Edgar Filing: PATTERSON UTI ENERGY INC

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10-Q

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, 2014

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

For the transition period from to

Commission file number 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)


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

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

(281) 765-7100

(Registrant’s telephone number, including area code)

N/A

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

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

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.

146,134,531 shares of common stock, $0.01 par value, as of July 23, 2014

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I — FINANCIAL INFORMATION
ITEM 1.	Financial Statements
	Unaudited consolidated condensed balance sheets		1
	Unaudited consolidated condensed statements of operations		2
	Unaudited consolidated condensed statements of comprehensive income		3
	Unaudited consolidated condensed statement of changes in stockholders’ equity		4
	Unaudited consolidated condensed statements of cash flows		5
	Notes to unaudited consolidated condensed 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		30
ITEM 4.	Controls and Procedures		30

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings		30
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		31
ITEM 6.	Exhibits		32
Signature			33

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

The following unaudited consolidated condensed 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 CONDENSED BALANCE SHEETS

(unaudited, in thousands, except share data)


	June 30, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	120,837		$	249,509
Accounts receivable, net of allowance for doubtful accounts of $3,677 and $3,674 at June 30, 2014 and December 31, 2013, respectively		507,930			451,517
Federal and state income taxes receivable		2,845			—
Inventory		28,525			21,248
Deferred tax assets, net		27,962			32,952
Other		70,632			53,424

Total current assets		758,731			808,650
Property and equipment, net		3,873,610			3,635,541
Goodwill and intangible assets		177,303			167,470
Deposits on equipment purchases		78,118			52,560
Other		20,605			22,906

Total assets	$	4,908,367		$	4,687,127

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	319,311		$	173,150
Federal and state income taxes payable		—			10,670
Accrued expenses		172,575			160,457
Current portion of long-term debt		10,000			10,000

Total current liabilities		501,886			354,277
Long-term debt		677,500			682,500
Deferred tax liabilities, net		873,106			887,864
Other		8,431			6,489

Total liabilities		2,060,923			1,931,130

Commitments and contingencies (see Note 9)
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $.01; authorized 300,000,000 shares with 188,958,501 and 186,487,246 issued and 146,139,916 and 144,219,189 outstanding at June 30, 2014 and December 31, 2013, respectively		1,890			1,865
Additional paid-in capital		961,854			913,505
Retained earnings		2,767,526			2,707,439
Accumulated other comprehensive income		15,209			14,076
Treasury stock, at cost, 42,818,585 shares and 42,268,057 shares at June 30, 2014 and December 31, 2013, respectively		(899,035	)		(880,888	)

Total stockholders’ equity		2,847,444			2,755,997

Total liabilities and stockholders’ equity	$	4,908,367		$	4,687,127

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Operating revenues:
Contract drilling	$	438,583		$	389,979		$	864,486		$	809,073
Pressure pumping		306,577			254,620			546,838			485,780
Oil and natural gas		12,116			14,717			24,120			31,502

Total operating revenues		757,276			659,316			1,435,444			1,326,355

Operating costs and expenses:
Contract drilling		255,318			242,748			506,377			489,820
Pressure pumping		241,977			188,280			441,785			356,436
Oil and natural gas		2,872			3,214			6,146			6,136
Depreciation, depletion, amortization and impairment		153,426			137,182			300,748			273,617
Selling, general and administrative		19,548			18,319			39,221			35,716
Net gain on asset disposals		(3,091	)		(1,033	)		(4,835	)		(908	)

Total operating costs and expenses		670,050			588,710			1,289,442			1,160,817

Operating income		87,226			70,606			146,002			165,538

Other income (expense):
Interest income		208			250			384			423
Interest expense, net of amount capitalized		(7,249	)		(6,941	)		(14,437	)		(13,707	)
Other		3			381			3			400

Total other expense		(7,038	)		(6,310	)		(14,050	)		(12,884	)

Income before income taxes		80,188			64,296			131,952			152,654

Income tax expense (benefit):
Current		25,680			2,335			52,615			9,908
Deferred		225			21,193			(9,768	)		45,748

Total income tax expense		25,905			23,528			42,847			55,656

Net income	$	54,283		$	40,768		$	89,105		$	96,998

Net income per common share:
Basic	$	0.37		$	0.28		$	0.62		$	0.66

Diluted	$	0.37		$	0.28		$	0.61		$	0.66

Weighted average number of common shares outstanding:
Basic		143,622			145,465			143,259			145,148

Diluted		146,029			146,374			145,586			146,292

Cash dividends per common share	$	0.10		$	0.05		$	0.20		$	0.10

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, in thousands)


	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014		2013
Net income	$	54,283	$	40,768		$	89,105	$	96,998
Other comprehensive income (loss), net of taxes of $0 for all periods:
Foreign currency translation adjustment		4,488		(3,748	)		1,133		(6,051	)

Total comprehensive income	$	58,771	$	37,020		$	90,238	$	90,947

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(unaudited, in thousands)


												Accumulated
	Common Stock					Additional						Other
	Number of					Paid-in			Retained			Comprehensive		Treasury
	Shares			Amount		Capital			Earnings			Income		Stock			Total
Balance, December 31, 2013		186,487		$	1,865	$	913,505		$	2,707,439		$	14,076	$	(880,888	)	$	2,755,997
Net income		—			—		—			89,105			—		—			89,105
Foreign currency translation adjustment		—			—		—			—			1,133		—			1,133
Issuance of restricted stock		1,057			11		(11	)		—			—		—			—
Vesting of stock unit awards		10			—		—			—			—		—			—
Forfeitures of restricted stock		(28	)		—		—			—			—		—			—
Exercise of stock options		1,433			14		26,845			—			—		—			26,859
Stock-based compensation		—			—		12,959			—			—		—			12,959
Tax benefit related to stock-based compensation		—			—		8,556			—			—		—			8,556
Payment of cash dividends		—			—		—			(29,018	)		—		—			(29,018	)
Purchase of treasury stock		—			—		—			—			—		(18,147	)		(18,147	)

Balance, June 30, 2014		188,959		$	1,890	$	961,854		$	2,767,526		$	15,209	$	(899,035	)	$	2,847,444

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


	Six Months Ended June 30,
	2014			2013
Cash flows from operating activities:
Net income	$	89,105		$	96,998
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		300,748			273,617
Dry holes and abandonments		321			15
Deferred income tax (benefit) expense		(9,768	)		45,748
Stock-based compensation expense		12,959			12,119
Net gain on asset disposals		(4,835	)		(908	)
Changes in operating assets and liabilities:
Accounts receivable		(56,963	)		(36,025	)
Income taxes receivable/payable		(13,473	)		(8,480	)
Inventory and other assets		(21,896	)		(12,805	)
Accounts payable		50,012			25,502
Accrued expenses		12,122			(12,453	)
Other liabilities		1,847			15

Net cash provided by operating activities		360,179			383,343

Cash flows from investing activities:
Purchases of property and equipment and acquisitions		(488,038	)		(332,598	)
Proceeds from disposal of assets		14,991			4,593

Net cash used in investing activities		(473,047	)		(328,005	)

Cash flows from financing activities:
Purchases of treasury stock		(13,554	)		(10,031	)
Dividends paid		(29,018	)		(14,673	)
Tax benefit related to stock-based compensation		8,556			4,862
Repayment of long-term debt		(5,000	)		(2,500	)
Proceeds from exercise of stock options		22,265			6,959

Net cash used in financing activities		(16,751	)		(15,383	)

Effect of foreign exchange rate changes on cash		947			(1,801	)

Net increase (decrease) in cash and cash equivalents		(128,672	)		38,154
Cash and cash equivalents at beginning of period		249,509			110,723

Cash and cash equivalents at end of period	$	120,837		$	148,877

Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest, net of capitalized interest of $3,326 in 2014 and $4,358 in 2013	$	(13,360	)	$	(12,686	)
Income taxes	$	(54,089	)	$	(13,238	)
Supplemental non-cash investing and financing information:
Net increase (decrease) in current liabilities for purchases of property and equipment	$	96,143		$	(16,169	)
Net (increase) decrease in deposits on equipment purchases	$	(25,558	)	$	13,789

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

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

1. Basis of Consolidation and Presentation

The unaudited interim consolidated condensed 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 condensed 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 Condensed Balance Sheet as of December 31, 2013, 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 condensed 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, 2013. The results of operations for the six months ended June 30, 2014 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 per common share in its unaudited consolidated condensed statements of operations: Basic net income per common share (“Basic EPS”) and diluted net income per common share (“Diluted EPS”).

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

Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted stock units is determined 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.

The following table presents information necessary to calculate net income per share for the three and six months ended June 30, 2014 and 2013 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts):


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
BASIC EPS:
Net income	$	54,283		$	40,768		$	89,105		$	96,998
Adjust for income attributed to holders of non-vested restricted stock		(559	)		(392	)		(910	)		(882	)

Income attributed to common stockholders	$	53,724		$	40,376		$	88,195		$	96,116

Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		143,622			145,465			143,259			145,148

Basic net income per common share	$	0.37		$	0.28		$	0.62		$	0.66

DILUTED EPS:
Income attributed to common stockholders	$	53,724		$	40,376		$	88,195		$	96,116

Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		143,622			145,465			143,259			145,148
Add dilutive effect of potential common shares		2,407			909			2,327			1,144

Weighted average number of diluted common shares outstanding		146,029			146,374			145,586			146,292

Diluted net income per common share	$	0.37		$	0.28		$	0.61		$	0.66

Potentially dilutive securities excluded as anti-dilutive		432			4,015			432			4,065

2. 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 are accounted for as liability awards. Share-settled performance unit awards are accounted for as equity awards. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units and share-settled performance unit awards vest.

On February 21, 2014, the Company’s Board of Directors adopted the Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (the “2014 Plan”), subject to approval by the Company’s stockholders. In addition, on the same date, the Board of Directors approved, subject to and effective upon the approval by the stockholders of the 2014 Plan, the termination of any future grants under all existing equity plans of the Company. On April 17, 2014, the Company’s stockholders approved the 2014 Plan. The aggregate number of shares of Common Stock authorized for grant under the 2014 Plan is 9,100,000, reduced by the number of shares that were subject to awards granted under existing equity plans of the Company during the period commencing on January 1, 2014 and ending on the date the 2014 Plan was approved by the stockholders.

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 for the three and six month periods ended June 30, 2014 and 2013 follow:


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Volatility		35.89	%		40.90	%		35.89	%		41.36	%
Expected term (in years)		5.00			5.00			5.00			5.00
Dividend yield		1.21	%		0.87	%		1.17	%		0.89	%
Risk-free interest rate		1.76	%		0.70	%		1.76	%		0.70	%

Stock option activity from January 1, 2014 to June 30, 2014 follows:


	Underlying Shares			Weighted Average Exercise Price
Outstanding at January 1, 2014		7,319,695		$	21.23
Granted		481,750		$	32.29
Exercised		(1,433,195	)	$	18.74
Cancelled		—			—
Expired		—			—

Outstanding at June 30, 2014		6,368,250		$	22.63

Exercisable at June 30, 2014		5,283,306		$	21.98

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

Restricted stock activity from January 1, 2014 to June 30, 2014 follows:


	Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock outstanding at January 1, 2014		1,496,692		$	20.84
Granted		767,900		$	33.41
Vested		(670,857	)	$	21.83
Forfeited		(28,344	)	$	21.49

Non-vested restricted stock outstanding June 30, 2014		1,565,391		$	26.57

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, 2014 to June 30, 2014 follows:


	Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock units outstanding at January 1, 2014		20,256		$	20.67
Granted		9,250		$	33.78
Vested		(9,754	)	$	22.13
Forfeited		—			—

Non-vested restricted stock units outstanding June 30, 2014		19,752		$	26.09

Performance Unit Awards — In 2011, 2012, 2013 and 2014 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 commencing on April 1 of the year of grant. For the 2012, and 2013 Stock-Settled Performance Units, the performance period 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 positive, and, when compared to the peer group, is at the 25^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 target number of shares with respect to the 2011 Stock-Settled Performance Units was 144,375. The performance period for the 2011 Stock-Settled Performance Units ended on March 31, 2014, and the Company’s total shareholder return was at the 94^th percentile. In April 2014, 288,750 shares were issued to settle the 2011 Stock-Settled Performance Units.

The total target number of shares with respect to the Stock-Settled Performance Units is set forth below:


	2014 Performance Unit Awards		2013 Performance Unit Awards		2012 Performance Unit Awards		2011 Performance Unit Awards
Target number of shares		154,000		236,500		192,000		144,375

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):


	2014 Performance Unit Awards		2013 Performance Unit Awards		2012 Performance Unit Awards		2011 Performance Unit Awards
Fair value at date of grant	$	5,388	$	5,564	$	3,065	$	5,569

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):


	2014 Performance Unit Awards		2013 Performance Unit Awards		2012 Performance Unit Awards		2011 Performance Unit Awards
Three months ended June 30, 2013		NA	$	464	$	255	$	464
Three months ended June 30, 2014	$	449	$	464	$	255		NA
Six months ended June 30, 2013		NA	$	464	$	510	$	928
Six months ended June 30, 2014	$	449	$	928	$	510	$	464

3. Property and Equipment

Property and equipment consisted of the following at June 30, 2014 and December 31, 2013 (in thousands):


	June 30, 2014			December 31, 2013
Equipment	$	6,168,403		$	5,749,975
Oil and natural gas properties		200,205			183,571
Buildings		81,611			80,050
Land		12,055			12,054

		6,462,274			6,025,650
Less accumulated depreciation and depletion		(2,588,664	)		(2,390,109	)

Property and equipment, net	$	3,873,610		$	3,635,541

4. 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 non-operating working interest basis, in oil and natural gas properties. Each of these segments represents a distinct type of business. These segments have separate management teams which report to the Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. Separate financial data for each of our business segments is provided in the table below (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Revenues:
Contract drilling	$	440,027		$	391,212		$	866,989		$	811,445
Pressure pumping		306,577			254,620			546,838			485,780
Oil and natural gas		12,116			14,717			24,120			31,502

Total segment revenues		758,720			660,549			1,437,947			1,328,727
Elimination of intercompany revenues (a)		(1,444	)		(1,233	)		(2,503	)		(2,372	)

Total revenues	$	757,276		$	659,316		$	1,435,444		$	1,326,355

Income before income taxes:
Contract drilling	$	69,617		$	47,069		$	136,694		$	119,618
Pressure pumping		24,910			30,254			26,453			58,769
Oil and natural gas		3,632			5,527			6,335			11,768

		98,159			82,850			169,482			190,155
Corporate and other		(14,024	)		(13,277	)		(28,315	)		(25,525	)
Net gain on asset disposals (b)		3,091			1,033			4,835			908
Interest income		208			250			384			423
Interest expense		(7,249	)		(6,941	)		(14,437	)		(13,707	)
Other		3			381			3			400

Income before income taxes	$	80,188		$	64,296		$	131,952		$	152,654


	June 30, 2014		December 31, 2013
Identifiable assets:
Contract drilling	$	3,801,864	$	3,569,588
Pressure pumping		890,870		761,199
Oil and natural gas		63,988		58,656
Corporate and other (c)		151,645		297,684

Total assets	$	4,908,367	$	4,687,127

(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 and certain deferred tax assets.

5. Goodwill and Intangible Assets

Goodwill — Goodwill by operating segment as of June 30, 2014 and changes for the six months then ended are as follows (in thousands):


	Contract Drilling		Pressure Pumping		Total
Balance December 31, 2013	$	86,234	$	67,575	$	153,809
Changes to goodwill		—		11,655		11,655

Balance June 30, 2014	$	86,234	$	79,230	$	165,464

There were no accumulated impairment losses as of June 30, 2014 or December 31, 2013.

Goodwill is evaluated at least annually on December 31, or when circumstances require, 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. The Company first determines whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a two-step impairment test. From time to time, the Company may perform the first step of the quantitative testing for goodwill impairment in lieu of performing the qualitative assessment. 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 the customer relationships acquired and a non-compete agreement. These intangible assets were recorded at fair value on the date of acquisition.

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, 2014 and 2013 and amortization expense of approximately $1.8 million was recorded in the six months ended June 30, 2014 and 2013 associated with customer relationships.

The following table presents the gross carrying amount and accumulated amortization of the customer relationships as of June 30, 2014 and December 31, 2013 (in thousands):


	June 30, 2014							December 31, 2013
	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer relationships	$	25,500	$	(13,661	)	$	11,839	$	25,500	$	(11,839	)	$	13,661

The non-compete agreement had 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 this agreement was 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 was amortized on a straight-line basis over the three-year term of the agreement and was fully amortized by September 30, 2013. Amortization expense of approximately $117,000 was recorded in the three months ended June 30, 2013 and amortization expense of approximately $233,000 was recorded in the six months ended June 30, 2013 associated with the non-compete agreement.

6. Accrued Expenses

Accrued expenses consisted of the following at June 30, 2014 and December 31, 2013 (in thousands):


	June 30, 2014		December 31, 2013
Salaries, wages, payroll taxes and benefits	$	54,822	$	45,836
Workers’ compensation liability		77,933		74,975
Property, sales, use and other taxes		12,226		12,367
Insurance, other than workers’ compensation		10,654		10,129
Accrued interest payable		7,585		7,604
Other		9,355		9,546

	$	172,575	$	160,457

7. Asset Retirement Obligation

The Company records a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. This liability is included in the caption “other” in the liabilities section of the consolidated condensed balance sheet. The following table describes the changes to the Company’s asset retirement obligations during the six months ended June 30, 2014 and 2013 (in thousands):


	Six Months Ended June 30,
	2014			2013
Balance at beginning of year	$	4,837		$	4,422
Liabilities incurred		91			177
Liabilities settled		(31	)		(31	)
Accretion expense		84			82
Revision in estimated costs of plugging oil and natural gas wells		20			—

Asset retirement obligation at end of period	$	5,001		$	4,650

8. Long Term Debt

Credit Facilities — On September 27, 2012, 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 lenders party 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 $500 million outstanding at any time. The revolving credit facility contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time.

The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments, which commenced December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments.

Subject to customary conditions, the Company may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility.

Loans under the Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon the Company’s debt to capitalization ratio. As of June 30, 2014, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. 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 rate payable to the lenders for the unused portion of the credit facility is 0.50%.

Each domestic subsidiary of the Company other than immaterial subsidiaries has unconditionally guaranteed all existing and future indebtedness and liabilities of the other guarantors and the Company 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 under the Credit Agreement.

The Credit Agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45%. 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, 2014. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants.

Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require the Company to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy of the Company, such acceleration is automatic), and (iii) require the Company to cash collateralize any outstanding letters of credit.

As of June 30, 2014, the Company had $87.5 million principal amount outstanding under the term loan facility at an interest rate of 2.50% and no amounts outstanding under the revolving credit facility. The Company had $39.8 million in letters of credit outstanding at June 30, 2014 and, as a result, had available borrowing capacity of approximately $460 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 B Notes on April 5 and October 5 of each year. 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 agreements. 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 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 of EBITDA for the four prior fiscal quarters to interest charges for that same period. The Company was in compliance with these covenants at June 30, 2014.

Events of default under the note purchase agreements 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 the note purchase agreements 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.

Debt issuance costs are deferred and recognized as interest expense over the term of the underlying debt. Interest expense related to the amortization of debt issuance costs was approximately $547,000 for the three months ended June 30, 2014 and 2013 and approximately $1.1 million for the six months ended June 30, 2014 and 2013.

Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of June 30, 2014 (in thousands):


Year ending December 31,
2014	$	5,000
2015		12,500
2016		28,750
2017		41,250
2018		—
Thereafter		600,000

Total	$	687,500

9. Commitments, Contingencies and Other Matters

As of June 30, 2014, 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, 2014, no amounts had been drawn under the letters of credit.

As of June 30, 2014, the Company had commitments to purchase approximately $347 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 and chemicals from certain vendors. These agreements expire in 2016 and 2017. As of June 30, 2014, the remaining obligation under these agreements was approximately $18.3 million, of which materials with a total purchase price of approximately $817,000 were required to be purchased during the remainder of 2014. In the event that the required minimum quantities are not purchased during any contract year, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November 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, 2014, advances of approximately $11.8 million had been made under this agreement and principal repayments of approximately $5.0 million had been received resulting in a balance outstanding of approximately $6.8 million.

In May 2013, the U.S. Equal Employment Opportunity Commission notified the Company of cause findings related to certain of its employment practices. The cause findings relate to allegations that the Company tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. The Company and the EEOC engaged in the statutory conciliation process. In March 2014, the EEOC notified us that this matter will be forwarded to its legal unit for litigation review.

The Company believes that litigation will ensue. The Company intends to defend itself vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter.

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

10. Stockholders’ Equity

Cash Dividends — The Company paid cash dividends during the six months ended June 30, 2014 and 2013 as follows:


2013:	Per Share		Total
			(in thousands)
Paid on March 29, 2013	$	0.05	$	7,312
Paid on June 28, 2013		0.05		7,361

Total cash dividends	$	0.10	$	14,673


2014:	Per Share		Total
			(in thousands)
Paid on March 27, 2014	$	0.10	$	14,456
Paid on June 26, 2014		0.10		14,562

Total cash dividends	$	0.20	$	29,018

On July 23, 2014, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.10 per share to be paid on September 24, 2014 to holders of record as of September 10, 2014. The amount and timing of all future dividend payments, if any, are 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 September 6, 2013, the Company’s Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of the Company’s common stock in open market or privately negotiated transactions. As of June 30, 2014, the Company had remaining authorization to purchase approximately $187 million of the Company’s outstanding common stock under the stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock.

The Company acquired 536,630 shares of treasury stock from employees during the six months ended June 30, 2014. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options. The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of stock options, the settlement of performance unit awards and the vesting of restricted stock. The total fair market value of these shares was approximately $17.7 million. These shares were acquired pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”) or the 2014 Plan and not pursuant to the stock buyback program.

Treasury stock acquisitions during the six months ended June 30, 2014 were as follows (dollars in thousands):


	June 30, 2014
	Shares		Cost
Treasury shares at beginning of period		42,268,057	$	880,888
Acquisitions pursuant to long-term incentive plans		536,630		17,681
Purchases pursuant to the 2013 buyback program		13,898		466

Treasury shares at end of period		42,818,585	$	899,035

11. Income Taxes

The Company’s effective income tax rate was 32.5% for the six months ended June 30, 2014, compared to 36.5% for the six months ended June 30, 2013. The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008), and allows a deduction of 9% on the lesser of qualified production activities income or taxable income. The prior year Domestic Production Activities Deduction was smaller due to lower

taxable income after the utilization of bonus depreciation and a federal net operating loss carryforward. In 2014, the Company does not have any remaining federal net operating loss carryforward, and bonus depreciation is currently unavailable, resulting in higher taxable income and, therefore, a larger Domestic Production Activities Deduction.

12. 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.

The estimated fair value of the Company’s outstanding debt balances (including current portion) as of June 30, 2014 and December 31, 2013 is set forth below (in thousands):


	June 30, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
Borrowings under credit agreement:
Term loan facility	$	87,500	$	87,500	$	92,500	$	92,500
4.97% Series A Senior Notes		300,000		323,706		300,000		304,293
4.27% Series B Senior Notes		300,000		308,171		300,000		286,772

Total debt	$	687,500	$	719,377	$	692,500	$	683,565

The carrying values of the balances outstanding under the term loan approximate their fair values as this instrument has a floating interest rate. The fair value of the 4.97% Series A Senior Notes and the 4.27% Series B Senior Notes at June 30, 2014 and December 31, 2013 are based on discounted cash flows associated with the respective notes using current market rates of interest at those respective dates. For the 4.97% Series A Senior Notes, the current market rates used in measuring this fair value were 3.55% at June 30, 2014 and 4.52% at December 31, 2013. For the 4.27% Series B Senior Notes, the current market rates used in measuring this fair value was 3.87% at June 30, 2014 and 4.89% at December 31, 2013. 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.

13. Recently Issued Accounting Standards

In February 2013, the FASB issued an accounting standards update to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. The update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The requirements in this update are effective during interim and annual periods beginning after December 15, 2013. The adoption of this update did not have a material impact on the Company’s consolidated condensed financial statements.

In May 2014, the FASB issued an accounting standards update to provide guidance on the recognition of revenue from customers. Under this guidance, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects in exchange for the goods or services. This guidance also requires more detailed disclosures to enable users of the financial statements to understand the nature, amount, timing and uncertainty, if any, of revenue and cash flows arising from contracts with customers. The requirements in this update are effective during interim and annual periods beginning after December 15, 2016. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements.

In June 2014, the FASB issued an accounting standards update to provide guidance on the accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period is treated as a performance condition. The requirements in this update are effective during interim and annual periods beginning after December 15, 2015. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

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 and cost expectations and backlog; financing of operations; 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; competition; equipment availability; government regulation; 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, volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates, utilization, margins and planned capital expenditures, global economic conditions, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, equipment specialization and new technologies, adverse credit and equity market conditions, difficulty in building and deploying new equipment and integrating acquisitions, shortages, delays in delivery and interruptions in supply of equipment, supplies and materials, weather, loss of key customers, liabilities from operations for which we do not have and receive full indemnification or insurance, ability to effectively identify and enter new markets, governmental regulation, ability to realize backlog, ability to retain management and field personnel and other factors. Refer to “Risk Factors” contained in Part 1 of our Annual Report on Form 10-K for the year ended December 31, 2013 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 these services, we also invest, on a non-operating working interest basis, in oil and natural gas properties.

We have a drilling fleet that consists of more than 275 marketable land-based drilling rigs. There continues to be uncertainty with respect to the global economic environment and crude oil and natural gas prices are volatile. During the second quarter of 2014, our average number of rigs operating in the United States was 201 compared to an average of 183 drilling rigs operating during the same period in 2013. During the second quarter of 2014, our average number of rigs operating in Canada was three compared to an average of two drilling rigs operating during the second quarter of 2013.

We have addressed our customers’ needs for drilling horizontal wells in 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, 2014, we had completed 133 APEX® rigs and made performance and safety improvements to existing high capacity rigs. We have plans to complete 25 additional new APEX® rigs during the four quarters ending June 2015. In connection with horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. In June 2014, we acquired the East Texas-based pressure pumping operations of a privately held company. The acquisition included 31,500 horsepower of hydraulic fracturing equipment and provides us with a new base of operations and employees to support drilling programs in East Texas and Louisiana. As of June 30, 2014, we had more than 790,000 hydraulic horsepower in our pressure pumping fleet. Relatively low natural gas prices and the industry-wide addition of new pressure pumping equipment to the marketplace has led to an excess supply of pressure pumping equipment in North America.

We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term of six months or more. Our backlog as of June 30, 2014 was approximately $1.52 billion. We expect approximately $548 million of our backlog to be realized in the remainder of 2014. We generally 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 for unscheduled standby or 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 an early termination payment to us in the event that the contract is terminated by the customer. For contracts that we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the day rate, for the period we expect to receive the lower rate.

For the three and six months ended June 30, 2014 and 2013, our operating revenues consisted of the following (in thousands):


	Three Months Ended June 30,								Six Months Ended June 30,
	2014				2013				2014				2013
Contract drilling	$	438,583	58	%	$	389,979	59	%	$	864,486	60	%	$	809,073	61	%
Pressure pumping		306,577	40			254,620	39			546,838	38			485,780	37
Oil and natural gas		12,116	2			14,717	2			24,120	2			31,502	2

	$	757,276	100	%	$	659,316	100	%	$	1,435,444	100	%	$	1,326,355	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 2014, our average number of rigs operating was 201 in the United States and three in Canada compared to 183 in the United States and two in Canada in the second quarter of 2013. Our average revenue per operating day was $23,630 in the second quarter of 2014 compared to $23,120 in the second quarter of 2013. Consolidated net income for the second quarter of 2014 was $54.3 million compared to consolidated net income of $40.8 million for the second quarter of 2013. This increase in consolidated net income was primarily due to an increase of $22.5 million in operating income from our contract drilling business resulting from the increases in the number of rigs operating and the average revenue per operating day, as well as lower average direct operating costs per operating day.

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. In June 2014, our average number of rigs operating was 204 in the United States and six in Canada.

We are highly impacted by operational risks, 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, 2013.

We believe that our liquidity as of June 30, 2014, which includes approximately $257 million in working capital, approximately $460 million available under our $500 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, debt financing and 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, 2014, 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, 2014, no amounts had been drawn under the letters of credit.

As of June 30, 2014, we had commitments to purchase approximately $347 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 and chemicals from certain vendors. These agreements expire in 2016 and 2017. As of June 30, 2014, the remaining obligation under these agreements was approximately $18.3 million, of which materials with a total purchase price of approximately $817,000 were required to be purchased during the remainder of 2014. 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 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, 2014, advances of approximately $11.8 million had been made under this agreement and repayments of approximately $5.0 million had been received resulting in a balance outstanding of approximately $6.8 million.

In May 2013, the U.S. Equal Employment Opportunity Commission notified us of cause findings related to certain of our employment practices. The cause findings relate to allegations that we tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. We and the EEOC engaged in the statutory conciliation process. In March 2014, the EEOC notified us that this matter will be forwarded to its legal unit for litigation review. We believe that litigation will ensue. We intend to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of this matter to have a material adverse effect on our financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter.

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 the continental United States, Alaska and western and northern Canada. We have more than 275 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. 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 is cyclical and at times experiences downturns in demand. 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 has been 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 has 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 older technology drilling rigs. Similarly, the substantial 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 across the industry. As a result of relatively 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 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.

Critical Accounting Policies

In addition to established accounting policies, our consolidated condensed 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, 2013.

Liquidity and Capital Resources

As of June 30, 2014, we had working capital of $257 million, including cash and cash equivalents of $121 million, compared to working capital of $454 million and cash and cash equivalents of $250 million at December 31, 2013. The decrease in working capital at June 30, 2014, compared to December 31, 2013, is primarily due to a reduction in cash and an increase in accounts payable both resulting primarily from an acceleration of our program of building new drilling rigs.

During the six months ended June 30, 2014, our sources of cash flow included:

•

$360 million from operating activities,

•

$30.8 million from the exercise of stock options and related tax benefits associated with stock-based compensation, and

•

$15.0 million in proceeds from the disposal of property and equipment.

During the six months ended June 30, 2014, we used $29.0 million to pay dividends on our common stock, $13.6 million to acquire shares of our common stock, $5.0 million to repay long-term debt and $488 million:

•

to build new drilling rigs and pressure pumping equipment,

•

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

•

to acquire and procure equipment and facilities to support our drilling and pressure pumping operations, including the acquisition of an East Texas-based pressure pumping operation, and

•

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

We paid cash dividends during the six months ended June 30, 2014 as follows:


	Per Share		Total
			(in thousands)
Paid on March 27, 2014	$	0.10	$	14,456
Paid on June 26, 2014	$	0.10	$	14,562

Total cash dividends	$	0.20	$	29,018

On July 23, 2014, our Board of Directors approved a cash dividend on our common stock in the amount of $0.10 per share to be paid on September 24, 2014 to holders of record as of September 10, 2014. 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 September 6, 2013, our Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of our common stock in open market or privately negotiated transactions. As of June 30, 2014, we had remaining authorization to purchase approximately $187 million of our outstanding common stock under the new stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock.

The Company acquired 536,630 shares of treasury stock from employees during the six months ended June 30, 2014. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options. The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of stock options, the settlement of performance unit awards and the vesting of restricted stock. The total fair market value of these shares was approximately $17.7 million. These shares were acquired pursuant to the terms of the 2005 Plan or the 2014 Plan and not pursuant to the stock buyback program.

Treasury stock acquisitions during the six months ended June 30, 2014 were as follows (dollars in thousands):


	June 30, 2014
	Shares		Cost
Treasury shares at beginning of period		42,268,057	$	880,888
Acquisitions pursuant to long-term incentive plans		536,630		17,681
Purchases pursuant to the 2013 buyback program		13,898		466

Treasury shares at end of period		42,818,585	$	899,035

On September 27, 2012, 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.

Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of June 30, 2014, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. 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 rate payable to the lenders for the unused portion of the credit facility is 0.50%.

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

The Credit Agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. 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, 2014. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants. 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 Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy, such acceleration is automatic), and (iii) requires us to cash collateralize any outstanding letters of credit.

As of June 30, 2014, we had $87.5 million principal amount outstanding under the term loan facility at an interest rate of 2.50% and no amounts outstanding under the revolving credit facility. We had $39.8 million in letters of credit outstanding at June 30, 2014 and, as a result, we had available borrowing capacity of approximately $460 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 pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022.

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

The Series A Notes 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 agreements. 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 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 of EBITDA for the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of June 30, 2014. 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 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 the note purchase agreements 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 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, 2014, which includes approximately $257 million in working capital, and approximately $460 million available under our $500 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, debt financing and 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, 2014 and 2013:


Contract Drilling	2014		2013		% Change
	(Dollars in thousands)
Revenues	$	438,583	$	389,979		12.5	%
Direct operating costs		255,318		242,748		5.2	%

Margin (1)		183,265		147,231		24.5	%
Selling, general and administrative		1,591		1,879		(15.3	)%
Depreciation, amortization and impairment		112,057		98,283		14.0	%

Operating income	$	69,617	$	47,069		47.9	%

Operating days		18,563		16,864		10.1	%
Average revenue per operating day	$	23.63	$	23.12		2.2	%
Average direct operating costs per operating day	$	13.75	$	14.39		(4.4	)%
Average margin per operating day (1)	$	9.87	$	8.73		13.1	%
Average rigs operating		204		185		10.3	%
Capital expenditures	$	211,917	$	117,794		79.9	%

(1)	Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per operating day is defined as margin divided by operating days.

The increases in revenues, direct operating costs and margin reflect the increase in the number of rigs operating. Average revenue per operating day increased and average direct operating costs per operating day decreased, which positively impacted margin and average margin per operating day. The increase in depreciation expense reflects significant capital expenditures incurred in recent years to add new rig capacity. Capital expenditures were incurred in recent years to build new drilling rigs, to modify and upgrade existing 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.


Pressure Pumping	2014			2013			% Change
	(Dollars in thousands)
Revenues	$	306,577		$	254,620			20.4	%
Direct operating costs		241,977			188,280			28.5	%

Margin (1)		64,600			66,340			(2.6	)%
Selling, general and administrative		5,067			4,297			17.9	%
Depreciation, amortization and impairment		34,623			31,789			8.9	%

Operating income	$	24,910		$	30,254			(17.7	)%

Fracturing jobs		271			344			(21.2	)%
Other jobs		1,058			1,187			(10.9	)%
Total jobs		1,329			1,531			(13.2	)%
Average revenue per fracturing job	$	1,063.28		$	678.34			56.7	%
Average revenue per other job	$	17.42		$	17.92			(2.8	)%
Average revenue per total job	$	230.68		$	166.31			38.7	%
Average direct operating costs per total job	$	182.07		$	122.98			48.0	%
Average margin per total job (1)	$	48.61		$	43.33			12.2	%
Margin as a percentage of revenues (1)		21.1	%		26.1	%		(19.2	)%
Capital expenditures and acquisitions	$	96,186		$	34,202			181.2	%

(1)

Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues.

Our customers have continued the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. In connection with the horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs, including the June 2014 acquisition of an East Texas-based pressure pumping operation. As a result, we have continued to experience an increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed, resulting in higher revenues and costs. Average revenue per fracturing job and average direct operating costs per total job increased as a result of this increase in the proportion of larger multi-stage fracturing jobs in 2014 as compared to 2013. Depreciation expense increased due to capital expenditures.


Oil and Natural Gas Production and Exploration	2014		2013		% Change
	(Dollars in thousands)
Revenues—Oil	$	10,747	$	13,165		(18.4	)%
Revenues – Natural gas and liquids		1,369		1,552		(11.8	)%

Revenues—Total		12,116		14,717		(17.7	)%
Direct operating costs		2,872		3,214		(10.6	)%

Margin (1)		9,244		11,503		(19.6	)%
Depletion and impairment		5,612		5,976		(6.1	)%

Operating income	$	3,632	$	5,527		(34.3	)%

Capital expenditures	$	8,742	$	5,438		60.8	%

(1)	Margin is defined as revenues less direct operating costs and excludes depletion and impairment.

Oil and natural gas and liquids revenues decreased primarily as a result of production declines on existing wells. Direct operating costs decreased due to lower exploration costs and lower taxes associated with lower production. Depletion expense decreased due to lower production. Depletion and impairment expense in 2014 includes approximately $798,000 of oil and natural gas property impairments compared to approximately $517,000 of oil and natural gas property impairments in 2013.


Corporate and Other	2014			2013			% Change
	(Dollars in thousands)
Selling, general and administrative	$	12,890		$	12,143			6.2	%
Depreciation	$	1,134		$	1,134			—
Net (gain) loss on asset disposals	$	(3,091	)	$	(1,033	)		199.2	%
Interest income	$	208		$	250			(16.8	)%
Interest expense	$	7,249		$	6,941			4.4	%
Other income (expense)	$	3		$	381			(99.2	)%
Capital expenditures	$	821		$	1,003			(18.1	)%

Selling, general and administrative expense increased in 2014 primarily as a result of increased personnel costs. 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. In 2014, the net gain on asset disposals resulted primarily from miscellaneous sales of drilling equipment.

The following tables summarize operations by business segment for the six months ended June 30, 2014 and 2013:


Contract Drilling	2014		2013		% Change
	(Dollars in thousands)
Revenues	$	864,486	$	809,073		6.8	%
Direct operating costs		506,377		489,820		3.4	%

Margin (1)		358,109		319,253		12.2	%
Selling, general and administrative		3,239		3,730		(13.2	)%
Depreciation, amortization and impairment		218,176		195,905		11.4	%

Operating income	$	136,694	$	119,618		14.3	%

Operating days		36,777		34,767		5.8	%
Average revenue per operating day	$	23.51	$	23.27		1.0	%
Average direct operating costs per operating day	$	13.77	$	14.09		(2.3	)%
Average margin per operating day (1)	$	9.74	$	9.18		6.1	%
Average rigs operating		203		192		5.7	%
Capital expenditures	$	336,840	$	252,177		33.6	%

(1)	Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per operating day is defined as margin divided by operating days.


Pressure Pumping	2014			2013			% Change
	(Dollars in thousands)
Revenues	$	546,838		$	485,780			12.6	%
Direct operating costs		441,785			356,436			23.9	%

Margin (1)		105,053			129,344			(18.8	)%
Selling, general and administrative		9,935			8,550			16.2	%
Depreciation, amortization and impairment		68,665			62,025			10.7	%

Operating income	$	26,453		$	58,769			(55.0	)%

Fracturing jobs		514			610			(15.7	)%
Other jobs		1,938			2,329			(16.8	)%
Total jobs		2,452			2,939			(16.6	)%
Average revenue per fracturing job	$	993.05		$	724.67			37.0	%
Average revenue per other job	$	18.79		$	18.78			—
Average revenue per total job	$	223.02		$	165.29			34.9	%
Average direct operating costs per total job	$	180.17		$	121.28			48.6	%
Average margin per total job (1)	$	42.84		$	44.01			(2.7	)%
Margin as a percentage of revenues (1)		19.2	%		26.6	%		(27.8	)%
Capital expenditures and acquisitions	$	132,483		$	64,436			105.6	%

(1)

During the first quarter of 2014, our Appalachian operations were negatively impacted by unusually severe weather. Margin was negatively impacted as a result of having crews and equipment on location that were unable to provide revenue generating services during the unusually severe weather. While on location, we continued to incur labor, demurrage and other costs, including fuel costs to run our equipment in order to protect it in the extraordinary weather conditions.


Oil and Natural Gas Production and Exploration	2014		2013		% Change
	(Dollars in thousands)
Revenues—Oil	$	21,078	$	28,560		(26.2	)%
Revenues – Natural gas and liquids		3,042		2,942		3.4	%

Revenues—Total		24,120		31,502		(23.4	)%
Direct operating costs		6,146		6,136		0.2	%

Margin (1)		17,974		25,366		(29.1	)%
Depletion and impairment		11,639		13,598		(14.4	)%

Operating income	$	6,335	$	11,768		(46.2	)%

Capital expenditures	$	17,426	$	14,102		23.6	%

(1)	Margin is defined as revenues less direct operating costs and excludes depletion and impairment.

Oil and natural gas and liquids revenues decreased primarily as a result of production declines on existing wells. Direct operating costs include a reduction in taxes due to lower production. This was offset by higher lease operating expenses and higher exploration costs. Depletion expense decreased primarily due to lower production. Depletion and impairment expense in 2014 includes approximately $1.8 million of oil and natural gas property impairments compared to approximately $2.4 million of oil and natural gas property impairments in 2013.


Corporate and Other	2014			2013			% Change
	(Dollars in thousands)
Selling, general and administrative	$	26,047		$	23,436			11.1	%
Depreciation	$	2,268		$	2,089			8.6	%
Net (gain) loss on asset disposals	$	(4,835	)	$	(908	)		432.5	%
Interest income	$	384		$	423			(9.2	)%
Interest expense	$	14,437		$	13,707			5.3	%
Other income (expense)	$	3		$	400			(99.3	)%
Capital expenditures	$	1,289		$	1,883			(31.5	)%

Income Taxes

Our effective income tax rate was 32.5% for the six months ended June 30, 2014, compared to 36.5% for the six months ended June 30, 2013. The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008), and allows a deduction of 9% on the lesser of qualified production activities income or taxable income. The prior year Domestic Production Activities Deduction was smaller due to lower taxable income after the utilization of bonus depreciation and a federal net operating loss carryforward. In 2014, we do not have any remaining federal net operating loss carryforward, and bonus depreciation is currently unavailable, resulting in higher taxable income and, therefore, a larger Domestic Production Activities Deduction.

Recently Issued Accounting Standards

In May 2014, the FASB issued an accounting standards update to provide guidance on the recognition of revenue from customers. Under this guidance, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects in exchange for the goods or services. This guidance also requires more detailed disclosures to enable users of the financial statements to understand the nature, amount, timing and uncertainty, if any, of revenue and cash flows arising from contracts with customers. The requirements in this update are effective during interim and annual periods beginning after December 15, 2016. We are currently evaluating the impact this guidance will have on 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, domestic and international military, political, economic and weather conditions, the ability of OPEC to set and maintain production and price targets, technical advances affecting energy consumption and production and the price and availability of alternative fuels. All of these factors are beyond our control. Declines in the market prices of natural gas and oil caused our customers to significantly reduce 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 attributable to increased development of unconventional oil and natural gas reservoirs and an improvement in the price of oil. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year (WTI spot price as reported by the United States Energy Information Administration). Natural gas prices decreased in 2011 to an average of $4.00 per Mcf (Henry Hub spot price as reported by the United States Energy Information Administration). This decrease continued into 2012 where natural gas prices fell below $2.00 per Mcf in April and averaged $2.75 per Mcf for the year, resulting in continued low levels of drilling activity for natural gas in 2012. The increase in drilling activity in oil rich basins absorbed some of the decrease in demand for natural gas drilling activities in 2012. During 2013, natural gas prices averaged $3.73 per Mcf, and oil prices averaged $97.91 per barrel, and demand for natural gas drilling activities continued to decline. During the first half of 2014, natural gas prices averaged $4.91 per Mcf and oil prices averaged $101.05 per barrel and demand for drilling activities 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 decade has significantly contributed to excess capacity in total available drilling rigs. 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 rigs 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 and term loan 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 2.25% to 3.25% and the margin on base rate loans ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At June 30, 2014, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. As of June 30, 2014, we had no balances outstanding under our revolving credit facility and $87.5 million outstanding under our term loan facility at an interest rate of 2.50%. The interest rate on the borrowings outstanding under our revolving credit and term loan 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.

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, 2014.

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 1. Legal Proceedings

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, 2014.


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 2014 (2)		397,236	$	32.74		—	$	187,483
May 2014		—		—		—	$	187,483
June 2014 (2)		151,884	$	33.56		13,898	$	187,016

Total		549,120	$	32.97		13,898	$	187,016

(1)	On September 9, 2013, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $200 million of our common stock in open market or privately negotiated transactions.

(2)

We withheld 397,236 shares in April 2014 with respect to employees’ tax withholding obligations upon vesting of restricted shares, settlement of performance unit awards and the exercise of stock options. In June 2014, we withheld 137,986 shares with respect to payroll tax withholding obligations upon the vesting of restricted shares. These shares were acquired at fair market value pursuant to the terms of the 2014 Plan and not pursuant to the stock buyback program.

ITEM 6. Exhibits

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



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

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

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

10.1		Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan, including Form of Executive Officer Share-Settled Performance Share Award Agreement, Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed April 21, 2014 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, 2014, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Condensed Balance Sheets, (ii) the Consolidated Condensed Statements of Operations, (iii) the Consolidated Condensed Statements of Comprehensive Income, (iv) the Consolidated Condensed Statement of Changes in Stockholders’ Equity, (v) the Consolidated Condensed Statements of Cash Flows, and (vi) Notes to Consolidated Condensed Financial Statements.

*	filed herewith

SIGNATURE

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


PATTERSON-UTI ENERGY, INC.

By:		/s/ John E. Vollmer III
		John E. Vollmer III
		Senior Vice President – Corporate Development,
		Chief Financial Officer and Treasurer
		(Principal Financial and Accounting Officer and
		Duly Authorized Officer)

Date: July 28, 2014

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