PTEN 10-Q Quarterly Report June 30, 2010

PATTERSON UTI ENERGY INC

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10-Q 1 d74142e10vq.htm FORM 10-Q 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 June 30, 2010


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. (Check one):


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

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

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

154,147,367 shares of common stock, $0.01 par value, as of July 30, 2010

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements
	Unaudited consolidated balance sheets		1
	Unaudited consolidated statements of operations		2
	Unaudited consolidated statements of changes in stockholders’ equity		3
	Unaudited consolidated statements of cash flows		5
	Notes to unaudited consolidated financial statements		6
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		23
ITEM 4.	Controls and Procedures		23

PART II — OTHER INFORMATION


ITEM 1A.	Risk Factors		24
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		25
ITEM 6.	Exhibits		25
Signature			27
EX-10.4
EX-10.5
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,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	95,979		$	49,877
Accounts receivable, net of allowance for doubtful accounts of $8,611 and $10,911 at June 30, 2010 and December 31, 2009, respectively		200,938			164,498
Federal and state income taxes receivable		5,160			118,869
Inventory		9,821			6,941
Deferred tax assets, net		21,320			32,877
Assets held for sale		—			42,424
Other		50,314			41,782

Total current assets		383,532			457,268
Property and equipment, net		2,289,929			2,110,402
Goodwill		86,234			86,234
Deposits on equipment purchases		32,940			914
Other		7,357			7,334

Total assets	$	2,799,992		$	2,662,152


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	172,352		$	83,700
Accrued expenses		123,953			109,608

Total current liabilities		296,305			193,308
Deferred tax liabilities, net		388,672			381,656
Other		6,593			5,488

Total liabilities		691,570			580,452

Commitments and contingencies (see Note 10)
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $.01; authorized 300,000,000 shares with 181,462,898 and 180,828,773 issued and 154,147,418 and 153,610,785 outstanding at June 30, 2010 and December 31, 2009, respectively		1,815			1,808
Additional paid-in capital		788,421			781,635
Retained earnings		1,920,184			1,901,853
Accumulated other comprehensive income		18,027			14,996
Treasury stock, at cost, 27,315,480 shares and 27,217,988 shares at June 30, 2010 and December 31, 2009, respectively		(620,025	)		(618,592	)

Total stockholders’ equity		2,108,422			2,081,700

Total liabilities and stockholders’ equity	$	2,799,992		$	2,662,152

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Operating revenues:
Contract drilling	$	239,966		$	101,716		$	450,711		$	327,420
Pressure pumping		59,364			33,616			113,115			71,721
Oil and natural gas		7,662			5,165			14,764			9,565

Total operating revenues		306,992			140,497			578,590			408,706


Operating costs and expenses:
Contract drilling		149,303			56,950			284,449			183,271
Pressure pumping		41,965			25,887			81,096			56,327
Oil and natural gas		1,780			1,820			3,842			3,796
Depreciation, depletion and impairment		78,783			68,257			154,499			137,989
Selling, general and administrative		12,343			11,454			23,806			21,829
Net (gain) loss on asset disposals		(21,939	)		234			(21,690	)		445
Provision for bad debts		(1,000	)		1,750			(1,000	)		5,750

Total operating costs and expenses		261,235			166,352			525,002			409,407

Operating income (loss)		45,757			(25,855	)		53,588			(701	)


Other income (expense):
Interest income		1,380			204			1,567			265
Interest expense		(1,383	)		(839	)		(2,784	)		(1,286	)
Other		174			12			249			35

Total other income (expense)		171			(623	)		(968	)		(986	)


Income (loss) before income taxes		45,928			(26,478	)		52,620			(1,687	)


Income tax expense (benefit):
Current		1,935			(2,388	)		(2,482	)		(2,554	)
Deferred		14,465			(7,199	)		21,388			1,923

Total income tax expense (benefit)		16,400			(9,587	)		18,906			(631	)

Income (loss) from continuing operations		29,528			(16,891	)		33,714			(1,056	)
Loss from discontinued operations, net of income taxes		—			(852	)		—			(484	)

Net income (loss)	$	29,528		$	(17,743	)	$	33,714		$	(1,540	)


Basic income (loss) per common share:
Income (loss) from continuing operations	$	0.19		$	(0.11	)	$	0.22		$	(0.01	)
Loss from discontinued operations, net of income taxes	$	0.00		$	(0.01	)	$	0.00		$	0.00
Net income (loss)	$	0.19		$	(0.12	)	$	0.22		$	(0.01	)

Diluted income (loss) per common share:
Income (loss) from continuing operations	$	0.19		$	(0.11	)	$	0.22		$	(0.01	)
Loss from discontinued operations, net of income taxes	$	0.00		$	(0.01	)	$	0.00		$	0.00
Net income (loss)	$	0.19		$	(0.12	)	$	0.22		$	(0.01	)

Weighted average number of common shares outstanding:
Basic		152,650			151,941			152,554			151,839

Diluted		152,871			151,941			152,852			151,839


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

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, 2009		180,829		$	1,808	$	781,635		$	1,901,853		$	14,996	$	(618,592	)	$	2,081,700

Comprehensive income:
Net income		—			—		—			33,714			—		—			33,714
Foreign currency translation adjustment, net of tax of $2,814		—			—		—			—			3,031		—			3,031

Total comprehensive income		—			—		—			33,714			3,031		—			36,745


Issuance of restricted stock		646			7		(7	)		—			—		—			—
Vesting of stock unit awards		7			—		—			—			—		—			—
Forfeitures of restricted stock		(53	)		—		—			—			—		—			—
Exercise of stock options		34			—		290			—			—		—			290
Stock-based compensation		—			—		7,987			—			—		—			7,987
Tax expense related to stock-based compensation		—			—		(1,484	)		—			—		—			(1,484	)
Payment of cash dividends		—			—		—			(15,383	)		—		—			(15,383	)
Purchase of treasury stock		—			—		—			—			—		(1,433	)		(1,433	)

Balance, June 30, 2010		181,463		$	1,815	$	788,421		$	1,920,184		$	18,027	$	(620,025	)	$	2,108,422

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 STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


	Six Months Ended
	June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	33,714		$	(1,540	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and impairment		154,499			137,989
Provision for bad debts		(1,000	)		5,750
Dry holes and abandonments		486			118
Deferred income tax expense		21,388			1,923
Stock-based compensation expense		7,987			9,439
Net (gain) loss on asset disposals		(21,690	)		445
Tax expense related to stock-based compensation		(1,484	)		(1,767	)
Changes in operating assets and liabilities:
Accounts receivable		(47,382	)		265,349
Income taxes receivable/payable		113,690			3,595
Inventory and other assets		(13,283	)		1,730
Accounts payable		18,441			(83,586	)
Accrued expenses		16,338			(26,324	)
Other liabilities		1,190			(33	)
Net cash provided by operating activities of discontinued operations		10,687			39,913

Net cash provided by operating activities		293,581			353,001

Cash flows from investing activities:
Purchases of property and equipment		(298,845	)		(246,543	)
Proceeds from disposal of assets		25,231			618
Net cash provided by investing activities of discontinued operations		42,646			89

Net cash used in investing activities		(230,968	)		(245,836	)

Cash flows from financing activities:
Purchases of treasury stock		(1,433	)		(1,178	)
Dividends paid		(15,383	)		(15,330	)
Line of credit issuance costs		—			(6,169	)
Proceeds from exercise of stock options		290			271

Net cash used in financing activities		(16,526	)		(22,406	)

Effect of foreign exchange rate changes on cash		15			1,683

Net increase in cash and cash equivalents		46,102			86,442
Cash and cash equivalents at beginning of period		49,877			81,223

Cash and cash equivalents at end of period	$	95,979		$	167,665


Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest expense	$	(1,733	)	$	(517	)
Income taxes	$	115,727		$	8,075

Supplemental investing and financing information:
Net increase in payables for purchases of property and equipment	$	71,259		$	15,964
Net (increase) decrease in deposits on equipment purchases	$	(32,026	)	$	30,616

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, 2009, as presented herein, was derived from the audited consolidated balance sheet of the Company, but does not include all disclosures required by accounting principles generally accepted in the United States of America. These unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009. The results of operations for the three and six months ended June 30, 2010 are not necessarily indicative of the results to be expected for the full year.

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

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

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

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

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

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

The following table presents information necessary to calculate income from continuing operations per share, income from discontinued operations per share and net income per share for the three months ended June 30, 2010 and 2009 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding, as their inclusion would have been anti-dilutive (in thousands, except per share amounts):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
BASIC EPS:
Income (loss) from continuing operations	$	29,528		$	(16,891	)	$	33,714		$	(1,056	)
Adjust for (income) loss attributed to holders of non-vested restricted stock		(232	)		155			(254	)		10

Income (loss) from continuing operations attributed to common stockholders	$	29,296		$	(16,736	)	$	33,460		$	(1,046	)


Loss from discontinued operations, net	$	—		$	(852	)	$	—		$	(484	)
Adjust for income attributed to holders of non-vested restricted stock		—			8			—			4

Loss from discontinued operations attributed to common stockholders	$	—		$	(844	)	$	—		$	(480	)


Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		152,650			151,941			152,554			151,839


Basic income (loss) from continuing operations per common share	$	0.19		$	(0.11	)	$	0.22		$	(0.01	)
Basic loss from discontinued operations per common share	$	0.00		$	(0.01	)	$	0.00		$	0.00
Basic net income (loss) per common share	$	0.19		$	(0.12	)	$	0.22		$	(0.01	)

DILUTED EPS:
Income (loss) from continuing operations attributed to common stockholders	$	29,296		$	(16,736	)	$	33,460		$	(1,046	)
Add incremental earnings related to potential common shares		—			—			—			—

Adjusted income (loss) from continuing operations attributed to common stockholders	$	29,296		$	(16,736	)	$	33,460		$	(1,046	)


Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		152,650			151,941			152,554			151,839
Add dilutive effect of potential common shares		221			—			298			—

Weighted average number of diluted common shares outstanding		152,871			151,941			152,852			151,839


Diluted income (loss) from continuing operations per common share	$	0.19		$	(0.11	)	$	0.22		$	(0.01	)
Diluted loss from discontinued operations per common share	$	0.00		$	(0.01	)	$	0.00		$	0.00
Diluted net income (loss) per common share	$	0.19		$	(0.12	)	$	0.22		$	(0.01	)

Potentially dilutive securities excluded as anti-dilutive		6,907			8,386			6,907			8,386

2. Discontinued Operations

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

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010		2009
Drilling and completion fluids revenues	$	—	$	20,267		$	3,737	$	48,097

Loss before income taxes	$	—	$	(1,287	)	$	—	$	(732	)
Income tax benefit		—		(435	)		—		(248	)

Loss from discontinued operations, net of income tax	$	—	$	(852	)	$	—	$	(484	)

3. Stock-based Compensation

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

Stock Options. The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate the grant date fair values for stock options granted in the three and six month periods ended June 30, 2010 and 2009 follow:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Volatility		45.92	%		50.02	%		45.98	%		49.91	%
Expected term (in years)		5.00			4.00			5.00			4.00
Dividend yield		1.35	%		1.52	%		1.35	%		1.68	%
Risk-free interest rate		2.46	%		1.68	%		2.47	%		1.66	%

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


				Weighted
				Average
	Underlying			Exercise
	Shares			Price
Outstanding at January 1, 2010		6,841,770		$	20.17
Granted		1,016,250		$	14.85
Exercised		(33,868	)	$	8.56
Cancelled		(10,000	)	$	13.17
Expired		(77,000	)	$	19.46

Outstanding at June 30, 2010		7,737,152		$	19.54

Exercisable at June 30, 2010		5,787,012		$	20.89

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

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


				Weighted
				Average
				Grant Date
	Shares			Fair Value
Non-vested restricted stock outstanding at January 1, 2010		1,231,901		$	21.67
Granted		645,950		$	14.27
Vested		(534,366	)	$	22.98
Forfeited		(53,026	)	$	22.08

Non-vested restricted stock outstanding at June 30, 2010		1,290,459		$	17.41

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

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


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

Non-vested restricted stock units outstanding at June 30, 2010		17,834		$	19.73

Performance Unit Awards. On April 28, 2009, the Company granted cash-settled performance unit awards to certain executive officers (the “2009 Performance Units”). The 2009 Performance Units provide for those executive officers to receive a cash payment upon the achievement of certain performance goals established by the Company during a specified period. The performance period for the 2009 Performance Units is the period from April 1, 2009 through March 31, 2012, but can extend through March 31, 2014 in certain circumstances. The performance goals for the 2009 Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee of the Board of Directors. These goals are considered to be market conditions under the relevant accounting standards and the market conditions are factored into the determination of the fair value of the performance units. Generally, the recipients will receive a base payment if the Company’s total shareholder return is positive and, when compared to the peer group, is at or above the 25 ^th percentile but less than the 50 ^th percentile, two times the base if at or above the 50 ^th percentile but less than the 75 ^th percentile, and four times the base if at the 75 ^th percentile or higher. The total base amount with respect to the 2009 Performance Units is approximately $1.7 million. As the 2009 Performance Units are to be settled in cash at the end of the performance period, the Company’s pro-rated obligation is measured at estimated fair value at the end of each reporting period using a Monte Carlo simulation model. As of June 30, 2010 this pro-rated obligation was approximately $917,000.

On April 27, 2010, the Company granted stock-settled performance unit awards to certain executive officers (the “2010 Performance Units”). The 2010 Performance Units provide for those executive officers to receive a grant of shares of stock upon the achievement of certain performance goals established by the Company during a specified period. The performance period for the 2010 Performance Units is the period from April 1, 2010 through March 31, 2013, but can extend through March 31, 2015 in certain circumstances. The performance goals for the 2010 Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee of the Board of Directors. These goals are considered to be market conditions under the relevant accounting standards and the market conditions are factored into the determination of the fair value of the performance units. Generally, the recipients will receive a base number of shares if the Company’s total shareholder return is positive and, when compared to the peer group, is at or above the 25 ^th percentile but less than the 50 ^th percentile, two times the base if at or above the 50 ^th percentile but less than the 75 ^th percentile, and four times the base if at the 75 ^th percentile or higher. The grant of shares when achievement is between the 25 ^th and 75 ^th percentile will be determined on a pro-rata basis. The total base number of shares with respect to the 2010 Performance Units is 89,375 shares. Because the 2010 Performance Units are stock-settled awards, they are accounted for as equity awards and measured at fair value on the date of grant. The fair value of the 2010 Performance Units as of the date of grant was approximately $3.1 million using a Monte Carlo

simulation model. This amount will be recognized on a straight-line basis over the performance period. During the three months ended June 30, 2010, the Company recognized approximately $260,000 in expense related to the 2010 Performance Units.

4. Property and Equipment

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


	June 30,			December 31,
	2010			2009
Equipment	$	3,543,064		$	3,230,737
Oil and natural gas properties		98,553			93,354
Buildings		57,042			56,563
Land		10,291			9,795

		3,708,950			3,390,449
Less accumulated depreciation and depletion		(1,419,021	)		(1,280,047	)

Property and equipment, net	$	2,289,929		$	2,110,402

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

5. Business Segments

The Company’s revenues, operating profits and identifiable assets are primarily attributable to three business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) the investment, on a working interest basis, in oil and natural gas properties. Each of these segments represents a distinct type of business. These segments have separate management teams which report to the Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. As discussed in Note 2, in January 2010 the Company exited the drilling and completion fluids business which previously was reported as a business segment. Operating results for that business for the three and six months ended June 30, 2010 and 2009 are presented as discontinued operations in the consolidated statements of operations. Separate financial data for each of our business segments is provided in the table below (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues:
Contract drilling (a)	$	240,894		$	101,917		$	452,371		$	327,739
Pressure pumping		59,364			33,616			113,115			71,721
Oil and natural gas		7,662			5,165			14,764			9,565

Total segment revenues		307,920			140,698			580,250			409,025
Elimination of intercompany revenues (a)		(928	)		(201	)		(1,660	)		(319	)

Total revenues	$	306,992		$	140,497		$	578,590		$	408,706


Income (loss) before income taxes:
Contract drilling	$	22,099		$	(14,885	)	$	30,800		$	26,126
Pressure pumping		6,706			(898	)		11,183			(1,773	)
Oil and natural gas		2,927			558			5,744			(2,998	)

		31,732			(15,225	)		47,727			21,355
Corporate and other		(7,914	)		(10,396	)		(15,829	)		(21,611	)
Net gain (loss) on asset disposals (b)		21,939			(234	)		21,690			(445	)
Interest income		1,380			204			1,567			265
Interest expense		(1,383	)		(839	)		(2,784	)		(1,286	)
Other		174			12			249			35

Income (loss) from continuing operations before income taxes	$	45,928		$	(26,478	)	$	52,620		$	(1,687	)


	June 30,		December 31,
	2010		2009
Identifiable assets:
Contract drilling	$	2,409,406	$	2,129,567
Pressure pumping		235,350		213,094
Oil and natural gas		29,906		25,355
Corporate and other (c)		125,330		294,136

Total assets	$	2,799,992	$	2,662,152


(a)		Consists of contract drilling intercompany revenues for drilling services provided to the oil and natural gas exploration and production segment.

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

(c)		Corporate and other assets at December 31, 2009 primarily include identifiable assets associated with the Company’s former drilling and completion fluids segment as well as cash on hand, income taxes receivable and certain deferred Federal income tax assets. Corporate assets at June 30, 2010 primarily include cash on hand and certain deferred Federal income tax assets.

6. Goodwill

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

As of June 30, 2010 and December 31, 2009, the Company had goodwill of $86.2 million, all within its contract drilling reporting unit. In the event that market conditions weaken, the Company may be required to record an impairment of goodwill in its contract drilling reporting unit in the future, and such impairment could be material.

7. Accrued Expenses

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


	June 30,		December 31,
	2010		2009
Salaries, wages, payroll taxes and benefits	$	27,512	$	14,744
Workers’ compensation liability		63,675		66,015
Insurance, other than workers’ compensation		10,957		11,261
Sales, use and other taxes		13,944		10,975
Other		7,865		6,613

	$	123,953	$	109,608

8. Asset Retirement Obligation

The Company records a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. This liability is included in the caption “other” in the liabilities section of the consolidated balance sheet. The following table describes the changes to the Company’s asset retirement obligations during the six months ended June 30, 2010 and 2009 (in thousands):


	Six Months Ended
	June 30,
	2010			2009
Balance at beginning of year	$	2,955		$	3,047
Liabilities incurred		142			93
Liabilities settled		(184	)		(172	)
Accretion expense		55			59
Revision in estimated costs of plugging oil and natural gas wells		—			(14	)

Asset retirement obligation at end of period	$	2,968		$	3,013

9. Borrowings Under Revolving Credit Facility

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

Interest is paid on the outstanding principal amount of revolving credit facility borrowings at a floating rate based on, at the Company’s election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on the Company’s debt to capitalization ratio. At June 30, 2010, the margin on LIBOR loans would have been 3.00% and the margin on base rate loans would have been 2.00%. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. This revolving credit facility includes various fees, including a commitment fee on the actual daily unused commitment. The commitment fee rate was 1.00% at June 30, 2010.

There are customary representations, warranties, restrictions and covenants associated with the revolving credit facility. Financial covenants under the revolving credit facility provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. As of June 30, 2010, the maximum debt to capitalization ratio was 35% and the minimum interest coverage ratio was 3.00 to 1. The Company does not expect that the restrictions and covenants will impact its ability to operate or react to opportunities that might arise.

As of June 30, 2010, the Company had no borrowings outstanding under the revolving credit facility. The Company had $41.2 million in letters of credit outstanding at June 30, 2010 and, as a result, had available borrowing capacity of approximately $199 million at that date. Each domestic subsidiary of the Company other than any immaterial subsidiary has unconditionally guaranteed the existing and future obligations of the Company and each other guarantor under the revolving credit facility and related loan documents, as well as obligations of the Company and its subsidiaries under any interest rate swap contracts that may be entered into with lenders party to the revolving credit facility.

10. Commitments, Contingencies and Other Matters

As of June 30, 2010, the Company maintained letters of credit in the aggregate amount of $41.2 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of June 30, 2010, no amounts had been drawn under the letters of credit.

As of June 30, 2010, the Company had commitments to purchase approximately $215 million of major equipment.

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

11. Stockholders’ Equity

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


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

Total cash dividends	$	0.10	$	15,330


	Per Share		Total
			(in thousands)
2010:
Paid on March 30, 2010	$	0.05	$	7,677
Paid on June 30, 2010		0.05		7,706

Total cash dividends	$	0.10	$	15,383

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

On August 1, 2007, the Company’s Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of the Company’s common stock in open market or privately negotiated transactions. During the six months ended June 30, 2010, the Company purchased 6,106 shares of its common stock under the program at a cost of approximately $84,000. As of June 30, 2010, the Company is authorized to purchase approximately $113 million of the Company’s outstanding common stock under the program. Shares purchased under the program are accounted for as treasury stock.

The Company purchased 91,386 shares of treasury stock from employees during the six months ended June 30, 2010. These shares were purchased at fair market value upon the vesting of restricted stock to provide the employees with the funds necessary to satisfy payroll tax withholding obligations. The total purchase price for these shares was approximately $1.3 million. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to the stock buyback program.

12. Income Taxes

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

As a result of the above conversion, the Company’s Canadian assets are no longer subject to United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, the Company has elected to permanently reinvest these unremitted earnings in Canada, and it intends to do so for the foreseeable future. As a result, no deferred United States Federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $825,000 as of June 30, 2010.

13. Recently Issued Accounting Standards

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

14. Subsequent Events

On July 2, 2010, the Company entered into an Asset Purchase Agreement (the “Purchase Agreement ”) by and among the Company, Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.), a Delaware corporation and a wholly-owned subsidiary of the Company (“Buyer”), Key Energy Pressure Pumping Services, LLC, a Texas limited liability company (“Key Pressure Pumping”), Key Electric Wireline Services, LLC, a Delaware limited liability company (together with Key Pressure Pumping, the “Sellers”), and Key Energy Services, Inc., a Maryland corporation. The transaction is expected to close during the quarter ending September 30, 2010.

Pursuant to the terms of the Purchase Agreement, the Buyer has agreed to purchase certain assets and assume certain liabilities from the Sellers relating to the businesses of providing certain pressure pumping services and electric wireline services to participants in the oil and natural gas industry for an approximate aggregate purchase price of $238 million in cash (the “Purchase Price”). The Purchase Price is subject to certain adjustments based on closing inventory and the value of certain owned properties that may be retained.

The Purchase Agreement contains customary representations, warranties, covenants, indemnification obligations and closing conditions. Subject to certain conditions and exceptions, the Purchase Agreement may be terminated prior to the Closing in the event that (i) Buyer and the Sellers mutually consent in writing to such termination, (ii) there is a material breach of any covenant in the Purchase Agreement by Buyer or the Sellers, (iii) any representation or warranty of Buyer or the Sellers made in the Purchase Agreement was untrue when made or becomes untrue or (iv) the closing has not occurred on or before December 1, 2010. The transaction is expected to close in September 2010.

Also on July 2, 2010, the Company entered into a 364-Day Credit Agreement (the “364-Day Credit Agreement”) among the Company, as borrower, and Wells Fargo Bank, N.A., as administrative agent and lender. The 364-Day Credit Agreement is a committed senior unsecured single draw term loan credit facility that permits a borrowing of up to $250 million; provided that the loan must be drawn no later than September 30, 2010 or, if an additional fee is paid, October 30, 2010. The maturity date under the 364-Day Credit Agreement is 364 days after the date on which the closing conditions under the 364-Day Credit Agreement are met.

Loans under the 364-Day Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 3.00% to 4.00% and the applicable margin on base rate loans varies from 2.00% to 3.00%, in each case determined based upon the Company’s debt to capitalization ratio.

Each domestic subsidiary of the Company other than any immaterial subsidiary has agreed to unconditionally guarantee all indebtedness and liabilities of the other guarantors and the Company arising under the 364-Day Credit Agreement and other loan documents. Such guarantees also cover obligations of the Company and any subsidiary of the Company arising under any interest rate swap contract with any person while such person is a lender under the 364-Day Credit Agreement.

The 364-Day Credit Agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 35% at any time, unless the Company enters into a bank credit facility that refinances the indebtedness under the credit agreement dated as of March 20, 2009 among the Company, the lenders party thereto and Wells Fargo, as administrative agent, in which case the debt to capitalization ratio may not exceed the lesser of (A) the debt to capitalization ratio as set forth in such credit facility and (B) 45%. The 364-Day Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The 364-Day Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) to interest charges. The 364-Day Credit Agreement also contains customary representations, warranties and affirmative and negative covenants.

DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

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

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


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

Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, pressure pumping services. In addition to the aforementioned contract services, we also invest, on a working interest basis, in oil and natural gas properties. Prior to the sale of substantially all of the assets of our drilling and completion fluids business in January 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators. Due to our exit from the drilling and completion fluids business in January 2010, we have presented the results of that operating segment as discontinued operations in this Report. For the three and six months ended June 30, 2010 and 2009, our operating revenues from continuing operations consisted of the following (dollars in thousands):


	Three Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
Contract drilling	$	239,966	79	%	$	101,716	72	%	$	450,711	77	%	$	327,420	80	%
Pressure pumping		59,364	19			33,616	24			113,115	20			71,721	18
Oil and natural gas		7,662	2			5,165	4			14,764	3			9,565	2

	$	306,992	100	%	$	140,497	100	%	$	578,590	100	%	$	408,706	100	%

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

Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the second quarter of 2010, our average number of rigs operating was 156 compared to 63 in the second quarter of 2009. Our average revenue per operating day was $16,920 in the second quarter of 2010 compared to $17,780 in the second quarter of 2009. We had consolidated net income of $29.5 million for the second quarter of 2010 compared to a consolidated net loss of $17.7 million for the second quarter of 2009. Included in consolidated net income for the second quarter of 2010 was a pre-tax gain on the sale of certain oil and natural gas properties of $20.1 million (approximately $12.9 million net of tax). The remaining increase in consolidated net income was primarily due to our contract drilling segment experiencing an increase in the average number of rigs operating and increases in large fracturing jobs in our pressure pumping segment in the second quarter of 2010 compared to the second quarter of 2009.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for natural gas and, to a lesser extent, oil. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our contract services. Conversely, in periods when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services. Subsequent to reaching a peak in June 2008, there was a significant decline in oil and natural gas prices and a substantial deterioration in the global economic environment. As part of this deterioration, there was substantial uncertainty in the capital markets and access to financing was reduced. Due to these conditions, our customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our services, as evidenced by the decline in our monthly average of rigs operating from a high of 283 in October 2008 to a low of 60 in June 2009 before partially recovering to 163 in June 2010. Furthermore, these factors have resulted in, and could continue to result in, certain of our customers experiencing an inability to pay suppliers, including us. We are also highly impacted by competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” included as Item 1A of Part II of this Report and included as Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

We believe that our liquidity as of June 30, 2010, which includes approximately $87.2 million in working capital and approximately $199 million available under our $240 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment and pay cash dividends.

On July 2, 2010, we entered into an Asset Purchase Agreement wherein one of our subsidiaries agreed to purchase certain assets and assume certain liabilities from Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC relating to the businesses of providing certain pressure pumping services and electric wireline services to participants in the oil and natural gas industry for an approximate aggregate purchase price of $238 million in cash. We also entered into the 364-Day Credit Agreement on July 2, 2010 which is a committed senior unsecured single draw term loan credit facility that permits a borrowing of up to $250 million; provided that the loan must be drawn no later than September 30, 2010 or, if an additional fee is paid, October 30, 2010. The maturity date under the 364-Day Credit Agreement is 364 days after the date on which the closing conditions under the 364-Day Credit Agreement are met.

If we pursue additional opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Commitments and Contingencies — As of June 30, 2010, we maintained letters of credit in the aggregate amount of $41.2 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of June 30, 2010, no amounts had been drawn under the letters of credit.

As of June 30, 2010, we had commitments to purchase approximately $215 million of major equipment.

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

Description of Business — We conduct our contract drilling operations primarily in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia and western Canada. As of June 30, 2010, we had approximately 350 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for

completion of new wells and remedial work on existing wells. We invest, on a working interest basis, in oil and natural gas properties. Prior to the sale of substantially all of the assets of our drilling and completion fluids business in January 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. Due to our exit from the drilling and completion fluids business in January 2010, we have presented the results of that operating segment as discontinued operations in this Report.

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

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

	•		movement of drilling rigs from region to region,

	•		reactivation of land-based drilling rigs, or

	•		construction of new drilling rigs.

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

Critical Accounting Policies

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

Liquidity and Capital Resources

As of June 30, 2010, we had working capital of $87.2 million, including cash and cash equivalents of $96.0 million compared to working capital of $264 million and cash and cash equivalents of $49.9 million at December 31, 2009. The decrease in working capital during the six months ended June 30, 2010 was primarily due to capital expenditures and deposits on equipment purchases exceeding operating cash flow.

During the six months ended June 30, 2010, our sources of cash flow included:

	•		$294 million from operating activities,

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

	•		$25.2 million in proceeds from the sale of certain oil and natural gas rights and the disposal of other assets.

During the six months ended June 30, 2010, we used $15.4 million to pay dividends on our common stock and $299 million to:

	•		build new drilling rigs,

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

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

	•		fund capital expenditures for our pressure pumping segment, and

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

We paid cash dividends during the six months ended June 30, 2010 as follows:


	Per Share		Total
			(in thousands)
Paid on March 30, 2010	$	0.05	$	7,677
Paid on June 30, 2010		0.05		7,706

Total cash dividends	$	0.10	$	15,383

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

On August 1, 2007, our Board of Directors approved a stock buyback program, authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. During the six months ended June 30, 2010, we purchased 6,106 shares of our common stock under the program at a cost of approximately $84,000. As of June 30, 2010, we are authorized to purchase approximately $113 million of our outstanding common stock under the program.

We have an unsecured revolving credit facility with a maximum borrowing and letter of credit capacity of $240 million. Interest is paid on the outstanding principal amount of borrowings under the revolving credit facility at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on our debt to capitalization ratio. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. As of June 30, 2010, we had no borrowings outstanding under the revolving credit facility. We had $41.2 million in letters of credit outstanding at June 30, 2010 and as a result, had available borrowing capacity of approximately $199 million at such date.

There are customary representations, warranties, restrictions and covenants associated with the revolving credit facility. Financial covenants under the revolving credit facility provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. As of June 30, 2010, the maximum debt to capitalization ratio was 35% and the minimum interest coverage ratio was 3.00 to 1. We were in compliance with these financial covenants as of June 30, 2010. We do not expect that the restrictions and covenants will impair our ability to operate or react to opportunities that might arise.

We believe that the current level of cash, short-term investments and borrowing capacity available under our revolving credit facility, together with cash expected to be generated from operations, should be sufficient to fund our current plans to build new equipment, make improvements to our existing equipment and pay cash dividends.

On July 2, 2010, we entered into an Asset Purchase Agreement wherein one of our subsidiaries agreed to purchase certain assets and assume certain liabilities from Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC relating to the business of providing certain pressure pumping services and certain electric wireline services to participants in the oil and natural gas industry for an approximate aggregate purchase price of $238 million in cash. We also entered into the 364-Day Credit Agreement on July 2, 2010 which is a committed senior unsecured single draw term loan credit facility that permits a borrowing of up to $250 million; provided that the loan must be drawn no later than September 30, 2010 or, if an additional fee is paid, October 30, 2010. The maturity date under the 364-Day Credit Agreement is 364 days after the date on which the closing conditions under the 364-Day Credit Agreement are met.

From time to time, opportunities to expand our business, including acquisitions and the building of new equipment, are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. If we pursue additional opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Results of Operations

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


Contract Drilling	2010		2009			% Change
	(Dollars in thousands)
Revenues	$	239,966	$	101,716			135.9	%
Direct operating costs	$	149,303	$	56,950			162.2	%
Selling, general and administrative	$	920	$	1,096			(16.1	)%
Depreciation	$	67,644	$	58,555			15.5	%
Operating income (loss)	$	22,099	$	(14,885	)		N/M
Operating days		14,186		5,720			148.0	%
Average revenue per operating day	$	16.92	$	17.78			(4.8	)%
Average direct operating costs per operating day	$	10.52	$	9.96			5.6	%
Average rigs operating		156		63			147.6	%
Capital expenditures	$	171,501	$	148,447			15.5	%

Revenues increased in 2010 compared to 2009 as a result of a significant increase in operating days reduced by the impact of a decrease in average revenue per operating day. Average revenue per operating day decreased in 2010 primarily due to decreases in dayrates for rigs that were operating in the spot market and a smaller proportion of rigs on term contracts which are generally at higher rates. Direct operating costs increased in 2010 compared to 2009 primarily as a result of an increase in the number of operating days. The increase in operating days was due to increased demand largely caused by higher prices for natural gas and oil. Significant capital expenditures were incurred in 2010 and 2009 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased as a result of capital expenditures.


Pressure Pumping	2010		2009			% Change
	(Dollars in thousands)
Revenues	$	59,364	$	33,616			76.6	%
Direct operating costs	$	41,965	$	25,887			62.1	%
Selling, general and administrative	$	2,805	$	1,939			44.7	%
Depreciation	$	7,888	$	6,688			17.9	%
Operating income (loss)	$	6,706	$	(898	)		N/M
Fracturing jobs		361		326			10.7	%
Other jobs		1,496		1,312			14.0	%
Total jobs		1,857		1,638			13.4	%
Average revenue per fracturing job	$	118.13	$	69.11			70.9	%
Average revenue per other job	$	11.18	$	8.45			32.3	%
Average revenue per total job	$	31.97	$	20.52			55.8	%
Average direct operating costs per total job	$	22.60	$	15.80			43.0	%
Capital expenditures	$	11,398	$	6,753			68.8	%

Our customers have increased their activities in the development of unconventional reservoirs in the Appalachian Basin resulting in an increase in larger fracturing jobs associated therewith. As a result, we have experienced an increase in the number of larger fracturing jobs as a proportion of the total fracturing jobs we performed. Revenues and direct operating costs increased primarily as a result of the increase in average revenue and direct operating costs per job. Increased average revenue per fracturing job reflects the increase in the proportion of larger fracturing jobs to total fracturing jobs, which was driven by demand for services associated with unconventional reservoirs. Average revenue per other job increased as a result of increased pricing for the services provided and a change in job mix. Average direct operating costs per job increased primarily due to the increase in larger fracturing jobs. Selling, general and administrative expense increased primarily due to additional costs necessary to support increased business activity in 2010. Significant capital expenditures have been incurred in recent years to add capacity. Depreciation expense increased as a result of capital expenditures.


Oil and Natural Gas Production and Exploration	2010		2009		% Change
	(Dollars in thousands,
	except sales prices)
Revenues	$	7,662	$	5,165		48.3	%
Direct operating costs	$	1,780	$	1,820		(2.2	)%
Depreciation, depletion and impairment	$	2,955	$	2,787		6.0	%
Operating income	$	2,927	$	558		424.6	%
Capital expenditures	$	5,493	$	1,551		254.2	%
Average net daily oil production (Bbls)		902		753		19.8	%
Average net daily natural gas production (Mcf)		3,024		3,478		(13.1	)%
Average oil sales price (per Bbl)	$	75.80	$	57.30		32.3	%
Average natural gas sales price (per Mcf)	$	5.24	$	3.92		33.7	%

Revenues increased due to higher average sales prices of oil and natural gas and increased oil production partially offset by a reduction in natural gas production. Depreciation, depletion and impairment expense in 2010 includes approximately $416,000 incurred to impair certain oil and natural gas properties compared to approximately $600,000 incurred to impair certain oil and natural gas properties in 2009. Capital expenditures increased in 2010 as a result of increases in commodity prices.


Corporate and Other	2010			2009			% Change
	(Dollars in thousands)
Selling, general and administrative	$	8,618		$	8,419			2.4	%
Depreciation	$	296		$	227			30.4	%
Provision for bad debts	$	(1,000	)	$	1,750			N/M
Net gain (loss) on asset disposals	$	21,939		$	(234	)		N/M
Interest income	$	1,380		$	204			576.5	%
Interest expense	$	1,383		$	839			64.8	%
Other income	$	174		$	12			1,350.0	%
Capital expenditures	$	1,515		$	—			N/A

The provision for bad debts in 2009 resulted from an increase in our reserve on specific account balances based on the deteriorating economic and credit environment at the time. The negative provision for bad debts in 2010 is the result of collections of certain accounts that had previously been reserved in addition to reductions in our reserve for specific accounts due to improved industry conditions. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on asset disposals in 2010 includes a gain of $20.1 million related to the sale of certain rights to explore and develop zones deeper than depths that we generally target for certain of the oil and natural gas properties in which we have working interests. Interest income increased due to the collection of interest on a customer account as well as interest received on prior overpayments of sales taxes in certain jurisdictions. Capital expenditures have increased in 2010 due to the ongoing implementation of a new enterprise resource planning system.

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


Contract Drilling	2010		2009		% Change
	(Dollars in thousands)
Revenues	$	450,711	$	327,420		37.7	%
Direct operating costs	$	284,449	$	183,271		55.2	%
Selling, general and administrative	$	2,152	$	2,082		3.4	%
Depreciation	$	133,310	$	115,941		15.0	%
Operating income	$	30,800	$	26,126		17.9	%
Operating days		27,007		17,193		57.1	%
Average revenue per operating day	$	16.69	$	19.04		(12.3	)%
Average direct operating costs per operating day	$	10.53	$	10.66		(1.2	)%
Average rigs operating		149		95		56.8	%
Capital expenditures	$	263,475	$	215,449		22.3	%

Revenues increased in 2010 compared to 2009 as a result of a significant increase in operating days somewhat reduced by the impact of a decrease in average revenue per operating day. Average revenue per operating day decreased in 2010 primarily due to decreases in dayrates for rigs that were operating in the spot market and a smaller proportion of rigs on term contracts which are generally at higher rates. Revenues in 2009 also included $7.5 million from the early termination of drilling contracts. We recognized no revenues from the early termination of drilling contracts in 2010. Direct operating costs increased in 2010 compared to

2009 primarily as a result of an increase in the number of operating days. The increase in operating days was due to increased demand largely caused by higher prices for natural gas and oil. Significant capital expenditures were incurred in 2010 and 2009 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased as a result of capital expenditures.


Pressure Pumping	2010		2009			% Change
	(Dollars in thousands)
Revenues	$	113,115	$	71,721			57.7	%
Direct operating costs	$	81,096	$	56,327			44.0	%
Selling, general and administrative	$	5,346	$	4,340			23.2	%
Depreciation	$	15,490	$	12,827			20.8	%
Operating income (loss)	$	11,183	$	(1,773	)		N/M
Fracturing jobs		658		745			(11.7	)%
Other jobs		2,750		2,705			1.7	%
Total jobs		3,408		3,450			(1.2	)%
Average revenue per fracturing job	$	126.09	$	64.67			95.0	%
Average revenue per other job	$	10.96	$	8.70			26.0	%
Average revenue per total job	$	33.19	$	20.79			59.6	%
Average direct operating costs per total job	$	23.80	$	16.33			45.7	%
Capital expenditures	$	20,811	$	28,573			(27.2	)%

Our customers have increased their activities in the development of unconventional reservoirs in the Appalachian Basin resulting in an increase in larger fracturing jobs associated therewith. As a result, we have experienced an increase in the number of larger fracturing jobs as a proportion of the total fracturing jobs we performed. A decrease in smaller traditional fracturing jobs contributed to the overall decrease in the number of total fracturing jobs. Revenues and direct operating costs increased primarily as a result of the increase in average revenue and direct operating costs per job. Increased average revenue per fracturing job reflects the increase in the proportion of larger fracturing jobs to total fracturing jobs, which was driven by demand for services associated with unconventional reservoirs. Average revenue per other job increased as a result of increased pricing for the services provided and a change in job mix. Average direct operating costs per job primarily increased due to the increase in larger fracturing jobs. Selling, general and administrative expense increased primarily due to additional costs necessary to support increased business activity in 2010. Significant capital expenditures have been incurred in recent years to add capacity. Depreciation expense increased as a result of capital expenditures.


Oil and Natural Gas Production and Exploration	2010		2009			% Change
	(Dollars in thousands,
	except sales prices)
Revenues	$	14,764	$	9,565			54.4	%
Direct operating costs	$	3,842	$	3,796			1.2	%
Depreciation, depletion and impairment	$	5,178	$	8,767			(40.9	)%
Operating income (loss)	$	5,744	$	(2,998	)		N/M
Capital expenditures	$	11,120	$	2,521			341.1	%
Average net daily oil production (Bbls)		830		817			1.6	%
Average net daily natural gas production (Mcf)		3,098		3,493			(11.3	)%
Average oil sales price (per Bbl)	$	75.96	$	47.74			59.1	%
Average natural gas sales price (per Mcf)	$	5.99	$	3.96			51.3	%

Revenues increased due to higher average sales prices of oil and natural gas partially offset by a reduction in natural gas production. Average net daily natural gas production decreased primarily due to production declines on existing wells. Depreciation, depletion and impairment expense in 2010 includes approximately $670,000 incurred to impair certain oil and natural gas properties compared to approximately $3.1 million incurred to impair certain oil and natural gas properties in 2009. Depletion expense decreased approximately $1.3 million primarily due to lower natural gas production and the impact of impairment charges. Capital expenditures increased in 2010 as a result of increases in commodity prices.


Corporate and Other	2010			2009		% Change
	(Dollars in thousands)
Selling, general and administrative	$	16,308		$	15,407		5.8	%
Depreciation	$	521		$	454		14.8	%
Provision for bad debts	$	(1,000	)	$	5,750		N/M
Net (gain) loss on asset disposals	$	(21,690	)	$	445		N/M
Interest income	$	1,567		$	265		491.3	%
Interest expense	$	2,784		$	1,286		116.5	%
Other income	$	249		$	35		611.4	%
Capital expenditures	$	3,439		$	—		N/A

Selling, general and administrative expense increased in 2010 primarily as a result of increased personnel costs. The provision for bad debts in 2009 resulted from an increase in our reserve on specific account balances based on the deteriorating economic and credit environment at the time. The negative provision for bad debts in 2010 is the result of collections of certain accounts that had previously been reserved and reductions in our reserve for certain accounts due to improved industry conditions. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on asset disposals in 2010 includes a gain of $20.1 million related to the sale of certain rights to explore and develop zones deeper than depths that we generally target for certain of the oil and natural gas properties in which we have working interests. Interest income increased due to the collection of interest on a customer account as well as interest received on prior overpayments of sales taxes in certain jurisdictions. Interest expense increased in 2010 due to the amortization of revolving credit facility issuance costs and increased fees associated with outstanding letters of credit and the unused portion of the revolving credit facility, all resulting from the re-negotiation of our revolving credit facility in March 2009. Capital expenditures have increased in 2010 due to the ongoing implementation of a new enterprise resource planning system.

Income Taxes

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

As a result of the above conversion, our Canadian assets are no longer subject to United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, we have elected to permanently reinvest these unremitted earnings in Canada, and we intend to do so for the foreseeable future. As a result, no deferred United States Federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $825,000 as of June 30, 2010.

Recently Issued Accounting Standards

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

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

Our revenue, profitability, financial condition and rate of growth are substantially dependent upon prevailing prices for natural gas and oil. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC to set and maintain production and price targets. All of these factors are beyond our control. During 2008, the monthly average market price of natural gas (monthly average Henry Hub price as reported by the Energy Information Administration) peaked in June at $13.06 per Mcf before rapidly declining to an average of $5.99 per Mcf in December. In 2009, the monthly average market price of natural gas

declined further to a low of $3.06 per Mcf in September. This decline in the market price of natural gas resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008 and drilling activities remained low throughout 2009. This reduction in demand combined with the reactivation and construction of new land drilling rigs in the United States during the last several years has resulted in excess capacity compared to demand. As a result of these factors, our average number of rigs operating has declined significantly from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for natural gas and oil would likely result in demand for our drilling rigs decreasing and would adversely affect our operating results, financial condition and cash flows.

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


ITEM 3.		*Quantitative and Qualitative Disclosures About Market Risk*

We currently have exposure to interest rate market risk associated with any borrowings that we have under our revolving credit facility or our 364-Day Credit Agreement. Interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on our debt to capitalization ratio. At June 30, 2010, the margin on LIBOR loans would have been 3.00% and the margin on base rate loans would have been 2.00%. As of June 30, 2010, we had no borrowings outstanding under our revolving credit facility. The 364-Day Credit Agreement was entered into on July 2, 2010 and no borrowings were made at that time.

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

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


ITEM 4.		*Controls and Procedures*

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

Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2010.

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 1A.		*Risk Factors*

Environmental Laws and Regulations, Including Violations Thereof, Could Materially Adversely Affect Our Operating Results.

All of our operations and facilities are subject to numerous Federal, state, foreign and local environmental laws, rules and regulations, including, without limitation, laws concerning the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance with these laws and regulations could be substantial. A failure to comply with these requirements could expose us to substantial civil and criminal penalties. In addition, environmental laws and regulations in the United States and Canada impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs, we may be deemed to be a responsible party under these laws and regulations.

We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the U.S. Environmental Protection Agency and the Canadian provinces of Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.

Both the Environmental Protection Agency and Congress are studying whether there is any link between hydraulic fracturing activities and soil or ground water contamination. As part of this study, the House Subcommittee on Energy and Environment sent requests to a number of companies, including one of our subsidiaries, for information on their hydraulic fracturing practices. Our subsidiary has responded to the inquiry. Bills pending in both the House and Senate, if adopted, would require the public disclosure of chemicals used in the fracturing process. It is possible that additional federal, state and local laws and regulations might be imposed on fracturing activities, which could result in increased costs to, and disclosure obligations for us to comply with such potential laws and regulations. In addition, such additional laws and regulations could restrict our ability and otherwise make it more difficult to provide fracturing services in connection with natural gas and oil wells and could have an adverse effect on our results of operation, liquidity and financial condition.


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, 2010.


							Approximate Dollar
					Total Number of		Value of Shares
					Shares (or Units)		That May Yet Be
					Purchased as Part		Purchased Under the
	Total		Average Price		of Publicly		Plans or
	Number of Shares		Paid per		Announced Plans		Programs (in
Period Covered	Purchased		Share		or Programs		thousands)(1)
April 1-30, 2010 (2)		628	$	14.83		—	$	113,247
May 1-31, 2010		—	$	—		—	$	113,247
June 1-30, 2010 (2)		74,891	$	13.83		6,106	$	113,162

Total		75,519	$	13.84		6,106	$	113,162


(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 628 shares in April and 68,785 shares in June from employees to provide the respective employees with the funds necessary to satisfy their tax withholding obligations with respect to the vesting of restricted shares. The price paid was the closing price of our common stock on the last business day prior to the date the shares vested. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to the stock buyback program.


ITEM 6.		*Exhibits*

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


2.1		Asset Purchase Agreement dated July 2, 2010 by and among Patterson-UTI Energy, Inc., a Delaware corporation, Portofino Acquisition Company, a Delaware corporation, Key Energy Pressure Pumping Services, LLC, a Texas limited liability company, Key Electric Wireline Services, LLC, a Delaware limited liability company, and Key Energy Services, Inc., a Maryland corporation (filed July 6, 2010 as Exhibit 2.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

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

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

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

10.1		Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.2		Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.3		Form of Amendment to Cash-Settled Performance Unit Award Agreement Under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010 and incorporated herein by reference).

10.4*		Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan.

10.5*		Form of Share-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan.

10.6		364-Day Credit Agreement dated July 2, 2010, among Patterson-UTI Energy, Inc., as borrower, and Wells Fargo Bank, N.A., as administrative agent and lender (filed July 6, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

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, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Stockholders’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.


*		filed herewith

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 2, 2010

TABLE OF CONTENTS

Part I Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 6. Exhibits

Exhibits

EX-10.4 EX-10.5 EX-31.1 EX-31.2 EX-32.1

PTEN 10-Q Quarter ended June 30, 2010

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Exhibits