Patterson-UTI Energy (PTEN) 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2012

or

¨ 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 incorporation or organization)	(I.R.S. Employer Identification No.)
450 GEARS ROAD, SUITE 500 HOUSTON, TEXAS	77067
(Address of principal executive offices)	(Zip Code)

(281) 765-7100

(Registrant’s telephone number, including area code)

N/A

(Former name, former address and former fiscal year,

if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨	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  ¨    No  x

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

151,762,648 shares of common stock, $0.01 par value, as of July 27, 2012

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
		Page
ITEM 1.	Financial Statements
	Unaudited consolidated balance sheets		1
	Unaudited consolidated statements of operations		2
	Unaudited consolidated statements of comprehensive income		3
	Unaudited consolidated statements of changes in stockholders’ equity		4
	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		18
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		27
ITEM 4.	Controls and Procedures		28
PART II — OTHER INFORMATION
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		28
ITEM 5.	Other Information		28
ITEM 6.	Exhibits		28
Signature			30

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, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	75,299		$	23,946
Accounts receivable, net of allowance for doubtful accounts of $4,734 and $4,887 at June 30, 2012 and December 31, 2011, respectively		528,808			518,109
Federal and state income taxes receivable		1,905			—
Inventory		27,390			31,306
Deferred tax assets, net		81,932			142,725
Other		45,231			48,864
Total current assets		760,565			764,950
Property and equipment, net		3,402,413			3,167,266
Goodwill and intangible assets		173,518			175,573
Deposits on equipment purchases		88,573			99,543
Other		17,546			14,569
Total assets	$	4,442,615		$	4,221,901
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	224,917		$	241,610
Federal and state income taxes payable		—			2,473
Accrued expenses		153,382			164,629
Current portion of long-term debt		—			10,000
Total current liabilities		378,299			418,712
Borrowings under revolving credit facility		—			110,000
Other long-term debt		600,000			382,500
Deferred tax liabilities, net		828,415			786,632
Other		6,618			7,426
Total liabilities		1,813,332			1,705,270
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 184,053,434 and 183,295,350 issued and 151,773,850 and 155,807,779 outstanding at June 30, 2012 and December 31, 2011, respectively		1,840			1,833
Additional paid-in capital		850,951			840,731
Retained earnings		2,453,741			2,279,367
Accumulated other comprehensive income		18,847			19,459
Treasury stock, at cost, 32,279,584 shares and 27,487,571 shares at June 30, 2012 and December 31, 2011, respectively		(696,096	)		(624,759	)
Total stockholders’ equity		2,629,283			2,516,631
Total liabilities and stockholders’ equity	$	4,442,615		$	4,221,901

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

1

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June  30,
	2012			2011			2012			2011
Operating revenues:
Contract drilling	$	460,249		$	386,479		$	949,731		$	763,837
Pressure pumping		206,173			200,131			447,895			379,790
Oil and natural gas		14,690			13,454			29,407			23,841
Total operating revenues		681,112			600,064			1,427,033			1,167,468
Operating costs and expenses:
Contract drilling		272,720			218,754			555,369			437,453
Pressure pumping		138,051			128,866			304,908			247,441
Oil and natural gas		2,583			2,103			5,313			4,100
Depreciation, depletion, amortization and impairment		128,477			102,749			251,430			198,964
Selling, general and administrative		16,719			16,749			30,587			32,724
Net gain on asset disposals		(28,332	)		(1,017	)		(30,732	)		(2,621	)
Provision for bad debts		—			—			1,600			—
Total operating costs and expenses		530,218			468,204			1,118,475			918,061
Operating income		150,894			131,860			308,558			249,407
Other income (expense):
Interest income		179			45			233			88
Interest expense		(5,051	)		(3,514	)		(9,633	)		(7,403	)
Other		(144	)		78			(89	)		197
Total other expense		(5,016	)		(3,391	)		(9,489	)		(7,118	)
Income from continuing operations before income taxes		145,878			128,469			299,069			242,289
Income tax expense (benefit):
Current		(829	)		15,449			6,681			19,031
Deferred		54,169			31,382			102,576			70,001
Total income tax expense		53,340			46,831			109,257			89,032
Income from continuing operations		92,538			81,638			189,812			153,257
Loss from discontinued operations, net of income taxes		—			—			—			(367	)
Net income	$	92,538		$	81,638		$	189,812		$	152,890
Basic income (loss) per common share:
Income from continuing operations	$	0.60		$	0.53		$	1.22		$	0.99
Loss from discontinued operations, net of income taxes	$	0.00		$	0.00		$	0.00		$	0.00
Net income	$	0.60		$	0.53		$	1.22		$	0.99
Diluted income (loss) per common share:
Income from continuing operations	$	0.60		$	0.52		$	1.22		$	0.98
Loss from discontinued operations, net of income taxes	$	0.00		$	0.00		$	0.00		$	0.00
Net income	$	0.60		$	0.52		$	1.22		$	0.98
Weighted average number of common shares outstanding:
Basic		153,269			153,556			153,947			153,340
Diluted		153,655			155,581			154,544			155,252
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.

2

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income	$	92,538		$	81,638		$	189,812		$	152,890
Other comprehensive income, net of taxes of $0 for all periods:
Foreign currency translation adjustment		(3,166	)		(538	)		(612	)		2,160
Total comprehensive income	$	89,372		$	81,100		$	189,200		$	155,050

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

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(unaudited, in thousands)

	Common Stock						Additional			Retained Earnings			Accumulated Other			Treasury Stock			Total
	Number of Shares			Amount			Paid-in Capital						Comprehensive Income
Balance, December 31, 2011		183,295		$	1,833		$	840,731		$	2,279,367		$	19,459		$	(624,759	)	$	2,516,631
Net income		—			—			—			189,812			—			—			189,812
Foreign currency translation adjustment		—			—			—			—			(612	)		—			(612	)
Issuance of restricted stock		788			8			(8	)		—			—			—			—
Vesting of stock unit awards		8			—			—			—			—			—			—
Forfeitures of restricted stock		(51	)		(1	)		1			—			—			—			—
Exercise of stock options		13			—			195			—			—			—			195
Stock-based compensation		—			—			11,240			—			—			—			11,240
Tax expense related to stock-based compensation		—			—			(1,208	)		—			—			—			(1,208	)
Payment of cash dividends		—			—			—			(15,438	)		—			—			(15,438	)
Purchase of treasury stock		—			—			—			—			—			(71,337	)		(71,337	)
Balance, June 30, 2012		184,053		$	1,840		$	850,951		$	2,453,741		$	18,847		$	(696,096	)	$	2,629,283

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

4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	189,812		$	152,890
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		251,430			198,964
Provision for bad debts		1,600			—
Dry holes and abandonments		85			150
Deferred income tax expense		102,576			70,001
Stock-based compensation expense		11,240			9,850
Tax expense related to stock-based compensation		(1,208	)		—
Net gain on asset disposals		(30,732	)		(2,621	)
Changes in operating assets and liabilities:
Accounts receivable		(10,448	)		(71,416	)
Income taxes receivable/payable		(4,458	)		73,749
Inventory and other assets		6,108			(13,719	)
Accounts payable		(8,466	)		10,649
Accrued expenses		(11,262	)		11,863
Other liabilities		(808	)		(4,748	)
Net cash used in operating activities of discontinued operations		—			(339	)
Net cash provided by operating activities		495,469			435,273
Cash flows from investing activities:
Purchases of property and equipment		(512,065	)		(427,618	)
Proceeds from disposal of assets		58,945			7,474
Net cash provided by investing activities of discontinued operations		—			25,500
Net cash used in investing activities		(453,120	)		(394,644	)
Cash flows from financing activities:
Purchases of treasury stock		(71,337	)		(4,216	)
Dividends paid		(15,438	)		(15,480	)
Tax benefit related to stock-based compensation		—			5,241
Proceeds from senior notes		300,000			—
Proceeds from borrowing under revolving credit facility		123,400			—
Repayment of borrowing under revolving credit facility		(233,400	)		—
Repayment of other long-term debt		(92,500	)		(2,500	)
Debt issuance costs		(1,549	)		—
Proceeds from exercise of stock options		195			13,008
Net cash provided by (used in) financing activities		9,371			(3,947	)
Effect of foreign exchange rate changes on cash		(367	)		290
Net increase in cash and cash equivalents		51,353			36,972
Cash and cash equivalents at beginning of period		23,946			27,612
Cash and cash equivalents at end of period	$	75,299		$	64,584
Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest, net of capitalized interest of $4,065 in 2012 and $4,468 in 2011	$	(8,153	)	$	(6,207	)
Income taxes	$	(7,250	)	$	61,351
Supplemental investing and financing information:
Net increase (decrease) in payables for purchases of property and equipment	$	(8,333	)	$	57,808
Net (increase) decrease in deposits on equipment purchases	$	10,970		$	(15,219	)

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

5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Consolidation and Presentation

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

The unaudited interim consolidated financial statements have been prepared by management of the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included either on the face of the financial statements or herein are sufficient to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for a fair statement of the information in conformity with accounting principles generally accepted in the United States of America have been included. The Unaudited Consolidated Balance Sheet as of December 31, 2011, 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, 2011. The results of operations for the three and six months ended June 30, 2012 are not necessarily indicative of the results to be expected for the full year.

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

The 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 (loss) per common share in its unaudited consolidated statements of operations: Basic net income (loss) per common share (“Basic EPS”) and diluted net income (loss) 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 using the treasury stock method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock.

6

The following table presents information necessary to calculate income from continuing operations per share, loss from discontinued operations per share and net income per share for the three and six months ended June 30, 2012 and 2011 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
BASIC EPS:
Income from continuing operations	$	92,538		$	81,638		$	189,812		$	153,257
Adjust for income attributed to holders of non-vested restricted stock		(806	)		(648	)		(1,550	)		(1,145	)
Income from continuing operations attributed to common stockholders	$	91,732		$	80,990		$	188,262		$	152,112
Loss from discontinued operations, net	$	—		$	—		$	—		$	(367	)
Adjust for loss attributed to holders of non-vested restricted stock		—			—			—			3
Loss from discontinued operations attributed to common stockholders	$	—		$	—		$	—		$	(364	)
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		153,269			153,556			153,947			153,340
Basic income from continuing operations per common share	$	0.60		$	0.53		$	1.22		$	0.99
Basic loss from discontinued operations per common share	$	0.00		$	0.00		$	0.00		$	0.00
Basic net income per common share	$	0.60		$	0.53		$	1.22		$	0.99
DILUTED EPS:
Income from continuing operations attributed to common stockholders	$	91,732		$	80,990		$	188,262		$	152,112
Add incremental earnings related to potential common shares		—			8			—			—
Adjusted income from continuing operations attributed to common stockholders	$	91,732		$	80,998		$	188,262		$	152,112
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		153,269			153,556			153,947			153,340
Add dilutive effect of potential common shares		386			2,025			597			1,912
Weighted average number of diluted common shares outstanding		153,655			155,581			154,544			155,252
Diluted income from continuing operations per common share	$	0.60		$	0.52		$	1.22		$	0.98
Diluted loss from discontinued operations per common share	$	0.00		$	0.00		$	0.00		$	0.00
Diluted net income per common share	$	0.60		$	0.52		$	1.22		$	0.98
Potentially dilutive securities excluded as anti-dilutive		5,969			380			5,529			1,796

2. Discontinued Operations

On January 27, 2011, the stock of the Company’s electric wireline subsidiary, Universal Wireline, Inc., was sold in a cash transaction for $25.5 million. Except for inventory, the working capital of Universal Wireline, Inc. was excluded from the sale and retained by a subsidiary of the Company. Universal Wireline, Inc. was formed in 2010 to acquire the electric wireline business of Key Energy Services, Inc. The results of operations of this business have been presented as results of discontinued operations in these consolidated financial statements. Upon being classified as held for sale, the carrying value of the assets to be disposed of were reduced to fair value less estimated costs to sell resulting in a charge of $2.2 million in 2010. Due to the fact that the carrying value of the assets had been adjusted to net realizable value during 2010, no significant additional gain or loss was recognized in connection with the sale in 2011.

7

Summarized operating results from discontinued operations for the three and six months ended June 30, 2012, and 2011 are shown below (in thousands):

	Three Months Ended June  30,				Six Months Ended June  30,
	2012		2011		2012		2011
Electric wireline revenues	$	—	$	—	$	—	$	1,104
Loss before income taxes	$	—	$	—	$	—	$	(576	)
Income tax benefit		—		—		—		209
Loss from discontinued operations, net of income tax	$	—	$	—	$	—	$	(367	)

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. The Company’s share-based awards have also included both cash-settled and share-settled performance unit awards. Cash-settled performance unit awards were 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, 2012 and 2011 follow:

	Three Months Ended June  30,						Six Months Ended June  30,
	2012			2011			2012			2011
Volatility		48.86	%		45.82	%		48.85	%		45.97	%
Expected term (in years)		5.00			5.00			5.00			5.00
Dividend yield		1.22	%		0.64	%		1.21	%		0.67	%
Risk-free interest rate		0.88	%		2.38	%		0.88	%		2.34	%

Stock option activity from January 1, 2012 to June 30, 2012 follows:

	Underlying Shares			Weighted Average Exercise Price
Outstanding at January 1, 2012		7,081,295		$	20.73
Granted		780,000		$	16.53
Exercised		(13,300	)	$	14.64
Outstanding at June 30, 2012		7,847,995		$	20.33
Exercisable at June 30, 2012		6,548,510		$	20.64

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. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

8

Restricted stock activity from January 1, 2012 to June 30, 2012 follows:

	Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock outstanding at January 1, 2012		1,213,799		$	24.13
Granted		788,650		$	15.60
Vested		(524,010	)	$	22.16
Forfeited		(51,696	)	$	21.89
Non-vested restricted stock outstanding at June 30, 2012		1,426,743		$	20.22

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. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

Restricted stock unit activity from January 1, 2012 to June 30, 2012 follows:

	Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock units outstanding at January 1, 2012		17,501		$	23.47
Granted		9,000		$	14.91
Vested		(7,830	)	$	21.08
Forfeited		—		$	—
Non-vested restricted stock units outstanding at June 30, 2012		18,671		$	20.35

Performance Unit Awards. In 2009, the Company granted cash-settled performance unit awards to certain executive officers (the “2009 Performance Units”). The 2009 Performance Units provided for those executive officers to receive a cash payment upon the achievement of certain performance goals established by the Compensation Committee during a specified period. The performance period for the 2009 Performance Units was the period from April 1, 2009 through March 31, 2012. The performance goals for the 2009 Performance Units were 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. These goals were considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the performance units. Generally, the recipients would receive a target payment if the Company’s total shareholder return was positive and, when compared to the peer group, was at or above the 50^th percentile but less than the 75^th percentile and two times the target if at the 75^th percentile or higher. The total target amount with respect to the 2009 Performance Units was approximately $3.4 million. If the Company’s total shareholder return was positive, and, when compared to the peer group, was at or above the 25^th percentile but less than the 50^th percentile, the recipients would only receive one-half of the target payment. Because the 2009 Performance Units were settled in cash at the end of the performance period, they were accounted for as liability awards and the Company’s pro-rated obligation was measured at estimated fair value at the end of each reporting period using a Monte Carlo simulation model. The performance period ended on March 31, 2012 and the Company’s total shareholder return was at the 46^th percentile. The resulting cash payments totaling $1.7 million were paid in April 2012. A compensation benefit associated with the 2009 Performance Units of approximately $1.9 million was recognized for the six months ended June 30, 2012. Compensation expense associated with the 2009 Performance Units was approximately $1.0 million and $2.2 million for the three and six month periods ended June 30, 2011, respectively.

In 2010, 2011 and 2012, the Company granted stock-settled performance unit awards to certain executive officers (the “Stock-Settled Performance Units”). The Stock-Settled Performance Units provide for the recipients to receive a grant of shares of stock upon the achievement of certain performance goals established by the Compensation Committee during the performance period. The performance period for the Stock-Settled Performance Units is the three year period commending on April 1 of the year of grant, but can extend for an additional two years in certain circumstances. The performance goals for the Stock-Settled 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. These goals are considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the performance units. Generally, the recipients will receive a target number of shares if the Company’s total shareholder return is positive and, when compared to the peer group, is at the 50^th percentile and two times the target if at the 75^th percentile or higher. If the Company’s total shareholder return is

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positive, and, when compared to the peer group, is at or above the 25^th percentile, but less than the 50^th percentile, the recipients will only receive one-half of the target number of shares. 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 target number of shares with respect to the Stock-Settled Performance Units is set forth below:

	2012 Performance Unit Awards		2011 Performance Unit Awards		2010 Performance Unit Awards
Target number of shares		192,000		144,375		178,750

Because the Stock-Settled Performance Units are stock-settled awards, they are accounted for as equity awards and measured at fair value on the date of grant using a Monte Carlo simulation model. The fair value of the Stock-Settled Performance Units is set forth below (in thousands):

	2012 Performance Unit Awards		2011 Performance Unit Awards		2010 Performance Unit Awards
Fair value at date of grant	$	3,065	$	5,569	$	3,117

These fair value amounts are charged to expense on a straight-line basis over the performance period. Compensation expense associated with the Stock-Settled Performance Units is shown below (in thousands):

	Three Months Ended June  30,				Six Months Ended June  30,
	2012		2011		2012		2011
Stock-based compensation expense associated with Stock-Settled Performance Units	$	979	$	724	$	1,703	$	983

4. Property and Equipment

Property and equipment consisted of the following at June 30, 2012 and December 31, 2011 (in thousands):

	June 30, 2012			December 31, 2011
Equipment	$	5,029,295		$	4,730,925
Oil and natural gas properties		145,303			131,812
Buildings		62,418			64,090
Land		10,411			11,467
		5,247,427			4,938,294
Less accumulated depreciation and depletion		(1,845,014	)		(1,771,028	)
Property and equipment, net	$	3,402,413		$	3,167,266

On April 23, 2012, the Company sold its flowback operations to a subsidiary of TETRA Technologies, Inc. in a cash transaction. The sale price was $42.5 million, and the Company recognized a gain of approximately $22.6 million in the second quarter of 2012 as a result of this transaction.

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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, included in discontinued operations for the six months ended June 30, 2011 are the operating results for an electric wireline business that was acquired on October 1, 2010 and sold in January 2011. Separate financial data for each of our business segments is provided in the table below (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues:
Contract drilling	$	461,798		$	387,622		$	952,501		$	765,647
Pressure pumping		206,173			200,131			447,895			379,790
Oil and natural gas		14,690			13,454			29,407			23,841
Total segment revenues		682,661			601,207			1,429,803			1,169,278
Elimination of intercompany revenues (a)		(1,549	)		(1,143	)		(2,770	)		(1,810	)
Total revenues	$	681,112		$	600,064		$	1,427,033		$	1,167,468
Income before income taxes:
Contract drilling	$	90,536		$	85,135		$	202,307		$	165,654
Pressure pumping		36,846			50,340			83,633			91,718
Oil and natural gas		7,224			7,129			14,742			11,947
		134,606			142,604			300,682			269,319
Corporate and other		(12,044	)		(11,761	)		(22,856	)		(22,533	)
Net gain on asset disposals (b)		28,332			1,017			30,732			2,621
Interest income		179			45			233			88
Interest expense		(5,051	)		(3,514	)		(9,633	)		(7,403	)
Other income (expense)		(144	)		78			(89	)		197
Income from continuing operations before income taxes	$	145,878		$	128,469		$	299,069		$	242,289

	June 30, 2012		December 31, 2011
Identifiable assets:
Contract drilling	$	3,466,902	$	3,252,116
Pressure pumping		774,924		748,643
Oil and natural gas		50,860		44,990
Corporate and other (c)		149,929		176,152
Total assets	$	4,442,615	$	4,221,901

(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 primarily include cash on hand, income taxes receivable and certain deferred tax assets.

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6. Goodwill and Intangible Assets

Goodwill— Goodwill by operating segment as of June 30, 2012 and changes for the six months then ended are as follows (in thousands):

	Contract Drilling		Pressure Pumping		Total
Balance December 31, 2011	$	86,234	$	67,575	$	153,809
Changes to goodwill		—		—		—
Balance June 30, 2012	$	86,234	$	67,575	$	153,809

There were no accumulated impairment losses as of June 30, 2012 or December 31, 2011.

Goodwill is evaluated at least annually on December 31 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. Goodwill impairment is measured using a two-step impairment test. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If the carrying value of a reporting unit exceeds its fair value the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of the shortfall.

Intangible Assets— Intangible assets were recorded in the pressure pumping operating segment in connection with the fourth quarter 2010 acquisition of the assets of a pressure pumping business. As a result of the purchase price allocation, the Company recorded intangible assets related to a non-compete agreement and the customer relationships acquired. These intangible assets were recorded at fair value on the date of acquisition.

The non-compete agreement has a term of three years from October 1, 2010. The value of this agreement was estimated using a with and without scenario where cash flows were projected through the term of the agreement assuming the agreement is in place and compared to cash flows assuming the non-compete agreement was not in place. The intangible asset associated with the non-compete agreement is being amortized on a straight-line basis over the three-year term of the agreement. Amortization expense of approximately $117,000 was recorded in the three months ended June 30, 2012 and 2011 and amortization expense of approximately $233,000 was recorded in the six months ended June 30, 2012 and 2011 associated with the non-compete agreement.

The value of the customer relationships was estimated using a multi-period excess earnings model to determine the present value of the projected cash flows associated with the customers in place at the time of the acquisition and taking into account a contributory asset charge. The resulting intangible asset is being amortized on a straight-line basis over seven years. Amortization expense of approximately $911,000 was recorded in the three months ended June 30, 2012 and 2011 and amortization expense of approximately $1.8 million was recorded in the six months ended June 30, 2012 and 2011 associated with customer relationships.

The following table presents the gross carrying amount and accumulated amortization of intangible assets as of June 30, 2012 (in thousands):

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Non-compete agreement	$	1,400	$	(816	)	$	584
Customer relationships		25,500		(6,375	)		19,125
Total intangible assets	$	26,900	$	(7,191	)	$	19,709

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7. Accrued Expenses

Accrued expenses consisted of the following at June 30, 2012 and December 31, 2011 (in thousands):

	June 30, 2012		December 31, 2011
Salaries, wages, payroll taxes and benefits	$	49,198	$	58,692
Workers’ compensation liability		66,214		66,121
Property, sales, use and other taxes		13,776		11,850
Insurance, other than workers’ compensation		8,789		6,012
Accrued interest payable		5,196		4,937
Deferred revenue - current		5,137		7,229
2009 Performance Unit Awards		—		3,640
Other		5,072		6,148
	$	153,382	$	164,629

Deferred revenue was recorded in the fourth quarter of 2010 in the purchase price allocation associated with the Company’s acquisition of a pressure pumping business. The deferred revenue relates to out-of-market pricing agreements that were in place at the acquired business at the time of the acquisition. The deferred revenue will be recognized as pressure pumping revenue over the remaining term of the pricing agreements. Deferred revenue of approximately $1.8 million and $3.6 million was recognized in the three and six months ended June 30, 2012, respectively, related to these pricing agreements. Deferred revenue of approximately $1.8 million and $4.7 million was recognized in the three and six months ended June 30, 2011, respectively, related to these pricing agreements.

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, 2012 and 2011 (in thousands):

	Six Months Ended June 30,
	2012			2011
Balance at beginning of year	$	3,455		$	3,063
Liabilities incurred		182			152
Liabilities settled		(83	)		(80	)
Accretion expense		79			70
Revision in estimated costs of plugging oil and natural gas wells		536			(2	)
Asset retirement obligation at end of period	$	4,169		$	3,203

9. Long Term Debt

Credit Facilities -On August 19, 2010, the Company entered into a Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other letter of credit issuer and lender parties thereto. The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility.

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

The term loan facility provided for a loan of $100 million which was funded on August 19, 2010. The term loan facility was payable in quarterly principal installments commencing November 19, 2010. The installment amounts were scheduled to vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments and 5.00% of the original principal amount for the next subsequent three quarterly installments, with the remainder becoming due at maturity. The maturity date for the term loan facility was August 19, 2014. The outstanding balance of the term loan facility was paid in full on June 14, 2012.

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Loans under the 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 2.75% to 3.75% and the applicable margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon the Company’s debt to capitalization ratio. As of June 30, 2012, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by the Company equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee payable to the lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75% based upon the Company’s debt to capitalization ratio and was 0.50% as of June 30, 2012.

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

The Credit Agreement contains customary representations, warranties, indemnities and affirmative and negative covenants. The Credit Agreement also requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45% at any time. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. The Company was in compliance with these covenants at June 30, 2012.

As of June 30, 2012, the outstanding balance under the term loan facility had been paid in full, and there were no borrowings outstanding under the revolving credit facility. The Company had $39.8 million in letters of credit outstanding at June 30, 2012 and, as a result, had available borrowing capacity of approximately $360 million at that date.

Senior Notes –On October 5, 2010, the Company completed the issuance and sale of $300 million in aggregate principal amount of its 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. The Company will pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.

On June 14, 2012, the Company completed the issuance and sale of $300 million in aggregate principal amount of its 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. The Company will pay interest on the Series A Notes on April 5 and October 5 of each year beginning October 5, 2012. The Series B Notes will mature on June 14, 2022.

The Series A Notes and Series B Notes are senior unsecured obligations of the Company which rank equally in right of payment with all other unsubordinated indebtedness of the Company. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of the existing domestic subsidiaries of the Company other than immaterial subsidiaries.

The Series A Notes and Series B Notes are prepayable at the Company’s option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreement. The Company must offer to prepay the notes upon the occurrence of any change of control. In addition, the Company must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

The respective note purchase agreements require compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The

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Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio for the four prior quarters of EBITDA to interest charges for that same period. The Company was in compliance with these covenants at June 30, 2012.

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

The Company incurred approximately $10.8 million in debt issuance costs during 2010 in connection with the Credit Agreement and the Series A Notes. The Company incurred approximately $1.5 million in debt issuance costs during 2012 in connection with the Series B Notes. These costs were deferred and are being recognized as interest expense over the term of the underlying debt. Interest expense related to the amortization of debt issuance costs was approximately $617,000 and 604,000 for the three months ended June 30, 2012 and 2011, respectively. Interest expense related to the amortization of debt issuance costs was approximately $1.2 million for the six months ended June 30, 2012 and 2011.

Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of June 30, 2012 (in thousands):

Year ending December 31,
2012	$	—
2013		—
2014		—
2015		—
2016		—
Thereafter		600,000
Total	$	600,000

10. Commitments, Contingencies and Other Matters

As of June 30, 2012, the Company maintained letters of credit in the aggregate amount of $39.8 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, 2012, no amounts had been drawn under the letters of credit.

As of June 30, 2012, the Company had commitments to purchase approximately $220 million of major equipment for its drilling and pressure pumping businesses.

The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants from certain vendors. These agreements expire in 2013 and 2016. As of June 30, 2012, the remaining obligation under these agreements is approximately $33.7 million, of which materials with a total purchase price of approximately $4.7 million are expected to be delivered during the last half of 2012. In the event that the required minimum quantities are not purchased during any contract year, the Company would be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November of 2011, the Company’s pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such vendor to finance the construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of June 30, 2012, advances of approximately $5.7 million had been made under this agreement and repayments of approximately $239,000 had been received resulting in a balance outstanding of approximately $5.5 million.

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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, 2011 and 2012 as follows:

2011:	Per Share		Total
			(in thousands)
Paid on March 30, 2011	$	0.05	$	7,708
Paid on June 30, 2011		0.05		7,772
Total cash dividends	$	0.10	$	15,480

2012:	Per Share		Total
			(in thousands)
Paid on March 30, 2012	$	0.05	$	7,788
Paid on June 29, 2012		0.05		7,650
Total cash dividends	$	0.10	$	15,438

On July 25, 2012, 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 28, 2012 to holders of record as of September 14, 2012. 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, 2012, approximately 4.7 million shares were purchased under the program at a cost of approximately $70.1 million. As of June 30, 2012, the Company was authorized to purchase approximately $42.8 million of the Company’s outstanding common stock under the program. On July 25, 2012, the Company’s Board of Directors terminated the remaining authority under the 2007 stock buyback program and approved a new stock buyback program authorizing purchases of up to $150 million of the Company’s common stock in open market or privately negotiated transactions. Shares purchased under the buyback programs are accounted for as treasury stock.

The Company purchased 83,229 shares of treasury stock from employees during the six months ended June 30, 2012. 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 $1.2 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 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 $23.5 million as of June 30, 2012.

13. Fair Values of Financial Instruments

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. These fair value estimates are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting.

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The estimated fair value of the Company’s outstanding debt balances (including current portion) as of June 30, 2012 and December 31, 2011 is set forth below (in thousands):

	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
Borrowings under Credit Agreement:
Revolving credit facility	$	—	$	—	$	110,000	$	110,000
Term loan facility		—		—		92,500		92,500
4.97% Series A Senior Notes		300,000		321,345		300,000		315,942
4.27% Series B Senior Notes		300,000		300,000		—		—
Total debt	$	600,000	$	621,345	$	502,500	$	518,442

The carrying values of the balances outstanding under the term loan facility and revolving credit facility at December 31, 2011 approximated their fair values as both facilities have a floating interest rate. The fair value of the 4.97% Series A Senior Notes at June 30, 2012 and December 31, 2011 was measured based on discounted cash flows associated with the Series A Senior Notes using current market rates of interest at those respective dates. The current market rates used in measuring this fair value were 3.78% at June 30, 2012 and 4.07% at December 31, 2011. The fair value of the 4.27% Series B Senior Notes at June 30, 2012 approximated carrying value due to the fact that these notes were priced and issued at a date in close proximity to June 30, 2012. These fair value estimates are based on observable market inputs and are considered Level 2 fair value estimates in the fair value hierarchy of fair value accounting.

14. Recently Issued Accounting Standards

In June 2011, the FASB issued an accounting standard update that requires that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. Historically, these components of other comprehensive income and total comprehensive income have been presented in the statement of changes in stockholders’ equity by many companies, including the Company. This requirement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and became effective for the Company in the quarter ending March 31, 2012. The adoption of this update has resulted in the addition of a new consolidated statement of comprehensive income being added to the Company’s consolidated financial statements.

In May 2011, the FASB issued an accounting standard update to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with United States GAAP and International Financial Reporting Standards. The amendments in this update do not require additional fair value measurements, but provide additional guidance as to measuring fair value as well as certain additional disclosure requirements. The requirements in this update are effective during interim and annual periods beginning after December 15, 2011 and became effective for the Company in the quarter ending March 31, 2012. The adoption of this update did not have a material impact on the Company’s disclosures included in its consolidated financial statements.

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DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue expectations and backlog; financing of operations; continued volatility of oil and natural gas prices; source and sufficiency of funds required for building new equipment and additional 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, global economic conditions, volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on day rates, utilization, margins and planned capital expenditures, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, adverse industry conditions, adverse credit and equity market conditions, difficulty in integrating acquisitions, shortages of labor, equipment, supplies and materials, weather, loss of key customers, liabilities from operations for which we do not have and receive full indemnification or insurance, 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, 2011 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, except as required by law.

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

Management Overview — We are a leading provider of 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 pressure pumping services. In addition to the aforementioned services, we also invest, on a non-operating working interest basis, in oil and natural gas properties. We acquired an electric wireline business on October 1, 2010 and sold the business on January 27, 2011. Due to our exit from the electric wireline business, we have presented the results of that business as discontinued operations in this Report.

As of June 30, 2012, we had a drilling fleet that consisted of more than 330 marketable land-based drilling rigs. Although there continued to be uncertainty with respect to the global economic environment and a decrease in commodity prices, activity in our drilling business increased during the second quarter of 2012 compared to the second quarter of 2011. In the second quarter of 2012, our average number of rigs operating was 224, including 224 in the United States and none in Canada, as compared to an average of 202 drilling rigs operating, including 199 rigs in the United States and 3 rigs in Canada during the same period in 2011.

While conventional wells remain an important source of natural gas and oil, this increased activity results, in part, from addressing our customers’ needs for drilling wells in the newer horizontal shale and other unconventional resource plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years. As of June 30, 2012, we have completed 100 new APEX^TM rigs and made performance and safety improvements to existing high capacity rigs. We expect to complete 24 new APEX^TM rigs in 2012. In connection with the newer horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. As of June 30, 2012, we have added approximately 500,000 hydraulic horsepower to our pressure pumping fleet since the end of 2009, and we had a total of approximately 660,000 hydraulic horsepower in our pressure pumping fleet at June 30, 2012. High oil prices have resulted in increased drilling and pressure pumping activity in the oil and liquids rich areas, although unusually low natural gas prices and the addition of new pressure pumping equipment to the marketplace has led to an excess supply of pressure pumping equipment in North America.

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We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with an original fixed term of six months or more. Our backlog as of June 30, 2012 was approximately $1.5 billion. We expect approximately $526 million of our backlog to be realized in the remainder of 2012. We calculate our backlog by multiplying the day rate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our term drilling contracts are subject to termination by the customer on short notice and provide for the payment of an early termination payment to us in the event that the contract is terminated by the customer.

For the three and six months ended June 30, 2012 and 2011, our operating revenues from continuing operations consisted of the following (in thousands):

	Three Months Ended June 30,								Six Months Ended June 30,
	2012				2011				2012				2011
Contract drilling	$	460,249	68	%	$	386,479	65	%	$	949,731	67	%	$	763,837	65	%
Pressure pumping		206,173	30			200,131	33			447,895	31			379,790	33
Oil and natural gas		14,690	2			13,454	2			29,407	2			23,841	2
	$	681,112	100	%	$	600,064	100	%	$	1,427,033	100	%	$	1,167,468	100	%

Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the second quarter of 2012, our average number of rigs operating was 224 compared to 202 in the second quarter of 2011. Our average revenue per operating day was $22,570 in the second quarter of 2012 compared to $21,000 in the second quarter of 2011. We had consolidated net income of $92.5 million for the second quarter of 2012 compared to consolidated net income of $81.6 million for the second quarter of 2011. The increase in consolidated net income was primarily due to our contract drilling segment experiencing an increase in the average number of rigs operating and an increase in the average revenue per operating day as well as a gain on the disposal of our flowback operations in 2012.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. 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 services. Conversely, in periods when these commodity prices deteriorate, the demand for our services generally weakens and we experience downward pressure on pricing for our services. After 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 number of rigs operating from a high of 283 in October 2008 to a low of 60 in June 2009. Our monthly average number of rigs operating has subsequently increased from the mid-year low of 60 in 2009 to 222 in June 2012 and our profitability has improved.

We are highly impacted by competition, the availability of excess equipment, labor issues, weather and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” included in Part I of our Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

We believe that our liquidity as of June 30, 2012, which includes approximately $382 million in working capital and approximately $360 million available under our $400 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, 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, 2012, we maintained letters of credit in the aggregate amount of $39.8 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, 2012, no amounts had been drawn under the letters of credit.

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As of June 30, 2012, we had commitments to purchase approximately $220 million of major equipment for our drilling and pressure pumping businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants from certain vendors. These agreements expire in 2013 and 2016. As of June 30, 2012, the remaining obligation under these agreements is approximately $33.7 million, of which materials with a total purchase price of approximately $4.7 million are expected to be delivered during the last half of 2012. In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November 2011, our pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and other assets and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of June 30, 2012, advances of approximately $5.7 million had been made under this agreement and repayments of approximately $239,000 had been received resulting in a balance outstanding of approximately $5.5 million.

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, Kansas, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia, Ohio and western Canada. As of June 30, 2012, we had more than 330 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for completion of new wells and remedial work on existing wells. We also invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests are located primarily in Texas and New Mexico.

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

In addition, unconventional resource plays have substantially increased 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 efficiently 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 technology drilling rigs.

Construction of new technology drilling rigs increased in recent years. The addition of new technology drilling rigs to the market, combined with a reduction in the drilling of vertical wells, has resulted in excess capacity of conventional drilling rigs. Similarly, the substantial recent increase in unconventional resource plays has led to higher demand for pressure pumping services, and there has been a significant increase in the construction of new pressure pumping equipment. As a result of low natural gas prices and the construction of new equipment, there is currently an excess of pressure pumping equipment available. In circumstances of excess capacity, providers of pressure pumping services will have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict either the future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses.

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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, 2011.

Liquidity and Capital Resources

As of June 30, 2012, we had working capital of $382 million, including cash and cash equivalents of $75.3 million compared to working capital of $346 million and cash and cash equivalents of $23.9 million at December 31, 2011.

During the six months ended June 30, 2012, our sources of cash flow included:

• $495 million from operating activities,

• $300 million in proceeds from the issuance of our Series B Senior Notes,

• $123 million in borrowings under our revolving credit facility,

• $58.9 million in proceeds from the disposal of property and equipment, including $42.5 million in proceeds from the sale of our flowback operations, and

�� • $195,000 from the exercise of stock options and related tax benefits associated with stock-based compensation.

During the six months ended June 30, 2012, we used $15.4 million to pay dividends on our common stock, $326 million to repay long-term debt, $71.3 million to repurchase shares of our common stock and $512 million:

• to build new drilling rigs and pressure pumping equipment,

• to make capital expenditures for the betterment and refurbishment of our drilling rigs and pressure pumping equipment,

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

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

We paid cash dividends during the six months ended June 30, 2012 as follows:

	Per Share		Total
			(in thousands)
Paid on March 30, 2012	$	0.05	$	7,788
Paid on June 29, 2012	$	0.05	$	7,650
Total cash dividends	$	0.10	$	15,438

On July 25, 2012, 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 28, 2012 to holders of record as of September 14, 2012. 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, 2012, we purchased approximately 4.7 million shares of our common stock under this program at a cost of approximately $70.1 million. As of June 30, 2012, we were authorized to purchase approximately $42.8 million of our outstanding common stock under the program. On July 25, 2012, our Board of Directors terminated the remaining authority under the 2007 stock buyback program and approved a new stock buyback program authorizing purchases of up to $150 million of our common stock in open market or privately negotiated transactions.

On August 19, 2010, we entered into a Credit Agreement (the “Credit Agreement”). The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility.

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

The term loan facility provided for a loan of $100 million which was funded on August 19, 2010. The term loan facility was payable in quarterly principal installments commencing November 19, 2010. The installment amounts were scheduled to vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the next subsequent three quarterly installments, with the remainder becoming due at maturity. The maturity date for the term loan facility was August 19, 2014. The outstanding balance of the term loan facility was paid in full on June 14, 2012.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon our debt to capitalization ratio. As of June 30, 2012, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee payable to the lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75% based upon our debt to capitalization ratio and was 0.50% as of June 30, 2012.

The Credit Agreement contains customary representations, warranties, indemnities and affirmative and negative covenants. The Credit Agreement also requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45% at any time. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of EBITDA of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of June 30, 2012. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

As of June 30, 2012, the outstanding balance under the term loan facility had been paid in full and there were no borrowings outstanding under the revolving credit facility. We had $39.8 million in letters of credit outstanding at June 30, 2012 and, as a result, we had available borrowing capacity under the revolving credit facility of approximately $360 million at that date.

On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.

On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We will pay interest on the Series B Notes on April 5 and October 5 of each year beginning October 5, 2012. The Series B Notes will mature on June 14, 2022.

The Series A and Series B Notes are prepayable at our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreement. We must offer to prepay the notes upon the occurrence of any change of control. In addition, we must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

The respective note purchase agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of

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the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio for the four prior quarters of EBITDA to interest charges for the same period. We were in compliance with these financial covenants as of June 30, 2012. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

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

We believe that our liquidity as of June 30, 2012, which included approximately $382 million in working capital and approximately $360 million available under our $400 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, 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, 2012 and 2011:

Contract Drilling	2012		2011		% Change
	(Dollars in thousands)
Revenues	$	460,249	$	386,479		19.1	%
Direct operating costs	$	272,720	$	218,754		24.7	%
Selling, general and administrative	$	1,286	$	1,308		(1.7	)%
Depreciation and impairment	$	95,707	$	81,282		17.7	%
Operating income	$	90,536	$	85,135		6.3	%
Operating days		20,392		18,406		10.8	%
Average revenue per operating day	$	22.57	$	21.00		7.5	%
Average direct operating costs per operating day	$	13.37	$	11.88		12.5	%
Average rigs operating		224		202		10.9	%
Capital expenditures	$	181,685	$	196,726		(7.6	)%

Revenues and direct operating costs increased in 2012 compared to 2011 as a result of an increase in the number of operating days and increases in average revenue and direct operating costs per operating day. Average revenue per operating day increased in 2012 primarily due to increases in contractual dayrates. Average direct operating costs per operating day increased in 2012 due primarily to higher labor and related costs as well as higher maintenance and repair costs. The increase in operating days was largely due to increased demand resulting from higher oil prices and the addition of newbuild APEX^TM rigs into our drilling fleet. Capital expenditures were incurred in 2012 and 2011 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased as a result of capital expenditures.

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Pressure Pumping	2012		2011		% Change
	(Dollars in thousands)
Revenues	$	206,173	$	200,131		3.0	%
Direct operating costs	$	138,051	$	128,866		7.1	%
Selling, general and administrative	$	4,344	$	4,456		(2.5	)%
Depreciation and amortization	$	26,932	$	16,469		63.5	%
Operating income	$	36,846	$	50,340		(26.8	)%
Fracturing jobs		326		349		(6.6	)%
Other jobs		1,425		1,636		(12.9	)%
Total jobs		1,751		1,985		(11.8	)%
Average revenue per fracturing job	$	542.52	$	484.21		12.0	%
Average revenue per other job	$	20.57	$	19.03		8.1	%
Average revenue per total job	$	117.75	$	100.82		16.8	%
Average direct operating costs per total job	$	78.84	$	64.92		21.4	%
Capital expenditures	$	57,525	$	41,435		38.8	%

Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. We have added additional equipment through construction and acquisition to meet this demand and expand our area of operations. As a result, although total fracturing jobs have decreased, we have experienced an increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. Average revenue per fracturing job increased as a result of this increase in the number of larger multi-stage fracturing jobs in 2012 as compared to 2011, as well as increased pricing. 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 total job increased primarily as a result of increased costs of materials and higher labor and related costs. These increases in direct operating costs were greater than the increased revenue in 2012 resulting in lower operating income in 2012 as compared to 2011. Significant capital expenditures have been incurred in recent years to add capacity in our pressure pumping segment. The increase in depreciation and amortization expense in 2012 was a result of our recent capital expenditures.

Oil and Natural Gas Production and Exploration	2012		2011		% Change
	(Dollars in thousands)
Revenues - Oil	$	13,509	$	12,000		12.6	%
Revenues – Natural gas and liquids	$	1,181	$	1,454		(18.8	)%
Revenues - Total	$	14,690	$	13,454		9.2	%
Direct operating costs	$	2,583	$	2,103		22.8	%
Depletion and impairment	$	4,883	$	4,222		15.7	%
Operating income	$	7,224	$	7,129		1.3	%
Capital expenditures	$	7,875	$	5,078		55.1	%

Total revenues increased as a result of increased production of oil. Oil production increased primarily due to the addition of new wells. Depletion and impairment expense in 2012 includes approximately $92,000 of oil and natural gas property impairments compared to approximately $759,000 of oil and natural gas property impairments in 2011. Depletion expense increased approximately $1.3 million in 2012 compared to 2011 primarily due to increased oil production.

Corporate and Other	2012			2011		% Change
	(Dollars in thousands)
Selling, general and administrative	$	11,089		$	10,985		0.9	%
Depreciation	$	955		$	776		23.1	%
Net gain on asset disposals	$	28,332		$	1,017		N/M
Interest income	$	179		$	45		297.8	%
Interest expense	$	5,051		$	3,514		43.7	%
Other income (expense)	$	(144	)	$	78		N/M
Capital expenditures	$	1,577		$	1,827		(13.7	)%

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 the disposal of assets in 2012 includes a gain of approximately $22.6 million associated with the sale of our flowback operations in April 2012. Interest expense increased in 2012 due primarily to interest charges on increased borrowings under our revolving credit facility.

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The following tables summarize operations by business segment for the six months ended June 30, 2012 and 2011:

Contract Drilling	2012		2011		% Change
	(Dollars in thousands)
Revenues	$	949,731	$	763,837		24.3	%
Direct operating costs	$	555,369	$	437,453		27.0	%
Selling, general and administrative	$	2,622	$	2,593		1.1	%
Depreciation and impairment	$	189,433	$	158,137		19.8	%
Operating income	$	202,307	$	165,654		22.1	%
Operating days		42,002		37,052		13.4	%
Average revenue per operating day	$	22.61	$	20.62		9.7	%
Average direct operating costs per operating day	$	13.22	$	11.81		11.9	%
Average rigs operating		231		205		12.7	%
Capital expenditures	$	382,292	$	331,975		15.2	%

Revenues and direct operating costs increased in 2012 compared to 2011 as a result of an increase in the number of operating days and increases in average revenue and direct operating costs per operating day. Average revenue per operating day increased in 2012 primarily due to increases in contractual dayrates. Average direct operating costs per operating day increased in 2012 due primarily to higher labor and related costs as well as higher maintenance and repair costs. The increase in operating days was largely due to increased demand resulting from higher oil prices and the addition of newbuild APEX^TM rigs into our drilling fleet. Capital expenditures were incurred in 2012 and 2011 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	2012		2011		% Change
	(Dollars in thousands)
Revenues	$	447,895	$	379,790		17.9	%
Direct operating costs	$	304,908	$	247,441		23.2	%
Selling, general and administrative	$	8,619	$	8,795		(2.0)	%
Depreciation and amortization	$	50,735	$	31,836		59.4	%
Operating income	$	83,633	$	91,718		(8.8)	%
Fracturing jobs		656		734		(10.6)	%
Other jobs		3,084		3,081		0.1	%
Total jobs		3,740		3,815		(2.0)	%
Average revenue per fracturing job	$	584.50	$	440.48		32.7	%
Average revenue per other job	$	20.90	$	18.33		14.0	%
Average revenue per total job	$	119.76	$	99.55		20.3	%
Average direct operating costs per total job	$	81.53	$	64.86		25.7	%
Capital expenditures	$	112,099	$	82,616		35.7	%

Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. We have added additional equipment through construction and acquisition to meet this demand and expand our area of operations. As a result, although total fracturing jobs have decreased, we have experienced an increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. Average revenue per fracturing job increased as a result of this increase in the number of larger multi-stage fracturing jobs in 2012 as compared to 2011, as well as increased pricing. 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 total job increased primarily as a result of increased costs of materials and higher labor and related costs. These increases in direct operating costs were greater than the increased revenue in 2012 resulting in lower operating income in 2012 as compared to 2011. Significant capital expenditures have been incurred in recent years to add capacity in our pressure pumping segment. The increase in depreciation and amortization expense in 2012 was a result of our recent capital expenditures.

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Oil and Natural Gas Production and Exploration	2012		2011		% Change
	(Dollars in thousands)
Revenues - Oil	$	27,322	$	21,087		29.6	%
Revenues – Natural gas and liquids	$	2,085	$	2,754		(24.3)	%
Revenues - Total	$	29,407	$	23,841		23.3	%
Direct operating costs	$	5,313	$	4,100		29.6	%
Depletion and impairment	$	9,352	$	7,794		20.0	%
Operating income	$	14,742	$	11,947		23.4	%
Capital expenditures	$	15,304	$	9,746		57.0	%

Total revenues increased as a result of increased production and higher prices for oil. Oil production increased primarily due to the addition of new wells. Depletion and impairment expense in 2012 includes approximately $384,000 of oil and natural gas property impairments compared to approximately $1.4 million of oil and natural gas property impairments in 2011. Depletion expense increased approximately $2.6 million in 2012 compared to 2011 primarily due to increased production.

Corporate and Other	2012		2011		% Change
	(Dollars in thousands)
Selling, general and administrative	$	19,346	$	21,336		(9.3)	%
Depreciation	$	1,910	$	1,197		59.6	%
Net gain on asset disposals	$	30,732	$	2,621		N/M
Provision for bad debts	$	1,600	$	—		N/M
Interest income	$	233	$	88		164.8	%
Interest expense	$	9,633	$	7,403		30.1	%
Other income (expense)	$	(89)	$	197		N/M
Capital expenditures	$	2,370	$	3,281		(27.8)	%

Selling, general and administrative expense decreased in 2012 primarily as a result of decreased personnel costs related to the final determination of payouts under the 2009 Performance Units upon the completion of the performance period. 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 the disposal of assets in 2012 includes a gain of approximately $22.6 million associated with the sale of our flowback operations in April 2012. A provision for bad debts was recognized in 2012 with respect to accounts receivable balances that are estimated to be uncollectible. Interest expense increased in 2012 due primarily to interest charges on increased borrowings under our revolving credit facility.

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 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 directly 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 $23.5 million as of June 30, 2012.

Recently Issued Accounting Standards

In June 2011, the FASB issued an accounting standard update that requires that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. Historically, these components of other comprehensive income and total comprehensive income have been presented in the statement of changes in stockholders’ equity by many companies, including the Company. This requirement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and became effective for us in the quarter ending March 31, 2012. The adoption of this update has resulted in the addition of a new consolidated statement of comprehensive income being added to our consolidated financial statements.

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In May 2011, the FASB issued an accounting standard update to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with United States GAAP and International Financial Reporting Standards. The amendments in this update do not require additional fair value measurements, but provide additional guidance as to measuring fair value as well as certain additional disclosure requirements. The requirements in this update are effective during interim and annual periods beginning after December 15, 2011 and became effective for us in the quarter ending March 31, 2012. The adoption of this update did not have a material impact on the disclosures included in our consolidated financial statements.

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

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by factors such as market supply and demand, international military, political and economic conditions, the ability of OPEC to set and maintain production and price targets, technical advances affecting energy consumption and the price and availability of alternative fuels. All of these factors are beyond our control. During the second quarter of 2008, the quarterly average market price of natural gas (Henry Hub spot price as reported by the United States Energy Information Administration) was $11.74 per Mcf and the quarterly average market price of oil (WTI spot price as reported by the Energy Information Administration) was $123.95 per barrel. In the last half of 2008, commodity prices rapidly declined and averaged $6.60 per Mcf for natural gas and $58.35 per barrel for oil in the fourth quarter of 2008. In 2009, the price of natural gas declined further and averaged $4.06 per Mcf for the year. These declines in the market price of natural gas and oil resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009. Drilling activities increased in 2010 as did the prices for oil and natural gas. The increased drilling activity was largely attributed to increased development of unconventional oil and natural gas reservoirs and an improvement in the price of oil which averaged $79.40 per barrel in 2010. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year. Natural gas prices decreased in 2011 to an average of $4.00 per Mcf. The 2011 decrease in natural gas prices was most significant in the fourth quarter where the average price dropped to $3.32 per Mcf and this decrease has continued into 2012 where natural gas prices fell below $2.00 per Mcf in April and averaged $2.28 per Mcf for the second quarter resulting in reduced drilling for natural gas in 2012. The increase in drilling activity in oil rich basins has absorbed the decrease in demand for natural gas drilling activities in 2012 and our total rig count has increased. Our average number of rigs operating remains well below the number of our available rigs. Construction of new land drilling rigs in the United States during the last ten years has significantly contributed to excess capacity. As a result of decreased drilling activity and excess capacity, our average number of rigs operating has declined 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 oil and natural gas would likely result in lower demand for our drilling rigs and pressure pumping services and could adversely affect our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our drilling and pressure pumping services.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We currently have exposure to interest rate market risk associated with any borrowings that we have under our revolving credit facility. Interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.75% to 3.75% and the margin on base rate loans ranges from 1.75% to 2.75%, based on our debt to capitalization ratio. At June 30, 2012, the margin on LIBOR loans was 2.75% and the margin on base rate loans was 1.75%. As of June 30, 2012, we had no balance outstanding under our revolving credit facility. The interest rate on the borrowings outstanding under our credit facilities is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.

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.

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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, 2012.

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

PART II — OTHER INFORMATION

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

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended June 30, 2012.

Period Covered	Total Number of  Shares Purchased		Average Price Paid per Share		Total Number  of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in thousands)(1)
April 1-30, 2012 (2)		57	$	16.32		—	$	112,868
May 1-31, 2012		2,342,126	$	15.37		2,342,126	$	76,879
June 1-30, 2012 (2)		2,449,147	$	14.43		2,366,658	$	42,777
Total		4,791,330	$	14.89		4,708,784	$	42,777	(3)

(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. The remaining authority under this buyback program was terminated on July 25, 2012.

(2) We purchased 57 shares in April and 82,489 shares in June from employees with respect to 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.

(3) On July 25, 2012, our Board of Directors terminated the remaining authority under the 2007 stock buyback program, and approved a new stock buyback program authorizing purchases of up to $150 million of our common stock in open market or privately negotiated transactions.

ITEM 5. Other Information

On July 25, 2012, Mr. Pipkin, the Company’s Chief Accounting Officer and Assistant Secretary, informed the Board that he will resign his employment with the Company effective as of August 10, 2012 so that he could accept a Chief Financial Officer position with a privately-owned company. The Company’s Chief Financial Officer will assume Mr. Pipkin’s responsibilities as principal accounting officer.

ITEM 6. Exhibits

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

3.1	Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.2	Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).
3.3	Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference).
10.1	Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with William Andrew Hendricks, Jr. (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).

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10.2*	Severance Agreement, effective as of April 2, 2012, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr.
10.3*	Change of Control Agreement, effective as of April 2, 2012, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr.
10.4	Note Purchase Agreement, dated June 14, 2012, by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed June 18, 2012 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, 2012, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statement of Changes in Stockholders’ Equity, (v) the Consolidated Statements of Cash Flows, and (vi) Notes to Consolidated Financial Statements.

* filed herewith

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SIGNATURE

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

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

DATE: July 30, 2012

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