10-Q

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 September 30, 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 (State or other jurisdiction of incorporation or organization)	75-2504748 (I.R.S. Employer Identification No.)
450 GEARS ROAD, SUITE 500 HOUSTON, TEXAS (Address of principal executive offices)	77067 (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. Yes þ No o

     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 (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).

Yes þ No o

      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 filer þ  Accelerated filer o  Non-accelerated filer o
(Do not check if a smaller reporting company) Smaller reporting company o 

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

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

     154,126,195 shares of common stock, $0.01 par value, as of October 29, 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		16
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		25
ITEM 4. Controls and Procedures		25
PART II — OTHER INFORMATION
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		26
ITEM 6. Exhibits		26
Signature		28
EX-2.2
EX-2.3
EX-31.1
EX-31.2
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)

	September 30,			December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	73,916		$	49,877
Accounts receivable, net of allowance for doubtful accounts of $8,053 and $10,911 at September 30, 2010 and December 31, 2009, respectively		251,646			164,498
Federal and state income taxes receivable		4,635			118,869
Inventory		9,530			6,941
Deferred tax assets, net		62,313			32,877
Assets held for sale		—			42,424
Other		49,454			41,782
Total current assets		451,494			457,268
Property and equipment, net		2,397,218			2,110,402
Goodwill		86,234			86,234
Deposits on equipment purchases		49,860			914
Other		12,602			7,334
Total assets	$	2,997,408		$	2,662,152
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	181,134		$	83,700
Accrued expenses		125,869			109,608
Current portion of long term debt		5,000			—
Total current liabilities		312,003			193,308
Long term debt		95,000			—
Deferred tax liabilities, net		448,645			381,656
Other		7,621			5,488
Total liabilities		863,269			580,452
Commitments and contingencies (see Note 11)
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 181,461,796 and 180,828,773 issued and 154,118,246 and 153,610,785 outstanding at September 30, 2010 and December 31, 2009, respectively		1,814			1,808
Additional paid-in capital		791,265			781,635
Retained earnings		1,941,854			1,901,853
Accumulated other comprehensive income		19,646			14,996
Treasury stock, at cost, 27,343,550 shares and 27,217,988 shares at September 30, 2010 and December 31, 2009, respectively		(620,440	)		(618,592	)
Total stockholders’ equity		2,134,139			2,081,700
Total liabilities and stockholders’ equity	$	2,997,408		$	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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Operating revenues:
Contract drilling	$	290,759		$	112,294		$	741,470		$	439,714
Pressure pumping		81,104			41,687			194,219			113,408
Oil and natural gas		6,800			5,690			21,564			15,255
Total operating revenues		378,663			159,671			957,253			568,377
Operating costs and expenses:
Contract drilling		174,999			71,035			459,448			254,306
Pressure pumping		51,305			31,092			132,401			87,419
Oil and natural gas		1,484			1,780			5,326			5,576
Depreciation, depletion and impairment		85,431			69,582			239,930			207,571
Selling, general and administrative		13,685			11,384			37,491			33,213
Net gain on asset disposals		(250	)		(868	)		(21,940	)		(423	)
Provision for bad debts		(500	)		285			(1,500	)		6,035
Total operating costs and expenses		326,154			184,290			851,156			593,697
Operating income (loss)		52,509			(24,619	)		106,097			(25,320	)
Other income (expense):
Interest income		64			53			1,631			318
Interest expense		(6,227	)		(1,448	)		(9,011	)		(2,734	)
Other		260			228			509			263
Total other income (expense)		(5,903	)		(1,167	)		(6,871	)		(2,153	)
Income (loss) before income taxes		46,606			(25,786	)		99,226			(27,473	)
Income tax expense (benefit):
Current		(1,748	)		(2,677	)		(4,230	)		(5,231	)
Deferred		18,980			(6,295	)		40,368			(4,372	)
Total income tax expense (benefit)		17,232			(8,972	)		36,138			(9,603	)
Income (loss) from continuing operations		29,374			(16,814	)		63,088			(17,870	)
Loss from discontinued operations, net of income taxes		—			(1,766	)		—			(2,250	)
Net income (loss)	$	29,374		$	(18,580	)	$	63,088		$	(20,120	)
Basic income (loss) per common share:
Income (loss) from continuing operations	$	0.19		$	(0.11	)	$	0.41		$	(0.12	)
Loss from discontinued operations, net of income taxes	$	0.00		$	(0.01	)	$	0.00		$	(0.01	)
Net income (loss)	$	0.19		$	(0.12	)	$	0.41		$	(0.13	)
Diluted income (loss) per common share:
Income (loss) from continuing operations	$	0.19		$	(0.11	)	$	0.41		$	(0.12	)
Loss from discontinued operations, net of income taxes	$	0.00		$	(0.01	)	$	0.00		$	(0.01	)
Net income (loss)	$	0.19		$	(0.12	)	$	0.41		$	(0.13	)
Weighted average number of common shares outstanding:
Basic		152,933			152,242			152,682			151,975
Diluted		154,109			152,242			152,682			151,975
Cash dividends per common share	$	0.05		$	0.05		$	0.15		$	0.15

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		—			—		—			63,088			—		—			63,088
Foreign currency translation adjustment, net of tax of $2,814		—			—		—			—			4,650		—			4,650
Total comprehensive income		—			—		—			63,088			4,650		—			67,738
Issuance of restricted stock		646			6		(6	)		—			—		—			—
Vesting of stock unit awards		7			—		—			—			—		—			—
Forfeitures of restricted stock		(54	)		—		—			—			—		—			—
Exercise of stock options		34			—		290			—			—		—			290
Stock-based compensation		—			—		11,881			—			—		—			11,881
Tax expense related to stock-based compensation		—			—		(2,535	)		—			—		—			(2,535	)
Payment of cash dividends		—			—		—			(23,087	)		—		—			(23,087	)
Purchase of treasury stock		—			—		—			—			—		(1,848	)		(1,848	)
Balance, September 30, 2010		181,462		$	1,814	$	791,265		$	1,941,854		$	19,646	$	(620,440	)	$	2,134,139

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 loss		—			—		—			(20,120	)		—		—			(20,120	)
Foreign currency translation adjustment, net of tax of $4,183		—			—		—			—			7,214		—			7,214
Total comprehensive income		—			—		—			(20,120	)		7,214		—			(12,906	)
Issuance of restricted stock		604			6		(6	)		—			—		—			—
Vesting of restricted stock units		6			—		—			—			—		—			—
Forfeitures of restricted stock		(41	)		—		—			—			—		—			—
Exercise of stock options		61			1		378			—			—		—			379
Stock-based compensation		—			—		14,108			—			—		—			14,108
Tax expense related to stock-based compensation		—			—		(2,720	)		—			—		—			(2,720	)
Payment of cash dividends		—			—		—			(23,005	)		—		—			(23,005	)
Purchase of treasury stock		—			—		—			—			—		(1,623	)		(1,623	)
Balance, September 30, 2009		180,822		$	1,808	$	777,272		$	1,927,699		$	12,988	$	(618,592	)	$	2,101,175

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)

	Nine Months Ended
	September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	63,088		$	(20,120	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and impairment		239,930			207,571
Provision for bad debts		(1,500	)		6,035
Dry holes and abandonments		479			120
Deferred income tax expense		40,368			(4,372	)
Stock-based compensation expense		11,881			13,848
Net gain on asset disposals		(21,940	)		(423	)
Tax expense related to stock-based compensation		(2,535	)		(2,720	)
Changes in operating assets and liabilities:
Accounts receivable		(97,455	)		255,856
Income taxes receivable/payable		114,209			(116	)
Inventory and other assets		(6,864	)		7,738
Accounts payable		31,674			(79,466	)
Accrued expenses		18,227			(25,510	)
Other liabilities		2,218			(55	)
Net cash provided by operating activities of discontinued operations		10,687			55,122
Net cash provided by operating activities		402,467			413,508
Cash flows from investing activities:
Purchases of property and equipment		(513,679	)		(350,441	)
Proceeds from disposal of assets		27,224			3,173
Net cash provided by investing activities of discontinued operations		42,646			(54	)
Net cash used in investing activities		(443,809	)		(347,322	)
Cash flows from financing activities:
Purchases of treasury stock		(1,848	)		(1,623	)
Dividends paid		(23,087	)		(23,005	)
Debt issuance costs		(10,328	)		(6,169	)
Proceeds from long term debt		100,000			—
Proceeds from exercise of stock options		290			379
Net cash provided by (used in) financing activities		65,027			(30,418	)
Effect of foreign exchange rate changes on cash		354			2,252
Net increase in cash and cash equivalents		24,039			38,020
Cash and cash equivalents at beginning of period		49,877			81,223
Cash and cash equivalents at end of period	$	73,916		$	119,243
Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest expense	$	(3,031	)	$	(1,440	)
Income taxes	$	115,661		$	7,754
Supplemental investing and financing information:
Net increase (decrease) in payables for purchases of property and equipment	$	66,819		$	(12,235	)
Net (increase) decrease in deposits on equipment purchases	$	(48,946	)	$	43,944

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 and nine months ended September 30, 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 and nine months ended September 30, 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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
BASIC EPS:
Income (loss) from continuing operations	$	29,374		$	(16,814	)	$	63,088		$	(17,870	)
Adjust for (income) loss attributed to holders of non-vested restricted stock		(224	)		159			(476	)		170
Income (loss) from continuing operations attributed to common stockholders	$	29,150		$	(16,655	)	$	62,612		$	(17,700	)
Loss from discontinued operations, net	$	—		$	(1,766	)	$	—		$	(2,250	)
Adjust for income attributed to holders of non-vested restricted stock		—			16			—			20
Loss from discontinued operations attributed to common stockholders	$	—		$	(1,750	)	$	—		$	(2,230	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		152,933			152,242			152,682			151,975
Basic income (loss) from continuing operations per common share	$	0.19		$	(0.11	)	$	0.41		$	(0.12	)
Basic loss from discontinued operations per common share	$	0.00		$	(0.01	)	$	0.00		$	(0.01	)
Basic net income (loss) per common share	$	0.19		$	(0.12	)	$	0.41		$	(0.13	)
DILUTED EPS:
Income (loss) from continuing operations attributed to common stockholders	$	29,150		$	(16,655	)	$	62,612		$	(17,700	)
Add incremental earnings related to potential common shares		1			—			—			—
Adjusted income (loss) from continuing operations attributed to common stockholders	$	29,151		$	(16,655	)	$	62,612		$	(17,700	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		152,933			152,242			152,682			151,975
Add dilutive effect of potential common shares		1,176			—			—			—
Weighted average number of diluted common shares outstanding		154,109			152,242			152,682			151,975
Diluted income (loss) from continuing operations per common share	$	0.19		$	(0.11	)	$	0.41		$	(0.12	)
Diluted loss from discontinued operations per common share	$	0.00		$	(0.01	)	$	0.00		$	(0.01	)
Diluted net income (loss) per common share	$	0.19		$	(0.12	)	$	0.41		$	(0.13	)
Potentially dilutive securities excluded as anti-dilutive		4,644			8,204			6,726			8,204

2. Discontinued Operations

     On January 20, 2010, the Company exited the drilling and completion fluids 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 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 2010.

7

     Summarized operating results from discontinued operations for the three and nine months ended September 30, 2010, and 2009 are shown below (in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010		2009
Drilling and completion fluids revenues	$	—	$	16,488		$	3,737	$	64,585
Loss before income taxes	$	—	$	(2,666	)	$	—	$	(3,398	)
Income tax benefit		—		(900	)		—		(1,148	)
Loss from discontinued operations, net of income tax	$	—	$	(1,766	)	$	—	$	(2,250	)

3. Acquisitions

     On October 1, 2010, two subsidiaries of the Company, Universal Pressure Pumping, Inc. (“UPP”) and Universal Wireline, Inc. completed the acquisition of certain assets from Key Energy Pressure Pumping Services, LLC (“Key Pressure Pumping”) and Key Electric Wireline Services, LLC (together with Key Pressure Pumping, the “Sellers”) relating to the businesses of providing pressure pumping services and electric wireline services to participants in the oil and natural gas industry for an approximate aggregate purchase price of $238 million in cash (the “Purchase Price”). This acquisition expands the Company’s pressure pumping operations to additional markets primarily in Texas. The Purchase Price, which was funded through a combination of cash on hand and a $200 million draw on the Company’s revolving credit facility, is subject to certain adjustments based on closing inventory. The Company is in the process of determining the fair values of the assets acquired and liabilities assumed and the results of operations for these acquired businesses will be included in the Company’s consolidated results of operations beginning in the quarter ending December 31, 2010. The acquisition was effected pursuant to an Asset Purchase Agreement dated July 2, 2010, as amended, modified and supplemented, by and among Patterson-UTI Energy, Inc., UPP (formerly known as Portofino Acquisition Company), Sellers and Key Energy Services, Inc., a Maryland corporation.

4. 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 both cash-settled and share-settled performance unit awards. Cash-settled performance unit awards are accounted for as liability awards. Share-settled performance unit awards are accounted for as equity awards. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units and share-settled performance unit awards 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 and nine month periods ended September 30, 2010 and 2009 follow:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010			2009
Volatility		N/A		49.53	%		45.98	%		49.90	%
Expected term (in years)		N/A		4.00			5.00			4.00
Dividend yield		N/A		1.39	%		1.35	%		1.67	%
Risk-free interest rate		N/A		2.27	%		2.47	%		1.67	%

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     Stock option activity from January 1, 2010 to September 30, 2010 follows:

				Weighted
				Average
	Underlying			Exercise
	Shares			Price
Outstanding at January 1, 2010		6,841,770		$	20.17
Granted		1,016,250		$	14.85
Exercised		(33,868	)	$	8.56
Cancelled		(10,000	)	$	13.17
Expired		(77,000	)	$	19.46
Outstanding at September 30, 2010		7,737,152		$	19.54
Exercisable at September 30, 2010		5,930,096		$	20.86

     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.

     Restricted stock activity from January 1, 2010 to September 30, 2010 follows:

				Weighted
				Average
				Grant Date
	Shares			Fair Value
Non-vested restricted stock outstanding at January 1, 2010		1,231,901		$	21.67
Granted		645,950		$	14.27
Vested		(713,329	)	$	23.64
Forfeited		(54,128	)	$	22.08
Non-vested restricted stock outstanding at September 30, 2010		1,110,394		$	16.08

     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 September 30, 2010 follows:

				Weighted
				Average
				Grant Date
	Shares			Fair Value
Non-vested restricted stock units outstanding at January 1, 2010		16,167		$	26.81
Granted		9,000		$	13.81
Vested		(7,333	)	$	28.08
Forfeited		—		$	—
Non-vested restricted stock units outstanding at September 30, 2010		17,834		$	19.73

     Performance Unit Awards. On April 28, 2009, the Company granted cash-settled 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

9

obligation is measured at estimated fair value at the end of each reporting period using a Monte Carlo simulation model. As of September 30, 2010 this pro-rated obligation was approximately $1.7 million.

     On April 27, 2010, the Company granted stock-settled performance unit awards to certain executive officers (the “2010 Performance Units”). The 2010 Performance Units provide for those executive officers to receive a grant of shares of stock upon the achievement of certain performance goals established by the Company during a specified period. The performance period for the 2010 Performance Units is the period from April 1, 2010 through March 31, 2013, but can extend through March 31, 2015 in certain circumstances. 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 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 number of shares 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 grant of shares when achievement is between the 25^th and 75^th percentile will be determined on a pro-rata basis. The total base number of shares with respect to the 2010 Performance Units is 89,375 shares. Because the 2010 Performance Units are stock-settled awards, they are accounted for as equity awards and measured at fair value on the date of grant. The fair value of the 2010 Performance Units as of the date of grant was approximately $3.1 million using a Monte Carlo simulation model. This amount will be recognized on a straight-line basis over the performance period. During the three and nine months ended September 30, 2010, the Company recognized approximately $260,000 and $520,000, respectively, in expense related to the 2010 Performance Units.

5. Property and Equipment

     Property and equipment consisted of the following at September 30, 2010 and December 31, 2009 (in thousands):

	September 30,			December 31,
	2010			2009
Equipment	$	3,684,115		$	3,230,737
Oil and natural gas properties		102,594			93,354
Buildings		56,824			56,563
Land		10,291			9,795
		3,853,824			3,390,449
Less accumulated depreciation and depletion		(1,456,606	)		(1,280,047	)
Property and equipment, net	$	2,397,218		$	2,110,402

     During the nine months ended September 30, 2010, the Company sold certain rights to explore and develop zones deeper than depths that it generally targets for certain of the oil and natural gas properties in which it has working interests. The proceeds from this sale were approximately $22.3 million and the sale resulted in a gain on disposal of $20.1 million.

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6. 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. As discussed in Note 2, in January 2010 the Company exited the drilling and completion fluids business which previously was reported as a business segment. Operating results for that business for the three and nine months ended September 30, 2010 and 2009 are presented as discontinued operations in the consolidated statements of operations. Separate financial data for each of our business segments is provided in the table below (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenues:
Contract drilling	$	291,597		$	112,620		$	743,967		$	440,359
Pressure pumping		81,104			41,687			194,219			113,408
Oil and natural gas		6,800			5,690			21,564			15,255
Total segment revenues		379,501			159,997			959,750			569,022
Elimination of intercompany revenues (a)		(838	)		(326	)		(2,497	)		(645	)
Total revenues	$	378,663		$	159,671		$	957,253		$	568,377
Income (loss) before income taxes:
Contract drilling	$	41,479		$	(19,911	)	$	72,279		$	6,215
Pressure pumping		17,586			1,211			28,769			(562	)
Oil and natural gas		2,465			1,854			8,209			(1,144	)
		61,530			(16,846	)		109,257			4,509
Corporate and other		(9,271	)		(8,641	)		(25,100	)		(30,252	)
Net gain on asset disposals (b)		250			868			21,940			423
Interest income		64			53			1,631			318
Interest expense		(6,227	)		(1,448	)		(9,011	)		(2,734	)
Other		260			228			509			263
Income (loss) from continuing operations before income taxes	$	46,606		$	(25,786	)	$	99,226		$	(27,473	)

	September 30,		December 31,
	2010		2009
Identifiable assets:
Contract drilling	$	2,563,883	$	2,129,567
Pressure pumping		246,034		213,094
Oil and natural gas		30,991		25,355
Corporate and other (c)		156,500		294,136
Total assets	$	2,997,408	$	2,662,152

(a)	Consists of contract drilling intercompany revenues for drilling services provided to the oil and natural gas exploration and production segment.
(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, income taxes receivable and certain deferred Federal income tax assets. Corporate assets at September 30, 2010 primarily include cash on hand and certain deferred Federal income tax assets.

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7. Goodwill

     Goodwill is evaluated at least annually to determine if the fair value of recorded goodwill has decreased below its carrying value. The Company performs this annual evaluation in the fourth quarter of each year. 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.

     As of September 30, 2010 and December 31, 2009, the Company had goodwill of $86.2 million, all within 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.

8. Accrued Expenses

     Accrued expenses consisted of the following at September 30, 2010 and December 31, 2009 (in thousands):

	September 30,		December 31,
	2010		2009
Salaries, wages, payroll taxes and benefits	$	23,929	$	14,744
Workers’ compensation liability		63,660		66,015
Insurance, other than workers’ compensation		11,332		11,261
Sales, use and other taxes		16,053		10,975
Other		10,895		6,613
	$	125,869	$	109,608

9. 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 nine months ended September 30, 2010 and 2009 (in thousands):

	Nine Months Ended
	September 30,
	2010			2009
Balance at beginning of year	$	2,955		$	3,047
Liabilities incurred		279			125
Liabilities settled		(331	)		(304	)
Accretion expense		83			89
Revision in estimated costs of plugging oil and natural gas wells		—			(14	)
Asset retirement obligation at end of period	$	2,986		$	2,943

10. Long Term Debt

     On July 2, 2010, the Company entered into a 364-Day Credit Agreement (the “364-Day Credit Agreement”) among the Company, as borrower, and Wells Fargo Bank, N.A., as administrative agent and lender. The 364-Day Credit Agreement was a committed senior unsecured single draw term loan credit facility that permitted a borrowing of up to $250 million; provided that the loan must be drawn no later than September 30, 2010 or, if an additional fee was paid, October 30, 2010. The maturity date under the 364-Day Credit Agreement was 364 days after the date on which the closing conditions under the 364-Day Credit Agreement were met. The loan was not drawn as of September 30, 2010 and the 364-Day Credit Agreement expired at that time.

     On August 19, 2010, the Company entered into a Credit Agreement (the “2010 Credit Agreement”) among the Company, as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other letter of credit issuer and lender parties thereto. The 2010 Credit Agreement is a committed senior unsecured credit facility that permits aggregate borrowings of up to $500 million pursuant to a revolving credit facility and a term loan facility. The 2010 Credit Agreement replaced a previous unsecured revolving credit facility.

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     The revolving credit facility permits aggregate borrowings of up to, at any time outstanding, $400 million, which contains a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $40 million. Subject to customary conditions, the Company may request that the lenders’ aggregate commitments with respect to the revolving credit facility be increased by up to $100 million, not to exceed total commitments of $500 million. The maturity date for the revolving facility is August 19, 2013.

     The term loan facility provided for a loan of $100 million which was funded on August 19, 2010. The term loan facility is payable in quarterly principal installments commencing November 19, 2010, and the installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the next subsequent three quarterly installments and the remainder at maturity. The maturity date for the term loan facility is August 19, 2014.

     Loans under the 2010 Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon the Company’s debt to capitalization ratio. As of September 30, 2010, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by the Company equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee payable to the lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75% based upon the Company’s debt to capitalization ratio and was 0.50% as of September 30, 2010.

     Each domestic subsidiary of the Company other than any immaterial subsidiary has unconditionally guaranteed all existing and future indebtedness and liabilities of the Company and the other guarantors arising under the 2010 Credit Agreement and other loan documents. Such guarantees also cover obligations of the Company and any subsidiary of the Company arising under any interest rate swap contract with any person while such person is a lender or affiliate of a lender under the 2010 Credit Agreement.

     The 2010 Credit Agreement contains customary representations, warranties, indemnities and affirmative and negative covenants. The 2010 Credit Agreement also requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45% at any time. The 2010 Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The 2010 Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. 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 September 30, 2010, the Company had $100 million outstanding under the term loan facility at an interest rate of 3.125% and no borrowings outstanding under the revolving credit facility. The Company had $41.2 million in letters of credit outstanding at September 30, 2010 and, as a result, had available borrowing capacity of approximately $359 million at that date.

     Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of September 30, 2010 (in thousands):

Year ending December 31,
2010	$	1,250
2011		6,250
2012		10,000
2013		12,500
2014		70,000
Thereafter		—
Total	$	100,000

11. Commitments, Contingencies and Other Matters

     As of September 30, 2010, the Company maintained letters of credit in the aggregate amount of $41.2 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms

13

of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of September 30, 2010, no amounts had been drawn under the letters of credit.

     As of September 30, 2010, the Company had commitments to purchase approximately $250 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.

12. Stockholders’ Equity

     Cash Dividends — The Company paid cash dividends during the nine months ended September 30, 2009 and 2010 as follows:

	Per Share		Total
			(in thousands)
2009:
Paid on March 31, 2009	$	0.05	$	7,655
Paid on June 30, 2009		0.05		7,675
Paid on September 30, 2009		0.05		7,675
Total cash dividends	$	0.15	$	23,005

	Per Share		Total
			(in thousands)
2010:
Paid on March 30, 2010	$	0.05	$	7,677
Paid on June 30, 2010		0.05		7,706
Paid on September 30, 2010		0.05		7,704
Total cash dividends	$	0.15	$	23,087

     On October 27, 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 December 30, 2010 to holders of record as of December 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 nine months ended September 30, 2010, the Company purchased 8,743 shares of its common stock under the program at a cost of approximately $123,000. As of September 30, 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 116,819 shares of treasury stock from employees during the nine months ended September 30, 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 $1.7 million. 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.

13. 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 $1.7 million as of September 30, 2010.

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14. Recently Issued Accounting Standards

     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.

     In October 2009, the FASB issued a new accounting standard that addresses the accounting for multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately rather than as a combined unit. This new standard addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Existing accounting standards require a vendor to use objective and reliable evidence of fair value for the undelivered items or the residual method to separate deliverables in a multiple-deliverable arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be separated in more circumstances than under current requirements. The new standard establishes a hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to multiple deliverables. The selling price used will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific objective evidence nor third-party evidence is available. The new standard must be prospectively applied to all revenue arrangements entered into in fiscal years beginning on or after June 15, 2010 and will be effective for the Company on January 1, 2011. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

15. Subsequent Events

     On October 5, 2010, the Company completed an issuance and sale of $300 million in aggregate principal amount of its 4.97% Series A Senior Notes due October 5, 2020 (the “Notes”) in a private placement. A portion of the proceeds from the Notes were used to repay a $200 million borrowing on the Company’s revolving credit facility which had been drawn to fund a portion of the acquisition that closed on October 1, 2010 as discussed in Note 3. The Notes are senior unsecured obligations of the Company, which rank equally in right of payment with all other unsubordinated indebtedness of the Company. The Notes are guaranteed on a senior unsecured basis by each of the existing domestic subsidiaries of the Company other than immaterial subsidiaries.

     The Notes bear interest at a rate of 4.97% per annum and were priced at 100% of the principal amount of the Notes. The Company will pay interest on the Notes on April 5 and October 5 of each year commencing on April 5, 2011. The Notes will mature on October 5, 2020. The Notes are prepayable at the Company’s option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the Notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreement. The Company must offer to prepay the Notes upon the occurrence of any change of control. In addition, the Company must offer to prepay the Notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid Note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

     The note purchase agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreement generally defines the interest coverage ratio as the ratio for the four prior quarters of EBITDA to interest charges.

     Events of default under the note purchase agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then holders of a majority in principal amount of the Notes have the right to declare all the Notes then outstanding to be immediately due and payable. In addition, if the Company defaults in payments on any Note, then until such defaults are cured, the holder thereof may declare all the Notes held by it to be immediately due and payable.

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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 and Part II of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 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 and nine months ended September 30, 2010 and 2009, our operating revenues from continuing operations consisted of the following (dollars in thousands):

	Three Months Ended September 30,								Nine Months Ended September 30,
	2010				2009				2010				2009
Contract drilling	$	290,759	77	%	$	112,294	70	%	$	741,470	78	%	$	439,714	77	%
Pressure pumping		81,104	21			41,687	26			194,219	20			113,408	20
Oil and natural gas		6,800	2			5,690	4			21,564	2			15,255	3
	$	378,663	100	%	$	159,671	100	%	$	957,253	100	%	$	568,377	100	%

     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 third quarter of 2010, our average number of rigs operating was 178 compared to 73 in the third quarter of 2009. Our average revenue per operating day was $17,730 in the third quarter of 2010 compared to $16,800 in the third quarter of 2009. We had consolidated net income of $29.4 million for the third quarter of 2010 compared to a consolidated net loss of $18.6 million for the third quarter of 2009. The increase in consolidated net

16

income was primarily due to our contract drilling segment experiencing an increase in the average number of rigs operating and increases in large fracturing jobs in our pressure pumping segment in the third quarter of 2010 compared to the third 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 184 in September 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 in Part I of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 and Part II of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010.

     We believe that our liquidity as of September 30, 2010, which includes approximately $139 million in working capital and approximately $359 million available under our $400 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment and pay cash dividends.

     On July 2, 2010, we entered into an Asset Purchase Agreement wherein one of our subsidiaries agreed to purchase certain assets and assume certain liabilities from Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC relating to the businesses of providing certain pressure pumping services and electric wireline services to participants in the oil and natural gas industry for an approximate aggregate purchase price of $238 million in cash. This transaction closed on October 1, 2010, with two of our subsidiaries purchasing such assets and assuming such liabilities. The purchase price was funded through a combination of cash on hand and a $200 million draw on our revolving credit facility. The revolving credit facility borrowing was subsequently repaid on October 5, 2010 using proceeds from the sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020.

     If we pursue additional 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 September 30, 2010, we maintained letters of credit in the aggregate amount of $41.2 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 September 30, 2010, no amounts had been drawn under the letters of credit.

     As of September 30, 2010, we had commitments to purchase approximately $250 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 September 30, 2010, we had approximately 350 marketable land-based drilling rigs. As of October 1, 2010, we provide pressure pumping and wireline services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. Wireline services consist primarily of perforating, completion and production logging and casing integrity services. 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.

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     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.

     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 has significantly contributed to 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 September 30, 2010, we had working capital of $139 million, including cash and cash equivalents of $73.9 million compared to working capital of $264 million and cash and cash equivalents of $49.9 million at December 31, 2009. The decrease in working capital during the nine months ended September 30, 2010 was primarily due to capital expenditures and deposits on equipment purchases exceeding operating cash flow.

     During the nine months ended September 30, 2010, our sources of cash flow included:

• $402 million from operating activities,

• $100 million in term borrowings under our $500 million credit facility,

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

• $27.2 million in proceeds from the sale of certain oil and natural gas rights and the disposal of other assets.

     During the nine months ended September 30, 2010, we used $23.1 million to pay dividends on our common stock, $10.3 million to pay debt issuance costs, and $514 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.

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     We paid cash dividends during the nine months ended September 30, 2010 as follows:

	Per Share		Total
			(in thousands)
Paid on March 30, 2010	$	0.05	$	7,677
Paid on June 30, 2010		0.05		7,706
Paid on September 30, 2010		0.05		7,704
Total cash dividends	$	0.15	$	23,087

     On October 27, 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 December 30, 2010 to holders of record as of December 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 nine months ended September 30, 2010, we purchased 8,743 shares of our common stock under the program at a cost of approximately $123,000. As of September 30, 2010, we are authorized to purchase approximately $113 million of our outstanding common stock under the program.

     On August 19, 2010, we entered into the 2010 Credit Agreement. The 2010 Credit Agreement is a committed senior unsecured credit facility that permits aggregate borrowings of up to $500 million pursuant to a revolving credit facility and a term loan facility. The 2010 Credit Agreement replaced a previous unsecured revolving credit facility.

     The revolving credit facility permits aggregate borrowings of up to, at any time outstanding, $400 million, which contains a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $40 million. Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility be increased by up to $100 million, not to exceed total commitments of $500 million. The maturity date for the revolving facility is August 19, 2013.

     The term loan facility provided for a loan of $100 million which was funded on August 19, 2010, the proceeds of which may be used for general corporate purposes. The term loan facility is payable in quarterly principal installments commencing November 19, 2010, and the installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the next subsequent three quarterly installments and the remainder at maturity. The maturity date for the term loan facility is August 19, 2014.

     Loans under the 2010 Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon our debt to capitalization ratio. As of September 30, 2010, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee payable to the lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75% based upon our debt to capitalization ratio and was 0.50% as of September 30, 2010.

     The 2010 Credit Agreement contains customary representations, warranties, indemnities and affirmative and negative covenants. The 2010 Credit Agreement also requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45% at any time. The 2010 Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The 2010 Credit Agreement generally defines the interest coverage ratio as the ratio of EBITDA of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of September 30, 2010. We do not expect that the restrictions and covenants will impair our ability to operate or react to opportunities that might arise.

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     As of September 30, 2010, the Company had $100 million outstanding under the term loan facility at an interest rate of 3.125% and no borrowings outstanding under the revolving credit facility. The Company had $41.2 million in letters of credit outstanding at September 30, 2010 and, as a result, had available borrowing capacity of approximately $359 million at that date.

     On October 5, 2010, we completed an issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Notes”) in a private placement.

     The Notes bear interest at a rate of 4.97% per annum and were priced at 100% of the principal amount of the Notes. We will pay interest on the Notes on April 5 and October 5 of each year commencing on April 5, 2011. The Notes will mature on October 5, 2020. The Notes are prepayable at the our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the Notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreement. We must offer to prepay the Notes upon the occurrence of any change of control. In addition, we must offer to prepay the Notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid Note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

     The note purchase agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreement generally defines the interest coverage ratio as the ratio for the four prior quarters of EBITDA to interest charges.

     Events of default under the note purchase agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then holders of a majority in principal amount of the Notes have the right to declare all the Notes then outstanding to be immediately due and payable. In addition, if we default in payments on any Note, then until such defaults are cured, the holder thereof may declare all the Notes held by it to be immediately due and payable.

     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, should be sufficient to fund our current plans to build new equipment, make improvements to our existing equipment and pay cash dividends.

     On July 2, 2010, we entered into an Asset Purchase Agreement wherein one of our subsidiaries agreed to purchase certain assets and assume certain liabilities from Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC relating to the business of providing certain pressure pumping services and certain electric wireline services to participants in the oil and natural gas industry for an approximate aggregate purchase price of $238 million in cash. The transaction closed on October 1, 2010, with two of our subsidiaries purchasing such assets and assuming such liabilities. The purchase price was funded through a combination of cash on hand and a $200 million draw on our revolving credit facility. The revolving credit facility borrowing was subsequently repaid on October 5, 2010 using proceeds from the sale of the Notes.

     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 additional 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.

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Results of Operations

     The following tables summarize operations by business segment for the three months ended September 30, 2010 and 2009:

Contract Drilling	2010		2009			%Change
	(Dollars in thousands)
Revenues	$	290,759	$	112,294			158.9	%
Direct operating costs	$	174,999	$	71,035			146.4	%
Selling, general and administrative	$	1,664	$	1,087			53.1	%
Depreciation	$	72,617	$	60,083			20.9	%
Operating income (loss)	$	41,479	$	(19,911	)		N/M
Operating days		16,400		6,685			145.3	%
Average revenue per operating day	$	17.73	$	16.80			5.5	%
Average direct operating costs per operating day	$	10.67	$	10.63			0.4	%
Average rigs operating		178		73			143.8	%
Capital expenditures	$	192,233	$	93,340			105.9	%

     Revenues increased in 2010 compared to 2009 as a result of a significant increase in operating days and an increase in average revenue per operating day. Direct operating costs increased in 2010 compared to 2009 primarily 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 prices for natural gas and oil. 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.

Pressure Pumping	2010		2009		%Change
	(Dollars in thousands)
Revenues	$	81,104	$	41,687		94.6	%
Direct operating costs	$	51,305	$	31,092		65.0	%
Selling, general and administrative	$	2,668	$	2,168		23.1	%
Depreciation	$	9,545	$	7,216		32.3	%
Operating income	$	17,586	$	1,211		N/M
Fracturing jobs		420		455		(7.7	)%
Other jobs		1,600		1,446		10.7	%
Total jobs		2,020		1,901		6.3	%
Average revenue per fracturing job	$	147.20	$	64.52		128.1	%
Average revenue per other job	$	12.05	$	8.53		41.3	%
Average revenue per total job	$	40.15	$	21.93		83.1	%
Average direct operating costs per total job	$	25.40	$	16.36		55.3	%
Capital expenditures	$	15,531	$	3,582		333.6	%

     Our customers have increased their activities in the development of unconventional reservoirs in the Appalachian Basin resulting in an increase in larger fracturing jobs associated therewith. As a result, we have experienced an increase in the number of larger fracturing jobs as a proportion of the total fracturing jobs we performed. Revenues and direct operating costs increased primarily as a result of the increase in average revenue and direct operating costs per job. Increased average revenue per fracturing job reflects the increase in the proportion of larger fracturing jobs to total fracturing jobs, which was driven by demand for services associated with unconventional reservoirs. Average revenue per other job increased as a result of increased pricing for the services provided and a change in job mix. Average direct operating costs per job increased primarily due to the increase in larger fracturing jobs. Significant capital expenditures have been incurred in recent years to add capacity. Depreciation expense increased as a result of capital expenditures.

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Oil and Natural Gas Production and Exploration	2010		2009		%Change
	(Dollars in thousands,
	except sales prices)
Revenues	$	6,800	$	5,690		19.5	%
Direct operating costs	$	1,484	$	1,780		(16.6	)%
Depreciation, depletion and impairment	$	2,851	$	2,056		38.7	%
Operating income	$	2,465	$	1,854		33.0	%
Capital expenditures	$	4,782	$	2,214		116.0	%
Average net daily oil production (Bbls)		828		735		12.7	%
Average net daily natural gas production (Mcf)		2,558		3,172		(19.4	)%
Average oil sales price (per Bbl)	$	73.26	$	66.01		11.0	%
Average natural gas sales price (per Mcf)	$	5.19	$	4.20		23.6	%

     Revenues increased due to higher average sales prices of oil and natural gas and increased oil production partially offset by a reduction in natural gas production. Depreciation, depletion and impairment expense in 2010 includes approximately $119,000 incurred to impair certain oil and natural gas properties compared to approximately $249,000 incurred to impair certain oil and natural gas properties in 2009. Capital expenditures increased in 2010 as a result of greater drilling activity and increased costs per well.

Corporate and Other	2010			2009		%Change
	(Dollars in thousands)
Selling, general and administrative	$	9,353		$	8,129		15.1	%
Depreciation	$	418		$	227		84.1	%
Provision for bad debts	$	(500	)	$	285		N/M
Net gain (loss) on asset disposals	$	250		$	868		(71.2	)%
Interest income	$	64		$	53		20.8	%
Interest expense	$	6,227		$	1,448		330.0	%
Other income	$	260		$	228		14.0	%
Capital expenditures	$	2,288		$	4,762		52.0	%

     Selling, general and administrative expense increased in 2010 primarily as a result of increased personnel costs. The 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 at the time. The negative provision for bad debts in 2010 is the result of reductions in our reserve for specific accounts due to improved industry conditions. 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 due to the recognition of deferred financing costs. Interest expense in 2010 includes $3.3 million due to the recognition of remaining deferred financing costs associated with the revolving credit facility that was replaced in August 2010 and includes $1.3 million due to the recognition of deferred financing costs associated with the 364-Day Credit Agreement as it expired on September 30, 2010. Capital expenditures have increased in 2010 due to the ongoing implementation of a new enterprise resource planning system.

     The following tables summarize operations by business segment for the nine months ended September 30, 2010 and 2009:

Contract Drilling	2010		2009		%Change
	(Dollars in thousands)
Revenues	$	741,470	$	439,714		68.6	%
Direct operating costs	$	459,448	$	254,306		80.7	%
Selling, general and administrative	$	3,816	$	3,169		20.4	%
Depreciation	$	205,927	$	176,024		17.0	%
Operating income	$	72,279	$	6,215		N/M
Operating days		43,407		23,878		81.8	%
Average revenue per operating day	$	17.08	$	18.42		(7.3	)%
Average direct operating costs per operating day	$	10.58	$	10.65		(0.7	)%
Average rigs operating		159		87		82.8	%
Capital expenditures	$	455,708	$	308,789		47.6	%

     Revenues increased in 2010 compared to 2009 as a result of a significant increase in operating days somewhat reduced by the impact of a decrease in 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 and a smaller proportion of rigs on term contracts which are generally at higher rates. Revenues in 2009 also included $8.0 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

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primarily 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 prices for natural gas and oil. 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.

Pressure Pumping	2010		2009			%Change
	(Dollars in thousands)
Revenues	$	194,219	$	113,408			71.3	%
Direct operating costs	$	132,401	$	87,419			51.5	%
Selling, general and administrative	$	8,014	$	6,508			23.1	%
Depreciation	$	25,035	$	20,043			24.9	%
Operating income (loss)	$	28,769	$	(562	)		N/M
Fracturing jobs		1,078		1,200			(10.2	)%
Other jobs		4,350		4,151			4.8	%
Total jobs		5,428		5,351			1.4	%
Average revenue per fracturing job	$	134.31	$	64.61			107.9	%
Average revenue per other job	$	11.36	$	8.64			31.5	%
Average revenue per total job	$	35.78	$	21.19			68.9	%
Average direct operating costs per total job	$	24.39	$	16.34			49.3	%
Capital expenditures	$	36,342	$	32,155			13.0	%

     Our customers have increased their activities in the development of unconventional reservoirs in the Appalachian Basin resulting in an increase in larger fracturing jobs associated therewith. As a result, we have experienced an increase in the number of larger fracturing jobs as a proportion of the total fracturing jobs we performed. A decrease in smaller traditional fracturing jobs contributed to the overall decrease in the number of total fracturing jobs. Revenues and direct operating costs increased primarily as a result of the increase in average revenue and direct operating costs per job. Increased average revenue per fracturing job reflects the increase in the proportion of larger fracturing jobs to total fracturing jobs, which was driven by demand for services associated with unconventional reservoirs. Average revenue per other job increased as a result of increased pricing for the services provided and a change in job mix. Average direct operating costs per job primarily increased due to the increase in larger fracturing jobs. Selling, general and administrative expense increased primarily due to additional costs necessary to support increased business activity in 2010. 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	$	21,564	$	15,255			41.4	%
Direct operating costs	$	5,326	$	5,576			(4.5	)%
Depreciation, depletion and impairment	$	8,029	$	10,823			(25.8	)%
Operating income (loss)	$	8,209	$	(1,144	)		N/M
Capital expenditures	$	15,902	$	4,735			235.8	%
Average net daily oil production (Bbls)		829		790			4.9	%
Average net daily natural gas production (Mcf)		2,916		3,385			(13.9	)%
Average oil sales price (per Bbl)	$	75.05	$	53.47			40.4	%
Average natural gas sales price (per Mcf)	$	5.75	$	4.04			42.3	%

     Revenues increased due to higher average sales prices of oil and natural gas partially offset by a reduction in natural gas production. Average net daily natural gas production decreased primarily due to production declines on existing wells. Depreciation, depletion and impairment expense in 2010 includes approximately $789,000 incurred to impair certain oil and natural gas properties compared to approximately $3.3 million incurred to impair certain oil and natural gas properties in 2009. Depletion expense decreased approximately $378,000 primarily due to lower natural gas production. Capital expenditures increased in 2010 as a result of greater drilling activity and increased costs per well.

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Corporate and Other	2010			2009		%Change
	(Dollars in thousands)
Selling, general and administrative	$	25,661		$	23,536		9.0	%
Depreciation	$	939		$	681		37.9	%
Provision for bad debts	$	(1,500	)	$	6,035		N/M
Net gain on asset disposals	$	21,940		$	423		N/M
Interest income	$	1,631		$	318		412.9	%
Interest expense	$	9,011		$	2,734		229.6	%
Other income	$	509		$	263		93.5	%
Capital expenditures	$	5,727		$	4,762		20.3	%

     Selling, general and administrative expense increased in 2010 primarily as a result of increased personnel costs. The 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 at the time. The negative provision for bad debts in 2010 is the result of collections of certain accounts that had previously been reserved and reductions in our reserve for certain accounts due to improved industry conditions. 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. The gain on asset disposals in 2010 includes a gain of $20.1 million related to the sale of certain rights to explore and develop zones deeper than depths that we generally target for certain of the oil and natural gas properties in which we have working interests. Interest income increased due to the collection of interest on a customer account as well as interest received on prior overpayments of sales taxes in certain jurisdictions. Interest expense increased due to the recognition of deferred financing costs. Interest expense in 2010 includes $3.3 million due to the recognition of remaining deferred financing costs associated with the revolving credit facility that was replaced in August 2010 and includes $1.3 million due to the recognition of deferred financing costs associated with the 364-Day Credit Agreement as it expired on September 30, 2010. Capital expenditures have increased in 2010 due to the ongoing implementation of a new enterprise resource planning system.

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 $1.7 million as of September 30, 2010.

Recently Issued Accounting Standards

     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.

     In October 2009, the FASB issued a new accounting standard that addresses the accounting for multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately rather than as a combined unit. This new standard addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Existing accounting standards require a vendor to use objective and reliable evidence of fair value for the undelivered items or the residual method to separate deliverables in a multiple-deliverable arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be separated in more circumstances than under current requirements. The new standard establishes a hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to multiple deliverables. The selling

24

price used will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific objective evidence nor third-party evidence is available. The new standard must be prospectively applied to all revenue arrangements entered into in fiscal years beginning on or after June 15, 2010 and will be effective for the Company on January 1, 2011. The adoption of this standard is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

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 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. Construction of new land drilling rigs in the United States during the last ten years has significantly contributed to excess capacity. 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 and oil would likely result in demand for our drilling rigs decreasing and would adversely affect our operating results, financial condition and cash flows.

     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 term credit facility or our revolving credit facility. Interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.75% to 3.75% and the margin on base rate loans ranges from 1.75% to 2.75%, based on our debt to capitalization ratio. At September 30, 2010, the margin on LIBOR loans was 2.75% and the margin on base rate loans was 1.75%. As of September 30, 2010, we had no borrowings outstanding under our revolving credit facility and $100 million outstanding under our term credit facility at an interest rate of 3.125%.

     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 September 30, 2010.

25

     Changes in Internal Control Over Financial Reporting —There were no changes in our internal control over financial reporting during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.

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 September 30, 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)
July 1-31, 2010 (2)		51	$	15.90		—	$	113,162
August 1-31, 2010 (2)		27,968	$	14.79		2,637	$	113,123
September 1-30, 2010 (2)		51	$	16.84		—	$	113,123
Total		28,070	$	14.79		2,637	$	113,123

(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 51 shares in July, 25,331 shares in August and 51 shares in September 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 6. Exhibits

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

2.1	Asset Purchase Agreement dated July 2, 2010 by and among Patterson-UTI Energy, Inc., Portofino Acquisition Company, Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, and Key Energy Services, Inc. (filed July 6, 2010 as Exhibit 2.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
2.2*	Letter Agreement dated September 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services LLC.
2.3*	Letter Agreement dated October 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services LLC.
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	Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 and incorporated herein by reference).
10.2	364-Day Credit Agreement dated July 2, 2010, among Patterson-UTI Energy, Inc., as borrower, and Wells Fargo Bank, N.A., as administrative agent and lender (filed July 6, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

26

10.3	Credit Agreement dated August 19, 2010, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swingline lender and lender and each of the other letter of credit issuer and lender parties thereto (filed August 19, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
10.4	Note Purchase Agreement dated October 5, 2010 by and among the Company and the purchasers named therein (filed October 6, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
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 September 30, 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

27

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: November 1, 2010

28

EX-2.2

Exhibit 2.2

[Patterson-UTI Energy, Inc. Letterhead]

September 1, 2010

Key Energy Services, Inc.
Key Electric Wireline Services, LLC
Key Energy Pressure Pumping Services, LLC
c/o Key Energy Services, Inc.
1301 McKinney, Suite 1800
Houston, Texas 77010
Attention: General Counsel

Dear Ladies and Gentlemen:

     Reference is hereby made to the Asset Purchase Agreement by and among Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.), as Buyer, Patterson-UTI Energy, Inc., as Buyer Parent, and Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC, as Sellers, and Key Energy Services, Inc., as Seller Parent, dated as of July 2, 2010 (the “Agreement”), relating to the acquisition of the assets of Sellers’ pressure pumping and wireline businesses. This letter sets forth each of our agreements to certain modifications to the Agreement, and unless expressly modified pursuant to this letter agreement, all other provisions of the Agreement remain in full force and effect. Capitalized terms used in this letter which are defined in the Agreement shall have the meaning set forth in the Agreement.

     Attached hereto as Exhibit A is a proposal dated August 30, 2010 from Environmental Resources Management (“ERM”) to Buyer that sets forth proposed Phase II ESA invasive testing and analysis to be performed at the Transferred Leased Real Properties (the “Subject Properties”) listed on Table 1 thereto. By this letter, (i) Sellers and Seller Parent consent to such testing and analysis at the Subject Properties, and (ii) Buyer and Buyer Parent acknowledge and agree that no Environmental Defect Notice shall be issued regarding any other Transferred Real Property and, prior to Closing, that no Phase II ESA shall be performed with respect to any other Transferred Real Property; provided, that this clause (ii) shall not apply to any Transferred Real Property affected by an Environmental Condition coming into existence after the time that the Phase I ESA for such property was conducted pursuant to Section 6.1(b) and prior to Closing and not resulting from the Phase II ESA work.

     Any Environmental Condition identified as a result of the Phase II ESA work approved hereby shall be treated as and shall constitute a Potentially Material Environmental Condition for all purposes of the Agreement, notwithstanding the definition of that term contained in the Agreement.

     Within ten days after delivery to Sellers of the last of the reports with respect to such Phase II ESA work, the parties shall work in good faith to agree on the scope of work necessary to Remediate any Environmental Conditions pursuant to Section 6.2, including an estimate of the reasonable costs required to conduct such Remediation. The following standards will be used in determining the scope of such Remediation: (i) for the Subject Properties located in Texas, the Tier 1 protective concentration levels (Remedy Standard A) for commercial/industrial uses provided pursuant to the Texas Risk Reduction Program, 30 T.A.C. Chapter 350, and (ii) for the Subject Property located in Arkansas, the risk-based remediation standards for industrial use approved by the Arkansas Department of Environmental Quality pursuant to Title 8 of the Arkansas Code and/or Arkansas Pollution Control and Ecology Commission Regulation 23. Notwithstanding any continuing efforts to complete any agreed upon Remediation work at the Subject Properties, the parties shall promptly proceed to the Closing of the transactions contemplated by the Agreement provided that the other conditions to Closing set forth in the Agreement have been satisfied.

     The parties hereto also agree that any Environmental Defect Notice delivered within five days after the delivery to Buyer of the last of the reports with respect to such Phase II ESA work shall be deemed to have been delivered on or before the Environmental Defect Notice Date.

     Separately, Disclosure Schedule 4.22 shall be modified to incorporate by reference the Phase I ESAs and Phase II ESAs prepared by ERM and, such reports shall not be treated as supplements pursuant to Section 6.6.

     Buyer and Buyer Parent agree that Buyer shall pay the first $2,000,000 of the aggregate reasonable and actual costs incurred by Buyer or Seller to perform any Remedial Action on the Subject Properties (including any properties that are removed from among the Purchased Assets pursuant to Section 6.2(c)) as agreed to pursuant hereto, notwithstanding the provisions of Section 13.3(a) of the Agreement; provided, that such Remedial Action with respect to a Subject Property that either Buyer or Seller elects to remove from the Purchased Assets pursuant to Section 6.2(c) shall have been initiated within 90 days after the Closing Date. Payments shall be made by Buyer as such costs are incurred and invoiced to Buyer.

     The parties hereto agree that Sellers’ Environmental Liabilities arising from or related to any Environmental Condition identified pursuant to the Phase II ESA work contemplated herein or any Remedial Actions in response thereto shall cease upon the earlier of (i) confirmation that the commercial/industrial standards identified above have been achieved, or (ii) five years from the Closing Date. Further, the Phase II ESA work shall not give rise to any indemnity obligations for Sellers or Seller Parent with respect to the Subject Properties other than pursuant to Section 13.3(a) of the Agreement as modified by the immediately preceding paragraph hereof.

     The parties agree that the leased properties in Goliad, Texas shall be retained by Sellers, shall not be a Transferred Leased Real Property, and any lease associated therewith shall not be a Transferred Lease.

-2-

               Please indicate your agreement to the foregoing by signing and dating below.

Very truly yours, Patterson-UTI Energy, Inc.
By:	/s/ John E. Vollmer III
	John E. Vollmer III
	Senior Vice President-Corporate Development, Chief Financial Officer and Treasurer
Universal Pressure Pumping, Inc.
By:	/s/ John E. Vollmer III
	John E. Vollmer III
	Senior Vice President-Corporate Development, Chief Financial Officer and Treasurer

Agreed to this 1st day of September, 2010
Key Energy Services, Inc.
By:	/s/ Newton W. Wilson III
	Newton W. Wilson III
	Senior Vice President and Chief Operating Officer
Key Energy Pressure Pumping Services, LLC
By:	/s/ Newton W. Wilson III
	Newton W. Wilson III
	President
Key Electric Wireline Services, LLC
By:	/s/ Newton W. Wilson III
	Newton W. Wilson III
	President

-3-

EX-2.3

Exhibit 2.3

October 1, 2010

Key Energy Pressure Pumping Services, LLC
Key Electric Wireline Services, LLC
Key Energy Services, Inc.
c/o Key Energy Services, Inc.
1301 McKinney, Suite 1800
Houston, Texas 77010
Attention: General Counsel

Dear Ladies and Gentlemen:

     Reference is hereby made to the Asset Purchase Agreement by and among Universal Pressure Pumping, Inc. (formerly known as Portofino Acquisition Company), as Buyer, Patterson-UTI Energy, Inc, as Buyer Parent, Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC, as Sellers, and Key Energy Services, Inc., as Seller Parent, dated as of July 2, 2010 (as modified by that certain Assignment and Assumption Agreement dated October 1, 2010, by and between Universal Pressure Pumping, Inc., and Universal Wireline, Inc., and as otherwise amended, modified or supplemented through the date hereof the “Purchase Agreement”). This letter sets forth each of our agreements to certain modifications to the terms of the Purchase Agreement, and unless expressly modified pursuant to this letter agreement, all other provisions of the Purchase Agreement remain in full force and effect. Capitalized terms used and not otherwise defined herein shall have the meanings assigned to them in the Purchase Agreement.

     The parties agree that the defined term “Buyer Lease Agreement” in Section 1.1 of the Purchase Agreement is hereby deleted in its entirety and replaced with the following definition:

     “Buyer Lease Agreement” means (i) a written lease agreement containing the material terms identified in Exhibit C to this Agreement between Buyer, as tenant, and an Affiliate of Sellers, as landlord, relating to the Tioga, North Dakota service facility used in the Wireline Business and (ii) the written sublease agreement between Buyer, as sublessee, and an Affiliate of Sellers, as sublessor, relating to the Midland, Texas office facility used in the Purchased Business.

     The parties agree that the defined term “Effective Time” in Section 1.1 of the Purchase Agreement is hereby deleted in its entirety and replaced with the following definition:

     “Effective Time” means 12:01 a.m. on the Closing Date.

     The parties agree that Exhibit A to this letter agreement and incorporated herein by reference sets forth the amount of funds that will be paid by Buyer to Sellers on the Closing Date, including the determination thereof.

     The parties agree that the following schedules contained in the Seller Disclosure Schedules to the Purchase Agreement are hereby amended and restated in their entirety, except

for Schedule 4.19 for which only the severance obligations portion of such schedule is hereby amended and restated, which amended and restated schedules are attached to this letter agreement as Exhibit B:

2.1(a)-1	Pressure Pumping Equipment and Machinery
2.1(a)-2	Wireline Equipment and Machinery
2.1(b)-1	Pressure Pumping Assumed Contracts
2.1(b)-2	Wireline Assumed Contracts
2.1(c)-1	Pressure Pumping Vehicles
2.1(c)-2	Wireline Vehicles
2.1(e)	Transferred Leased Real Property and Transferred Leases
2.1(f)	Transferred Intellectual Property
2.1(g)	Transferred Permits
4.19	Business Employees — Severance Obligations

     The parties agree that all amounts listed on the amended and restated severance obligations portion of Schedule 4.19, included as part of Exhibit B hereto, shall, for the purposes of Section 8.4(j) of the Purchase Agreement, be subject to, and apply towards, Sellers’ and Buyer’s respective obligation to pay such retention benefits, including the limitation on total payments by Buyer not to exceed $900,000.

     This letter agreement (i) shall be governed by the law of the state of Texas, without regard to the conflicts of law principles of such state, (ii) may only be amended by a writing signed by all parties hereto, and (iii) may be executed in one or more counterparts, all of which shall be considered one and the same document.

[Signature Page Follows]

- 2 -

               Please indicate your agreement to the foregoing by signing and dating below.

Very truly yours, Universal Pressure Pumping, Inc.
By:	/s/ John E. Vollmer
	John E. Vollmer
	Senior Vice President — Corporate Development, Chief Financial Officer and Treasurer
Universal Wireline, Inc.
By:	/s/ John E. Vollmer
	John E. Vollmer
	Senior Vice President — Corporate Development, Chief Financial Officer and Treasurer
Patterson-UTI Energy, Inc.
By:	/s/ John E. Vollmer
	John E. Vollmer
	Senior Vice President — Corporate Development, Chief Financial Officer and Treasurer

Agreed to this 1st day of October, 2010.
KEY ENERGY PRESSURE PUMPING SERVICES, LLC
By:	/s/ J. Marshall Dodson J. Marshall Dodson
	Vice President and Treasurer
KEY ELECTRIC WIRELINE SERVICES, LLC
By:	/s/ J. Marshall Dodson J. Marshall Dodson
	Vice President and Treasurer
KEY ENERGY SERVICES, INC.
By:	/s/ J. Marshall Dodson J. Marshall Dodson
	Vice President and Treasurer

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, Douglas J. Wall, certify that:

     (1) I have reviewed this quarterly report on Form 10-Q of Patterson-UTI Energy, Inc;

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

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

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

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

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

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

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

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

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

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

      /s/ Douglas J. Wall  

Douglas J. Wall 

President and Chief Executive Officer 

Date: November 1, 2010

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, John E. Vollmer III, certify that:

     (1) I have reviewed this quarterly report on Form 10-Q of Patterson-UTI Energy, Inc;

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

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

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

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

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

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

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

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

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

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

      /s/ John E. Vollmer III  

John E. Vollmer III 

Senior Vice President — Corporate
Development, Chief Financial Officer
and Treasurer 

Date: November 1, 2010

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NOT FILED PURSUANT TO THE SECURITIES EXCHANGE ACT OF 1934

     In connection with the quarterly report of Patterson-UTI Energy, Inc. (the “Company”) on Form 10-Q for the period ending September 30, 2010, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Douglas J. Wall, Chief Executive Officer, and John E. Vollmer III, Chief Financial Officer, of the Company, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

     A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission upon request.

/s/ Douglas J. Wall Douglas J. Wall

Chief Executive Officer

November 1, 2010

/s/ John E. Vollmer III John E. Vollmer III

Chief Financial Officer

November 1, 2010