Patterson-UTI Energy (PTEN) 10-Q 2010 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2010

or

o 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 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

DELAWARE	75-2504748
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
450 GEARS ROAD, SUITE 500
HOUSTON, TEXAS	77067
(Address of principal executive offices)	(Zip Code)

(281) 765-7100
(Registrant’s telephone number, including area code)

N/A
(Former name, former address and former fiscal year,
if changed since last report)

     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. Yesþ Noo

     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 Regulation S-T (section 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).

Yesþ           Noo

     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. (Check one):

Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

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

     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

     153,854,555 shares of common stock, $0.01 par value, as of May 3, 2010

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
	PART I — FINANCIAL INFORMATION
ITEM 1.	Financial Statements
	Unaudited consolidated balance sheets		1
	Unaudited consolidated statements of operations		2
	Unaudited consolidated statements of changes in stockholders’ equity		3
	Unaudited consolidated statements of cash flows		5
	Notes to unaudited consolidated financial statements		6
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		20
ITEM 4.	Controls and Procedures		20
	PART II — OTHER INFORMATION
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		21
ITEM 5.	Other Information		21
ITEM 6.	Exhibits		21
Signature			22
EX-10.3
EX-31.1
EX-32.1
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

     The following unaudited consolidated financial statements include all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim periods presented.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands, except share data)

	March 31,			December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	63,884		$	49,877
Accounts receivable, net of allowance for doubtful accounts of $9,887 and $10,911 at March 31, 2010 and December 31, 2009, respectively		178,574			164,498
Federal and state income taxes receivable		122,479			118,869
Inventory		9,354			6,941
Deferred tax assets, net		28,079			32,877
Assets held for sale		—			42,424
Other		40,355			41,782
Total current assets		442,725			457,268
Property and equipment, net		2,189,972			2,110,402
Goodwill		86,234			86,234
Deposits on equipment purchases		17,713			914
Other		6,854			7,334
Total assets	$	2,743,498		$	2,662,152
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	164,401		$	83,700
Accrued expenses		105,020			109,608
Total current liabilities		269,421			193,308
Deferred tax liabilities, net		380,966			381,656
Other		5,909			5,488
Total liabilities		656,296			580,452
Commitments and contingencies (see Note 10)
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $.01; authorized 300,000,000 shares with 180,816,010 and 180,828,773 issued and 153,576,049 and 153,610,785 outstanding at March 31, 2010 and December 31, 2009, respectively		1,808			1,808
Additional paid-in capital		785,691			781,635
Retained earnings		1,898,362			1,901,853
Accumulated other comprehensive income		20,321			14,996
Treasury stock, at cost, 27,239,961 shares and 27,217,988 shares at March 31, 2010 and December 31, 2009, respectively		(618,980	)		(618,592	)
Total stockholders’ equity		2,087,202			2,081,700
Total liabilities and stockholders’ equity	$	2,743,498		$	2,662,152

The accompanying notes are an integral part of these unaudited consolidated financial statements.

1

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands, except per share data)

	Three Months Ended
	March 31,
	2010			2009
Operating revenues:
Contract drilling	$	210,745		$	225,704
Pressure pumping		53,751			38,105
Oil and natural gas		7,102			4,400
Total operating revenues		271,598			268,209
Operating costs and expenses:
Contract drilling		135,146			126,321
Pressure pumping		39,131			30,440
Oil and natural gas		2,062			1,976
Depreciation, depletion and impairment		75,716			69,732
Selling, general and administrative		11,463			10,375
Net loss on asset disposals		249			211
Provision for bad debts		—			4,000
Total operating costs and expenses		263,767			243,055
Operating income		7,831			25,154
Other income (expense):
Interest income		187			61
Interest expense		(1,401	)		(447	)
Other		75			23
Total other income (expense)		(1,139	)		(363	)
Income before income taxes		6,692			24,791
Income tax expense (benefit):
Current		(4,417	)		(166	)
Deferred		6,923			9,122
Total income tax expense		2,506			8,956
Income from continuing operations		4,186			15,835
Income from discontinued operations, net of income taxes		—			368
Net income	$	4,186		$	16,203
Basic income per common share:
Income from continuing operations	$	0.03		$	0.10
Income from discontinued operations, net of income taxes	$	0.00		$	0.00
Net income	$	0.03		$	0.11
Diluted income per common share:
Income from continuing operations	$	0.03		$	0.10
Income from discontinued operations, net of income taxes	$	0.00		$	0.00
Net income	$	0.03		$	0.11
Weighted average number of common shares outstanding:
Basic		152,458			151,735
Diluted		153,122			151,829
Cash dividends per common share	$	0.05		$	0.05

The accompanying notes are an integral part of these unaudited consolidated financial statements.

2

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(unaudited, in thousands)

												Accumulated
	Common Stock					Additional						Other
	Number of					Paid-in			Retained			Comprehensive		Treasury
	Shares			Amount		Capital			Earnings			Income		Stock			Total
Balance, December 31, 2009		180,829		$	1,808	$	781,635		$	1,901,853		$	14,996	$	(618,592	)	$	2,081,700
Comprehensive income:
Net income		—			—		—			4,186			—		—			4,186
Foreign currency translation adjustment, net of tax of $2,814		—			—		—			—			5,325		—			5,325
Total comprehensive income		—			—		—			4,186			5,325		—			9,511
Issuance of restricted stock		12			—		—			—			—		—			—
Forfeitures of restricted stock		(43	)		—		—			—			—		—			—
Exercise of stock options		18			—		163			—			—		—			163
Stock-based compensation		—			—		4,126			—			—		—			4,126
Tax expense related to stock-based compensation		—			—		(233	)		—			—		—			(233	)
Payment of cash dividends		—			—		—			(7,677	)		—		—			(7,677	)
Purchase of treasury stock		—			—		—			—			—		(388	)		(388	)
Balance, March 31, 2010		180,816		$	1,808	$	785,691		$	1,898,362		$	20,321	$	(618,980	)	$	2,087,202

The accompanying notes are an integral part of these unaudited consolidated financial statements.

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(unaudited, in thousands)

												Accumulated
	Common Stock					Additional						Other
	Number of					Paid-in			Retained			Comprehensive			Treasury
	Shares			Amount		Capital			Earnings			Income			Stock			Total
Balance, December 31, 2008		180,192		$	1,801	$	765,512		$	1,970,824		$	5,774		$	(616,969	)	$	2,126,942
Comprehensive income:
Net income		—			—		—			16,203			—			—			16,203
Foreign currency translation adjustment, net of tax of $213		—			—		—			—			(368	)		—			(368	)
Total comprehensive income		—			—		—			16,203			(368	)		—			15,835
Issuance of restricted stock		17			—		—			—			—			—			—
Forfeitures of restricted stock		(9	)		—		—			—			—			—			—
Exercise of stock options		18			—		37			—			—			—			37
Stock-based compensation		—			—		4,694			—			—			—			4,694
Tax expense related to stock-based compensation		—			—		(591	)		—			—			—			(591	)
Payment of cash dividends		—			—		—			(7,655	)		—			—			(7,655	)
Purchase of treasury stock		—			—		—			—			—			(216	)		(216	)
Balance, March 31, 2009		180,218		$	1,801	$	769,652		$	1,979,372		$	5,406		$	(617,185	)	$	2,139,046

The accompanying notes are an integral part of these unaudited consolidated financial statements.

4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)

	Three Months Ended
	March 31,
	2010			2009
Cash flows from operating activities:
Net income	$	4,186		$	16,203
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and impairment		75,716			69,732
Provision for bad debts		—			4,000
Dry holes and abandonments		350			127
Deferred income tax expense		6,923			9,122
Stock-based compensation expense		4,126			4,614
Net loss on asset disposals		249			211
Tax expense related to stock-based compensation		(233	)		(591	)
Changes in operating assets and liabilities:
Accounts receivable		(25,732	)		194,907
Income taxes receivable/payable		(3,617	)		(1,152	)
Inventory and other assets		(2,248	)		4,604
Accounts payable		19,465			(73,601	)
Accrued expenses		(2,632	)		(23,529	)
Other liabilities		506			27
Net cash provided by operating activities of discontinued operations		10,687			9,630
Net cash provided by operating activities		87,746			214,304
Cash flows from investing activities:
Purchases of property and equipment		(108,938	)		(89,792	)
Proceeds from disposal of assets		288			404
Net cash provided by investing activities of discontinued operations		42,646			31
Net cash used in investing activities		(66,004	)		(89,357	)
Cash flows from financing activities:
Purchases of treasury stock		(388	)		(216	)
Dividends paid		(7,677	)		(7,655	)
Line of credit issuance costs		—			(5,548	)
Proceeds from exercise of stock options		163			37
Net cash used in financing activities		(7,902	)		(13,382	)
Effect of foreign exchange rate changes on cash		167			(500	)
Net increase in cash and cash equivalents		14,007			111,065
Cash and cash equivalents at beginning of period		49,877			81,223
Cash and cash equivalents at end of period	$	63,884		$	192,288
Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest expense	$	(1,700	)	$	(15	)
Income taxes	$	912		$	(264	)
Non-cash investing and financing activities:
Net increase in payables for purchases of property and equipment	$	62,235		$	20,063
Net (increase) decrease in deposits on equipment purchases	$	(16,798	)	$	20,417

The accompanying notes are an integral part of these unaudited consolidated financial statements.

5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Consolidation and Presentation

     The unaudited interim consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. (the “Company”) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any entity which would require consolidation.

     The unaudited interim consolidated financial statements have been prepared by management of the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included either on the face of the financial statements or herein are sufficient to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for a fair statement of the information in conformity with accounting principles generally accepted in the United States have been included. The Unaudited Consolidated Balance Sheet as of December 31, 2009, as presented herein, was derived from the audited consolidated balance sheet of the Company, but does not include all disclosures required by accounting principles generally accepted in the United States of America. These unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009. The results of operations for the three months ended March 31, 2010 are not necessarily indicative of the results to be expected for the full year.

     The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which uses the Canadian dollar as its functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity.

     Certain reclassifications have been made to the 2009 consolidated financial statements in order for them to conform with the 2010 presentation.

     The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value.

     The Company provides a dual presentation of its net income per common share in its unaudited consolidated statements of operations: Basic net income per common share (“Basic EPS”) and diluted net income per common share (“Diluted EPS”).

     Basic EPS excludes dilution and is computed by first allocating earnings between common stockholders and holders of non-vested shares of restricted stock. Basic EPS is then determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding during the period, excluding non-vested shares of restricted stock.

     Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted stock units is determined based on the treasury stock method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock.

6

     The following table presents information necessary to calculate income from continuing operations per share, income from discontinued operations per share and net income per share for the three months ended March 31, 2010 and 2009 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding, as their inclusion would have been anti-dilutive (in thousands, except per share amounts):

	Three Months Ended
	March 31,
	2010			2009
BASIC EPS:
Income from continuing operations	$	4,186		$	15,835
Adjust for income attributed to holders of non-vested restricted stock		(31	)		(141	)
Income from continuing operations attributed to common stockholders	$	4,155		$	15,694
Income from discontinued operations, net	$	—		$	368
Adjust for income attributed to holders of non-vested restricted stock		—			(3	)
Income from discontinued operations attributed to common stockholders	$	—		$	365
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		152,458			151,735
Basic income from continuing operations per common share	$	0.03		$	0.10
Basic income from discontinued operations per common share	$	0.00		$	0.00
Basic net income per common share	$	0.03		$	0.11
DILUTED EPS:
Income from continuing operations attributed to common stockholders	$	4,155		$	15,694
Add incremental earnings related to potential common shares		—			—
Adjusted income from continuing operations attributed to common stockholders	$	4,155		$	15,694
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		152,458			151,735
Add dilutive effect of potential common shares		664			94
Weighted average number of diluted common shares outstanding		153,122			151,829
Diluted income from continuing operations per common share	$	0.03		$	0.10
Diluted income from discontinued operations per common share	$	0.00		$	0.00
Diluted net income per common share	$	0.03		$	0.11
Potentially dilutive securities excluded as anti-dilutive		4,198			6,759

2. Discontinued Operations

     On January 20, 2010, the Company exited the drilling and completion fluids services business, which had previously been presented as one of the Company’s reportable operating segments. On that date, the Company’s wholly owned subsidiary, Ambar Lone Star Fluids Services LLC, completed the sale of substantially all of its assets, excluding billed accounts receivable. The sales price was approximately $42.6 million. Upon the Company’s exit from the drilling and completion fluids services business, the Company classified its drilling and completion fluids operating segment as a discontinued operation. Accordingly, the results of operations of this business have been reclassified and presented as results of discontinued operations for all periods presented in these consolidated financial statements. As of December 31, 2009, the assets to be disposed of were considered held for sale and were presented separately within current assets under the caption “Assets held for sale” in the consolidated balance sheet. Upon being classified as held for sale, the assets to be disposed of were adjusted to fair value less estimated costs to sell resulting in an impairment loss of $1.9 million. Due to the fact that the carrying value of the assets had been adjusted to net realizable value, no additional gain or loss was recognized in connection with the sale in the first quarter of 2010.

7

     Summarized operating results from discontinued operations for the three months ended March 31, 2010, and 2009 are shown below (in thousands):

	2010		2009
Drilling and completion fluids revenues	$	3,737	$	27,830
Income before income taxes	$	—	$	555
Income tax expense		—		(187	)
Income from discontinued operations	$	—	$	368

3. Stock-based Compensation

     The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the cost of share-based payments under the fair-value-based method. Share-based awards consist of equity instruments in the form of stock options, restricted stock or restricted stock units and have included service and, in certain cases, performance conditions. Additionally, share-based awards also include cash-settled performance unit awards which are accounted for as liability awards. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units vest.

     Stock Options.The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate the grant date fair values for stock options granted in the three month periods ended March 31, 2010 and 2009 follow:

	Three Months Ended
	March 31,
	2010			2009
Volatility		47.30	%		47.26	%
Expected term (in years)		5.00			4.00
Dividend yield		1.30	%		5.56	%
Risk-free interest rate		2.69	%		1.28	%

     Stock option activity from January 1, 2010 to March 31, 2010 follows:

				Weighted
				Average
	Underlying			Exercise
	Shares			Price
Outstanding at January 1, 2010		6,841,770		$	20.17
Granted		40,000		$	15.35
Exercised		(18,534	)	$	8.80
Cancelled		(10,000	)	$	13.17
Outstanding at March 31, 2010		6,853,236		$	20.18
Exercisable at March 31, 2010		5,417,444		$	21.28

     Restricted Stock.For all restricted stock awards to date, shares of common stock were issued when the awards were made. Non-vested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are paid on non-vested shares of restricted stock. For restricted stock awards made prior to 2008, the Company uses the “graded-vesting” attribution method to recognize periodic compensation cost over the vesting period. For restricted stock awards made in 2008 and thereafter, the Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

8

     Restricted stock activity from January 1, 2010 to March 31, 2010 follows:

				Weighted
				Average
				Grant Date
	Shares			Fair Value
Non-vested restricted stock outstanding at January 1, 2010		1,231,901		$	21.67
Granted		12,000		$	15.35
Vested		(121,230	)	$	29.89
Forfeited		(43,297	)	$	22.78
Non-vested restricted stock outstanding at March 31, 2010		1,079,374		$	20.63

     Restricted Stock Units.For all restricted stock unit awards made to date, shares of common stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on non-vested restricted stock units.

     Restricted stock unit activity from January 1, 2010 to March 31, 2010 follows:

			Weighted
			Average
			Grant Date
	Shares		Fair Value
Non-vested restricted stock units outstanding at January 1, 2010		16,167	$	26.81
Granted		—	$	—
Vested		—	$	—
Forfeited		—	$	—
Non-vested restricted stock units outstanding at March 31, 2010		16,167	$	26.81

     Performance Unit Awards.On April 28, 2009, the Company granted performance unit awards to certain executive officers (the “2009 Performance Units”). The 2009 Performance Units provide for those executive officers to receive a cash payment upon the achievement of certain performance goals established by the Company during a specified period. The performance period for the 2009 Performance Units is the period from April 1, 2009 through March 31, 2012, but can extend through March 31, 2014 in certain circumstances. The performance goals for the 2009 Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee of the Board of Directors. These goals are considered to be market conditions under the relevant accounting standards and the market conditions are factored into the determination of the fair value of the performance units. Generally, the recipients will receive a base payment if the Company’s total shareholder return is positive and, when compared to the peer group, is at or above the 25^th percentile but less than the 50^th percentile, two times the base if at or above the 50^th percentile but less than the 75^th percentile, and four times the base if at the 75^th percentile or higher. The total base amount with respect to the 2009 Performance Units is approximately $1.7 million. As the 2009 Performance Units are to be settled in cash at the end of the performance period, the Company’s pro-rated obligation is measured at estimated fair value at the end of each reporting period using a Monte Carlo simulation model. As of March 31, 2010 this pro-rated obligation was approximately $556,000.

4. Property and Equipment

     Property and equipment consisted of the following at March 31, 2010 and December 31, 2009 (in thousands):

	March 31,			December 31,
	2010			2009
Equipment	$	3,379,962		$	3,230,737
Oil and natural gas properties		97,029			93,354
Buildings		57,250			56,563
Land		9,795			9,795
		3,544,036			3,390,449
Less accumulated depreciation and depletion		(1,354,064	)		(1,280,047	)
Property and equipment, net	$	2,189,972		$	2,110,402

9

5. Business Segments

     The Company’s revenues, operating profits and identifiable assets are primarily attributable to three business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) the investment, on a working interest basis, in oil and natural gas properties. Each of these segments represents a distinct type of business. These segments have separate management teams which report to the Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. Separate financial data for each of our business segments is provided in the table below (in thousands):

	Three Months Ended
	March 31,
	2010			2009
Revenues:
Contract drilling (a)	$	211,477		$	225,822
Pressure pumping		53,751			38,105
Oil and natural gas		7,102			4,400
Total segment revenues		272,330			268,327
Elimination of intercompany revenues (a)		(732	)		(118	)
Total revenues	$	271,598		$	268,209
Income (loss) before income taxes:
Contract drilling	$	8,701		$	41,011
Pressure pumping		4,477			(875	)
Oil and natural gas		2,817			(3,556	)
		15,995			36,580
Corporate and other		(7,915	)		(11,215	)
Net loss on asset disposals (b)		(249	)		(211	)
Interest income		187			61
Interest expense		(1,401	)		(447	)
Other		75			23
Income from continuing operations before income taxes	$	6,692		$	24,791

	March 31,		December 31,
	2010		2009
Identifiable assets:
Contract drilling	$	2,270,085	$	2,129,567
Pressure pumping		218,051		213,094
Oil and natural gas		28,737		25,355
Corporate and other (c)		226,625		294,136
Total assets	$	2,743,498	$	2,662,152

(a)	Includes contract drilling intercompany revenues of approximately $732,000 and $118,000 for the three months ended March 31, 2010 and 2009, respectively.
(b)	Net gains or losses associated with the disposal of assets relate to corporate strategy decisions of the executive management group. Accordingly, the related gains or losses have been separately presented and excluded from the results of specific segments.
(c)	Corporate and other assets at December 31, 2009 primarily include identifiable assets associated with the Company’s former drilling and completion fluids segment as well as cash on hand and certain deferred Federal income tax assets. Corporate assets at March 31, 2010 primarily include cash on hand and certain deferred Federal income tax assets.

6. Goodwill

     Goodwill is evaluated at least annually to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing have been determined to be its operating segments.

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     As of March 31, 2010 and December 31, 2009, the Company had goodwill of $86.2 million, all in its contract drilling reporting unit. In the event that market conditions weaken, the Company may be required to record an impairment of goodwill in its contract drilling reporting unit in the future, and such impairment could be material.

7. Accrued Expenses

     Accrued expenses consisted of the following at March 31, 2010 and December 31, 2009 (in thousands):

	March 31,		December 31,
	2010		2009
Salaries, wages, payroll taxes and benefits	$	18,189	$	14,744
Workers’ compensation liability		62,166		66,015
Insurance, other than workers’ compensation		13,356		11,261
Sales, use and other taxes		7,325		10,975
Other		3,984		6,613
	$	105,020	$	109,608

8. Asset Retirement Obligation

     The Company records a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. This liability is included in the caption “other” in the liabilities section of the consolidated balance sheet. The following table describes the changes to the Company’s asset retirement obligations during the three months ended March 31, 2010 and 2009 (in thousands):

	Three Months Ended
	March 31,
	2010			2009
Balance at beginning of year	$	2,955		$	3,047
Liabilities incurred		47			48
Liabilities settled		(125	)		(37	)
Accretion expense		28			30
Revision in estimated costs of plugging oil and natural gas wells		—			14
Asset retirement obligation at end of period	$	2,905		$	3,074

9. Borrowings Under Revolving Credit Facility

     The Company has an unsecured revolving credit facility with a maximum borrowing capacity of $240 million, including a letter of credit sublimit of $150 million and a swing line sublimit of $40 million. In addition, the aggregate borrowing and letter of credit capacity under the revolving credit facility may, subject to the terms and conditions set forth therein including the receipt of additional commitments from lenders, be increased up to a maximum amount not to exceed $450 million.

     Interest is paid on the outstanding principal amount of revolving credit facility borrowings at a floating rate based on, at the Company’s election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on the Company’s debt to capitalization ratio. At March 31, 2010, the margin on LIBOR loans would have been 3.00% and the margin on base rate loans would have been 2.00%. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. This revolving credit facility includes various fees, including a commitment fee on the actual daily unused commitment. The commitment fee rate was 1.00% at March 31, 2010.

     There are customary representations, warranties, restrictions and covenants associated with the revolving credit facility. Financial covenants under the revolving credit facility provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. As of March 31, 2010, the maximum debt to capitalization ratio was 35% and the minimum interest coverage ratio was 3.00 to 1. The Company does not expect that the restrictions and covenants will impact its ability to operate or react to opportunities that might arise.

     As of March 31, 2010, the Company had no borrowings outstanding under the revolving credit facility. The Company had $45.9 million in letters of credit outstanding at March 31, 2010 and, as a result, had available borrowing capacity of approximately $194

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million at that date. Each domestic subsidiary of the Company has unconditionally guaranteed the existing and future obligations of the Company and each other guarantor under the revolving credit facility and related loan documents, as well as obligations of the Company and its subsidiaries under any interest rate swap contracts that may be entered into with lenders party to the revolving credit facility.

10. Commitments, Contingencies and Other Matters

     As of March 31, 2010, the Company maintained letters of credit in the aggregate amount of $45.9 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2010, no amounts had been drawn under the letters of credit.

     As of March 31, 2010, the Company had commitments to purchase approximately $168 million of major equipment.

     The Company is party to various legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition, results of operations or cash flows.

11. Stockholders’ Equity

     Cash Dividends —The Company paid cash dividends during the three months ended March 31, 2009 and 2010 as follows:

	Per Share		Total
			(in thousands)
2009:
Paid on March 31, 2009	$	0.05	$	7,655
Total cash dividends	$	0.05	$	7,655

	Per Share		Total
			(in thousands)
2010:
Paid on March 30, 2010	$	0.05	$	7,677
Total cash dividends	$	0.05	$	7,677

     On April 28, 2010, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.05 per share to be paid on June 30, 2010 to holders of record as of June 15, 2010. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.

     On August 1, 2007, the Company’s Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of the Company’s common stock in open market or privately negotiated transactions. During the three months ended March 31, 2010, the Company did not purchase any shares of its common stock under the program. As of March 31, 2010, the Company is authorized to purchase approximately $113 million of the Company’s outstanding common stock under the program. Shares purchased under the program are accounted for as treasury stock.

     The Company purchased 21,973 shares of treasury stock from employees during the three months ended March 31, 2010. These shares were purchased at fair market value upon the vesting of restricted stock to provide the employees with the funds necessary to satisfy payroll tax withholding obligations. The total purchase price for these shares was approximately $388,000. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to the stock buyback program.

12. Income Taxes

     On January 1, 2010, the Company converted its Canadian operations from a Canadian branch to a controlled foreign corporation for Federal income tax purposes. Because the statutory tax rates in Canada are lower than those in the United States, this transaction triggered a $5.1 million reduction in the Company’s deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the Canadian assets.

     As a result of the above conversion, the Company’s Canadian assets are no longer subject to United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, the Company has elected to permanently reinvest these unremitted earnings in Canada, and it intends to do so for the foreseeable future. As a result, no deferred United States Federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $2.8 million as of March 31, 2010.

13. Recently Issued Accounting Standards

     In December 2008, the SEC issued a Final Rule,Modernization of Oil and Gas Reporting(“Final Rule”). The Final Rule revises certain oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act, and the Exchange Act, as well as Industry Guide 2. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. The disclosure requirements are effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. The Company applied the provisions of

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the Final Rule in connection with its December 31, 2009 oil and natural gas reserve estimation process. The application of the Final Rule did not have a material impact on the Company.

     In June 2009, the FASB issued a new accounting standard that amends the accounting and disclosure requirements for the consolidation of variable interest entities. This new standard removes the previously existing exception from applying consolidation guidance to qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this new standard, generally accepted accounting principles required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. This new standard is effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. This new standard became effective for the Company on January 1, 2010. The adoption of this standard did not impact the Company’s consolidated financial statements.

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DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

     This Quarterly Report on Form 10-Q (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; financing of operations; continued volatility of oil and natural gas prices; source and sufficiency of funds required for immediate capital needs and additional rig acquisitions (if further opportunities arise); impact of inflation; demand for our services; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts and often use words such as “believes,” “budgeted,” “continue,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Forward-looking statements may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act.

     Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, deterioration of global economic conditions, declines in oil and natural gas prices that could adversely affect demand for our services and their associated effect on day rates, rig utilization and planned capital expenditures, excess availability of land drilling rigs, including as a result of the reactivation or construction of new land drilling rigs, adverse industry conditions, adverse credit and equity market conditions, difficulty in integrating acquisitions, demand for oil and natural gas, shortages of rig equipment, governmental regulation and ability to retain management and field personnel. Refer to “Risk Factors” contained in Part 1 of our Annual Report on Form 10-K for the year ended December 31, 2009 for a more complete discussion of these and other factors that might affect our performance and financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes in internal estimates or otherwise.

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

     Management Overview— We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, pressure pumping services. In addition to the aforementioned contract services, we also invest, on a working interest basis, in oil and natural gas properties. Prior to the sale of substantially all of the assets of our drilling and completion fluids business in January 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators. Due to our exit from the drilling and completion fluids business in January 2010, we have presented the results of that operating segment as discontinued operations in this Report. For the three months ended March 31, 2010 and 2009, our operating revenues from continuing operations consisted of the following (dollars in thousands):

	Three Months Ended March 31,
	2010				2009
Contract drilling	$	210,745	77	%	$	225,704	84	%
Pressure pumping		53,751	20			38,105	14
Oil and natural gas		7,102	3			4,400	2
	$	271,598	100	%	$	268,209	100	%

     We provide our contract services to oil and natural gas operators in many of the oil and natural gas producing regions of North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia and western Canada, while our pressure pumping services are focused primarily in the Appalachian Basin. The oil and natural gas properties in which we hold interests are primarily located in Texas and New Mexico.

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     Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the first quarter of 2010, our average number of rigs operating was 142 compared to 127 in the first quarter of 2009. Our average revenue per operating day was $16,440 in the first quarter of 2010 compared to $19,670 in the first quarter of 2009. We had consolidated net income of $4.2 million for the first quarter of 2010 compared to consolidated net income of $16.2 million for the first quarter of 2009. The decrease in consolidated net income was primarily due to our contract drilling segment experiencing a decrease in average revenue per operating day and operating income, which was partially offset by increases in operating income in our pressure pumping and oil and natural gas segments in the first quarter of 2010 compared to the first quarter of 2009.

     Our revenues, profitability and cash flows are highly dependent upon prevailing prices for natural gas and, to a lesser extent, oil. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our contract services. Conversely, in periods when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services. Subsequent to reaching a peak in June 2008, there was a significant decline in oil and natural gas prices and a substantial deterioration in the global economic environment. As part of this deterioration, there was substantial uncertainty in the capital markets and access to financing was reduced. Due to these conditions, our customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our services, as evidenced by the decline in our monthly average of rigs operating from a high of 283 in October 2008 to a low of 60 in June 2009 before partially recovering to 146 in March 2010. Furthermore, these factors have resulted in, and could continue to result in, certain of our customers experiencing an inability to pay suppliers, including us. We are also highly impacted by competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” included as Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

     We believe that the liquidity shown on our balance sheet as of March 31, 2010, which includes approximately $173 million in working capital (including $63.9 million in cash) and approximately $194 million available under our $240 million revolving credit facility, together with cash expected to be generated from operations (including an expected Federal income tax refund in 2010 of approximately $114 million resulting from the carry-back of net operating losses), should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, expand into new regions and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

     Commitments and Contingencies— As of March 31, 2010, we maintained letters of credit in the aggregate amount of $45.9 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2010, no amounts had been drawn under the letters of credit.

     As of March 31, 2010, we had commitments to purchase approximately $168 million of major equipment.

     Trading and Investing— We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

     Description of Business— We conduct our contract drilling operations primarily in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia and western Canada. As of March 31, 2010, we had approximately 350 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We invest, on a working interest basis, in oil and natural gas properties. Prior to the sale of substantially all of the assets of our drilling and completion fluids business in January 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. Due to our exit from the drilling and completion fluids business in January 2010, we have presented the results of that operating segment as discontinued operations in this Report.

     The North American land drilling industry has experienced periods of downturn in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins and, at times, have sustained losses during the downturn periods.

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     In addition, exploration and development of unconventional resource plays has substantially increased recently and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs may be hampered by their lack of capability to successfully compete for this work. Other ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

• movement of drilling rigs from region to region,

• reactivation of land-based drilling rigs, or

• construction of new drilling rigs.

     Construction of new drilling rigs increased significantly during the last ten years. The addition of new drilling rigs to the market coupled with a decrease in demand has resulted in excess capacity. We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.

Critical Accounting Policies

     In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Liquidity and Capital Resources

     As of March 31, 2010, we had working capital of $173 million, including cash and cash equivalents of $63.9 million. During the three months ended March 31, 2010, our sources of cash flow included:

• $87.8 million from operating activities, and

• $42.6 million in proceeds from the disposal of our drilling and completion fluids business.

     During the three months ended March 31, 2010, we used $7.7 million to pay dividends on our common stock and $109 million to:

• build new drilling rigs,

• make capital expenditures for the betterment and refurbishment of our drilling rigs,

• acquire and procure drilling equipment and facilities to support our drilling operations,

• fund capital expenditures for our pressure pumping segment, and

• fund investments in oil and natural gas properties on a working interest basis.

     We paid cash dividends during the three months ended March 31, 2010 as follows:

	Per Share		Total
			(in thousands)
Paid on March 30, 2010	$	0.05	$	7,677
Total cash dividends	$	0.05	$	7,677

     On April 28, 2010, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on June 30, 2010 to holders of record as of June 15, 2010. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

     On August 1, 2007, our Board of Directors approved a stock buyback program, authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. During the three months ended March 31, 2010, we did not purchase any shares of our common stock under the program. As of March 31, 2010, we are authorized to purchase approximately $113 million of our outstanding common stock under the program.

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     We have an unsecured revolving credit facility with a maximum borrowing and letter of credit capacity of $240 million. Interest is paid on the outstanding principal amount of borrowings under the revolving credit facility at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on our debt to capitalization ratio. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. As of March 31, 2010, we had no borrowings outstanding under the revolving credit facility. We had $45.9 million in letters of credit outstanding at March 31, 2010 and as a result, had available borrowing capacity of approximately $194 million at such date.

     There are customary representations, warranties, restrictions and covenants associated with the revolving credit facility. Financial covenants under the revolving credit facility provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. As of March 31, 2010, the maximum debt to capitalization ratio was 35% and the minimum interest coverage ratio was 3.00 to 1. We were in compliance with these financial covenants as of March 31, 2010. We do not expect that the restrictions and covenants will impair our ability to operate or react to opportunities that might arise.

     We believe that the current level of cash, short-term investments and borrowing capacity available under our revolving credit facility, together with cash expected to be generated from operations (including an expected Federal income tax refund in 2010 of approximately $114 million resulting from the carry-back of net operating losses), should be sufficient to meet our current capital needs. From time to time, opportunities to expand our business, including acquisitions and the building of new equipment, are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Results of Operations

     The following tables summarize operations by business segment for the three months ended March 31, 2010 and 2009:

Contract Drilling	2010		2009		% Change
	(Dollars in thousands)
Revenues	$	210,745	$	225,704		(6.6	)%
Direct operating costs	$	135,146	$	126,321		7.0	%
Selling, general and administrative	$	1,232	$	986		24.9	%
Depreciation	$	65,666	$	57,386		14.4	%
Operating income	$	8,701	$	41,011		(78.8	)%
Operating days		12,821		11,473		11.7	%
Average revenue per operating day	$	16.44	$	19.67		(16.4	)%
Average direct operating costs per operating day	$	10.54	$	11.01		(4.3	)%
Average rigs operating		142		127		11.8	%
Capital expenditures	$	91,974	$	67,002		37.3	%

     Revenues decreased in 2010 compared to 2009 as a result of a significant decrease in the average revenue per operating day. Average revenue per operating day decreased in 2010 primarily due to decreases in dayrates for rigs that were operating in the spot market. Revenues in 2009 also included $6.6 million from the early termination of drilling contracts. We recognized no revenues from the early termination of drilling contracts in 2010. Direct operating costs increased in 2010 compared to 2009 as a result of an increase in the number of operating days. The increase in operating days was due to increased demand largely caused by higher commodity prices for natural gas and oil. Average direct operating costs per operating day decreased in 2010 primarily due to spreading fixed costs over a larger number of operating days. Significant capital expenditures were incurred in 2010 and 2009 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased as a result of capital expenditures.

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Pressure Pumping	2010		2009			% Change
	(Dollars in thousands)
Revenues	$	53,751	$	38,105			41.1	%
Direct operating costs	$	39,131	$	30,440			28.6	%
Selling, general and administrative	$	2,541	$	2,401			5.8	%
Depreciation	$	7,602	$	6,139			23.8	%
Operating income (loss)	$	4,477	$	(875	)		N/A	%
Total jobs		1,596		1,911			(16.5	)%
Average revenue per job	$	33.68	$	19.94			68.9	%
Average direct operating costs per job	$	24.52	$	15.93			53.9	%
Capital expenditures	$	9,413	$	21,820			(56.9	)%

     Our customers have increased their focus on the emerging development of unconventional reservoirs in the Appalachian Basin and the larger jobs associated therewith. As a result of this focus on unconventional reservoirs, we experienced a decrease in smaller traditional pressure pumping jobs, which contributed to the overall decrease in the number of total jobs. Revenues and direct operating costs increased as a result of the increase in average revenue and direct operating costs per job. Increased average revenue per job reflects an increase in the proportion of larger jobs to total jobs, which was driven by demand for services associated with unconventional reservoirs. Average direct operating costs per job increased due to the increase in larger jobs and as a result of fixed costs being spread over a reduced number of total jobs. Significant capital expenditures have been incurred in recent years to add capacity. Depreciation expense increased as a result of capital expenditures.

Oil and Natural Gas Production and Exploration	2010		2009			% Change
	(Dollars in thousands,
	except sales prices)
Revenues	$	7,102	$	4,400			61.4	%
Direct operating costs	$	2,062	$	1,976			4.4	%
Depreciation, depletion and impairment	$	2,223	$	5,980			(62.8	)%
Operating income (loss)	$	2,817	$	(3,556	)		N/A	%
Capital expenditures	$	5,627	$	970			480.1	%
Average net daily oil production (Bbls)		757		882			(14.2	)%
Average net daily natural gas production (Mcf)		3,174		3,508			(9.5	)%
Average oil sales price (per Bbl)	$	76.16	$	39.48			92.9	%
Average natural gas sales price (per Mcf)	$	6.71	$	4.01			67.3	%

     Revenues increased due to higher average sales prices of oil and natural gas partially offset by a reduction in the average net daily production of oil and natural gas. Average net daily oil and natural gas production decreased primarily due to production declines on existing wells. Direct operating costs increased primarily due to increased production taxes and other production costs. Depreciation, depletion and impairment expense in 2010 includes approximately $254,000 incurred to impair certain oil and natural gas properties compared to approximately $2.5 million incurred to impair certain oil and natural gas properties in 2009. Depletion expense decreased approximately $1.5 million primarily due to lower production and the impact of decreases in the carrying value of properties resulting from previous impairment charges. Capital expenditures increased in 2010 as a result of increases in commodity prices.

Corporate and Other	2010		2009		% Change
	(Dollars in thousands)
Selling, general and administrative	$	7,690	$	6,988		10.0	%
Depreciation	$	225	$	227		(0.9	)%
Provision for bad debts	$	—	$	4,000		(100.0	)%
Net loss on asset disposals	$	249	$	211		18.0	%
Interest income	$	187	$	61		206.6	%
Interest expense	$	1,401	$	447		213.4	%
Other income	$	75	$	23		226.1	%
Capital expenditures	$	1,924	$	—		N/A	%

     Selling, general and administrative expense increased in 2010 primarily as a result of increased professional fees. Provision for bad debts in 2009 resulted from an increase in our reserve on specific account balances based on the deteriorating economic and credit environment. No provision for bad debts was necessary in 2010. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. Interest expense increased in 2010 due to the amortization of revolving credit facility issuance costs and increased fees associated with

18

outstanding letters of credit and the unused portion of the revolving credit facility all resulting from the re-negotiation of our revolving credit facility in March 2009. Capital expenditures increased in 2010 due to the purchase and ongoing implementation of a new enterprise resource planning system.

Discontinued Operations:	2010		2009		% Change
	(Dollars in thousands)
Drilling and completion fluids revenue	$	3,737	$	27,830		(86.6	)%
Drilling and completion fluids direct operating costs	$	3,307	$	24,522		(86.5	)%
Drilling and completion fluids selling, general and administrative	$	264	$	2,175		(87.9	)%
Drilling and completion fluids depreciation	$	166	$	615		(73.0	)%
Net gain on asset disposals/retirements	$	—	$	37		(100.0	)%
Income tax expense	$	—	$	187		(100.0	)%
Income from discontinued operations, net of income taxes	$	—	$	368		(100.0	)%

     On January 20, 2010, we exited our drilling and completion fluids services business which had previously been presented as one of our reportable operating segments. On that date, our wholly owned subsidiary, Ambar Lone Star Fluids Services LLC, completed the sale of substantially all of its assets, excluding billed accounts receivable. Upon our exit from this business, we classified our drilling and completion fluids operating segment as a discontinued operation. Accordingly, the results of operations for this business have been reclassified for all periods presented.

Income Taxes

     On January 1, 2010, we converted our Canadian operations from a Canadian branch to a controlled foreign corporation for Federal income tax purposes. Because the statutory tax rates in Canada are lower than those in the United States, this transaction triggered a $5.1 million reduction in our deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the Canadian assets.

     As a result of the above conversion, our Canadian assets are no longer subject to United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, we have elected to permanently reinvest these unremitted earnings in Canada, and we intend to do so for the foreseeable future. As a result, no deferred United States Federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $2.8 million as of March 31, 2010.

Recently Issued Accounting Standards

     In December 2008, the SEC issued a Final Rule,Modernization of Oil and Gas Reporting(“Final Rule”). The Final Rule revises certain oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act, and the Exchange Act, as well as Industry Guide 2. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. The disclosure requirements are effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. We applied the provisions of the Final Rule in connection with our December 31, 2009 oil and natural gas reserve estimation process. The application of the Final Rule did not have a material impact on us.

     In June 2009, the FASB issued a new accounting standard that amends the accounting and disclosure requirements for the consolidation of variable interest entities. This new standard removes the previously existing exception from applying consolidation guidance to qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this new standard, generally accepted accounting principles required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. This new standard is effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. This new standard became effective for us on January 1, 2010. The adoption of this standard did not impact our consolidated financial statements.

Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

     Our revenue, profitability, financial condition and rate of growth are substantially dependent upon prevailing prices for natural gas and, to a lesser extent, oil. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC to set and maintain production and price targets. All of these factors are beyond our control. During 2008, the monthly average market price of natural gas (monthly average Henry Hub price as reported by the Energy Information Administration) peaked in June at $13.06 per Mcf before rapidly declining to an average of $5.99 per Mcf in December. In 2009, the monthly average market price of natural gas declined further to a low of $3.06 per Mcf in September. This decline in the market price of natural gas resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008 and drilling activities remained low throughout 2009 and into 2010. This reduction in demand combined with the reactivation and construction of new land drilling rigs in the United States during the last several years has resulted in excess capacity compared to demand. As a result of these factors, our average number of rigs operating has declined significantly from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for natural gas would likely result in demand for our drilling rigs remaining low and adversely affect our operating results, financial condition and cash flows.

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     The North American land drilling industry has experienced downturns in demand during the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

     We currently have exposure to interest rate market risk associated with any borrowings that we have under our revolving credit facility. Interest is paid on the outstanding principal amount of revolving credit facility borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00%, and the margin on base rate loans ranges from 2.00% to 3.00%, based on our debt to capitalization ratio. At March 31, 2010, the margin on LIBOR loans would have been 3.00% and the margin on base rate loans would have been 2.00%. As of March 31, 2010, we had no borrowings outstanding under our revolving credit facility.

     We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency risk is not material to our results of operations or financial condition.

     The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

ITEM 4. Controls and Procedures

     Disclosure Controls and Procedures— We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act), designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

     Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2010.

     Changes in Internal Control Over Financial Reporting—During the first quarter of 2010, we implemented the first phase of a new enterprise resource planning software system to replace our various legacy systems. We are modifying the design and documentation of internal control processes and procedures relating to the new system. We believe that the new system will strengthen our internal controls over financial reporting as additional phases are implemented; however, there are inherent risks in implementing any new system that could impact our financial reporting.

     In the event that issues arise, we have manual procedures in place which would facilitate our continued recording and reporting of results from the new system. However, because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     We will continue to monitor, test and appraise the impact and effect of the new system on our internal controls and procedures as additional phases and features of the system are implemented. There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting, except as described above.

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PART II — OTHER INFORMATION

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

     The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended March 31, 2010.

							Approximate Dollar
					Total Number of		Value of Shares
					Shares (or Units)		That May Yet Be
					Purchased as Part		Purchased Under the
	Total		Average Price		of Publicly		Plans or
	Number of Shares		Paid per		Announced Plans		Programs (in
Period Covered	Purchased		Share		or Programs		thousands)(1)
January 1-31, 2010 (2)		21,973	$	17.64		—	$	113,247
February 1-28, 2010		—	$	—		—	$	113,247
March 1-31, 2010		—	$	—		—	$	113,247
Total		21,973	$	17.64		—	$	113,247

(1)

On August 2, 2007, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions.

(2)

We purchased 21,973 shares from employees to provide the respective employees with the funds necessary to satisfy their tax withholding obligations with respect to the vesting of restricted shares. The price paid was the closing price of our common stock on the last business day prior to the date the shares vested. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to the stock buyback program.

ITEM 5. Other Information

          On April 27, 2010, the Compensation Committee of the Board of Directors of the Company granted performance unit awards to certain executive officers under the Company’s 2005 Long-Term Incentive Plan, as amended (the “2005 Plan”), for the performance period beginning April 1, 2010 and ending March 31, 2013 (the “2010 Performance Units”). The 2010 Performance Units provide an opportunity for those executive officers to receive an award of shares of Company common stock upon the achievement of certain performance goals established by the Compensation Committee during a specified period. The performance goals for the 2010 Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return of a peer group determined by the Compensation Committee. Total shareholder return for the Company will be measured based on $100 invested in the Company’s common stock on the first day of the performance period, with dividends reinvested. The recipients will receive a base number of shares if the Company’s total shareholder return is at or above the 25th percentile but less than the 50th percentile, two times the base if at or above the 50th percentile but less than the 75th percentile and four times the base if at the 75th percentile or higher. If the Company’s total shareholder return is between the 25th and 50th percentile or between the 50th and 75th percentile, the number of shares awarded will be adjusted on a linear basis. The base number of shares for Mark Siegel, Douglas Wall, John Vollmer and Kenneth Berns are 32,500, 24,375, 16,250 and 16,250, respectively.

          No award of shares will be made in respect of the 2010 Performance Units unless the Company has positive total shareholder return as of the end of the performance period; except, that if during the two year period ending March 31, 2015 the Company’s total shareholder return for any 30 consecutive day period equals or exceeds 18% on an annualize basis from April 1, 2010 through the end of such 30 consecutive day period, then share awards, if any, will be made as set forth above based on the Company’s total shareholder return relative to the peer group as of March 31, 2013.

          The foregoing description of the 2010 Performance Units does not purport to be complete and is qualified in its entirety by reference to (i) the 2005 Plan, as amended, which is listed as Exhibits 10.6, 10.7 and 10.8 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, and Exhibits 10.1 and 10.2 to the Company’s Current Report on Form 8-K filed April 27, 2010, all of which are incorporated herein by reference and (ii) the form of award agreement for the 2010 Performance Units, including terms and conditions, that will be filed by the Company with the SEC after the award agreements governing the awards are entered into between the Company and each of the executive officers referenced above.

ITEM 6. Exhibits

          The following exhibits are filed herewith or incorporated by reference, as indicated:

3.1	Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.2	Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.3	Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference).
10.1	Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
10.2	Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
10.3*	Form of Amendment to Cash-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan.
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
32.1*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	The following materials from Patterson-UTI Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Stockholders’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.

* filed herewith

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SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PATTERSON-UTI ENERGY, INC.
By:	/s/ Gregory W. Pipkin
	Gregory W. Pipkin
	(Principal Accounting Officer and Duly Authorized Officer) Chief Accounting Officer and Assistant Secretary

DATED: May 4, 2010

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