e10vq

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, 2009


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

For the transition period from to

Commission file number 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)


DELAWARE		75-2504748
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

450 GEARS ROAD, SUITE 500
HOUSTON, TEXAS		77067
(Address of principal executive offices)		(Zip Code)

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

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

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


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.

153,603,673 shares of common stock, $0.01 par value, as of October 30, 2009

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,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	119,243		$	81,223
Accounts receivable, net of allowance for doubtful accounts of $15,178 and $9,330 at September 30, 2009 and December 31, 2008, respectively		120,914			414,531
Federal and state income taxes receivable		10,465			10,175
Inventory		34,913			41,999
Deferred tax assets, net		98,058			35,928
Other		52,136			57,518

Total current assets		435,729			641,374
Property and equipment, net		2,115,132			1,937,112
Goodwill		86,234			86,234
Deposits on equipment purchases		—			43,944
Other		7,876			4,153

Total assets	$	2,644,971		$	2,712,817


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	89,634		$	169,958
Accrued expenses		108,933			132,655

Total current liabilities		198,567			302,613
Deferred tax liabilities, net		339,763			277,717
Other		5,466			5,545

Total liabilities		543,796			585,875

Commitments and contingencies (see Note 9)
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $.01; authorized 300,000,000 shares with 180,822,195 and 180,192,093 issued and 153,604,207 and 153,094,803 outstanding at September 30, 2009 and December 31, 2008, respectively		1,808			1,801
Additional paid-in capital		777,272			765,512
Retained earnings		1,927,699			1,970,824
Accumulated other comprehensive income		12,988			5,774
Treasury stock, at cost, 27,217,988 shares and 27,097,290 shares at September 30, 2009 and December 31, 2008, respectively		(618,592	)		(616,969	)

Total stockholders’ equity		2,101,175			2,126,942

Total liabilities and stockholders’ equity	$	2,644,971		$	2,712,817

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Operating revenues:
Contract drilling	$	112,294		$	498,510		$	439,714		$	1,335,494
Pressure pumping		41,687			60,618			113,408			160,576
Drilling and completion fluids		16,488			35,734			64,585			107,029
Oil and natural gas		5,690			13,670			15,255			36,270

Total operating revenues		176,159			608,532			632,962			1,639,369


Operating costs and expenses:
Contract drilling		71,035			282,698			254,306			778,446
Pressure pumping		28,219			36,576			78,087			97,587
Drilling and completion fluids		16,606			33,426			60,133			93,408
Oil and natural gas		1,780			4,338			5,576			9,934
Depreciation, depletion and impairment		70,131			67,998			209,335			197,397
Selling, general and administrative		15,871			17,469			48,091			52,212
Net gain on asset disposals/retirements		(898	)		(505	)		(548	)		(3,040	)
Other operating expenses		700			1,250			6,700			1,850

Total operating costs and expenses		203,444			443,250			661,680			1,227,794

Operating income (loss)		(27,285	)		165,282			(28,718	)		411,575


Other income (expense):
Interest income		53			601			318			1,437
Interest expense		(1,448	)		(125	)		(2,734	)		(465	)
Other		228			44			263			781

Total other income (expense)		(1,167	)		520			(2,153	)		1,753


Income (loss) before income taxes		(28,452	)		165,802			(30,871	)		413,328


Income tax expense (benefit):
Current		(3,659	)		44,287			(6,483	)		102,228
Deferred		(6,213	)		12,769			(4,268	)		43,523

Total income tax expense (benefit)		(9,872	)		57,056			(10,751	)		145,751

Net income (loss)	$	(18,580	)	$	108,746		$	(20,120	)	$	267,577


Net income (loss) per common share:
Basic	$	(0.12	)	$	0.70		$	(0.13	)	$	1.73

Diluted	$	(0.12	)	$	0.69		$	(0.13	)	$	1.71


Weighted average number of common shares outstanding:
Basic		152,242			154,266			151,975			153,617

Diluted		152,242			155,308			151,975			155,215


Cash dividends per common share	$	0.05		$	0.16		$	0.15		$	0.44

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

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 (loss):
Net loss		—			—		—			(20,120	)		—		—			(20,120	)
Foreign currency translation adjustment, net of tax of $4,183		—			—		—			—			7,214		—			7,214

Total comprehensive loss		—			—		—			(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.

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, 2007		177,386		$	1,773	$	703,581		$	1,716,620		$	20,207		$	(546,151	)	$	1,896,030

Comprehensive income:
Net income		—			—		—			267,577			—			—			267,577
Foreign currency translation adjustment, net of tax of $2,194		—			—		—			—			(3,783	)		—			(3,783	)

Total comprehensive income		—			—		—			267,577			(3,783	)		—			263,794


Issuance of restricted stock		577			6		(6	)		—			—			—			—
Forfeitures of restricted stock		(39	)		—		—			—			—			—			—
Exercise of stock options		2,302			23		25,516			—			—			—			25,539
Stock-based compensation		—			—		15,144			—			—			—			15,144
Tax benefit related to stock-based compensation		—			—		16,224			—			—			—			16,224
Payment of cash dividends		—			—		—			(68,307	)		—			—			(68,307	)
Purchase of treasury stock		—			—		—			—			—			(54,859	)		(54,859	)

Balance, September 30, 2008		180,226		$	1,802	$	760,459		$	1,915,890		$	16,424		$	(601,010	)	$	2,093,565

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)


	Nine Months Ended
	September 30,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(20,120	)	$	267,577
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and impairment		209,335			197,397
Provision for bad debts		6,700			1,850
Dry holes and abandonments		120			894
Deferred income tax expense (benefit)		(4,268	)		43,523
Stock-based compensation expense		14,108			15,144
Net gain on asset disposals/retirements		(548	)		(3,040	)
Changes in operating assets and liabilities:
Accounts receivable		288,189			(75,526	)
Income taxes receivable		(116	)		(2,257	)
Inventory and other assets		15,148			4,709
Accounts payable		(68,357	)		4,048
Accrued expenses		(23,884	)		3,985
Other liabilities		(79	)		1,337

Net cash provided by operating activities		416,228			459,641

Cash flows from investing activities:
Purchases of property and equipment		(350,626	)		(329,262	)
Proceeds from disposal of assets		3,304			8,697

Net cash used in investing activities		(347,322	)		(320,565	)

Cash flows from financing activities:
Purchases of treasury stock		(1,623	)		(54,859	)
Dividends paid		(23,005	)		(68,307	)
Tax benefit (expense) related to stock-based compensation		(2,720	)		16,224
Repayment of borrowings under line of credit		—			(50,000	)
Line of credit issuance costs		(6,169	)		—
Proceeds from exercise of stock options		379			25,539

Net cash used in financing activities		(33,138	)		(131,403	)

Effect of foreign exchange rate changes on cash		2,252			(88	)

Net increase in cash and cash equivalents		38,020			7,585
Cash and cash equivalents at beginning of period		81,223			17,434

Cash and cash equivalents at end of period	$	119,243		$	25,019


Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest expense	$	(1,440	)	$	(462	)
Income taxes	$	7,754		$	(89,815	)

Non-cash investing and financing activities:
Net decrease in payables for purchases of property and equipment	$	(12,235	)	$	(2,046	)
Net (increase) decrease in deposits on equipment purchases	$	43,944		$	(20,685	)

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

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, 2008, 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, 2008. The results of operations for the three and nine months ended September 30, 2009 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 2008 consolidated financial statements in order for them to conform with the 2009 presentation.

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

The Company has performed an evaluation of subsequent events through November 2, 2009 at the time of issuance of the unaudited consolidated financial statements.

The Company provides a dual presentation of its net income (loss) per common share in its Unaudited Consolidated Statements of Income: Basic net income (loss) per common share (“Basic EPS”) and diluted net income (loss) per common share (“Diluted EPS”). The Company adopted a new accounting standard in the quarter ended March 31, 2009, which clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of earnings-per-share using the two-class method. All earnings per share data presented for the three and nine months ended September 30, 2008 has been adjusted retrospectively to conform with this accounting standard. The impact of this retrospective application was to reduce Diluted EPS for the three months ended September 30, 2008 by $0.01 and to reduce Basic EPS and Diluted EPS for the nine months ended September 30, 2008 by $0.01.

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.

The following table presents information necessary to calculate net income (loss) per share for the three and nine months ended September 30, 2009 and 2008 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 during the three and nine months ended September 30, 2009 and 2008 (in thousands, except per share amounts):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
BASIC EPS:
Net income (loss)	$	(18,580	)	$	108,746		$	(20,120	)	$	267,577
Less (earnings) loss attributed to holders of non-vested restricted stock		174			(1,023	)		190			(2,484	)

Earnings (loss) attributed to common stockholders	$	(18,406	)	$	107,723		$	(19,930	)	$	265,093


Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		152,242			154,266			151,975			153,617


Basic net income (loss) per common share	$	(0.12	)	$	0.70		$	(0.13	)	$	1.73


DILUTED EPS:
Earnings (loss) attributed to common stockholders	$	(18,406	)	$	107,723		$	(19,930	)	$	265,093
Add incremental earnings related to potential common shares		—			5			—			19

Adjusted earnings attributed to common stockholders	$	(18,406	)	$	107,728		$	(19,930	)	$	265,112


Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		152,242			154,266			151,975			153,617
Add dilutive effect of potential common shares		—			1,042			—			1,598

Weighted average number of diluted common shares outstanding		152,242			155,308			151,975			155,215


Diluted net income (loss) per common share	$	(0.12	)	$	0.69		$	(0.13	)	$	1.71


Potentially dilutive securities excluded as anti-dilutive		8,204			1,455			8,204			2,380

2. Stock-based Compensation

The Company recognizes the cost of share-based awards under the fair-value-based method. The Company uses share-based awards to compensate employees and non-employee directors. Prior to 2009, share-based awards consisted 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. Beginning in 2009, share-based awards also include cash settled performance unit awards which are accounted for as a liability. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units vest.

Stock Options. The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton valuation model (“Black-Scholes”). 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, 2009 and 2008 follow:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2009			2008		2009			2008
Volatility		49.53	%		N/A		49.90	%		35.73	%
Expected term (in years)		4.00			N/A		4.00			4.00
Dividend yield		1.39	%		N/A		1.67	%		1.68	%
Risk-free interest rate		2.27	%		N/A		1.67	%		2.94	%

Stock option activity from January 1, 2009 to September 30, 2009 follows:


				Weighted
				Average
	Underlying			Exercise
	Shares			Price
Outstanding at January 1, 2009		5,933,572		$	21.20
Granted		1,037,500		$	13.12
Exercised		(61,268	)	$	6.19
Expired		(3,400	)	$	14.64

Outstanding at September 30, 2009		6,906,404		$	20.13

Exercisable at September 30, 2009		5,184,862		$	20.98

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, 2009 to September 30, 2009 follows:


				Weighted
				Average
				Grant Date
	Shares			Fair Value
Non-vested restricted stock outstanding at January 1, 2009		1,429,571		$	28.49
Granted		603,600		$	13.75
Vested		(711,452	)	$	27.99
Forfeited		(40,599	)	$	27.54

Non-vested restricted stock outstanding at September 30, 2009		1,281,120		$	21.85

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, 2009 to September 30, 2009 follows:


				Weighted
				Average
				Grant Date
	Shares			Fair Value
Non-vested restricted stock units outstanding at January 1, 2009		17,500		$	31.60
Granted		6,500		$	14.39
Vested		(5,833	)	$	31.60
Forfeited		(2,000	)	$	14.39

Non-vested restricted stock units outstanding at September 30, 2009		16,167		$	26.81

Performance Unit Awards. On April, 28, 2009, the Company granted performance unit awards to certain executive officers (the “2009 Performance Units”). The 2009 Performance Units provide for those executive officers to receive a cash payment upon the achievement of certain performance goals established by the Company during a specified period. The performance period for the 2009 Performance Units is the period from April 1, 2009 through March 31, 2012. The performance metrics 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. 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 obligation is measured at estimated fair value at the end of each reporting period and as of September 30, 2009 this obligation was approximately $595,000.

3. Property and Equipment

Property and equipment consisted of the following at September 30, 2009 and December 31, 2008 (in thousands):


	September 30,			December 31,
	2009			2008
Equipment	$	3,220,688		$	2,896,992
Oil and natural gas properties		89,967			89,809
Buildings		63,004			62,340
Land		9,698			9,824

		3,383,357			3,058,965
Less accumulated depreciation and depletion		(1,268,225	)		(1,121,853	)

Property and equipment, net	$	2,115,132		$	1,937,112

4. Business Segments

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Revenues:
Contract drilling (a)	$	112,620		$	500,030		$	440,359		$	1,338,856
Pressure pumping		41,687			60,618			113,408			160,576
Drilling and completion fluids (b)		16,527			35,861			64,624			107,207
Oil and natural gas		5,690			13,670			15,255			36,270

Total segment revenues		176,524			610,179			633,646			1,642,909
Elimination of intercompany revenues (a)(b)		(365	)		(1,647	)		(684	)		(3,540	)

Total revenues	$	176,159		$	608,532		$	632,962		$	1,639,369


Income (loss) before income taxes:
Contract drilling	$	(19,911	)	$	157,243		$	6,215		$	382,424
Pressure pumping		1,211			12,860			(562	)		31,589
Drilling and completion fluids		(2,281	)		(924	)		(2,858	)		3,798
Oil and natural gas		1,854			4,554			(1,144	)		16,024

		(19,127	)		173,733			1,651			433,835
Corporate and other		(9,056	)		(8,956	)		(30,917	)		(25,300	)
Net gain on asset disposals/retirements (c)		898			505			548			3,040
Interest income		53			601			318			1,437
Interest expense		(1,448	)		(125	)		(2,734	)		(465	)
Other		228			44			263			781

Income (loss) before income taxes	$	(28,452	)	$	165,802		$	(30,871	)	$	413,328


	September 30,		December 31,
	2009		2008
Identifiable assets:
Contract drilling	$	2,130,657	$	2,255,421
Pressure pumping		209,928		210,805
Drilling and completion fluids		57,129		99,433
Oil and natural gas		24,833		31,760
Corporate and other (d)		222,424		115,398

Total assets	$	2,644,971	$	2,712,817


(a)		Includes contract drilling intercompany revenues of approximately $326,000 and $1.5 million for the three months ended September 30, 2009 and 2008, respectively. Includes contract drilling intercompany revenues of approximately $645,000 and $3.4 million for the nine months ended September 30, 2009 and 2008, respectively.

(b)		Includes drilling and completion fluids intercompany revenues of approximately $39,000 and $126,000 for the three months ended September 30, 2009 and 2008, respectively. Includes drilling and completion fluids intercompany revenues of approximately $39,000 and $177,000 for the nine months ended September 30, 2009 and 2008, respectively.

(c)		Net gains associated with the disposal or retirement of assets relate to decisions of the executive management group regarding corporate strategy. Accordingly, the related gains have been separately presented and excluded from the results of specific segments.

(d)		Corporate and other assets primarily include cash on hand managed by the parent corporation and certain deferred Federal income tax assets.

5. Goodwill

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

As of September 30, 2009 and December 31, 2008 the Company had goodwill of $86.2 million, all in its contract drilling reporting unit. In the event that market conditions remain weak, 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.

6. Accrued Expenses

Accrued expenses consisted of the following at September 30, 2009 and December 31, 2008 (in thousands):


	September 30,		December 31,
	2009		2008
Salaries, wages, payroll taxes and benefits	$	13,959	$	30,334
Workers’ compensation liability		65,535		70,439
Sales, use and other taxes		14,519		12,015
Insurance, other than workers’ compensation		10,764		14,209
Other		4,156		5,658

	$	108,933	$	132,655

7. 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 Company’s consolidated balance sheet. The following table describes the changes to the Company’s asset retirement obligations during the nine months ended September 30, 2009 and 2008 (in thousands):


	2009			2008
Balance at beginning of year	$	3,047		$	1,593
Liabilities incurred		125			427
Liabilities settled		(304	)		(265	)
Accretion expense		89			44
Revision in estimated costs of plugging oil and natural gas wells		(14	)		1,303

Asset retirement obligation at end of period	$	2,943		$	3,102

8. Borrowings Under Line of Credit

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

Interest is paid on the outstanding principal amount of LOC borrowings at a floating rate based on, at the Company’s election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on the Company’s debt to capitalization ratio. At September 30, 2009, the margin on LIBOR loans would have been 3.00% and the margin on base rate loans would have been 2.00%. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. This LOC facility includes various fees, including a commitment fee on the actual daily unused commitment (the commitment fee rate was 1.00% at September 30, 2009).

The Company incurred line of credit issuance costs of approximately $6.2 million during the nine months ended September 30, 2009 in connection with the LOC. These costs are being amortized to interest expense over the contractual term of the LOC.

There are customary representations, warranties, restrictions and covenants associated with the LOC. Financial covenants provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. 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, 2009, the Company had no borrowings outstanding under the LOC. The Company had $46.3 million in letters of credit outstanding at September 30, 2009 and, as a result, had available borrowing capacity of approximately $194 million at that date. Each domestic subsidiary of the Company has unconditionally guaranteed the existing and future obligations of the Company and each other guarantor under the LOC and related loan documents, as well as obligations of the Company and its subsidiaries under any interest rate swap contracts that may be entered into with lenders party to the LOC.

9. Commitments, Contingencies and Other Matters

Commitments – As of September 30, 2009, the Company maintained letters of credit in the aggregate amount of $46.3 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 at various times during the calendar year and are typically renewed annually. As of September 30, 2009, no amounts had been drawn under the letters of credit.

As of September 30, 2009, the Company had commitments to purchase approximately $128 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.

10. Stockholders’ Equity

Cash Dividends — The Company paid cash dividends during the nine months ended September 30, 2008 and 2009 as follows:


	Per Share		Total
			(in thousands)
2008:
Paid on March 28, 2008	$	0.12	$	18,493
Paid on June 27, 2008		0.16		25,011
Paid on September 29, 2008		0.16		24,803

Total cash dividends	$	0.44	$	68,307


	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

On October 28, 2009, 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, 2009 to holders of record as of December 15, 2009. 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 (“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, 2009, the Company purchased 5,715 shares of its common stock under the Program at a cost of approximately $79,000. As of September 30, 2009, 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 114,983 shares of stock from employees during the nine months ended September 30, 2009 on dates that corresponded with the vesting of restricted stock. These shares were purchased at fair market value to provide employees with the funds necessary to satisfy payroll tax withholding obligations and have been accounted for as treasury stock. The total purchase price for these shares was approximately $1.5 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 Program.

11. Recently Issued Accounting Standards

In September 2006, the Financial Accounting Standards Board (“FASB”) issued an accounting standard that defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurement. The initial application of this standard was limited to financial assets and liabilities and became effective on January 1, 2008 for the Company. The impact of the initial application of this standard was not material. On January 1, 2009, the Company adopted this standard on a prospective basis for non-financial assets and liabilities that are not measured at fair value on a recurring basis. The application of this standard to the Company’s non-financial assets and liabilities is primarily limited to assets acquired and liabilities assumed in a business combination, asset retirement obligations and asset impairments, including goodwill and long-lived assets and has not had a material impact on the Company.

In December 2007, the FASB issued a new accounting standard that calls for significant changes from then current practice in accounting for business combinations. The new standard is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and became effective for the Company on January 1, 2009. The application of this new standard did not have a material impact on the Company.

In June 2008, the FASB issued a new accounting standard which clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of basic earnings-per-share using the two-class method. Certain of the Company’s share-based payment awards entitle the holders to receive non-forfeitable dividends. This standard is effective for financial statements issued for fiscal years beginning after December 15, 2008, as well as interim periods within those years and became effective for the Company on January 1, 2009. The impact of the adoption of this standard is discussed in Note 1.

In December 2008, the SEC issued a Final Rule, Modernization of Oil and Gas Reporting (“Final Rule”). The Final Rule revises certain oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as well as Industry Guide 2. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. The disclosure requirements are effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. The application of the Final Rule is not expected to have a material impact on the Company.

In April 2009, the FASB issued a staff position to provide additional guidance for determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurements under generally accepted accounting principles. The provisions of this staff position are effective for financial statements issued for interim and annual periods ending after June 15, 2009 and became effective for the Company in the quarter ended June 30, 2009. The adoption of this staff position did not have a material impact on the Company.

In April 2009, the FASB issued a staff position which increases the frequency of fair value disclosures for financial instruments from annual only to quarterly reporting periods. The provisions of this staff position are effective for financial statements issued for interim and annual periods ending after June 15, 2009 and became effective for the Company in the quarter ended June 30, 2009. The adoption of this staff position did not have a material impact on the Company.

In June 2009, the FASB issued a new accounting standard that amends the accounting and disclosure requirements for the consolidation of variable interest entities. This new standard removes the previously existing exception from applying consolidation guidance to qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this Statement, 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 and will become effective for the Company on January 1, 2010. The adoption of this standard is not expected to have a material impact on the Company.

In June 2009, the FASB issued the FASB Accounting Standards Codification (“Codification”). Effective for financial statements issued for interim and annual periods ending after September 15, 2009, the Codification became the source of authoritative U.S. generally accepted accounting principles. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions or EITF Abstracts. Instead, it will issue Accounting Standards Updates to update the Codification. The adoption of the Codification did not have a material impact on the Company.

FORWARD LOOKING STATEMENTS AND CAUTIONARY STATEMENTS FOR PURPOSES OF
THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995

Forward-looking statements may be made by management orally or in writing, including, but not limited to our filings with the SEC under the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”). “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 2 of Part I of this Quarterly Report on Form 10-Q contains forward-looking statements which are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. These 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); 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,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” 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 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 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, 2008 for a more complete discussion of these and other factors that might affect our performance and financial results. 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, future events or otherwise.

You are cautioned not to place undue reliance on any of our forward-looking statements, which speak only as of the date such forward looking statement was made.

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, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also invest, on a working interest basis, in oil and natural gas properties. For the three and nine months ended September 30, 2009 and 2008, our operating revenues consisted of the following (dollars in thousands):


	Three Months Ended September 30,								Nine Months Ended September 30,
	2009				2008				2009				2008
Contract drilling	$	112,294	64	%	$	498,510	82	%	$	439,714	70	%	$	1,335,494	81	%
Pressure pumping		41,687	24			60,618	10			113,408	18			160,576	10
Drilling and completion fluids		16,488	9			35,734	6			64,585	10			107,029	7
Oil and natural gas		5,690	3			13,670	2			15,255	2			36,270	2

	$	176,159	100	%	$	608,532	100	%	$	632,962	100	%	$	1,639,369	100	%

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

Typically, the profitability of our business is most readily assessed by two primary indicators in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the third quarter of 2009, our average number of rigs operating was 73 compared to 276 in the third quarter of 2008. Our average number of rigs operating during the third quarter of 2009 included approximately four rigs under term contracts that earned standby revenues of $3.4 million. Rigs on standby earn a discounted dayrate since they do not have crews and have lower costs. Our average revenue per operating day was $16,800 in the third quarter of 2009 compared to $19,620 in the third quarter of 2008. We had a consolidated net loss of $18.6 million for the third quarter of 2009 compared to consolidated net income of $109 million for the third quarter of 2008. This decrease was primarily due to our contract drilling segment experiencing a significant decrease in the average number of rigs operating as compared to the third quarter of 2008.

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. Since reaching a peak in 2008, there has been a significant decline in oil and natural gas prices. During this time there has also been a substantial deterioration in the global economic environment. As part of this deterioration, there has been substantial uncertainty in the capital markets and access to financing has been 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 recovering slightly to 81 in September 2009. Furthermore, these factors have resulted in, and could continue to result in, certain of our customers experiencing an inability to pay suppliers, including us, if they are not able to access capital to fund their operations. We are also highly impacted by competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” included as Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

We believe that the liquidity shown on our balance sheet as of September 30, 2009, which includes approximately $237 million in working capital (including $119 million in cash and cash equivalents) and approximately $194 million available under our $240 million LOC, together with cash expected to be generated from operations (including expected income tax refunds resulting from the carry-back of net operating losses), should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, expand into new regions, pay cash dividends and survive the current downturn in our industry.

Commitments and Contingencies — As of September 30, 2009, we maintained letters of credit in the aggregate amount of $46.3 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 at various times during each calendar year and are typically renewed annually. As of September 30, 2009, no amounts had been drawn under the letters of credit.

As of September 30, 2009, we had commitments to purchase approximately $128 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 in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Alabama, Colorado, Arizona, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania, West Virginia and western Canada. As of September 30, 2009, we had approximately 350 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We provide 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. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. We also invest, on a working interest basis, in oil and natural gas properties.

The North American land drilling industry has experienced periods of downturn 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.

In addition to adverse effects that declines in demand have had or could have on us, 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.

As a result of an increase in drilling activity and increased prices for drilling services in recent years prior to the current downturn, construction of new drilling rigs increased significantly. The addition of new drilling rigs to the market and the decrease in demand has resulted in excess capacity. We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.

Critical Accounting Policies

In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

Liquidity and Capital Resources

As of September 30, 2009, we had working capital of $237 million, including cash and cash equivalents of $119 million. For the nine months ended September 30, 2009, our sources of cash flow included $416 million from operating activities.

During the nine months ended September 30, 2009, we used $23.0 million to pay dividends on our common stock, $6.2 million to pay issuance costs related to our LOC and $351 million:

•

to build new drilling rigs,

•

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

•

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

•

to fund capital expenditures for our pressure pumping and drilling and completion fluids segments, and

•

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

We paid cash dividends during the nine months ended September 30, 2009 as follows:


	Per Share		Total
			(in thousands)
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

On October 28, 2009, 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, 2009 to holders of record as of December 15, 2009. 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 (“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, 2009, we purchased 5,715 shares of our common stock under the Program at a cost of approximately $79,000. As of September 30, 2009, we are authorized to purchase approximately $113 million of our outstanding common stock under the Program. Shares purchased under the Program have been accounted for as treasury stock.

We have an unsecured LOC with a maximum borrowing and letter of credit capacity of $240 million. Interest is paid on the outstanding principal amount of borrowings under the LOC at a floating rate based on, at our election, LIBOR or a base rate. The

margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on our debt to capitalization ratio. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. As of September 30, 2009, we had no borrowings outstanding under the LOC. We had $46.3 million in letters of credit outstanding at September 30, 2009 and, as a result, had available borrowing capacity of approximately $194 million at such date.

We believe that the current level of cash, short-term investments and borrowing capacity available under our LOC, together with cash expected to be generated from operations (including expected income tax refunds resulting from the carry-back of net operating losses), should be sufficient to meet our current capital needs. From time to time, acquisition opportunities are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Should opportunities for growth requiring capital arise, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, borrowing capacity under our LOC or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Results of Operations

The following tables summarize operations by business segment for the three months ended September 30, 2009 and 2008:


Contract Drilling	2009			2008		% Change
	(Dollars in thousands)
Revenues	$	112,294		$	498,510		(77.5	)%
Direct operating costs	$	71,035		$	282,698		(74.9	)%
Selling, general and administrative	$	1,087		$	1,382		(21.3	)%
Depreciation	$	60,083		$	57,187		5.1	%
Operating income (loss)	$	(19,911	)	$	157,243		N/M
Operating days		6,685			25,403		(73.7	)%
Average revenue per operating day	$	16.80		$	19.62		(14.4	)%
Average direct operating costs per operating day	$	10.63		$	11.13		(4.5	)%
Average rigs operating		73			276		(73.6	)%
Capital expenditures	$	93,340		$	125,892		(25.9	)%

Revenues and direct operating costs decreased in the third quarter of 2009 compared to the third quarter of 2008 primarily as a result of a decrease in the number of operating days. The decrease in operating days was due to decreased demand largely caused by lower commodity prices for natural gas and oil. Our average number of rigs operating during the third quarter of 2009 included an average of approximately four rigs that earned standby revenues of $3.4 million. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. Average revenue per operating day decreased in the third quarter of 2009 compared to the third quarter of 2008 primarily due to decreases in dayrates for rigs that were operating in the spot market and the expiration of term contracts that were entered into at higher rates. Average direct operating costs per operating day decreased in the third quarter of 2009 compared to the third quarter of 2008 primarily due to decreases in labor and repair costs. Significant capital expenditures have been incurred to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment.


Pressure Pumping	2009		2008		% Change
	(Dollars in thousands)
Revenues	$	41,687	$	60,618		(31.2	)%
Direct operating costs	$	28,219	$	36,576		(22.8	)%
Selling, general and administrative	$	5,041	$	6,109		(17.5	)%
Depreciation	$	7,216	$	5,073		42.2	%
Operating income	$	1,211	$	12,860		(90.6	)%
Total jobs		1,990		3,732		(46.7	)%
Average revenue per job	$	20.95	$	16.24		29.0	%
Average direct operating costs per job	$	14.18	$	9.80		44.7	%
Capital expenditures	$	3,582	$	17,607		(79.7	)%

for services associated with unconventional reservoirs partially offset by the impact of reduced pricing. Average direct operating costs per job increased due to the increase in larger jobs and as a result of fixed costs being spread over a significantly reduced number of total jobs. In anticipation of increased activity associated with the unconventional reservoirs in the Appalachian Basin, we have added facilities, equipment and personnel in recent years. Delays in the development of these reservoirs and lower commodity prices have caused less demand for our pressure pumping services, negatively impacting the profitability of this business. Selling, general and administrative expenses decreased in the third quarter of 2009 compared to the third quarter of 2008 primarily due to headcount reductions. Significant capital expenditures were incurred in 2008 to add capacity and modify and upgrade existing equipment. The increase in depreciation expense is a result of capital expenditures.


Drilling and Completion Fluids	2009			2008			% Change
	(Dollars in thousands)
Revenues	$	16,488		$	35,734			(53.9	)%
Direct operating costs	$	16,606		$	33,426			(50.3	)%
Selling, general and administrative	$	1,614		$	2,478			(34.9	)%
Depreciation	$	549		$	754			(27.2	)%
Operating loss	$	(2,281	)	$	(924	)		146.9	%
Capital expenditures	$	179		$	1,398			(87.2	)%

Revenues and direct operating costs decreased in the third quarter of 2009 compared to the third quarter of 2008 due to decreased sales volume both on land and offshore in the Gulf of Mexico. Selling, general and administrative expenses decreased in the third quarter of 2009 compared to the third quarter of 2008 primarily due to a decrease in compensation costs for sales and support personnel due to headcount reductions. Capital expenditures decreased in the third quarter of 2009 compared to the third quarter of 2008 due to the slowdown in activity.


Oil and Natural Gas Production and Exploration	2009		2008		% Change
	(Dollars in thousands,
	except sales prices)
Revenues	$	5,690	$	13,670		(58.4	)%
Direct operating costs	$	1,780	$	4,338		(59.0	)%
Depreciation, depletion and impairment	$	2,056	$	4,778		(57.0	)%
Operating income	$	1,854	$	4,554		(59.3	)%
Capital expenditures	$	2,214	$	7,852		(71.8	)%
Average net daily oil production (Bbls)		735		894		(17.8	)%
Average net daily natural gas production (Mcf)		3,172		3,946		(19.6	)%
Average oil sales price (per Bbl)	$	66.01	$	116.86		(43.5	)%
Average natural gas sales price (per Mcf)	$	4.20	$	11.19		(62.5	)%

Revenues decreased due to lower average sales prices and net daily production of oil and natural gas. Average net daily oil and natural gas production decreased primarily due to production declines on existing wells. Depreciation, depletion and impairment expense in the third quarter of 2009 includes approximately $249,000 incurred to impair certain oil and natural gas properties compared to approximately $1.6 million incurred to impair certain oil and natural gas properties in the third quarter of 2008. Depletion expense decreased approximately $1.3 million primarily due to lower production and the impact of decreases in carrying value of properties resulting from impairment charges recognized prior to the third quarter of 2009. Capital expenditures decreased in the third quarter of 2009 compared to the third quarter of 2008 due to the decline in commodity prices.


Corporate and Other	2009			2008			% Change
	(Dollars in thousands)
Selling, general and administrative	$	8,129		$	7,500			8.4	%
Depreciation	$	227		$	206			10.2	%
Other operating expenses	$	700		$	1,250			(44.0	)%
Net gain on asset disposals/retirements	$	(898	)	$	(505	)		77.8	%
Interest income	$	53		$	601			(91.1	)%
Interest expense	$	1,448		$	125			1,058.4	%
Other income	$	228		$	44			418.2	%
Capital expenditures	$	4,762		$	351			1,256.7	%

Selling, general and administrative expenses increased in the third quarter of 2009 compared to the third quarter of 2008 primarily as a result of increased professional fees. Other operating expenses decreased due to a decrease in bad debt expense of $550,000 in the third quarter of 2009 compared to the third quarter of 2008. Gains on the disposal and retirement of assets are treated as part of

our corporate activities because such transactions relate to corporate strategy decisions of the Company’s executive management group. Interest expense increased in the third quarter of 2009 compared to the third quarter of 2008 due to amortization of LOC issuance costs and increased fees associated with outstanding letters of credit and the unused portion of the LOC. Capital expenditures increased in the third quarter of 2009 compared to the third quarter of 2008 due to the purchase and ongoing implementation of a new enterprise resource planning system.

The following tables summarize operations by business segment for the nine months ended September 30, 2009 and 2008:


Contract Drilling	2009		2008		% Change
	(Dollars in thousands)
Revenues	$	439,714	$	1,335,494		(67.1	)%
Direct operating costs	$	254,306	$	778,446		(67.3	)%
Selling, general and administrative	$	3,169	$	4,203		(24.6	)%
Depreciation	$	176,024	$	170,421		3.3	%
Operating income	$	6,215	$	382,424		(98.4	)%
Operating days		23,878		69,881		(65.8	)%
Average revenue per operating day	$	18.42	$	19.11		(3.6	)%
Average direct operating costs per operating day	$	10.65	$	11.14		(4.4	)%
Average rigs operating		87		255		(65.9	)%
Capital expenditures	$	308,789	$	260,918		18.3	%

Revenues and direct operating costs decreased in the first nine months of 2009 compared to the first nine months of 2008 primarily as a result of a decrease in the number of operating days. The decrease in operating days was due to decreased demand largely caused by lower commodity prices for natural gas and oil. Our average number of rigs operating during the first nine months of 2009 included an average of approximately seven rigs that earned standby revenues of $21.5 million. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. Additionally, we recognized $7.5 million of revenues during the first nine months of 2009 from the early termination of drilling contracts. Significant capital expenditures have been incurred to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment.


Pressure Pumping	2009			2008		% Change
	(Dollars in thousands)
Revenues	$	113,408		$	160,576		(29.4	)%
Direct operating costs	$	78,087		$	97,587		(20.0	)%
Selling, general and administrative	$	15,840		$	17,550		(9.7	)%
Depreciation	$	20,043		$	13,850		44.7	%
Operating income (loss)	$	(562	)	$	31,589		N/M
Total jobs		5,582			10,043		(44.4	)%
Average revenue per job	$	20.32		$	15.99		27.1	%
Average direct operating costs per job	$	13.99		$	9.72		43.9	%
Capital expenditures	$	32,155		$	48,255		(33.4	)%

Our customers have increased their focus on the emerging development of unconventional reservoirs in the Appalachian Basin and the larger jobs associated therewith. As a result of this focus on unconventional reservoirs and declining commodity prices, we have experienced a decrease in the number of smaller traditional pressure pumping jobs, which has contributed to the overall decrease in the number of total jobs. Revenues and direct operating costs decreased as a result of a decrease in the number of total jobs. Increased average revenue per job was due to an increase in the proportion of larger jobs to total jobs, which was driven by demand for services associated with unconventional reservoirs partially offset by the impact of reduced pricing. Average direct operating costs per job increased due to the increase in larger jobs and as a result of fixed costs being spread over a significantly reduced number of jobs. In anticipation of increased activity associated with the unconventional reservoirs in the Appalachian Basin, we have added facilities, equipment and personnel in recent years. Delays in the development of these reservoirs and lower commodity prices have caused less demand for our pressure pumping services, negatively impacting the profitability of this business. Selling, general and administrative expenses decreased in the first nine months of 2009 compared to the first nine months of 2008 primarily due to headcount reductions. Significant capital expenditures have been incurred to add capacity, expand our areas of operation and modify and upgrade existing equipment. The increase in depreciation expense is a result of these capital expenditures.


Drilling and Completion Fluids	2009			2008		% Change
	(Dollars in thousands)
Revenues	$	64,585		$	107,029		(39.7	)%
Direct operating costs	$	60,133		$	93,408		(35.6	)%
Selling, general and administrative	$	5,546		$	7,621		(27.2	)%
Depreciation	$	1,764		$	2,202		(19.9	)%
Operating income (loss)	$	(2,858	)	$	3,798		N/M
Capital expenditures	$	185		$	2,931		(93.7	)%

Revenues and direct operating costs decreased in the first nine months of 2009 compared to the first nine months of 2008 due to decreased sales volume both on land and offshore in the Gulf of Mexico. Selling, general and administrative expenses decreased in the first nine months of 2009 compared to the first nine months of 2008 primarily due to a decrease in compensation costs for sales and support personnel due to headcount reductions. Capital expenditures decreased in the first nine months of 2009 compared to the first nine months of 2008 due to the slowdown in activity.


Oil and Natural Gas Production and Exploration	2009			2008		% Change
	(Dollars in thousands,
	except sales prices)
Revenues	$	15,255		$	36,270		(57.9	)%
Direct operating costs	$	5,576		$	9,934		(43.9	)%
Depreciation, depletion and impairment	$	10,823		$	10,312		5.0	%
Operating income (loss)	$	(1,144	)	$	16,024		N/M
Capital expenditures	$	4,735		$	16,807		(71.8	)%
Average net daily oil production (Bbls)		790			803		(1.6	)%
Average net daily natural gas production (Mcf)		3,385			3,833		(11.7	)%
Average oil sales price (per Bbl)	$	53.47		$	113.33		(52.8	)%
Average natural gas sales price (per Mcf)	$	4.04		$	10.78		(62.5	)%

Revenues decreased primarily due to lower average sales prices and net daily production of oil and natural gas. Average net daily natural gas production decreased primarily due to production declines on existing wells. Depreciation, depletion and impairment expense in the first nine months of 2009 includes approximately $3.3 million incurred to impair certain oil and natural gas properties compared to approximately $1.9 million incurred to impair certain oil and natural gas properties in the first nine months of 2008. The increase in impairment charges in 2009 was due to a reduction in commodity price expectations and a decline in production of certain wells. Capital expenditures decreased in the first nine months of 2009 compared to the first nine months of 2008 due to the decline in commodity prices.


Corporate and Other	2009			2008			% Change
	(Dollars in thousands)
Selling, general and administrative	$	23,536		$	22,838			3.1	%
Depreciation	$	681		$	612			11.3	%
Other operating expenses	$	6,700		$	1,850			262.2	%
Net gain on asset disposals/retirements	$	(548	)	$	(3,040	)		(82.0	)%
Interest income	$	318		$	1,437			(77.9	)%
Interest expense	$	2,734		$	465			488.0	%
Other income	$	263		$	781			(66.3	)%
Capital expenditures	$	4,762		$	351			1,256.7	%

Other operating expenses increased due to an increase in bad debt expense of $4.9 million in the first nine months of 2009 compared to the first nine months of 2008. Gains and losses on the disposal and retirement of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of the Company’s executive management group. In the first nine months of 2008 we recognized a net gain on the disposal of assets of approximately $3.0 million primarily due to the sale of certain assets in our contract drilling segment. Interest expense increased in the first nine months of 2009 compared to the first nine months of 2008 due to amortization of LOC issuance costs and increased fees associated with outstanding letters of credit and the unused portion of the LOC. Capital expenditures increased in the first nine months of 2009 compared to the first nine months of 2008 due to the purchase and ongoing implementation of a new enterprise resource planning system.

Recently Issued Accounting Standards

In September 2006, the Financial Accounting Standards Board (“FASB”) issued an accounting standard that defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurement. The initial application of this standard was limited to financial assets and liabilities and became effective on January 1, 2008 for us. The impact of the initial application of this standard was not material. On January 1, 2009, we adopted this standard on a prospective basis for non-financial assets and liabilities that are not measured at fair value on a recurring basis. The application of this standard to our non-financial assets and liabilities is primarily limited to assets acquired and liabilities assumed in a business combination, asset retirement obligations and asset impairments, including goodwill and long-lived assets and has not had a material impact on us.

In December 2007, the FASB issued a new accounting standard that calls for significant changes from then current practice in accounting for business combinations. The new standard is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and became effective for us on January 1, 2009. The application of this new standard did not have a material impact on us.

In June 2008, the FASB issued a new accounting standard which clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of basic earnings-per-share using the two-class method. Certain of our share-based payment awards entitle the holders to receive non-forfeitable dividends. This standard is effective for financial statements issued for fiscal years beginning after December 15, 2008, as well as interim periods within those years and became effective for us on January 1, 2009. The impact of the adoption of this standard is discussed in Note 1 to our unaudited consolidated financial statements included in this Report.

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

In April 2009, the FASB issued a staff position to provide additional guidance for determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurements under generally accepted accounting principles. The provisions of this staff position are effective for financial statements issued for interim and annual periods ending after June 15, 2009 and became effective for us in the quarter ended June 30, 2009. The adoption of this staff position did not have a material impact on us.

In April 2009, the FASB issued a staff position which increases the frequency of fair value disclosures for financial instruments from annual only to quarterly reporting periods. The provisions of this staff position are effective for financial statements issued for interim and annual periods ending after June 15, 2009 and became effective for us in the quarter ended June 30, 2009. The adoption of this staff position did not have a material impact on us.

In June 2009, the FASB issued a new accounting standard that amends the accounting and disclosure requirements for the consolidation of variable interest entities. This new standard removes the previously existing exception from applying consolidation guidance to qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this Statement, 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 and will become effective for us on January 1, 2010. The adoption of this standard is not expected to have a material impact on us.

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

Our revenue, profitability, financial condition and rate of growth are substantially dependent upon prevailing prices for natural gas and, to a lesser extent, oil. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC to set and maintain production and price targets. All of these factors are beyond our control. During 2008, the monthly average market price of natural gas (monthly average Henry Hub price as reported by the Energy Information Administration) peaked in June at $13.06 per Mcf before rapidly declining to an average of $5.99 per Mcf in December. In 2009, the average market price of natural gas declined further and averaged $3.06 per Mcf in the month of September. This has resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008 and continuing into 2009. This reduction in demand combined with the reactivation and construction of new land drilling rigs in the United States during the last several years has resulted in excess capacity compared to demand. As a result of these factors, our average number of rigs operating has declined significantly. 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. Continued low market prices for natural gas will likely result in demand for our drilling rigs remaining low and 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 LOC. The LOC calls for periodic interest payments at a floating rate ranging from LIBOR plus 3.00% to 4.00% or at a base rate plus 2.00% to 3.00%. The applicable rate above LIBOR or the prime rate is based upon our debt to capitalization ratio. As of September 30, 2009, we had no borrowings outstanding under our LOC.

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 rate 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.

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, 2009.

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, 2009.


							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, 2009		—	$	—		—	$	113,280
August 1-31, 2009 (2)		31,557	$	14.08		2,391	$	113,247
September 1-30, 2009		—	$	—		—	$	113,247

Total		31,557	$	14.08		2,391	$	113,247


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

(2)		We purchased 29,166 shares from employees to provide the respective employees with the funds necessary to satisfy their tax withholding obligations with respect to the vesting of restricted shares. The price paid was the closing price of our common stock on the last business day prior to the date the shares vested. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to the stock buyback program.

ITEM 6. Exhibits

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

3.1		Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).

3.2		Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).

3.3		Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference).

10.1		Indemnification Agreement between the Company and Seth D. Wexler, effective as of August 10, 2009 (form of which has been filed on April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).

10.2*		Change in Control Agreement between the Company and Seth D. Wexler, effective as of November 2, 2009.

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, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (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


	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

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	PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements
	Unaudited consolidated balance sheets		1
	Unaudited consolidated statements of income		2
	Unaudited consolidated statements of changes in stockholders’ equity		3
	Unaudited consolidated statements of cash flows		5
	Notes to unaudited consolidated financial statements		6
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		22
ITEM 4.	Controls and Procedures		22

	PART II — OTHER INFORMATION
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		23
ITEM 6.	Exhibits		23
Signature			24
EX-10.2
EX-31.1
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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