Patterson-UTI Energy 10Q 2009 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended June 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 (State or other jurisdiction of incorporation or organization)		75-2504748 (I.R.S. Employer Identification No.)

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

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

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

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

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

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


Large accelerated filerþ		Accelerated filero		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller Reporting Companyo

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

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

153,613,685 shares of common stock, $0.01 par value, as of July 31, 2009

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 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		21
ITEM 4. Controls and Procedures		21
Forward Looking Statements and Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		22

PART II — OTHER INFORMATION
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		23
ITEM 4. Submission of Matters to a Vote of Security Holders		23
ITEM 5. Other Information		23
ITEM 6. Exhibits		24
Signature		25
EX-10.2
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)


	June 30,			December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	167,665		$	81,223
Accounts receivable, net of allowance for doubtful accounts of $14,481 and $9,330 at June 30, 2009 and December 31, 2008, respectively		118,475			414,531
Federal and state income taxes receivable		6,765			10,175
Inventory		40,486			41,999
Deferred tax assets, net		59,671			35,928
Other		56,723			57,518

Total current assets		449,785			641,374
Property and equipment, net		2,093,609			1,937,112
Goodwill		86,234			86,234
Deposits on equipment purchases		13,327			43,944
Other		8,396			4,153

Total assets	$	2,651,351		$	2,712,817


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	111,100		$	169,958
Accrued expenses		108,603			132,655

Total current liabilities		219,703			302,613
Deferred tax liabilities, net		305,500			277,717
Other		5,528			5,545

Total liabilities		530,731			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 180,802,252 and 180,192,093 issued and 153,615,821 and 153,094,803 outstanding at June 30, 2009 and December 31, 2008, respectively		1,808			1,801
Additional paid-in capital		773,617			765,512
Retained earnings		1,953,954			1,970,824
Accumulated other comprehensive income		9,388			5,774
Treasury stock, at cost, 27,186,431 shares and 27,097,290 shares at June 30, 2009 and December 31, 2008, respectively		(618,147	)		(616,969	)

Total stockholders’ equity		2,120,620			2,126,942

Total liabilities and stockholders’ equity	$	2,651,351		$	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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Operating revenues:
Contract drilling	$	101,716		$	416,835		$	327,420		$	836,984
Pressure pumping		33,616			57,094			71,721			99,958
Drilling and completion fluids		20,267			38,745			48,097			71,295
Oil and natural gas		5,165			13,609			9,565			22,600

Total operating revenues		160,764			526,283			456,803			1,030,837


Operating costs and expenses:
Contract drilling		56,950			251,381			183,271			495,748
Pressure pumping		22,862			32,506			49,868			61,011
Drilling and completion fluids		19,005			31,449			43,527			59,982
Oil and natural gas		1,820			3,529			3,796			5,596
Depreciation, depletion and impairment		68,857			65,673			139,204			129,399
Selling, general and administrative		16,236			17,747			32,220			34,743
Net loss (gain) on asset disposals/retirements		176			(2,721	)		350			(2,535	)
Other operating expenses		2,000			300			6,000			600

Total operating costs and expenses		187,906			399,864			458,236			784,544

Operating income (loss)		(27,142	)		126,419			(1,433	)		246,293


Other income (expense):
Interest income		204			493			265			836
Interest expense		(839	)		(63	)		(1,286	)		(340	)
Other		12			353			35			737

Total other income (expense)		(623	)		783			(986	)		1,233


Income (loss) before income taxes		(27,765	)		127,202			(2,419	)		247,526


Income tax expense (benefit):
Current		(2,862	)		29,229			(2,824	)		57,941
Deferred		(7,160	)		16,551			1,945			30,754

Total income tax expense (benefit)		(10,022	)		45,780			(879	)		88,695

Net income (loss)	$	(17,743	)	$	81,422		$	(1,540	)	$	158,831


Net income (loss) per common share:
Basic	$	(0.12	)	$	0.52		$	(0.01	)	$	1.03

Diluted	$	(0.12	)	$	0.52		$	(0.01	)	$	1.01


Weighted average number of common shares outstanding:
Basic		151,941			153,978			151,839			153,289

Diluted		151,941			155,894			151,839			155,410


Cash dividends per common share	$	0.05		$	0.16		$	0.10		$	0.28

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:
Net loss		—			—		—			(1,540	)		—		—			(1,540	)
Foreign currency translation adjustment, net of tax of $2,095		—			—		—			—			3,614		—			3,614

Total comprehensive income		—			—		—			(1,540	)		3,614		—			2,074


Issuance of restricted stock		588			6		(6	)		—			—		—			—
Vesting of restricted stock units		6			—		—			—			—		—			—
Forfeitures of restricted stock		(32	)		—		—			—			—		—			—
Exercise of stock options		48			1		270			—			—		—			271
Stock-based compensation		—			—		9,608			—			—		—			9,608
Tax expense related to stock-based compensation		—			—		(1,767	)		—			—		—			(1,767	)
Payment of cash dividends		—			—		—			(15,330	)		—		—			(15,330	)
Purchase of treasury stock		—			—		—			—			—		(1,178	)		(1,178	)

Balance, June 30, 2009		180,802		$	1,808	$	773,617		$	1,953,954		$	9,388	$	(618,147	)	$	2,120,620

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		—			—		—			158,831			—			—			158,831
Foreign currency translation adjustment, net of tax of $1,206		—			—		—			—			(2,081	)		—			(2,081	)

Total comprehensive income		—			—		—			158,831			(2,081	)		—			156,750


Issuance of restricted stock		577			6		(6	)		—			—			—			—
Forfeitures of restricted stock		(30	)		—		—			—			—			—			—
Exercise of stock options		2,284			23		25,344			—			—			—			25,367
Stock-based compensation		—			—		10,137			—			—			—			10,137
Tax benefit related to stock-based compensation		—			—		16,068			—			—			—			16,068
Payment of cash dividends		—			—		—			(43,504	)		—			—			(43,504	)
Purchase of treasury stock		—			—		—			—			—			(4,559	)		(4,559	)

Balance, June 30, 2008		180,217		$	1,802	$	755,124		$	1,831,947		$	18,126		$	(550,710	)	$	2,056,289

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)


	Six Months Ended
	June 30,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(1,540	)	$	158,831
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and impairment		139,204			129,399
Provision for bad debts		6,000			600
Dry holes and abandonments		118			600
Deferred income tax expense		1,945			30,754
Stock-based compensation expense		9,608			10,137
Net loss (gain) on asset disposals/retirements		350			(2,535	)
Changes in operating assets and liabilities:
Accounts receivable		290,501			(19,609	)
Income taxes receivable/payable		3,595			(19,923	)
Inventory and other assets		4,031			(2,912	)
Accounts payable		(74,914	)		14,929
Accrued expenses		(24,113	)		(13,960	)
Other liabilities		(17	)		(13,035	)

Net cash provided by operating activities		354,768			273,276

Cash flows from investing activities:
Purchases of property and equipment		(246,549	)		(176,162	)
Proceeds from disposal of assets		713			4,429

Net cash used in investing activities		(245,836	)		(171,733	)

Cash flows from financing activities:
Purchases of treasury stock		(1,178	)		(4,559	)
Dividends paid		(15,330	)		(43,504	)
Tax benefit (expense) related to stock-based compensation		(1,767	)		16,068
Repayment of borrowings under line of credit		—			(50,000	)
Line of credit issuance costs		(6,169	)		—
Proceeds from exercise of stock options		271			25,367

Net cash used in financing activities		(24,173	)		(56,628	)

Effect of foreign exchange rate changes on cash		1,683			(117	)

Net increase in cash and cash equivalents		86,442			44,798
Cash and cash equivalents at beginning of period		81,223			17,434

Cash and cash equivalents at end of period	$	167,665		$	62,232


Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest expense	$	(517	)	$	(444	)
Income taxes	$	8,075		$	(60,025	)

Non-cash investing and financing activities:
Net increase (decrease) in payables for purchases of property and equipment	$	15,964		$	(7,119	)
Net decrease in deposits on equipment purchases	$	30,616		$	1,223

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 six months ended June 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.

The Company has performed an evaluation of subsequent events through August 4, 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 the provisions of FASB Staff Position No. EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities(“FSP EITF 03-6-1”) in the quarter ended March 31, 2009. FSP EITF 03-6-1 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 six months ended June 30, 2008 has been adjusted retrospectively to conform with the provisions of FSP EITF 03-6-1. The impact of this retrospective application was to reduce Basic EPS for the three months ended June 30, 2008 by $0.01 and to reduce Basic EPS and Diluted EPS for the six months ended June 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 six months ended June 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 six months ended June 30, 2009 and 2008 (in thousands, except per share amounts):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
BASIC EPS:
Net income (loss)	$	(17,743	)	$	81,422		$	(1,540	)	$	158,831
Less earnings attributed to holders of non-vested restricted stock		163			(750	)		14			(1,466	)

Earnings attributed to common stockholders	$	(17,580	)	$	80,672		$	(1,526	)	$	157,365


Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		151,941			153,978			151,839			153,289


Basic net income per common share	$	(0.12	)	$	0.52		$	(0.01	)	$	1.03


DILUTED EPS:
Earnings attributed to common stockholders	$	(17,580	)	$	80,672		$	(1,526	)	$	157,365
Add incremental earnings related to potential common shares		—			6			—			15

Adjusted earnings attributed to common stockholders	$	(17,580	)	$	80,678		$	(1,526	)	$	157,380


Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		151,941			153,978			151,839			153,289
Add dilutive effect of potential common shares		—			1,916			—			2,121

Weighted average number of diluted common shares outstanding		151,941			155,894			151,839			155,410


Diluted net income per common share	$	(0.12	)	$	0.52		$	(0.01	)	$	1.01


Potentially dilutive securities excluded as anti-dilutive		8,386			655			8,386			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. All share-based awards have been equity instruments in the form of stock options, restricted stock or restricted stock units and have included service and, in certain cases, performance conditions. 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 six month periods ended June 30, 2009 and 2008 follow:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Volatility		50.02	%		35.74	%		49.91	%		35.73	%
Expected term (in years)		4.00			4.00			4.00			4.00
Dividend yield		1.52	%		1.64	%		1.68	%		1.68	%
Risk-free interest rate		1.68	%		2.92	%		1.66	%		2.94	%

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


				Weighted
				Average
	Underlying			Exercise
	Shares			Price
Outstanding at January 1, 2009		5,933,572		$	21.20
Granted		1,022,500		$	13.11
Exercised		(47,600	)	$	5.69
Expired		—		$	—

Outstanding at June 30, 2009		6,908,472		$	20.11

Exercisable at June 30, 2009		5,022,389		$	20.74

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 used 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 June 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		588,600		$	13.74
Vested		(526,947	)	$	28.26
Forfeited		(31,874	)	$	28.59

Non-vested restricted stock outstanding at June 30, 2009		1,459,350		$	22.62

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 June 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		—		$	—

Non-vested restricted stock units outstanding at June 30, 2009		18,167		$	25.44

3. Property and Equipment

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


	June 30,			December 31,
	2009			2008
Equipment	$	3,151,517		$	2,897,431
Oil and natural gas properties		89,117			89,809
Buildings		65,271			61,529
Land		10,220			10,196

		3,316,125			3,058,965
Less accumulated depreciation and depletion		(1,222,516	)		(1,121,853	)

Property and equipment, net	$	2,093,609		$	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 based upon the type and nature of services and products offered. 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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues:
Contract drilling (a)	$	101,917		$	417,874		$	327,739		$	838,826
Pressure pumping		33,616			57,094			71,721			99,958
Drilling and completion fluids (b)		20,267			38,746			48,097			71,346
Oil and natural gas		5,165			13,609			9,565			22,600

Total segment revenues		160,965			527,323			457,122			1,032,730
Elimination of intercompany revenues (a)(b)		(201	)		(1,040	)		(319	)		(1,893	)

Total revenues	$	160,764		$	526,283		$	456,803		$	1,030,837


Income (loss) before income taxes:
Contract drilling	$	(14,885	)	$	106,795		$	26,126		$	225,181
Pressure pumping		(898	)		14,277			(1,773	)		18,729
Drilling and completion fluids		(1,095	)		4,055			(577	)		4,722
Oil and natural gas		558			7,173			(2,998	)		11,470

		(16,320	)		132,300			20,778			260,102
Corporate and other		(10,646	)		(8,602	)		(21,861	)		(16,344	)
Net gain (loss) on asset disposals/retirements (c)		(176	)		2,721			(350	)		2,535
Interest income		204			493			265			836
Interest expense		(839	)		(63	)		(1,286	)		(340	)
Other		12			353			35			737

Income (loss) before income taxes	$	(27,765	)	$	127,202		$	(2,419	)	$	247,526


	June 30,		December 31,
	2009		2008
Identifiable assets:
Contract drilling	$	2,116,820	$	2,255,421
Pressure pumping		213,917		210,805
Drilling and completion fluids		69,787		99,433
Oil and natural gas		25,020		31,760
Corporate and other (d)		225,807		115,398

Total assets	$	2,651,351	$	2,712,817


(a)		Includes contract drilling intercompany revenues of approximately $201,000 and $1.0 million for the three months ended


		June 30, 2009 and 2008, respectively. Includes contract drilling intercompany revenues of approximately $319,000 and $1.8 million for the six months ended June 30, 2009 and 2008, respectively.

(b)		Includes drilling and completion fluids intercompany revenues of approximately $1,000 for the three months ended June 30, 2008. Includes drilling and completion fluids intercompany revenues of approximately $51,000 for the six months ended June 30, 2008.

(c)		Net gains or losses associated with the disposal or retirement of assets relate to decisions of the executive management group regarding corporate strategy. Accordingly, the related gains or losses 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 June 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 June 30, 2009 and December 31, 2008 (in thousands):


	June 30,		December 31,
	2009		2008
Salaries, wages, payroll taxes and benefits	$	11,417	$	30,334
Workers’ compensation liability		67,367		70,439
Sales, use and other taxes		12,784		12,015
Insurance, other than workers’ compensation		13,397		14,209
Other		3,638		5,658

	$	108,603	$	132,655

7. Asset Retirement Obligation

Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” requires that the Company record 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 six months ended June 30, 2009 and 2008 (in thousands):


	2009			2008
Balance at beginning of year	$	3,047		$	1,593
Liabilities incurred		93			261
Liabilities settled		(172	)		(207	)
Accretion expense		59			29
Revision in estimated costs of plugging oil and natural gas wells		(14	)		1,025

Asset retirement obligation at end of period	$	3,013		$	2,701

8. Borrowings Under Line of Credit

The Company entered into an unsecured revolving line of credit (“LOC”) on March 20, 2009 with a maximum borrowing capacity of $220 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. On June 19, 2009, the Company entered into a Commitment Increase and Joinder Agreement to increase the maximum borrowing capacity to $240 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 June 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 June 30, 2009).

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

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 June 30, 2009, the Company had no borrowings outstanding under the LOC. The Company had $46.3 million in letters of credit outstanding at June 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 June 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 June 30, 2009, no amounts had been drawn under the letters of credit.

As of June 30, 2009, the Company had commitments to purchase approximately $154 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 six months ended June 30, 2008 and 2009 as follows:


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

Total cash dividends	$	0.28	$	43,504


2009:	Per Share		Total
			(in thousands)
Paid on March 31, 2009	$	0.05	$	7,655
Paid on June 30, 2009		0.05		7,675

Total cash dividends	$	0.10	$	15,330

On July 29, 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 September 30, 2009 to holders of record as of September 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 six months ended June 30, 2009, the Company purchased 3,324 shares of its common stock under the Program at a cost of approximately $46,000. As of June 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 85,817 shares of stock from employees during the six months ended June 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 $1.1 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 FASB issued Statement No. 157, Fair Value Measurements (“FAS 157”). FAS 157 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 FAS 157 was limited to financial assets and liabilities and became effective on January 1, 2008 for the Company. The impact of the initial application of FAS 157 was not material. On January 1, 2009, the Company adopted FAS 157 on a prospective basis for non-financial assets and liabilities that are not measured at fair value on a recurring basis. The application of FAS 157 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. This application of FAS 157 has not had a material impact on the Company.

In December 2007, the FASB issued Statement No. 141(R),Business Combinations(“FAS 141(R)”) and Statement No. 160,Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51(“FAS 160”). FAS 141(R) is a revision of Statement No. 141,Business Combinations, and calls for significant changes from current practice in accounting for business combinations. FAS 141(R) 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. FAS 160 amends ARB 51 to establish accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years beginning on or after December 15, 2008. Both FAS 141(R) and FAS 160 became effective for the Company on January 1, 2009. The application of FAS 141(R) and FAS 160 did not have a material impact on the Company.

In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities(“FSP EITF 03-6-1”). FSP EITF 03-6-1 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. FSP EITF 03-6-1 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 FSP EITF 03-6-1 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 Company is currently evaluating the impact that the Final Rule may have on its consolidated financial statements.

In April 2009, the FASB issued FASB Staff Position No. 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly(“FSP 157-4”). FSP 157-4 provides 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 FAS 157. The provisions of this FSP 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 FSP 157-4 did not have a material impact on the Company.

In April 2009, the FASB issued FASB Staff Position No. 107-1 and APB No. 28-1,Interim Disclosures about Fair Value of Financial Instruments(“FSP 107-1”). This FSP increases the frequency of fair value disclosures as required by FAS 107,Disclosures about Fair Value of Financial Instruments, from annual only to quarterly reporting periods. The provisions of this FSP 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 FSP 107-1 did not have a material impact on the Company.

In June 2009, the FASB issued Statement of Financial Accounting Standards No. 167,Amendments to FASB Interpretation No. 46(R)(“FAS 167”). FAS 167 retains the scope of FASB Interpretation No. 46(R) with the addition of entities previously considered qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this Statement, FASB Interpretation No. 46(R) required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. FAS 167 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 FAS 167 is not expected to have a material impact on the Company.

In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162(“FAS 168”). On the effective date of FAS 168, theFASB Accounitng Standards Codification(“Codification”) will become the source of authoritative U.S. generally accepted accounting principles. Following FAS 168, the FASB will not 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. FAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009 and will be effective for the Company in the quarter ending September 30, 2009. The adoption of FAS 168 will not have a material impact on the Company.

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 six months ended June 30, 2009 and 2008, our operating revenues consisted of the following (dollars in thousands):


	Three Months Ended June 30,								Six Months Ended June 30,
	2009				2008				2009				2008
Contract drilling	$	101,716	63	%	$	416,835	79	%	$	327,420	72	%	$	836,984	81	%
Pressure pumping		33,616	21			57,094	11			71,721	16			99,958	10
Drilling and completion fluids		20,267	13			38,745	7			48,097	10			71,295	7
Oil and natural gas		5,165	3			13,609	3			9,565	2			22,600	2

	$	160,764	100	%	$	526,283	100	%	$	456,803	100	%	$	1,030,837	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, Mississippi 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 second quarter of 2009, our average number of rigs operating was 63 compared to 244 in the second quarter of 2008. Our average number of rigs operating during the second quarter of 2009 included approximately seven rigs under term contracts that earned standby revenues of $7.5 million. Rigs on standby earn a discounted dayrate since they do not have crews and have lower costs. Additionally, we recognized $901,000 of revenues during the second quarter of 2009 from the early termination of term contracts. Our average revenue per operating day was $17,780 in the second quarter of 2009 compared to $18,740 in the second quarter of 2008. We had a consolidated net loss of $17.7 million for the second quarter of 2009 compared to consolidated net income of $81.4 million for the second 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 second 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 have reduced or curtailed their drilling programs, which has 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 60 in June 2009. Furthermore, these factors could 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 June 30, 2009, which includes approximately $230 million in working capital (including $168 million in cash and cash equivalents) and approximately $194 million available under our current $240 million line of credit, 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, expand into new regions, pay cash dividends and survive the current downturn in our industry.

Commitments and Contingencies— As of June 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 June 30, 2009, no amounts had been drawn under the letters of credit.

As of June 30, 2009, we had commitments to purchase approximately $154 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 June 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 recent 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 June 30, 2009, we had working capital of $230 million, including cash and cash equivalents of $168 million. For the six months ended June 30, 2009, our sources of cash flow included $355 million from operating activities.

During the six months ended June 30, 2009, we used $15.3 million to pay dividends on our common stock, $6.2 million to pay issuance costs related to our LOC and $247 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 six months ended June 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

Total cash dividends	$	0.10	$	15,330

On July 29, 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 September 30, 2009 to holders of record as of September 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 six months ended June 30, 2009, we purchased 3,324 shares of our common stock under the Program at a cost of approximately $46,000. As of June 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 revolving line of credit with a maximum borrowing and letter of credit capacity of $240 million. Interest is paid on the outstanding principal amount of borrowings under the revolving line of credit 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 June 30, 2009, we had no borrowings outstanding under this revolving line of credit. We had $46.3 million in letters of credit outstanding at June 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 current revolving line of credit, together with cash expected to be generated from operations, 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 existing 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 June 30, 2009 and 2008:


	2009			2008		%Change
Contract Drilling	(Dollars in thousands)
Revenues	$	101,716		$	416,835		(75.6	)%
Direct operating costs	$	56,950		$	251,381		(77.3	)%
Selling, general and administrative	$	1,096		$	1,297		(15.5	)%
Depreciation	$	58,555		$	57,362		2.1	%
Operating income (loss)	$	(14,885	)	$	106,795		N/M
Operating days		5,720			22,245		(74.3	)%
Average revenue per operating day	$	17.78		$	18.74		(5.1	)%
Average direct operating costs per operating day	$	9.96		$	11.30		(11.9	)%
Average rigs operating		63			244		(74.2	)%
Capital expenditures	$	148,447		$	67,815		118.9	%

Revenues and direct operating costs decreased in the second quarter of 2009 compared to the second 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 second quarter of 2009 included an average of approximately seven rigs that earned standby revenues of $7.5 million. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. Additionally, we recognized $901,000 of revenues during the second quarter of 2009 from the early termination of drilling contracts. Excluding the impact of standby revenues and the

early termination of drilling contracts, average revenue per operating day decreased in the second quarter of 2009 compared to the second 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 at higher rates. Average direct operating costs per operating day decreased in the second quarter of 2009 compared to the second quarter of 2008 primarily due to decreases in labor and repair costs as well as the impact of rigs earning standby revenues for which no crews were maintained in the second quarter of 2009. 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.


	2009			2008		%Change
Pressure Pumping	(Dollars in thousands)
Revenues	$	33,616		$	57,094		(41.1	)%
Direct operating costs	$	22,862		$	32,506		(29.7	)%
Selling, general and administrative	$	4,964		$	5,834		(14.9	)%
Depreciation	$	6,688		$	4,477		49.4	%
Operating income (loss)	$	(898	)	$	14,277		N/M
Total jobs		1,681			3,400		(50.6	)%
Average revenue per job	$	20.00		$	16.79		19.1	%
Average direct operating costs per job	$	13.60		$	9.56		42.3	%
Capital expenditures	$	6,753		$	17,689		(61.8	)%

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 second quarter of 2009 compared to the second quarter of 2008 primarily due to headcount reductions. Significant capital expenditures have been incurred to add capacity and modify and upgrade existing equipment. The increase in depreciation expense is a result of these capital expenditures.


	2009			2008		%Change
Drilling and Completion Fluids	(Dollars in thousands)
Revenues	$	20,267		$	38,745		(47.7	)%
Direct operating costs	$	19,005		$	31,449		(39.6	)%
Selling, general and administrative	$	1,757		$	2,517		(30.2	)%
Depreciation	$	600		$	724		(17.1	)%
Operating income (loss)	$	(1,095	)	$	4,055		N/M
Capital expenditures	$	—		$	1,525		(100.0	)%

Revenues and direct operating costs decreased in the second quarter of 2009 compared to the second 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 second quarter of 2009 compared to the second quarter of 2008 primarily due to a decrease in compensation costs for sales and support personnel due to headcount reductions.


	2009		2008		%Change
Oil and Natural Gas Production and Exploration	(Dollars in thousands,
	except sales prices)
Revenues	$	5,165	$	13,609		(62.0	)%
Direct operating costs	$	1,820	$	3,529		(48.4	)%
Depreciation, depletion and impairment	$	2,787	$	2,907		(4.1	)%
Operating income	$	558	$	7,173		(92.2	)%
Capital expenditures	$	1,551	$	4,527		(65.7	)%
Average net daily oil production (Bbls)		753		814		(7.5	)%
Average net daily natural gas production (Mcf)		3,478		4,126		(15.7	)%
Average oil sales price (per Bbl)	$	57.30	$	123.71		(53.7	)%
Average natural gas sales price (per Mcf)	$	3.92	$	11.85		(66.9	)%

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 second quarter of 2009 includes approximately $600,000 incurred to impair certain oil and natural gas properties compared to approximately $79,000 incurred to impair certain oil and natural gas properties in the second quarter 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. Depletion expense decreased approximately $609,000 primarily due to the impact of decreases in carrying value of properties resulting from impairment charges recognized prior to the second quarter of 2009.


	2009		2008			%Change
Corporate and Other	(Dollars in thousands)
Selling, general and administrative	$	8,419	$	8,099			4.0	%
Depreciation	$	227	$	203			11.8	%
Other operating expenses	$	2,000	$	300			566.7	%
Net loss (gain) on asset disposals/retirements	$	176	$	(2,721	)		N/M
Interest income	$	204	$	493			(58.6	)%
Interest expense	$	839	$	63			1,231.7	%
Other income	$	12	$	353			(96.6	)%

Selling, general and administrative expenses increased in the second quarter of 2009 compared to the second quarter of 2008 primarily as a result of increased professional fees and increased non-cash stock based compensation. Other operating expenses increased due to an increase in bad debt expense of $1.7 million in the second quarter of 2009 compared to the second quarter 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 second quarter of 2008 we recognized a net gain on the disposal of assets of approximately $2.7 million primarily due to the sale of certain assets in our contract drilling segment. Interest expense increased in the second quarter of 2009 compared to the second quarter of 2008 due to amortization of LOC issuance costs and increased fees associated with the unused portion of the LOC.

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


	2009		2008		%Change
Contract Drilling	(Dollars in thousands)
Revenues	$	327,420	$	836,984		(60.9	)%
Direct operating costs	$	183,271	$	495,748		(63.0	)%
Selling, general and administrative	$	2,082	$	2,821		(26.2	)%
Depreciation	$	115,941	$	113,234		2.4	%
Operating income	$	26,126	$	225,181		(88.4	)%
Operating days		17,193		44,478		(61.3	)%
Average revenue per operating day	$	19.04	$	18.82		1.2	%
Average direct operating costs per operating day	$	10.66	$	11.15		(4.4	)%
Average rigs operating		95		244		(61.1	)%
Capital expenditures	$	215,449	$	135,026		59.6	%

Revenues and direct operating costs decreased in the first six months of 2009 compared to the first six 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 six months of 2009 included an average of approximately nine rigs that earned standby revenues of $18.1 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 six months of 2009 from the early termination of drilling contracts. Average direct operating costs per operating day decreased in the first six months of 2009 compared to the first six months of 2008 primarily due to decreases in labor and repair costs as well as the impact of rigs earning standby revenues for which no crews were maintained in the first six months of 2009. Selling, general and administrative expenses decreased in the first six months of 2009 compared to the first six months of 2008 primarily as a result of lower professional fees and headcount reductions. 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.


	2009			2008		%Change
Pressure Pumping	(Dollars in thousands)
Revenues	$	71,721		$	99,958		(28.2	)%
Direct operating costs	$	49,868		$	61,011		(18.3	)%
Selling, general and administrative	$	10,799		$	11,441		(5.6	)%
Depreciation	$	12,827		$	8,777		46.1	%
Operating income (loss)	$	(1,773	)	$	18,729		N/M
Total jobs		3,592			6,311		(43.1	)%
Average revenue per job	$	19.97		$	15.84		26.1	%
Average direct operating costs per job	$	13.88		$	9.67		43.5	%
Capital expenditures	$	28,573		$	30,648		(6.8	)%

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. 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.


	2009			2008		%Change
Drilling and Completion Fluids	(Dollars in thousands)
Revenues	$	48,097		$	71,295		(32.5	)%
Direct operating costs	$	43,527		$	59,982		(27.4	)%
Selling, general and administrative	$	3,932		$	5,143		(23.5	)%
Depreciation	$	1,215		$	1,448		(16.1	)%
Operating income (loss)	$	(577	)	$	4,722		N/M
Capital expenditures	$	6		$	1,533		(99.6	)%

Revenues and direct operating costs decreased in the first six months of 2009 compared to the first six 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 six months of 2009 compared to the first six months of 2008 primarily due to a decrease in compensation costs for sales and support personnel due to headcount reductions.


	2009			2008		%Change
	(Dollars in thousands,
Oil and Natural Gas Production and Exploration	except sales prices)
Revenues	$	9,565		$	22,600		(57.7	)%
Direct operating costs	$	3,796		$	5,596		(32.2	)%
Depreciation, depletion and impairment	$	8,767		$	5,534		58.4	%
Operating income (loss)	$	(2,998	)	$	11,470		N/M
Capital expenditures	$	2,521		$	8,955		(71.8	)%
Average net daily oil production (Bbls)		817			758		7.8	%
Average net daily natural gas production (Mcf)		3,493			3,776		(7.5	)%
Average oil sales price (per Bbl)	$	47.74		$	111.23		(57.1	)%
Average natural gas sales price (per Mcf)	$	3.96		$	10.57		(62.5	)%

Revenues decreased primarily due to lower average sales prices of oil and natural gas. Average net daily oil production increased due to the addition of new wells. Average net daily natural gas production decreased primarily due to production declines on existing wells. Depreciation, depletion and impairment expense in the first six months of 2009 includes approximately $3.1 million incurred to impair certain oil and natural gas properties compared to approximately $300,000 incurred to impair certain oil and natural gas properties in the first six 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. Depletion expense increased approximately $518,000 due to lower reserves, which resulted from decreased oil and natural gas commodity prices.


	2009		2008			%Change
Corporate and Other	(Dollars in thousands)
Selling, general and administrative	$	15,407	$	15,338			0.4	%
Depreciation	$	454	$	406			11.8	%
Other operating expenses	$	6,000	$	600			900.0	%
Net loss (gain) on asset disposals/retirements	$	350	$	(2,535	)		N/M
Interest income	$	265	$	836			(68.3	)%
Interest expense	$	1,286	$	340			278.2	%
Other income	$	35	$	737			(95.3	)%

Other operating expenses increased due to an increase in bad debt expense of $5.4 million in the first six months of 2009 compared to the first six 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 six months of 2008 we recognized a net gain on the disposal of assets of approximately $2.5 million primarily due to the sale of certain assets in our contract drilling segment. Interest expense increased in the first six months of 2009 compared to the first six months of 2008 due to amortization of LOC issuance costs and increased fees associated with the unused portion of the LOC.

Recently Issued Accounting Standards

In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“FAS 157”). FAS 157 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 FAS 157 was limited to financial assets and liabilities and became effective on January 1, 2008 for us. The impact of the initial application of FAS 157 was not material. On January 1, 2009, we adopted FAS 157 on a prospective basis for non-financial assets and liabilities that are not measured at fair value on a recurring basis. The application of FAS 157 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. This application of FAS 157 has not had a material impact on us.

In December 2007, the FASB issued Statement No. 141(R),Business Combinations(“FAS 141(R)”) and Statement No. 160,Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51(“FAS 160”). FAS 141(R) is a revision of Statement No. 141,Business Combinations, and calls for significant changes from current practice in accounting for business combinations. FAS 141(R) 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. FAS 160 amends ARB 51 to establish accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years beginning on or after December 15, 2008. Both FAS 141(R) and FAS 160 became effective for us on January 1, 2009. The application of FAS 141(R) and FAS 160 did not have a material impact on us.

In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities(“FSP EITF 03-6-1”). FSP EITF 03-6-1 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. FSP EITF 03-6-1 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 adoption of FSP EITF 03-6-1 has not had a material impact on us.

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

In April 2009, the FASB issued FASB Staff Position No. 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have significantly Decreased and Identifying Transactions That Are Not Orderly. (“FSP 157-4”). FSP 157-4 provides 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 FAS 157. The provisions of this FSP 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 FSP 157-4 did not have a material impact on us.

In April 2009, the FASB issued FASB Staff Position No. 107-1 and APB No. 28-1,Interim Disclosures about Fair Value of Financial Instruments(“FSP 107-1”). This FSP increases the frequency of fair value disclosures as required by FAS 107,Disclosures about Fair Value of Financial Instruments, from annual only to quarterly reporting periods. The provisions of this FSP 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 FSP 107-1 did not have a material impact on us.

qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this Statement, FASB Interpretation No. 46(R) required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. FAS 167 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 FAS 167 is not expected to have a material impact on us.

In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162(“FAS 168”). On the effective date of FAS 168, theFASB Accounitng Standards Codification(“Codification”) will become the source of authoritative U.S. generally accepted accounting principles. Following FAS 168, the FASB will not 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. FAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009 and will be effective for us in the quarter ending September 30, 2009. The adoption of FAS 168 will not 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 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 to an average of $3.91 per Mcf in the month of June. 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 June 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 June 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.

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 Exchange Act and the Securities 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.

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 June 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)
April 1-30, 2009		—	$	—		—	$	113,326
May 1-31, 2009		—	$	—		—	$	113,326
June 1-30, 2009 (2)		70,439	$	13.66		3,324	$	113,280

Total		70,439	$	13.66		3,324	$	113,280


(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 67,115 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 4.Submission of Matters to a Vote of Security Holders

On June 3, 2009, the Company held its Annual Meeting of Stockholders. At the meeting, the stockholders voted on the following matters:

	1.		The election of seven persons to serve as directors of the Company.

	2.		Ratification of the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm of the Company for the fiscal year ending December 31, 2009.

The seven nominees for election to the Board of Directors of the Company were elected at the meeting, and the other proposal received the affirmative votes required for approval. The voting results were as follows:


1.	Election of Directors	Votes For	Votes Withheld
	Mark S. Siegel	128,155,761	4,666,853
	Kenneth N. Berns	128,148,585	4,674,029
	Charles O. Buckner	119,527,156	13,295,458
	Curtis W. Huff	119,300,512	13,522,102
	Terry H. Hunt	125,492,385	7,330,228
	Kenneth R. Peak	119,312,590	13,510,024
	Cloyce A. Talbott	124,580,927	8,241,687


			Votes		Broker
		Votes For	Against	Abstentions	Non-votes
2.	Ratification of PricewaterhouseCoopers LLP as the Company’s independent registered public accounting firm	131,162,270	1,610,301	50,042	0

ITEM 5.Other Information

Effective as of August 10, 2009, the Company’s General Counsel and Secretary has resigned from those positions.

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		Credit Agreement dated March 20, 2009, among the Company, as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, each of Amegy Bank, N.A., Comerica Bank, and HSBC Bank USA, N.A., as lender, Bank of America, N.A., as syndication agent, letter of credit issuer and lender, and The Bank of Tokyo-Mitsubishi UFJ, Ltd. As documentation agent and lender (filed March 25, 2009 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.2*		Commitment Increase and Joinder Agreement dated June 19, 2009, among the Company, as borrower, Regions Bank as the new lender, Bank of America, N.A., as a letter of credit issuer and Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender.

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 June 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

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: August 4, 2009

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Patterson-UTI Energy (PTEN) 10-Q2009 Q2 Quarterly report

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