incl. Gulf of Mexico)		45		56		44
Total		1,345		1,326		1,086
Canada:
Land		466		327		220
Offshore		4		1		1
Total		470		328		221
International (excluding Canada):
Land		768		743		722
Offshore		295		282		275
Total		1,063		1,025		997
Worldwide total		2,878		2,679		2,304
Land total		2,534		2,340		1,984
Offshore total		344		339		320

	Three Months Ended				Year Ended
	March 31				December 31
Oil vs. Natural Gas		2010		2009		2009
United States (incl. Gulf of Mexico):
Oil		456		281		282
Natural gas		889		1,045		804
Total		1,345		1,326		1,086
Canada:
Oil		256		125		102
Natural gas		214		203		119
Total		470		328		221
International (excluding Canada):
Oil		810		807		776
Natural gas		253		218		221
Total		1,063		1,025		997
Worldwide total		2,878		2,679		2,304
Oil total		1,522		1,213		1,160
Natural gas total		1,356		1,466		1,144

	Three Months Ended				Year Ended
	March 31				December 31
Drilling Type	2010		2009		2009
United States (incl. Gulf of Mexico):
Horizontal		663		491		455
Vertical		459		574		431
Directional		223		261		200
Total		1,345		1,326		1,086

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.

During the latter portion of 2008 and throughout much of 2009, there was an unprecedented decline in oil and natural prices and demand for our services due to the worldwide recession. Since then, prices have rebounded. According to the International Energy Agency’s (IEA) April 2010 “Oil Market Report,” 2010 world petroleum demand is forecasted to increase 2% over 2009 levels. Despite the reduction in demand from peak levels in 2008 due to the worldwide recession, 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 2009, the region experienced an unprecedented decline in rig count and drilling activity due to the decline in natural gas prices. Beginning in the fourth quarter of 2009 and continuing through the first quarter of 2010, drilling activity has improved. As of March 31, 2010, rig counts had increased approximately 20% from the end of 2009. Horizontal-directed drilling activity is now higher than peak levels in 2008. These trends have led to increased demand for our products and services and provided opportunities for price increases during the quarter as increased completions intensity in unconventional shale plays has resulted in absorption of much of the industry’s excess oilfield equipment capacity. However, new production resulting from this increased activity, coupled with natural gas storage volumes exiting the heating season at levels above the five-year average, have weakened natural gas prices, which could negatively impact drilling activity in coming quarters.

International operations

Consistent with our long-term strategy to grow our operations outside of North America, we expect to continue to invest capital in our international operations. During 2009, operating income declined from 2008 levels due to a drop in rig count and the impact of pricing concessions that were renegotiated or given in the contract retendering process. During the first quarter of 2010, as expected, we experienced margin contraction due to declines related to this contract repricing, weather-related issues, project delays, and lower activity in certain key markets. However, despite tempered activity levels in the first quarter, our current visibility to multiple projects and some momentum in project activity lead us to believe that a resurgence may occur in the latter half of 2010 and into 2011.

Venezuela. We historically had remeasured our net Bolívar Fuerte-denominated monetary asset position at the official, fixed exchange rate of 2.15 Bolívar Fuerte to United States dollar. In January 2010, the Venezuelan government announced a devaluation of the Bolívar Fuerte under a new two-exchange rate system; a 2.6 Bolívar Fuerte to United States dollar rate for essential products and a 4.3 Bolívar Fuerte to United States dollar rate for non-essential products. In the first quarter of 2010, as a result of the devaluation, we recorded a foreign exchange loss of $31 million, which was not tax deductible in Venezuela. We also recorded $10 million of additional tax expense for local Venezuelan income tax purposes as a result of a taxable gain on our net United States dollar-denominated monetary asset position in the country. We are now utilizing the 4.3 Bolívar Fuerte to United States dollar exchange rate.

Initiatives, recent contract awards, and acquisitions

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

-	increasing our market share in more economic, unconventional shale plays and deepwater markets by leveraging our broad technology offerings to provide value to our customers through integrated solutions and the ability to more efficiently drill and complete their wells;
-	making key investments in technology and capital to accelerate growth opportunities;
-	improving working capital, operating within our cash flow, and managing our balance sheet to maximize our financial flexibility;
-	continuing to seek ways to be one of the most cost efficient service providers in the industry by using our scale and breadth of operations; and
-	expanding our business with national oil companies.

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

-	an offshore, multi-services contract in Angola valued at approximately $1.3 billion for the provision of cementing, production enhancement, completion tools, wireline, and perforating services;
-	a contract valued at approximately $750 million from a major exploration and production company for stimulation services in the Williston basin;
-	a two-year contract, plus options, with ConocoPhillips China Inc., valued at approximately $40 million, which includes provisions for directional-drilling and logging-while-drilling services on the Peng Lai Development in China's Bohai Bay; and
-	frac pack and gravel pack completions awards in Brazil.

We continue to be active in acquiring complementary businesses with differentiated solutions that fit our core technology themes. Thus far in 2010, we have signed definitive agreements on five oilfield service acquisitions including the following:

-	Boots & Coots – well intervention and pressure control services, which is still subject to approval by Boots and Coots’ stockholders, regulatory approvals, and other customary closing conditions;
-	Tierra Geophysical – 3D wave equation modeling and depth imaging seismic processing solutions that enhance sub-salt and wide azimuth imaging;
-	Wellbore Energy Solutions – wellbore cleaning services that are critical in completing complicated, tortuous path, deepwater wellbores;
-	Diamond Rotating Heads – rotating control devices utilized during underbalanced and managed pressure drilling applications; and
-	Watertectonics – wellsite processing of fresh water and flowback for reuse in hydraulic fracturing applications.

RESULTS OF OPERATIONS IN 2010 COMPARED TO 2009

Three Months Ended March 31, 2010 Compared with Three Months Ended March 31, 2009

	Three Months Ended
REVENUE:	March 31				Increase			Percentage
Millions of dollars	2010		2009		(Decrease)			Change
Completion and Production	$	1,964	$	2,028	$	(64	)		(3	)%
Drilling and Evaluation		1,797		1,879		(82	)		(4	)
Total revenue	$	3,761	$	3,907	$	(146	)		(4	)%

By geographic region:
Completion and Production:
North America	$	1,125	$	1,071	$	54		5	%
Latin America		202		232		(30	)	(13	)
Europe/Africa/CIS		385		426		(41	)	(10	)
Middle East/Asia		252		299		(47	)	(16	)
Total		1,964		2,028		(64	)	(3	)
Drilling and Evaluation:
North America		579		612		(33	)	(5	)
Latin America		293		324		(31	)	(10	)
Europe/Africa/CIS		535		542		(7	)	(1	)
Middle East/Asia		390		401		(11	)	(3	)
Total		1,797		1,879		(82	)	(4	)
Total revenue by region:
North America		1,704		1,683		21		1
Latin America		495		556		(61	)	(11	)
Europe/Africa/CIS		920		968		(48	)	(5	)
Middle East/Asia		642		700		(58	)	(8	)

	Three Months Ended
OPERATING INCOME:	March 31						Increase			Percentage
Millions of dollars	2010			2009			(Decrease)			Change
Completion and Production	$	238		$	363		$	(125	)		(34	)%
Drilling and Evaluation		270			304			(34	)		(11	)
Corporate and other		(59	)		(51	)		(8	)		(16	)
Total operating income	$	449		$	616		$	(167	)		(27	)%

By geographic region:
Completion and Production:
North America	$	137	$	166	$	(29	)	(17	)%
Latin America		29		54		(25	)	(46	)
Europe/Africa/CIS		39		77		(38	)	(49	)
Middle East/Asia		33		66		(33	)	(50	)
Total		238		363		(125	)	(34	)
Drilling and Evaluation:
North America		93		64		29		45
Latin America		17		54		(37	)	(69	)
Europe/Africa/CIS		91		91		–		–
Middle East/Asia		69		95		(26	)	(27	)
Total		270		304		(34	)	(11	)
Total operating income by region
(excluding Corporate and other):
North America		230		230		–		–
Latin America		46		108		(62	)	(57	)
Europe/Africa/CIS		130		168		(38	)	(23	)
Middle East/Asia		102		161		(59	)	(37	)

The 4% decline in consolidated revenue in the first quarter of 2010 compared to the first quarter of 2009 was due to a reduction in drilling activity in certain international regions, primarily Latin America and Middle East/Asia. These declines were partially offset by increases in drilling activity in North America due primarily to increased horizontal-directed drilling activity. Revenue outside North America was 55% of consolidated revenue in the first quarter of 2010 and 57% of consolidated revenue in the first quarter of 2009.

The decrease in consolidated operating income compared to the first quarter of 2009 was primarily a result of significant decreases in our Completion and Production segment, driven by decreased international rig activity in certain regions and the impact of pricing concessions that were renegotiated or given in the contract retendering process.

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

Completion and Production decrease in revenue compared to the first quarter of 2009 was a result of activity declines in Latin America, Europe/Africa/CIS, and Middle East/Asia. North America revenue increased 5% due to an increase in demand for production enhancement services in United States land. In addition, Canada experienced increases in demand for cementing and production enhancement services. Latin America revenue decreased 13% as cementing and production enhancement services activity decreased in Mexico and Venezuela. Europe/Africa/CIS revenue declined 10% as lower demand for production enhancement services in the United Kingdom and lower direct sales for completion tools in Nigeria outweighed higher cementing activity in Norway. Middle East/Asia revenue decreased 16% largely due to a decrease in demand for all products and services in both the Middle East and Asia Pacific. Revenue outside of North America was 43% of total segment revenue in the first quarter of 2010 and 47% of total segment revenue in the first quarter of 2009.

Completion and Production segment operating income declines compared to the first quarter of 2009 were seen across all regions. In North America, operating income fell 17% largely due to price declines across all product lines from first quarter of 2009 levels. However, Canada showed small increases in all product service lines due to increased demand. Latin America operating income decreased 46% due to lower demand and higher costs across all product service lines throughout the region. Europe/Africa/CIS operating income declined 49% due to lower demand and higher costs for production enhancement services in the North Sea and Algeria and also lower demand for completion tools throughout the region. Middle East/Asia operating income decreased 50%, primarily due to lower demand and higher costs for production enhancement services throughout the region and lower demand for completion tools in China and India.

Drilling and Evaluation revenue declined compared to the first quarter of 2009, primarily due to pricing declines and lower drilling activity in North America, Latin America, and Middle East/Asia. North America revenue fell 5% on decreased demand for drilling fluid services and drilling services in United States land. Latin America revenue declined 10% as higher activity across all product service lines in Brazil was outweighed by activity declines in Venezuela and Mexico. Europe/Africa/CIS revenue remained essentially flat as lower demand for drilling fluid services and wireline and perforating services in Africa was offset by increased demand for all products and services in Norway. Middle East/Asia revenue fell 3% as decreased demand for drilling services in Saudi Arabia and most products and services in Indonesia outweighed increased demand for drilling fluid services and wireline and perforating services in Kuwait and Australia. Revenue outside of North America was 68% of total segment revenue in the first quarter of 2010 and 67% of total segment revenue in the first quarter of 2009.

The decrease in Drilling and Evaluation operating income compared to the first quarter of 2009 was due to lower activity and pricing declines. North America operating income increased 45%, primarily due to an improved cost structure across the region. Latin America operating income fell 69% primarily due to decreased demand across most product service lines in Mexico and pricing declines in Columbia. The Europe/Africa/CIS region operating income remained flat as increased demand for drilling fluid services and drilling services in Europe were offset by decreased demand for wireline and perforating services in Africa. Middle East/Asia operating income decreased 27% over the first quarter of 2009 due to a decline in drilling activity in Saudi Arabia and Indonesia.

Corporate and other expenses were $59 million in the first quarter of 2010 compared to $51 million in the first quarter of 2009. The 16% increase was primarily related to higher legal and environmental costs in the first quarter of 2010.

NONOPERATING ITEMS

Interest expense increased $26 million in the first quarter of 2010 compared to the first quarter of 2009 primarily due to the issuance of $2 billion in senior notes during March of 2009.

Other, net in the first three months of 2010 included a $31 million foreign exchange loss associated with the devaluation of the Venezuelan Bolívar Fuerte.

Provision for income taxes on continuing operations in the first quarter of 2010 of $121 million resulted in an effective tax rate of 36% compared to an effective tax rate on continuing operations of 32% in the first quarter of 2009. The higher effective tax rate in the first quarter of 2010 was primarily due to the non tax-deductibility of the $31 million foreign exchange loss related to the devaluation in Venezuela. Also, as a result of the devaluation, we recognized $10 million of additional tax expense for local Venezuelan income tax purposes due to a taxable gain on our net United States dollar-denominated monetary asset position in the country.

ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. For information related to environmental matters, see Note 6 to the condensed consolidated financial statements and “Risk Factors—Environmental requirements.”

NEW ACCOUNTING PRONOUNCEMENTS

In October 2009, the FASB issued an update to existing guidance on revenue recognition for arrangements with multiple deliverables. This update will allow companies to allocate consideration received for qualified separate deliverables using estimated selling price for both delivered and undelivered items when vendor-specific objective evidence or third-party evidence is unavailable. Additional disclosures discussing the nature of multiple element arrangements, the types of deliverables under the arrangements, the general timing of their delivery, and significant factors and estimates used to determine estimated selling prices are required. We will adopt this update for new revenue arrangements entered into or materially modified beginning January 1, 2011. We do not expect the provisions of this update to have a material 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.

RISK FACTORS

While it is not possible to identify all risk factors, we continue to face many risks and uncertainties that could cause actual results to differ from our forward-looking statements and could otherwise have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

The risk factors discussed below update the risk factors previously disclosed in our 2009 Annual Report on Form 10-K.

TSKJ Matters

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

At this time, other than the claims being considered by the SFO, no claims by governmental authorities in foreign jurisdictions have been asserted against the indemnified parties. 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 and its majority-owned subsidiaries related to these matters. An adverse determination or result against us or any party indemnified by us in any investigation or third-party claim related to these FCPA matters could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. See Note 5 to our condensed consolidated financial statements for additional information.

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. Initial estimates by KBR indicated that costs of these various solutions ranged up to $148 million. In March 2006, Petrobras commenced arbitration against KBR claiming $220 million plus interest for the cost of monitoring and replacing the defective bolts and all related costs and expenses of the arbitration, including the cost of attorneys’ fees. We understand KBR is vigorously defending this matter and 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 arbitration panel set the final hearing on liability and damages for early May 2010. Our estimation of the indemnity obligation regarding the Barracuda-Caratinga arbitration is recorded as a liability in our condensed consolidated financial statements as of March 31, 2010 and December 31, 2009. An adverse determination or result against KBR in the arbitration could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. See Note 5 to our condensed consolidated financial statements for additional information regarding the KBR indemnification.

Environmental Requirements

Changes in environmental requirements may negatively impact demand for our services. For example, oil and natural gas exploration and production may decline as a result of environmental requirements (including land use policies responsive to environmental concerns). State, national, and international governments and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could have an adverse effect on our results of operations, liquidity, and financial condition.

We are a leading provider of hydraulic fracturing services, a process that creates fractures extending from the well bore through the rock formation to enable natural gas or oil to move more easily through the rock pores to a production well. Bills pending in the United States House and Senate have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process. This legislation, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays and increased operating costs. During the first quarter of 2010, the United States Environmental Protection Agency announced it will begin a detailed scientific study of hydraulic fracturing and the alleged effect on surface and ground water. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have an adverse impact on our future results of operations, liquidity, and financial condition.

Exploration and Production Activity

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. Demand is directly affected by trends in oil and natural gas prices, which, historically, have been volatile and are likely to continue to be volatile.

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other economic factors that are beyond our control. 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 natural gas companies can similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects.

The recent worldwide recession has reduced the levels of economic activity and the expansion of industrial business operations. This has negatively impacted worldwide demand for energy, resulting in lower oil and natural gas prices, a lowering of the level of exploration, development, and production activity, and a corresponding decline in the demand for our well services and products. This reduction in demand could continue through 2010 and beyond, which could have an adverse effect on revenue and profitability.

Factors affecting the prices of oil and natural gas include:

-	governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;
-	global weather conditions and natural disasters;
-	worldwide political, military, and economic conditions;
-	the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;
-	oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
-	the cost of producing and delivering oil and natural gas;
-	Potential acceleration of development of alternative fuels; and
-	the level of supply and demand for oil and natural gas, especially demand for natural gas in the United States.

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 legislation is not applicable to our company.

However, we continue to see a delay in receiving payment on our receivables from our primary customer in Venezuela. If our customer further delays in paying or fails 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.

As of March 31, 2010, our total net investment in Venezuela was approximately $200 million. In addition to this amount, we also have $214 million of surety bond guarantees outstanding relating to our Venezuelan operations.

We historically had remeasured our net Bolívar Fuerte-denominated monetary asset position at the official, fixed exchange rate of 2.15 Bolívar Fuerte to United States dollar. In January 2010, the Venezuelan government announced a devaluation of the Bolívar Fuerte under a new two-exchange rate system: a 2.6 Bolívar Fuerte to United States dollar rate for essential products and a 4.3 Bolívar Fuerte to United States dollar rate for non-essential products.

The future results of our Venezuelan operations will be affected by many factors, including our ability to take actions to mitigate the effect of the devaluation, further actions of the Venezuelan government, and general economic conditions such as continued inflation and future customer payments and spending.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk, see Item 7(a), “Quantitative and Qualitative Disclosures About Market Risk,” in our 2009 Annual Report on Form 10-K. Our exposure to market risk has not changed materially since December 31, 2009.

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 March 31, 2010 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 March 31, 2010 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 5 and 6 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 March 31, 2010.

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

January 1-31

99,863

31.67

–

February 1-28

14,942

29.52

–

March 1-31

5,614

31.21

–

Total

120,419

31.39

–

(a)

All of the 120,419 shares purchased during the three-month period ended March 31, 2010 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. [Removed and Reserved]

Item 5. Other Information

None.

Item 6. Exhibits

2.1	Agreement and Plan of Merger dated April 9, 2010, by and among Halliburton Company,
	Gradient, LLC, and Boots & Coots, Inc. (incorporated by reference to Exhibit 2.1 to
	Halliburton’s Form 8-K filed April 12, 2010, File No. 1-3492).

* 10.1	Resignation, General Release, and Settlement Agreement (David S. King).

* 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.

** 101.INS	XBRL Instance Document

** 101.SCH	XBRL Taxonomy Extension Schema Document

** 101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

** 101.LAB	XBRL Taxonomy Extension Label Linkbase Document

** 101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document


*	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: April 22, 2010

	Three Months Ended March 31		Year Ended December 31
	2010		2009		2008		2007		2006
Earnings available for fixed charges:
Income from continuing operations
before income taxes and noncontrolling interest	$	333	$	1,682	$	3,849	$	3,447	$	3,186
Add:
Distributed earnings from equity in
unconsolidated affiliates		1		17		30		43		28
Fixed charges		95		361		232		222		238
Subtotal		429		2,060		4,111		3,712		3,452
Less:
Equity in earnings of
unconsolidated affiliates		4		16		50		57		65
Total earnings available for fixed charges	$	425	$	2,044	$	4,061	$	3,655	$	3,387

Fixed charges:
Interest expense	$	79	$	297	$	167	$	168	$	179
Rental expense representative of interest		16		64		65		54		59
Total fixed charges	$	95	$	361	$	232	$	222	$	238

Ratio of earnings to fixed charges		4.5		5.7		17.5		16.5		14.2